Note: Descriptions are shown in the official language in which they were submitted.
METHOD OF SOLVENT RECOVERY FROM A SOLVENT BASED HEAVY OIL
EXTRACTION PROCESS
BACKGROUND
Field of Disclosure
[0001] The present disclosure relates to production of a bitumen product
from a
subterranean reservoir with improved processes for solvent recovery at end of
production or
near end of production of heavy oil from a solvent-based heavy oil extraction
process.
Description of Related Art
[0002] This section is intended to introduce various aspects of the art.
This discussion is
believed to facilitate a better understanding of particular aspects of the
present techniques.
Accordingly, it should be understood that this section should be read in this
light, and not
necessarily as admissions of prior art.
[0003] Modern society is greatly dependent on the use of hydrocarbon
resources for fuels
and chemical feedstocks. Subterranean rock formations that can be termed
"reservoirs" may
contain resources such as hydrocarbons that can be recovered. Removing
hydrocarbons from
the subterranean reservoirs depends on numerous physical properties of the
subterranean rock
formations, such as the permeability of the rock containing the hydrocarbons,
the ability of
the hydrocarbons to flow through the subterranean rock formations, and the
proportion of
hydrocarbons present, among other things.
[0004] Easily produced sources of hydrocarbons are dwindling, leaving
less conventional
sources to satisfy future needs. As the costs of hydrocarbons increase, less
conventional
sources become more economical. One example of less conventional sources
becoming more
economical is that of oil sand production. The hydrocarbons produced from less
conventional sources may have relatively high viscosities, for example,
ranging from 1000
centipoise (cP) to 20 million cP, with American Petroleum Institute (API)
densities ranging
from 8 degree ( ) API, or lower densities, up to 200 API, or higher densities.
The
hydrocarbons recovered from less conventional sources may include heavy oil.
However, the
hydrocarbons produced from the less conventional sources may be difficult to
recover using
conventional techniques. For example, the heavy oil may be sufficiently
viscous that
economical production of the heavy oil from a subterranean formation (also
referred to as a
"subterranean reservoir" herein) is precluded.
[0005] Several conventional processes for the extraction of heavy oils,
such as but not
limited to thermal extraction processes, have been utilized to decrease the
viscosity of the
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heavy oil. Decreasing the viscosity of the heavy oil may decrease a resistance
of the heavy
oil to flow and/or permit production of the heavy oil from the subterranean
reservoir by
piping, flowing, and/or pumping the heavy oil from the subterranean reservoir.
While each
of these extraction processes may be effective under certain conditions, each
possess inherent
limitations.
[0006] One of the conventional extraction processes utilizes steam
injection. The steam
injection may be utilized to heat the heavy oil to decrease the viscosity of
the heavy oil.
Water and/or steam may represent an effective heat transfer medium, but the
pressure
required to produce saturated steam at a desired temperature may limit the
applicability of
steam injection to high pressure operation and/or require a large amount of
energy to heat the
steam.
[0007] Another group of the conventional extraction processes utilizes
cold and/or heated
solvents. Cold and/or heated solvents may be injected into a subterranean
reservoir as liquids
and/or vapors to decrease the viscosity of heavy oil present within the
subterranean reservoir.
The injected solvent may dissolve the heavy oil, dilute the heavy oil, and/or
transfer thermal
energy to the heavy oil.
[0008] Some processes combine both steam injection and solvent injection
to obtain
improved extraction from both the use of the heat of the steam as well as the
solvency of the
heavy oils in the injected solvent to decrease the viscosity of the heavy oil.
While these
processes using a combination of steam and solvent are effective, they are
also hampered by
the associated capital and maintenance costs of having to produce and supply
both steam and
solvent to the process.
[0009] The solvent based extraction processes (which include the use of
an injected
solvent alone or with another fluid such as steam as described above) tend to
have the benefit
of improving the overall extraction of heavy oil from a subterranean reservoir
or formation.
However, a significant cost in these solvent based processes is the cost of
the solvents
themselves which are difficult to recover from the subterranean reservoir
during heavy oil
recovery, as well as after the well has neared or is at the end of its
economically useful life.
At the end (or near the end) of the reservoir's production, typically a
significant volume of
solvent, worth millions of dollars of solvent value, that has been injected to
assist in the
extraction of the heavy oil may be remaining in the reservoir.
[0010] Conventional process for solvent recovery at near end of life of
reservoirs in
solvent based extraction processes generally involves reducing or cutting off
the solvent
injection and utilizing steam injected through an upper injection well as a
mechanism to
recover the solvent with bitumen from the reservoir. The injected steam
evaporates the
retained solvent and condenses it at the edge of the chamber where it gravity
drains to a lower
production well along with extracted bitumen. The steam injection process thus
recovers the
solvent as a liquid through the process of gravity drainage. This technique
can result in very
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slow and inefficient solvent recovery. Additionally, the production of the
large amounts of
steam required is very energy intensive as well as requiring large amounts of
water, which
not only needs to be significantly treated (e.g., water softening, pH control,
etc.) in order to
produce the steam but requires a large amount of water which may not be
readily available in
a solvent-based extraction processes location. Even more of an impediment to
conventional
steam-based solvent recovery processes is typically that the solvent-based
extraction
processes require little or essentially no steam for use in injection process.
As such, the
solvent-based extraction processes typically have significantly undersized
steam capacity (if
any) to perform the steam flooding recovery processes. Therefore, extensive
capital and
construction is required to employ large steam generation systems at these
sites to employ
these conventional steam injection based solvent recovery processes to
resources previously
utilizing solvent-based heavy oil recovery processes.
[0011] Improved processes that can recover the remaining solvent from a
subterranean
reservoir can significantly reduce the overall cost of producing heavy oil
from solvent based
extraction processes. Additionally, removal of remaining solvents in a
subterranean reservoir
may provide environmental improvements by reducing the amount of remaining
solvents in a
shut-in reservoir from a solvent based heavy oil recovery process. Therefore,
a need exists in
the industry for improved technology, including technology that improves the
recovery of
solvents remaining in a subterranean reservoir at the end (or near the end,
i.e., "late life") of
the reservoir's production stage.
SUMMARY
[0012] It is an object of the present disclosure to provide systems and
methods for
improving the recovery of solvents from a subterranean reservoir remaining in
the reservoir
at the end (or near the end, i.e. "late life") of the production stage of a
reservoir that has been
subjected to a solvent based heavy oil extraction process.
[0013] An embodiment disclosed herein includes a process for the
recovery of a solvent
from a subterranean reservoir containing a solvent and a heavy oil, the
process comprising:
a) recovering a heavy oil from a subterranean reservoir utilizing a solvent-
assisted gravity drainage process wherein a portion of a solvent from the
solvent-assisted
gravity drainage process remains located in the subterranean reservoir;
b) injecting a gas phase dilution agent into the subterranean reservoir;
c) contacting at least a portion of the gas phase dilution agent with the
solvent;
d) vaporizing at least a portion of the solvent that is in the liquid phase to
produce a vaporized solvent; and
e) extracting at least a portion of the gas phase dilution agent and the
vaporized
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solvent from the subterranean reservoir.
[0014] In
a preferred embodiment, the gas phase dilution agent comprises a non-
condensable gas which remains in vapor phase at pressure and temperature of
the
subterranean reservoir.
[0015] Another embodiment disclosed herein includes the process wherein the
solvent-
assisted gravity drainage process step comprises a well pair located in the
subterranean
reservoir, wherein the well pair is comprised of at least one injection well
and at least one
production well and further wherein the at least one injection well is
converted to an NCG
injection well prior to, or in conjunction with, step b), and injecting the
gas phase dilution
agent into the subterranean reservoir via the NCG injection well.
[0016]
Another embodiment disclosed herein includes the process wherein the solvent-
assisted gravity drainage process step comprises at least two well pairs
located in the
subterranean reservoir, wherein each well pair is comprised of an injection
well and a
production well in step a), prior to, or in conjunction with, step b):
- converting at least one of the injection wells or production wells to an NCG
injection well; and
- converting at least one of the injection wells or production wells to an
NCG/vaporized solvent production well;
wherein at least a portion of the gas phase dilution agent is injected into
the
subterranean reservoir via the NCG injection well; and at least a portion of
the gas phase
dilution agent and the vaporized solvent is extracted from the subterranean
reservoir via the
NCG/vaporized solvent production well.
[0017]
Another embodiment disclosed herein includes the process wherein the solvent-
assisted gravity drainage process step comprises at least three well pairs
located in the
subterranean reservoir, wherein each well pair is comprised of an injection
well and a
production well in step a), prior to, or in conjunction with, step b):
- converting at least two of the injection wells to NCG injection wells;
and
- converting at least one of the injection wells or production wells to an
NCG/vaporized solvent production well;
wherein at least a portion of the gas phase dilution agent is injected into
the
subterranean reservoir via the NCG injection wells; and at least a portion of
the gas phase
dilution agent and the vaporized solvent is extracted from the subterranean
reservoir via the
NCG/vaporized solvent production well.
[0018]
Another embodiment disclosed herein includes the process wherein the solvent-
assisted gravity drainage process step comprises at least three well pairs
located in the
subterranean reservoir, wherein each well pair is comprised of an injection
well and a
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production well in step a), prior to, or in conjunction with, step b):
- converting at least one of the injection wells to NCG injection wells;
and
- converting at least two of the injection wells or production wells to an
NCG/vaporized solvent production well;
wherein at least a portion of the gas phase dilution agent is injected into
the
subterranean reservoir via the NCG injection well; and at least a portion of
the gas phase
dilution agent and the vaporized solvent is extracted from the subterranean
reservoir via the
NCG/vaporized solvent production wells.
[0019] Another embodiment disclosed herein includes the process wherein
the solvent-
assisted gravity drainage process step comprises at least two well pairs
located in the
subterranean reservoir, wherein each well pair is comprised of an injection
well and a
production well in step a), prior to, or in conjunction with, step b):
- converting an existing infill well or installing a new infill well in the
subterranean reservoir located in a horizontal direction between the two well
pairs for
use as an NCG/vaporized solvent production well; and
- converting the two injection wells or the two production wells to NCG
injection wells;
wherein at least a portion of the gas phase dilution agent is injected into
the
subterranean reservoir via the NCG injection well; and at least a portion of
the gas phase
dilution agent and the vaporized solvent is extracted from the subterranean
reservoir via the
NCG/vaporized solvent production well.
[0020] Another embodiment disclosed herein includes the process wherein
the solvent-
assisted gravity drainage process step comprises at least two well pairs
located in the
subterranean reservoir, wherein each well pair is comprised of an injection
well and a
production well in step a), prior to, or in conjunction with, step b):
- converting an existing infill well or installing a new infill well in the
subterranean reservoir located in a horizontal direction between the two well
pairs for use as
an NCG injection well; and
- converting the two injection wells or the two production wells to an
NCG/vaporized solvent production well;
wherein at least a portion of the gas phase dilution agent is injected into
the
subterranean reservoir via the NCG injection well; and at least a portion of
the gas phase
dilution agent and the vaporized solvent is extracted from the subterranean
reservoir via the
NCG/vaporized solvent production wells.
[0021] Another embodiment disclosed herein includes the process wherein the
solvent-
.
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assisted gravity drainage process step comprises at least one well pair
located in the
subterranean reservoir, wherein each well pair is comprised of an injection
well and a
production well in step a), and prior to, or in conjunction with, step b):
- converting at least one of the injection well or the production well in
each well
pair to a NCG/vaporized solvent production well;
- injecting the gas phase dilution agent into the top of the subterranean
reservoir
or into an existing top zone of the subterranean reservoir;
- creating a gas cap in the subterranean reservoir comprising the gas phase
dilution agent; and
- expanding the gas cap downward into the subterranean reservoir to at least a
point wherein gas cap is in contact with the NCG/vaporized solvent production
wells;
wherein in step e), the at least a portion of the gas phase dilution agent and
the
vaporized solvent is extracted from the subterranean reservoir via the
NCG/vaporized solvent
production well.
[0022] Another embodiment disclosed herein includes a system for the
recovery of a
solvent from a subterranean reservoir containing a solvent and a heavy oil,
the system
comprising:
- a subterranean reservoir containing an existing solvent comprising a
liquid
phase and a heavy oil;
- a first injector fluidly connected to the subterranean reservoir, wherein
the
injector is located to inject a gas phase dilution agent into the subterranean
reservoir, so as to
contact at least a portion of the gas phase dilution agent with the existing
solvent and
vaporize at least a portion of the existing solvent to produce a vaporized
solvent; and
- a first NCG/vaporized solvent production well located within the
subterranean
reservoir and fluidly connected to the first injector;
wherein the first NCG/vaporized solvent production well is configured to
recover
a portion of the gas phase dilution agent and a portion of the vaporized
solvent.
[0023] The foregoing has broadly outlined the features of the present
disclosure so that
the detailed description that follows may be better understood. Additional
features will also
be described herein.
DESCRIPTION OF THE DRAWINGS
[0024] These and other features, aspects and advantages of the present
disclosure will
become apparent from the following description and the accompanying drawings,
which are
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briefly discussed below.
[0025] Figure 1 illustrates the solvent stripping mechanism due to
dilution and partial
pressure reduction by non-condensable gases.
[0026] Figure 2 illustrates the solvent vaporization due to dilution and
partial pressure
reduction by non-condensable gases.
[0027] Figure 3 is a simplistic diagram of a single well pair
configuration in a
subterranean reservoir as used in an embodiment of the invention herein.
[0028] Figures 4A-4E illustrate reservoir well configurations and flow
patterns for
various gas sweep embodiments of the present invention.
[0029] Figure 5 is a simplified illustration of the well configuration
utilized in modeling
embodiments of the gas sweep configurations of the present invention.
[0030] Figure 6A is a graph of the solvent production rate as a function
of time for the
steam injection model (SAGD mode) of an embodiment of the present invention
for a single
well pair configuration.
100311 Figure 6B is a graph of the solvent production rate as a function of
time for the
NCG injection model of an embodiment of the present invention for a single
well pair
configuration.
[0032] Figure 6C is a graph of the solvent production rate as a function
of time for the
inter-well pair NCG flood model of an embodiment of the present invention for
a multiple
well pair configuration using a gas flood/sweep configuration.
[0033] Figure 7 is a graph comparing the solvent recovery (in percentage
of total solvent)
for different solvent recovery methods. It includes the steam only (switch to
SAGD), NCG
injection for a single well pair configuration, and an inter-well pair NCG
flood case of the
present invention for a multiple well pair configuration. using a gas
flood/sweep
configuration.
[0034] Figure 8 illustrates a reservoir well configuration and flow
patterns for a gas cap
expansion embodiment of the present invention.
[0035] Figure 9 is a graph comparing the solvent recovery (in percentage
of total solvent)
for the present invention for a multiple well pair configuration using the gas
cap expansion
configuration and inter-well pair NCG flood configuration.
[0036] Figure 10 is a graph comparing the solvent recovery (in
percentage of total
solvent) for two models of the present invention using the gas flood/sweep
configuration and
the gas cap expansion configuration, in comparison with a steam injection only
(SAGD)
solvent recovery model of the prior art for a multiple well pair
configuration.
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DETAILED DESCRIPTION
[0037] 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.
[0038] At the outset, for ease of reference, certain terms used in this
application and their
meanings as used in this context are set forth. To the extent a term used
herein is not defined
below, it should be given the broadest definition persons in the pertinent art
have given that
term as reflected in at least one printed publication of issued patent.
Further, the present
techniques are not limited by the usage of the terms shown below, as all
equivalents,
synonyms, new developments, and terms or processes that serve the same or a
similar
purpose are considered to be within the scope of the present disclosure.
[0039] A "hydrocarbon" is an organic compound that primarily includes the
elements
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. However, the techniques described herein
are not limited
to heavy oils, but may also be used with any number of other subterranean
reservoirs.
Hydrocarbon compounds may be aliphatic or aromatic, and may be straight
chained,
branched, or partially or fully cyclic.
[0040] "Bitumen" is a naturally occurring heavy oil material. Generally,
it is the
hydrocarbon component found in oil sands. Bitumen can vary in composition
depending
upon the degree of loss of more volatile components. It can vary from a very
viscous, tar-
like, semi-solid material to solid forms. The hydrocarbon types found in
bitumen can include
aliphatics, aromatics, resins, and asphaltenes. A typical bitumen might be
composed of:
19 weight A (wt.%) 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 in excess of 7 wt.%).
[0041] The percentage of the hydrocarbon types found in bitumen can vary.
In addition,
bitumen can contain some water and nitrogen compounds ranging from less than
0.4 wt.% to
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in excess of 0.7 wt.%. The metals content, while small, may be removed to
avoid
contamination of synthetic crude oil. Nickel can vary from less than 75 ppm
(parts per
million) to more than 200 ppm. Vanadium can range from less than 200 ppm to
more than
500 ppm.
[0042] The term "heavy oil" includes bitumen, as well as lighter materials
that may be
found in a sand or carbonate reservoir. "Heavy oil" includes oils that are
classified by the
American Petroleum Institute (API), as heavy oils, extra heavy oils, or
bitumens. Thus the
term "heavy oil" includes bitumen. Heavy oil may have a viscosity of about
1000 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 22.30 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
10.00 API
(density greater than 1,000 kg/m3 or greater than 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. The recovery of heavy oils is based on the viscosity decrease of
fluids with
increasing temperature and/or solvent concentration. Once the viscosity is
reduced, the
mobilization of fluids by steam, hot water flooding, or gravity is possible.
The reduced
viscosity makes the drainage quicker and therefore directly contributes to the
recovery rate.
A heavy oil may include heavy end components and light end components.
100431 The term "asphaltenes" or "asphaltene content" refers to pentane
insolubles (or
the amount of pentane insoluble in a sample) according to ASTM D3279. Other
examples of
standard ASTM asphaltene tests include ASTM test numbers D4055, D6560, and
D7061.
100441 "Heavy end components" in heavy oil may comprise a heavy viscous
liquid or
solid made up of heavy hydrocarbon molecules. Examples of heavy hydrocarbon
molecules
include, but are not limited to, molecules having greater than or equal to 30
carbon atoms
(C30+). The amount of molecules in the heavy hydrocarbon molecules may include
any
number within or bounded by the preceding range. The heavy viscous liquid or
solid may be
composed of molecules that, when separated from the heavy oil, have a higher
density and
viscosity than a density and viscosity of the heavy oil containing both heavy
end components
and light end components. For example, in Athabasca bitumen, about 70 weight
(wt.) % of
the bitumen contains C30+ molecules with about 18 wt. % of the Athabasca
bitumen being
classified as asphaltenes. The heavy end components may include asphaltenes in
the form of
solids or viscous liquids.
[0045] "Light end components" in heavy oil may comprise those components
in the
heavy oil that have a lighter molecular weight than heavy end components. The
light end
components may include what can be considered to be medium end components.
Examples
of light end components and medium end components include, but are not limited
to, light
and medium hydrocarbon molecules having greater than or equal to 1 carbon atom
and less
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than 30 carbon atoms. The amount of molecules in the light and medium end
components
may include any number within or bounded by the preceding range. The light end
components and medium end components may be composed of molecules that have a
lower
density and viscosity than a density and viscosity of heavy end components
from the heavy
oil.
[0046] A "fluid" includes a gas or a liquid and may include, for example,
a produced or
native reservoir hydrocarbon, an injected mobilizing fluid, hot or cold water,
or a mixture of
these among other materials. "Vapor" refers to the gas phase which may contain
various
materials. Vapor may consist of solvent in the gas form, steam, wet steam, and
mixtures of
steam and wet steam, any of which could possibly be used with a solvent and
other
substances, and any material in the vapor phase.
[0047] "Facility" or "surface facility" is a tangible piece of physical
equipment through
which hydrocarbon fluids are either produced from a subterranean reservoir or
injected into a
subterranean reservoir, or equipment that can be used to control production or
completion
operations. In its broadest sense, the term facility is applied to any
equipment that may be
present along the flow path between a subterranean reservoir and its delivery
outlets.
Facilities may comprise production wells, injection wells, well tubulars,
wellbore head
equipment, gathering lines, manifolds, pumps, compressors, separators, surface
flow lines,
steam generation plants, solvent vaporizers, processing plants, and delivery
outlets. In some
instances, the term "surface facility" is used to distinguish from those
facilities other than
wells.
[0048] "Pressure" is the force exerted per unit area on the walls of a
volume. Pressure
may be shown in this disclosure as pounds per square inch (psi), kilopascals
(kPa) or
megapascals (MPa). "Atmospheric pressure" refers to the local pressure of the
air.
"Absolute pressure" (psia) refers to the sum of the atmospheric pressure (14.7
psia at
standard conditions) plus the gauge pressure. "Gauge pressure" (psig) refers
to the pressure
measured by a gauge, which indicates only the pressure exceeding the local
atmospheric
pressure (i.e., a gauge pressure of 0 psig corresponds to an absolute pressure
of 14.7 psia).
The term "vapor pressure" has the usual thermodynamic meaning. For a pure
component in
an enclosed system at a given pressure, the component vapor pressure is
essentially equal to
the total pressure in the system. Unless otherwise specified,, the pressures
in the present
disclosure are absolute pressures.
[0049] A "subterranean reservoir" (or "subterranean formation") is a
subsurface rock, for
example carbonate or sand reservoir, from which a production fluid, or
resource, can be
harvested. A subterranean reservoir may interchangeably be referred to as a
subterranean
formation. The subterranean formation may include sand, granite, silica,
carbonates, clays,
and organic matter, such as bitumen, heavy oil (e.g., bitumen), oil, gas, or
coal, among others.
Subterranean reservoirs can vary in thickness from less than one foot (0.3048
meters (m)) to
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hundreds of feet (hundreds of meters). The resource is generally a
hydrocarbon, such as a
heavy oil impregnated into a sand bed.
[0050] A "thermal extraction process" (or "thermal recovery process")
includes any type
of hydrocarbon extraction process that uses a heat source to enhance the
extraction/recovery
of heavy oils, including bitumen, from a subterranean reservoir or formation,
for example, by
lowering the viscosity of a hydrocarbon. The processes may use injected
mobilizing fluids,
such as but not limited to hot water, wet steam, dry steam, or solvents, alone
or in any
combination, to lower the viscosity of the hydrocarbon. Any of the thermal
recovery
processes may be used in concert with solvents. For example, thermal recovery
processes
may include cyclic steam stimulation (CSS), steam assisted gravity drainage
(SAGD), steam
flooding, in-situ combustion and other such processes.
[0051] A "solvent-based extraction process" (or "solvent-based recovery
process")
includes any type of hydrocarbon extraction process that uses a solvent to
enhance the
extraction/recovery of heavy oils, including bitumen, from .a subterranean
reservoir or
formation, for example, by diluting or lowering a viscosity of the
hydrocarbon. Solvent-based
recovery processes may be used in combination with other recovery processes,
such as, for
example, thermal recovery processes. In solvent-based recovery processes, a
solvent is
injected into a subterranean reservoir. The solvent may be heated or unheated
prior to
injection, may be a vapor or liquid and may be injected with or without steam.
Solvent-based
recovery processes may include, but are not limited to, solvent assisted
cyclic steam
stimulation (SA-CSS), solvent assisted steam assisted gravity drainage (SA-
SAGD), solvent
assisted steam flood (SA-SF), vapor extraction process (VAPEX), thermal
variations of
VAPEX such as heated vapor extraction process (H-VAPEX) and azeotropic heated
vapor
extraction process (Azeo-VAPEX), cyclic solvent process (CSP), heated cyclic
solvent
process (H-CSP), solvent flooding, heated solvent flooding, liquid extraction
process, heated
liquid extraction process, solvent-based extraction recovery process (SEP),
thermal solvent-
based extraction recovery processes (TSEP), liquid addition to steam for
enhanced recovery
(LASER), and any other such recovery process employing solvents either alone
or in
combination with steam. A solvent-based recovery process may be a thermal
recovery
process if the solvent is heated prior to injection into the subterranean
reservoir. The solvent-
based recovery process may employ gravity drainage.
[0052] Steam to Oil Ratio ("SOR") is the ratio of a volume of steam (in
cold water
equivalents) required to produce a volume of oil. Cumulative SOR ("CSOR") is
the average
volume of steam (in cold water equivalents) over the life of the operation
required to produce
a volume of oil. Instantaneous ("ISOR") is the instantaneous .rate of steam
(in cold water
equivalents) required to produce a volume of oil. SOR, CSOR, and ISOR are
calculated at
standard temperature and pressure ("STP", 15 C and 100kPa or 60 F and 14.696
psi).
[0053] Likewise, Solvent to Oil Ratio ("SoiOR") is the ratio of a volume
of solvent (in
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cold liquid equivalents) required to produce a volume of oil. Cumulative SolOR
("CS010R") is
the average volume of solvent (in cold liquid equivalents) over the life of
the operation
required to produce a volume of oil. Instantaneous ("ISolOR") is the
instantaneous rate of
solvent required to produce a volume of oil. SolOR, CS010R, .and ISoiOR are
calculated at
STP.
[0054] "Azeotrope" means the "thermodynamic azeotrope" as described
further herein.
[0055] A "wellbore" is a hole in the subsurface made by drilling or
inserting a conduit
into the subsurface. A wellbore may have a substantially circular cross
section or any other
cross-sectional shape, such as an oval, a square, a rectangle, a triangle, or
other regular or
irregular shapes. The term "well," when referring to an opening in the
formation or reservoir,
may be used interchangeably with the term "wellbore." Further, multiple pipes
may be
inserted into a single wellbore, for example, as a liner configured to allow
flow from an outer
chamber to an inner chamber.
[0056] "Permeability" is the capacity of a rock structure to transmit
fluids through the
interconnected pore spaces of the structure. The customary unit of measurement
for
permeability is the milliDarcy (mD).
[0057] "Reservoir matrix" refers to the solid porous material forming
the structure of the
subterranean reservoir. The subterranean reservoir is composed of the solid
reservoir matrix,
typically rock or sand, around pore spaces in which resources such as heavy
oil may be
located. The porosity of a subterranean reservoir is defined by the percentage
of volume of
void space in the rock or sand reservoir matrix that potentially contains
resources and water.
[0058] A "solvent extraction chamber" is a region of a subterranean
reservoir containing
heavy oil that forms around a well that is injecting solvent into the
subterranean reservoir.
The solvent extraction chamber has a temperature and a pressure that is
generally at or close
to a temperature and pressure of the solvent injected into the subterranean
reservoir. The
solvent extraction chamber may form when heavy oil has, due to heat from the
solvent,
dissolution within the solvent, combination with the solvent, and/or the
action of gravity, at
least partially mobilized through the pore spaces of the reservoir matrix. The
mobilized
heavy oil may be at least partially replaced in the pore spaces by solvent,
thus forming the
solvent chamber. In practice, layers in the subterranean reservoir containing
heavy oil may
not necessarily have pore spaces that contain 100 percent (%) heavy oil and
may contain only
70 - 80 volume (vol.) % heavy oil with the remainder possibly being water or
gas. A water
and/or gas containing layer in the subterranean reservoir may comprise 100%
water and/or
gas in the pore spaces, but generally contains 5 - 70 vol.% gas and 20 - 30
vol.% water with
any remainder possibly being heavy oil.
[0059] A "vapor chamber" is a solvent extraction chamber that includes a
vapor, or
vaporous solvent. Thus, when the solvent is injected into the subterranean
reservoir as a
vapor, a vapor chamber may be formed around the well.
- 12 -
CA 2974711 2017-07-27
[0060] A "reservoir chamber" is a region of the subterranean reservoir
that generally
contains heavy oil and is affected by (such as increased in temperature or
modified in
pressure) and mobilized by the oil recovery process. It is generally a region
near the wells,
surrounding the wells, as well as intermediate locations between the wells,
especially
between the injection wells and production wells that are under fluid
communication. This
not only includes the reservoir matrix wherein the heavy oil is located, but
also includes rock
and mineral deposits that may surround the area but may be affected by the
heavy oil
recovery process (such as experiencing an increase in temperature). Where
solvent extraction
chamber(s) and/or vapor chamber(s) exist, these are part of the overall
reservoir chamber.
[0061] A "non-condensable gas" or "NCG" is a compound that is in a vapor
phase at
reservoir pressure and temperature conditions. The term NCG may be used in
this disclosure
for the purposes as a shorthand reference to the term "gas phase dilution
agent".
[0062] A "gas phase dilution agent" is an agent, composition or stream
containing at least
some amount, preferably at least 50% by weight in amount, of "non-condensable
gas" or
"NCG".
[0063] "Produced Bitumen to Retained Solvent ratio" or "PBRS" is the
amount of
bitumen (by standard condition liquid volume equivalent) extracted from the
well or reservoir
divided by the amount of unrecovered solvent (by standard condition liquid
volume
equivalent) injected into the well or reservoir. It is used to measure the
solvent recovery
efficiency of a solvent assisted production process or solvent recovery
process.
[0064] "A late life" or "end of life" phase as it refers to solvent
based heavy oil recovery
processes herein can include the later stages of heavy oil production during
such processes, a
switch from heavy oil production mode to a solvent recovery mode during such
processes, or
a combination thereof. These generally will not be distinct phases in such
processes, but a
gradual, or multi-step, shift from the general heavy oil production mode of
the heavy oil
extraction process to a solvent recovery process mode, generally performed
near the end of
the useful/economic production cycle of a heavy oil reservoir.
[0065] A "hydrocarbon solvent" or "hydrocarbon mixture" ,as used herein
means a pure
component or near pure component solvent or a mixture of at least two, and
more usually, at
least three, hydrocarbon compounds having a number of carbon atoms from the
range of C1
to C30+. A hydrocarbon mixture is often at least hydrocarbons in the range of
C3 to Cp or
higher. For industrial applications, the commercially available solvents are
generally are a
mixture of hydrocarbon compounds. Commercial grade ethane, propane, butane,
LPG, gas
condensate, diluents, and naphtha are among the used hydrocarbon solvent.
[0066] The terms "approximately," "about," "substantially," and similar
terms are
intended to have a broad meaning in harmony with the common and accepted usage
by those
of ordinary skill in the art to which the subject matter of this disclosure
pertains. It should be
understood by those of skill in the art who review this disclosure that these
terms are intended
- 13 -
CA 2974711 2017-07-27
=
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.
These terms when used in reference to a quantity or amount of a material, or a
specific
characteristic of the material, refer to an amount that is sufficient to
provide an effect that the
material or characteristic was intended to provide. The exact degree of
deviation allowable
may in some cases depend on the specific context.
[0067] 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.
[0068] As used herein, the phrase "at least one," in reference to a list
of one or more
entities should be understood to mean at least one entity selected from any
one or more of the
entity in the list of entities, but not necessarily including at least one of
each and every entity
specifically listed within the list of entities and not excluding any
combinations of entities in
the list of entities. This definition also allows that entities may optionally
be present other
than the entities specifically identified within the list of entities to which
the phrase "at least
one" refers, whether related or unrelated to those entities specifically
identified. Thus, as a
non-limiting example, "at least one of A and B" (or, equivalently, "at least
one of A or B," or,
equivalently "at least one of A and/or B") may refer, to at least one,
optionally including
more than one, A, with no B present (and optionally including entities other
than B); to at
least one, optionally including more than one, B, with no A present (and
optionally including
entities other than A); to at least one, optionally including more than one,
A, and at least one,
optionally including more than one, B (and optionally including other
entities). In other
words, the phrases "at least one," "one or more," and "and/or" are open-ended
expressions
that are both conjunctive and disjunctive in operation. For example, each of
the expressions
"at least one of A, B and C," "at least one of A, B, or C," "one or more of A,
B, and C," "one
or more of A, B, or C" and "A, B, and/or C" may mean A alone, B alone, C
alone, A and B
together, A and C together, B and C together, A, B and C together, and
optionally any of the
above in combination with at least one other entity.
[0069] As used herein, the term -and/or" placed between a first entity and
a second entity
means one of (1) the first entity, (2) the second entity, and (3) the first
entity and the second
entity. Multiple entities listed with "and/or" should be construed in the same
manner, i.e.,
"one or more" of the entities so conjoined. Other entities may optionally be
present other
than the entities specifically identified by the "and/or" clause, whether
related or unrelated to
those entities specifically identified. Thus, as a non-limiting example, a
reference to "A
and/or B," when used in conjunction with open-ended language such as
"comprising" may
refer to A only (optionally including entities other than B); to B only
(optionally including
entities other than A); to both A and B (optionally including other entities).
These entities
may refer to elements, actions, structures, steps, operations, values, and the
like.
- 14 -
CA 2974711 2017-07-27
[0070] As used herein the terms "adapted.' and "configured" mean that the
element,
component, or other subject matter is designed and/or intended to perform a
given function.
Thus, the use of the terms "adapted" and "configured" should not be construed
to mean that a
given element, component, or other subject matter is simply "capable of'
performing a given
function but that the element, component, and/or other subject matter is
specifically selected,
created, implemented, utilized, programmed, and/or designed for the purpose of
performing
the function. It is also within the scope of the present disclosure that
elements, components,
and/or other recited subject matter that is recited as being adapted to
perform a particular
function may additionally or alternatively be described as being configured to
perform that
function, and vice versa.
[0071] 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, embodiments, and/or methods according to the present
disclosure, are
intended to convey that the described component, feature, detail, structure,
embodiment,
and/or method is an illustrative, non-exclusive example of components,
features, details,
structures, embodiments, and/or methods according to the present disclosure.
Thus, the
described component, feature, detail, structure, embodiment, and/or method is
not intended to
be limiting, required, or exclusive/exhaustive; and other components,
features, details,
structures, embodiments, and/or methods, including structurally and/or
functionally similar
and/or equivalent components, features, details, structures, embodiments,
and/or methods, are
also within the scope of the present disclosure.
[0072] Any of the ranges disclosed may include any number within and/or
bounded by
the range given.
[0073] In the illustrative figures herein, in general, elements that are
likely to be included
are illustrated in solid lines, while elements that are optional are
illustrated in dashed lines.
However, elements that are shown in solid lines may not be 'essential. Thus,
an element
shown in solid lines may be omitted without departing from the scope of the
present
disclosure.
[0074] Figures 1-10 provide illustrative, non-exclusive examples of
systems according to
the present disclosure, components of systems, data that may be utilized to
select a
composition of a hydrocarbon solvent mixture and or a reservoir injection
mixture that may
be utilized with systems, and/or methods, according to the present disclosure,
of operating
and/or utilizing systems. Elements that serve a similar, or at least
substantially similar,
purpose are labeled with like numbers in each of Figures 1-10, and these
elements may not be
discussed in detail herein with reference to each of Figures 1-10. Similarly,
all elements may
not be labeled in each of Figures 1-10, but associated reference numerals may
be utilized for
consistency. Elements, components, and/or features that are discussed herein
with reference
to one or more of Figures 1-10 may be included in and/or utilized with any of
Figures 1-10
=
- 15 -
CA 2974711 2017-07-27
without departing from the scope of the present disclosure.
[0075] Solvent based heavy oil extraction (or "recovery") processes can
be utilized over
conventional non-solvent based heavy oil extraction processes (such as steam
assisted gravity
drainage, or SAGD processes) to improve extraction of heavy oil from a
subterranean
reservoir. Solvent-based recovery processes may be used in combination with
other recovery
processes, such as, for example, thermal recovery processes, such as SAGD. In
solvent-based
recovery processes, a solvent is injected into a subterranean reservoir. The
solvent may be
heated or unheated prior to injection, may be a vapor or liquid and may be
injected with or
without steam. Solvent-based recovery processes may include, but are not
limited to, solvent
assisted cyclic steam stimulation (SA-CSS), solvent assisted steam assisted
gravity drainage
(SA-SAGD), solvent assisted steam flood (SA-SF), vapor extraction process
(VAPEX),
thermal variations of VAPEX such as heated vapor extraction process (H-VAPEX)
and
azeotropic heated vapor extraction process (Azeo-VAPEX), cyclic solvent
process (CSP),
heated cyclic solvent process (H-CSP), liquid addition to steam enhanced
recovery (LASER),
solvent flooding, heated solvent flooding, liquid extraction process, heated
liquid extraction
process, solvent-based extraction recovery process (SEP), thermal solvent-
based extraction
recovery processes (TSEP), and any other such recovery process employing
solvents either
alone or in combination with steam. A solvent-based recovery process may be a
thermal
recovery process if the solvent is heated prior to injection into the
subterranean reservoir.
The solvent-based recovery process may employ gravity drainage
[0076] In these solvent based recovery processes, a large quantity of
solvent is retained in
the reservoir that is trapped under thermodynamic equilibrium and fluid flow
behaviors in the
depleted zone under the reservoir conditions. This trapped solvent, at the end
of bitumen
recovery, can be a considerable portion of the process cost, often amounting
to over millions
of dollars of trapped/unrecovered solvent. Economical or operational
conditions may require
the recovery of this solvent during or at the end of the bitumen recovery. The
recovery of
trapped solvent in late life of a reservoir operation, or progressively as
ultimate recoverable
bitumen is approaching in the life of a reservoir operation, or when otherwise
economically
or operationally necessary, can significantly reduce the process cost and
improve the
economics of solvent based recovery processes. Additional environmental
benefits may be
achieved by reducing the amount of solvent in a reservoir after end of life
(i.e., shut in).
[0077] When considering the general economic values of unrecovered
solvents in a
typical heavy oil reservoir at near the end of the production phase (i.e.,
late life) of a solvent
based heavy oil recovery process, the value of the remaining solvent can
amount to millions
of dollars of stranded solvent in the reservoir and can be one of the largest
overall costs in a
solvent based heavy oil process. High solvent usage processes (such as VAPEX)
may have
significantly higher quantities of unrecovered or unrecoverable solvents
during the process
and thus at late life. "PBRS", a measure of economic viability, is the
"Produced Bitumen to
Retained Solvent" ratio and is the amount of bitumen (by standard condition
volume) from
- 16 -
CA 2974711 2017-07-27
the well or reservoir divided by the amount of unrecovered solvent (by
standard condition
volume) from the well or reservoir. In reservoirs undergoing the VAPEX
process, near the
end of the production life of the reservoir, the PBRS depends on many factors
such as the
geometry and geology of the reservoir, the type and geometry of the wells,
operating
conditions, selection of solvent ratios and/or solvent concentrations, as well
as many other
possible factors. However, a significant magnitude of lost 'potential
resources and lost
economics are subject to recovery by improved solvent recovery processes.
[0078] In the methods discovered and herein disclosed, recovery of the
trapped solvent
can be achieved by changing the phase behavior conditions in the reservoir by
introducing a
gas phase dilution agent. Preferably, a heating agent may also utilized or
otherwise present as
stored heat in the reservoir from solvent-based thermal recovery process to
provide
vaporization energy for stripping of the solvent. Alternatively, the gas phase
dilution agent
can also serve as a, or the, heating agent as well. The heating agent may be
comprised of the
non-condensable gas, steam or a combination thereof. The heat stored in the
reservoir during
a solvent-based thermal heavy oil recovery process may serve as the heating
agent as well. In
preferred embodiments, the gas phase dilution agent contains or is
substantially comprised of
a non-condensable gas under reservoir pressure and temperature conditions. For
simplicity
purposes herein, the gas phase dilution agent (which may also be referred to
as the
"dilution/heating agent" or designated as "D/HA") may be described as a non-
condensable
gas or NCG herein. =
[0079] In the present disclosure, a gas phase dilution agent, preferably
a non-condensable
gas, and associated processes, methods, and configurations are utilized to
improve solvent
recovery from subterranean reservoirs at late life of solvent based heavy oil
recovery
processes. In the majority of the embodiments herein, the gas phase dilution
agent will be
utilized, at least in part, to reduce the partial pressure of the liquid phase
solvent in the
reservoir and thus vaporize the solvent, or at least a portion of the solvent
by the various
methods and configurations disclosed herein. This includes vaporizing at least
a portion of
the lower boiling point components of the solvent. In conventional solvent
recovery systems,
the recovery mode is to recover the solvent mainly in the liquid phase,
preferably by
"pushing" the solvent, or by evaporating and then condensing the solvent, and
recovering the
primarily liquid solvent from the production well. As an example, a solvent
based thermal
gravity drainage-based heavy oil recovery process, for example thermal VAPEX,
may switch
to steam injection at the end of the life of the economical production, which
is also known as
switching to steam assisted gravity drainage (SAGD). In this, setup, steam
evaporates the
liquid phase solvent, which then condenses at the edge of the chamber and is
produced
mainly as a liquid phase. In contrast, the methods disclosed herein are
designed to vaporize,
in-situ, the solvent (or components of solvent) and recover the solvent from
the reservoir
primarily in the vapor phase by injection and production of gas (preferably a
non-
condensable gas) as discussed further herein. It has been discovered herein,
and as will be
- 17 -
CA 2974711 2017-07-27
shown, that recovering the solvent primarily in the vapor phase according to
the methods
herein, results in a distinctly improved recovery rate (i.e., solvent recovery
percentage) over
methods of recovering the solvent in the liquid phase. For simplicity herein,
the term
"solvent" as used refers to the solvent which is targeted to be recovered from
the reservoir,
and includes the previously injected solvent that is to be recovered from the
reservoir, or a
portion of the components thereof unless otherwise noted.
[0080] To simplify the discussions in this disclosure, the term "late
life" as it refers to
solvent based heavy oil recovery processes herein can include the later stages
of heavy oil
production during such processes, a switch from heavy oil production mode to a
solvent
recovery mode during such processes for example due to operational or economic
factors, or
a combination thereof. As will be obvious to one of skill in the art in light
of this disclosure,
these generally will not be distinct phases in such processes, but a gradual,
or multi-step, shift
from the general heavy oil production mode of the heavy oil extraction process
to a solvent
recovery process mode, generally performed near the end of the useful
production cycle of a
heavy oil reservoir, or otherwise due to other factors such as operational or
economic
considerations.
[0081] To help illustrate the present concepts, Figure 1 illustrates the
solvent stripping
mechanism due to dilution. Introduction of a non-condensable diluting agent
into the pore
space results in a drop in the solvent partial pressure, thus reducing its
molar fraction in the
liquid phase. The smaller liquid phase molar fraction implies stripping of the
solvent from the
liquid phase into a gas phase. The solvent is thus easier to displace due to
the gas phase
mobility. Continuous injection of the diluting agent into the reservoir and
production of the
solvent vapor results in the removal of much of the solvent. This is
demonstrated on Figure 1
by the dashed arrows, where the solvent stored during the thermal solvent-
based recovery
(shown by the triangles) is reduced to much lower values (shown by the
circles) at the end of
the solvent striping process.
[0082] This concept is further illustrated in Figure 2 which depicts the
injected solvent
content of a reservoir as an example. Here, on the left hand side, illustrates
the amount of
solvent in the reservoir in both the liquid phase (x, : the molar fraction of
solvent in the liquid
phase) and the vapor phase (y, : the molar fraction of solvent in the vapor
phase), as well as
the bitumen in the liquid phase. By adding the non-condensable 'gas (NCG) to
the reservoir, a
greater portion of the liquid solvent vaporizes and increases the solvent
concentration in the
vapor phase of the reservoir. This vaporized fraction of the solvent can then
be extracted
from the reservoir by the various methods described herein. These methods, as
will be
shown, result in significantly increased amounts of overall solvent recovery,
as well as
significantly increased rates in overall solvent recovery, and are
particularly beneficial for
application in late life solvent recovery applications.
[0083] Following are specific methods for employing the concept of this
invention. Most
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CA 2974711 2017-07-27
of these methods have been modeled using state-of-the-art techniques and shown
to produce
significant improvement in solvent recovery, both in reduction of time of
recovery as well as
the total amount of solvent recovered. While not explicitly illustrated or
quantified herein,
these methods additionally have the benefit of significantly reducing the
overall cost of
solvent recovery, as these methods require significantly less time for
recovery of the solvent
(therefore reducing manhours, capital employed, maintenance, etc.), as well as
not requiring
the installation or operation of large steam generation systems. " These
methods as described
herein, particularly where the solvent is substantially recovered in the vapor
phase, solvent
can more easily be separated from the NCG utilized in the injection and
recovery techniques
discussed herein, than is prior art recovery methods such as steam injection
at late life
wherein the solvent is recovered in a liquid phase generally mixed with both
water and
recovered bitumen. These methods are also very effective in maintaining
reservoir pressure
during the solvent recovery and shut-in phases of the reservoir to prevent
intrusion or
unwanted cross flow from other reservoirs or reservoir chambers in the region.
These
methods may additionally have ecological benefits, by reducing the amount of
water utilized
(i.e., by reducing overall steam demand during recovery), reducing the amount
of
unrecoverable water (i.e., by reducing the amount of water, from steam, left
in the reservoir at
the end of the reservoir production/recovery), enhancing solvent recovery
percentage, as well
as reducing the cost of solvent recovery (thereby making the solvent recovery
from the
reservoir even more feasible).
[0084] One embodiment of the present invention is to utilize the NCG
injection recovery
process in a "single well pair" configuration. It should be noted that the
term "single well
pair" as used herein, is meant to use where the primary implementation of this
embodiment is
to induce recovery between an injector and a producer in a well pair. This
does not mean that
this method may not be utilized where there is more than one well pair (or
infill wells) in the
reservoir or in the vicinity of the "single well pair", but only that the
primary mode of the
recovery operation described in this embodiment is to induce recovery between
an injector
and a producer in a well pair as compared to other embodiments of the methods
disclosed
herein, where the primary mode of the recovery operation in these other
embodiments may be
to induce recovery between or with multiple well pairs (and/or infill wells).
[0085] Figure 3 is a simplistic diagram of a single well pair
configuration in a
subterranean reservoir (400) which may be utilized to illustrate the current
NCG injection
recovery process as applied to a single well pair configuration. Here, the
well pair consists of
an injection well (401) and a production well (405).
[0086] Generally in a solvent assisted gravity-based drainage process the
injection well
will be located at a location above the production well as shown. It should
also be mentioned
that the methods herein are not limited to well pairs that only have a
vertical offset
component. In embodiments, the well pair may be staggered (i.e., contain an
offset between
the two wells in the well pair contains both a lateral, as well as a vertical,
component). The
- 19 -
=
CA 2974711 2017-07-27
basic operation of the methods herein may also apply between pairs that only
have a
significantly horizontal offset component. While most of the single well pair
and multiple
well pair configurations illustrated herein will show the wells in the well
pairs (i.e., the
original injection and production) as significantly vertically oriented with
respect to one
another, the principles of the concepts may additionally apply to these other
configurations
unless otherwise noted.
100871 In Figure 3, the diluting/heating agent (or "D/HA") containing a
non-condensable
gas (which, for simplicity purposes in the figures and descriptions herein,
the diluting/heating
agent may be referred to alternatively herein as "NCG") is injected into the
reservoir via the
injection well (401). The NCG can be injected at approximately ambient surface
temperature
or can be heated prior to injection into the reservoir. Heating the NCG prior
to injection can
improve the solvent recovery by providing heat for the evaporation of the
solvent in the
reservoir. In other embodiments, the temperature of the well can be raised
prior to, or with,
the injection of the NCG into the reservoir. This can be done during normal
recovery
operations or as part of preparation for the solvent recovery stage. In the
first case, the NCG,
as well as the retained solvent, take advantage of the residual heat stored in
the reservoir to
improve solvent recovery. In this single well configuration, the NCG and
evaporated solvent
tend to move upward in the reservoir chamber (410) prior to moving down at the
interface of
the reservoir chamber towards the production well (405) as illustrated by flow
arrows (415).
The flow arrows show the path of the NCG and vaporized solvent in the
reservoir chamber
(410).
100881 State-of-the-art reservoir production modeling was performed to
show the
improved solvent recovery rates in conjunction with an embodiment of the
present invention,
as well compare the solvent recovery rates and efficiencies to conventional
techniques for
solvent recovery utilizing steam, such as switching to Steani-Assisted Gravity
Drainage
(SAGD) process near the end of the production life (i.e., late life) of the
reservoir. In this
modeled comparison, the NCG injection process was utilized in conjunction with
a thermal
solvent vapor extraction (VAPEX) process, at "late-life" reservoir conditions.
For the
comparison models, the reservoir temperature, reservoir pressure and well
spacing all were
modeled at the same value. The case shown in Figure 6A operated a thermal
VAPEX
process for the heavy oil production period, followed by injecting only steam
for solvent
recovery according to the prior art. The case shown in Figure 6B operated the
same thermal
VAPEX process for the heavy oil production period, however, followed by
injecting a NCG
gas according to an embodiment herein. The solvent used in all of the models
herein was a
mixture of essentially C3-C9 hydrocarbons which exemplifies a typical diluent
solvent
mixture utilized in a solvent-based heavy oil recovery process (such as
thermal VAPEX, or
SA-SAGD process). The NCG utilized in all of the models herein was a 50%/50%
by mole
mixture of C1 (methane) and CO2 (carbon dioxide) which is exemplary of a
production gas
that may be used, readily obtainable, or easily obtainable, in reservoir heavy
oil recovery
- 20 -
CA 2974711 2017-07-27
processes. Figures 6A and 6B show the solvent production rates in both liquid
and gas
phases from the start of solvent recovery stage for the case of single well
pair based on single
well pair steam injection (Figure 6A) and on single well pair NCG injection
(Figure 6B).
[0089] The results for the single well pair embodiment are shown in
Figures 6A and 6B.
In the case of utilizing steam injection for solvent recovery, Figure 6A, most
of the solvent is
vaporized by hot steam and moved to the edge of the chamber where it condenses
and is then
produced as a liquid phase. On the other hand, in the case when using NCG
injection for
solvent recovery as shown in Figure 6B, the processes described herein allow
for some
diluting of the gas phase and as a result stripping of the solvent into the
gas phase, which
results in recovery of some of the solvent in the gas form, and an overall
higher solvent
recovery. .As a result, there is a significant increase in the overall solvent
recovery rate (i.e.,
the sum of the "liquid" and "gas" production lines), especially on the front-
end of the
timeline. This results in not only additional solvent recovered, but more
solvent recovered in
a significantly shorter amount of time when utilizing the methods herein.
[0090] Even though the present invention is economically beneficial for
late life recovery
of solvent in a solvent-based bitumen recovery process (such as VAPEX) in
single well pair
configuration such as was exemplified in the models described prior (and
results illustrated in
comparative Figures 6A and 6B), it is seen that the use of the present
invention in certain
multiple well-pair configurations and "sweep" configurations can provide even
significantly
greater improvements in solvent recovery (as shown in Figure 6C and Figure 7
and processes
as will be described further herein). Additionally, the hydrocarbon solvents
are generally and
primarily in vapor form when injected in a thermal solvent-assisted heavy oil
recovery
process, for example VAPEX and SA-SAGD. However, the solvent then condenses as
it heat
up the oil and the formation, which means that some of it is left behind as a
liquid phase. In
addition to enhancing solvent recovery at the end of life of a VAPEX process,
it will be
shown herein that the present invention also provides more significant solvent
recovery when
utilized for solvent recovery in a reservoir which has utilized an SA-SAGD
process during
production. In fact, the present invention even eclipses the overall solvent
recovery as
compared to when a steam only (SAGD) process is utilized in late life recovery
of solvent
from solvent-assisted gravity drainage process.
[0091] We start here with a discussion on a few different configuration
embodiments of
implementations of the present invention to multiple well pair configurations.
It has been
discovered that embodiments of the present invention can be very effectively
used in
reservoirs with multiple wells or multiple well pairs, especially in certain,
distinct flow
patterns or "modes". Figures 4A, 4B & 4C will be utilized to illustrate these
preferred modes
using a typical, but non-limiting, example well configurations. In these
figures, the
subterranean reservoir or "reservoir" (600) contains a five well pair
configuration is shown
for purposes of illustration. This may illustrate a typical reservoir wherein
five horizontal
well pairs are utilized in a solvent-assisted gravity drainage process (such
as VAPEX or SA-
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CA 2974711 2017-07-27
SAGD), wherein each well in the well pair run in a substantially horizontal
direction within
the subterranean reservoir, and wherein the injection well and the production
well of each of
the well pairs are oriented in a substantially vertical direction with respect
to one another, and
further wherein the top well is utilized as an injection well and the bottom
well used as a
production well in each pair. Each of the five horizontal well pairs comprises
an injection
well (601) and a production well (605) wherein, in Figures 4A-4C (and
additionally as in
later figures as will be discussed), these wells are shown in an elevation
view, as viewed
down the axis of the horizontally running injection and production wells (601)
and (605).
[0092] Starting with the reservoir and well configuration description as
illustrated in
Figure 4A, each of the five horizontal well pairs comprises an injection well
(601) and a
production well (605). During normal operation of a solvent-based gravity
drainage process,
solvent is injected into the injection well (601). This solvent (as well as
other components
such as steam) is utilized to reduce the viscosity of the heavy oil (or
"bitumen") that is
present in the reservoir (600). The solvent and reduced viscosity heavy oil
flow in a pattern
which forms the reservoir chamber(s) (610). Here the injected vapor pushes out
from the
injection well (601) and forms the reservoir chamber (610) wherein the flow is
generally
outward from injection well (601), wherein the reservoir chamber flow
boundaries (615) are
illustrated in Figure 4A. The condensed solvent and reduced viscosity heavy
oil liquid
drainage is through the reservoir chamber (610) and the exterior of the liquid
flow pattern
(620) follows the bottom outer boundaries follow the outer contour of
reservoir chamber
(610) and is recovered primarily as a liquid from the production well (605).
These figure
elements shown in Figure 4A of the operating (or production) portion of the
solvent assisted
gravity drainage are typically the same for Figures 4B and 4C for the purposes
of these
illustrations.
[0093] In Figures 4A, 4B, and 4C, will illustrate different NCG "sweep"
configurations
of the present invention in late life production/solvent recovery. Starting
with Figure 4A,
alternative existing injection wells (the first, third and fifth elements 601
starting from the left
in Figure 4A) are converted to, and utilized as "NCG injection wells", while
the intermediate
existing injection wells (the second and fourth elements 601 starting from the
left in Figure
4A) and all production wells (the elements 605 in Figure 4A) are converted to,
and utilized as
"NCG/vaporized solvent and liquid production wells". In this embodiment, the
NCG is
injected via the NCG injection wells. As noted prior, the NCG may comprise any
gas that is
non-condensable under the reservoir pressure and temperature" conditions. The
NCG may
also be heated prior to injection to improve solvent recovery. The NCG may
also use
existing stored heat in the reservoir to obtain an increase in temperature
which improves
solvent recovery. In such embodiment, the reservoir temperature is raised
during the normal
thermal production cycle of the reservoir, which increases heavy oil
production and in these
illustrated late life cycles, provides additional heating to the injected NCG
in the present
solvent recovery processes. For simplicity purposes in the figures and
description herein, the
-22 -
CA 2974711 2017-07-27
diluting/heating agent (or "D/HA") containing a non-condensable gas may be
referred to
interchangeably as "NCG".
[0094] Returning to Figure 4A, in this embodiment, a substantial amount
of NCG is
injected into the now converted NCG injection wells. By the term "substantial
amount of
NCG injected" (or similar) it is meant that a volume or volume rate of NCG is
injected into
the reservoir sufficient to vaporize at least a portion of the components in
the liquid solvent
(due to a decrease in partial pressure of the solvent in the vapor phase)
thereby decreasing the
partial pressure of at least some of the components in the solvent in the
vapor phase by at
least 5%, at least 10%, at least 25%, at least 50%, at least 75%, or more
preferably at least
99%. In preferred embodiments, at least 10 wt%, at least 25 wt%, at least 50
wt%, or more
preferably at least 98 wt% of the liquid solvent in the reservoir is converted
to a vapor. After
injecting the NCG, at least a portion of the solvent in the reservoir chambers
(610) begins to
vaporize due to an imposed decrease in the partial pressure of the solvent in
the reservoir
chamber (as used here the term "solvent" is to also include the solvent
components,
especially the lower boiling point solvent components). Instead of condensing
and moving
down the reservoir chambers as discussed and operated in the production cycle
(to be
recovered by the lower located production wells), here, a significant portion
of the solvent
vaporizes and moves upward through the alternate reservoir chambers (i.e., the
chambers
now containing the NCG injection wells). The pressure gradient in the
reservoir is
maintained such that the pressure near the NCG/vaporized solvent production
wells is lower
than the pressure of at least one, and preferably all, of the NCG injection
well(s). This
provides a flooding or sweeping effect across the reservoir providing the
mechanism to both
1) lower the partial pressure of the solvent in the reservoir charnber(s),
thereby converting at
least a portion of the liquid solvent to a vapor, and 2) moving the now
vaporized solvent and
NCG across the reservoir from the NCG injection well(s) to the NCG/vaporized
solvent
production well for recovery. This embodiment herein utilizes at least one
existing
production/injection well as a now converted NCG injection well and at least
two existing
production/injection wells as a now converted NCG/vaporized solvent production
wells as
described above. This creates an NCG/vaporized solvent sweep flow pattern
(625) as shown
in Figure 4A. It is noted that the produced NCG with the = vaporized solvent
from the
production wells is separated in a surface facility the separated NCG is
recompressed and re
heated to a desired temperature if required and is re-injected (recycled) in
the NCG injection
wells. Any additionally required NCG for solvent recovery process may be added
to the
recycled NCG stream. The separated solvent from the produced NCG/solvent gas
is the
recovered solvent from the gas phase stream. The produced liquid from
production wells also
contain some dissolved NCG, solvent and heavy oil which is treated in the
surface facility to
separate heavy oil, solvent, and NCG from each other.
[0095] Figure 4B illustrates another embodiment of the NCG sweep
technique in a well
pattern similar to that in Figures 4A & 4C. The elements in Figures 4A, 4B and
4C are
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CA 2974711 2017-07-27
numbered similarly. In Figure 4B, the reservoir (600) contains a five well
pair configuration
for purposes of illustration. This may illustrate a typical reservoir wherein
five horizontal
well pairs (wherein each well pair is shown in these figures for illustrative
purposes wherein
the injector well and the production well are in a substantially vertical
orientation to each
other, i.e., "vertical well pair", and where each well pair is located in a
substantially
horizontal direction relative to at least one adjacent well pair) are utilized
in a solvent-assisted
gravity drainage process (such as VAPEX or SA-SAGD), wherein the wells of each
well pair
is oriented in a vertical orientation to one another with the top well
utilized as an injection
well and the bottom well used as a production well in each pair. Each of the
five horizontal
well pairs comprises an injection well (601) and a production well (605).
During normal
operation of a solvent assisted gravity drainage process, solvent is injected
into the injection
wells (601) similarly to as described in Figure 4A. This solvent (as well as
other components
such as steam) is utilized to reduce the viscosity of the heavy oil (or
"bitumen") that is
present in the reservoir (600). The production process and elements (610)
through (620)
operate in a similar manner to as described in Figure 4A during normal
production life of the
reservoir under solvent assisted gravity drainage conditions.
[0096] In Figure 4B, an embodiment of the late life production/solvent
recovery NCG
sweep configuration is illustrated as follows. In this embodiment, one of the
injection wells
at one end of the series of wells is converted to, and utilized as an
"NCG/vaporized solvent
production well" (shown in Figure 4B as the first element 601 starting from
the left), while
the other existing injection wells in a series are converted to, and utilized
as "NCG injection
wells" (shown in Figure 4B as the second, third, fourth and fifth elements 601
starting from
the left). Also, all of the production wells are converted to liquid
production wells (shown in
Figure 4B as 605). In this embodiment, the NCG is injected via the four NCG
injection wells.
As noted prior, the NCG may comprise any gas that is non-condensable under the
reservoir
pressure and temperature conditions. The NCG may also be heated prior to
injection to
improve solvent recovery. The NCG may also use existing stored heat in the
reservoir to
obtain an increase in temperature to improve solvent recovery. In such
embodiment, the
reservoir temperature is raised during the normal thermal production cycle of
the reservoir,
which increases heavy oil production and in these illustrated late life
cycles, provides
additional heating to the injected NCG in the present solvent recovery
processes.
[0097] Returning to Figure 4B, in this embodiment, a substantial amount
of NCG is
injected into now converted NCG injection wells. After injecting the NCG, at
least a portion
of the solvent in the reservoir chambers (610) begins to vaporize due to a
decrease in the
partial pressure of the solvent in the gas phase (as used here to also include
the solvent
components, especially the lower boiling point solvent components). Instead of
condensing
and moving down the reservoir chambers as discussed in the production cycle
(to be
recovered by the lower located production wells), a significant portion of the
solvent in the
reservoir chambers vaporizes and moves upward through the reservoir chambers
while
=
- 24 -
CA 2974711 2017-07-27
additionally moving with a horizontal component direction toward the now
converted
NCG/vaporized solvent production well which is located on one side of the
series of now
converted NCG injection wells. This embodiment herein utilizes at least one
existing
injection well as a now converted NCG injection well and at least one existing
injection well
as a now converted NCG/vaporized solvent production well as described above.
This creates
an NCG/vaporized solvent sweep flow pattern (625) as shown in Figure 4B.
[0098] Figure 4C illustrates another embodiment of the NCG flood
technique in a well
pattern similar to that in Figures 4A & 4B. In Figure 4C, the reservoir (600)
contains, a five
well pair configuration for purposes of illustration. This may illustrate a
typical reservoir
wherein five horizontal well pairs are utilized in a solvent-assisted gravity
drainage process
(such as VAPEX or SA-SAGD). Each of the five horizontal well pairs comprises
an injection
well (601) and a production well (605). During normal operation of a solvent
assisted gravity
drainage process, solvent is injected into the injection wells (601) similarly
to as described in
Figure 4A. This solvent (as well as other components such as steam) is
utilized to reduce the
viscosity of the heavy oil (or "bitumen") that is present in the reservoir
(600). The
production process and elements (610) through (620) operate in a similar
manner to as
described in Figure 4A during normal production life of the reservoir under
solvent assisted
gravity drainage conditions.
[0099] In Figure 4C, an embodiment of a late life production/solvent
recovery NCG
sweep configuration is illustrated as follows. In this embodiment, one of the
existing injection
wells at one end of the series of wells is converted to an "NCG/vaporized
solvent production
well" (shown in Figure 4C as the third element 601 starting from the left),
while the other
existing injection wells in a series are converted to "NCG injection wells"
(shown in Figure
4B as the first, second, fourth and fifth elements 601 starting from the
left). Also all of the
production wells are converted to liquid production wells. In this embodiment,
the NCG is
injected via the four NCG injection wells. As noted prior, the NCG may
comprise any gas
that is non-condensable under the reservoir pressure and temperature
conditions. The NCG
may also be heated prior to injection to improve solvent recovery. The NCG may
also use
existing stored heat in the reservoir to obtain an increase in temperature to
improve solvent
recovery. In such embodiment, the reservoir temperature is raised during the
normal thermal
heavy oil production cycle of the reservoir, which increases heavy oil
production and in these
illustrated late life cycles, provides additional heating to the injected NCG
in the present
solvent recovery processes.
[00100] Returning to Figure 4C, in this embodiment, a substantial amount of
NCG is
injected into now converted NCG injection wells. After injecting the NCG, at
least a portion
of the solvent in the reservoir chambers (610) begins to vaporize due to a
decrease in the
partial pressure of the solvent in the vapor phase (as used here to also
include the solvent
components, especially the lower boiling point solvent components). Instead of
condensing
and moving down the reservoir chambers as discussed in the production cycle
(to be
- 25 -
CA 2974711 2017-07-27
recovered by the lower located production wells), a significant portion of the
solvent in the
reservoir chambers vaporizes and moves upward through the reservoir chambers
while
additionally moving with a horizontal component direction toward the now
converted
NCG/vaporized solvent production well which is located within the series of
NCG injection
wells (i.e., at least one well pair containing a NCG injection well is located
on each side of
the converted NCG/vaporized solvent production well). Also, any draining
liquid is
produced from the production wells that are located in the bottom of drainage
chamber. This
embodiment herein utilizes at least two existing production or injection wells
as a now
converted NCG injection well and at least one existing production or injection
well as a now
converted NCG/vaporized solvent production well as described above. This
creates an
NCG/vaporized solvent sweep flow pattern (625) as shown in Figure 4C.
[00101] It is noted herein that while these embodiments as illustrated in
Figures 4A-4C
contemplate utilizing the existing production wells as liquid production wells
(as well as the
data from the models herein are based on utilizing the existing production
wells as liquid
production wells), in embodiments of the inter-well pair (or multi-well pair)
processes herein,
some, or all of the production wells may be converted to NCG/vaporized solvent
production
wells or NCG injection wells.
[00102] The results for the inter-well pair NCG flood case of the present
invention, as
shown in Figure 6C, the dilution and stripping once again take place, but now
the gas phase
sweeps the reservoir area between two chambers and allows for more effective
stripping of
the solvent into the gas and more effective and faster sweeping of solvent in
gas and liquid
phases to the production wells. As can be seen comparing the results from
Figures 6A, 6B
and 6C, there is a significant increase in the overall solvent recovery rate
(i.e., the sum of the
"liquid" and "gas" production lines) over the base case steam injection
recovery (shown in
Figure 6A), especially on the front-end of the timeline for the embodiments of
both the single
well pair NCG injection process (results shown in Figure 6B), as well as the
inter-well pair
NCG flood process (results shown in Figure 6C) of the present invention. This
results in not
only additional solvent recovered, but more solvent recovered in a
significantly shorter
amount of time when utilizing the methods herein. It can also be seen that the
Solvent
Production Rate of the inter-well pair NCG flood process (Figure 6C) of the
present invention
shows significant recovery results over the single well NCG injection
embodiment (Figure
6B).
[00103] Figure 7 shown the total Solvent Recovery, for all three (3) cases
described in
Figures 6A-6C. As can be seen from Figure 7, the process employing the NCG
injection
embodiment of the invention as well as the inter-well pair NCG flood
embodiment recovered
more solvent than the steam injection (SAGD) case in the early days, even
though the SAGD
case did ultimately recover slightly more overall solvent than the NCG
injection embodiment.
However, what is taken away here is that the process according to the present
invention, the
NCG injection was able to ultimately recover nearly as much (or more) solvent
from the
- 26 -
CA 2974711 2017-07-27
reservoir as the conventional steam injection case (SAGD) Considering the high
cost
associated with steam generation, water treatment, and other limitations of
the steam only
case as discussed before, this comparable final solvent recovery easily
economically justifies
the additional NCG production and injection costs for implementing the methods
of the
present invention over the steam only late life process (SAGD). The SAGD
process, as
discussed prior, requires significantly additional capital equipment and
energy costs, mainly
due to the SAGD's process requirement to install and operate substantial
onsite steam
generation facilities, which are not already existing in solvent assisted
heavy oil recovery
operations. This makes the present invention significantly more desirable than
conventional
SAGD processes when all of the costs in implementing the processes are
factored in.
[00104] In the NCG injection case of the present invention, only NCG is
required, no
steam is required even as a heating agent, as the heat stored in the reservoir
is sufficient to
maintain the process of liquid solvent stripping into the injected diluting
agent. Even if some
steam may be added to the process, mainly if heating is required, the amount
of steam used
would be only a small fraction of what would be required for a steam only
(SAGD mode)
recovery operation; and existing facilities in a solvent assisted heavy oil
recovery operation
may be sufficient for these purposes without the need to install .and operate
additional costly
steam generation facilities. Much of this NCG utilized in the present methods
may be readily
available from site operations, can be obtained or supplemented by pipelines,
or can be
utilized NCGs, such as CO2, in a sequestration mode. The NCG may be comprised
of C1, C2/
C3, N2, CO2, natural gas, produced gas, flue gas or any combination thereof.
In contrast, in a
solvent-based extraction process, the steam facilities required to perform the
steam only
(SAGD) process as modeled are not already present (at least not in the
capacity that they
would be in a non-solvent SAGD type operation). In order to perform the SAGD
operation,
highly capital intensive, energy intensive and manpower intensive steam
generation facilities
must be physically brought to the near vicinity of the well site and connected
to the injection
well(s). When these additional costs are factored in between the NCG injection
case of the
present invention and the steam injection (SAGD mode) solvent recovery of the
prior art, the
NCG injection recovery process of the present invention possess significantly
improved
economics.
[00105] This basic embodiment and associated methods can. be expanded by using
infill
wells. Figures 4D and 4E illustrate these embodiments. The elements (600)
through (625) in
these two figures are essentially the same as described in Figure 4A. However,
in this
embodiment, the use of an infill well (630), or multiple infill wells (not
shown) may be used
in the solvent recovery process. Here, an existing infill well (630) may be
utilized or an infill
well may be installed specifically to be used in the solvent recovery methods
as disclosed and
described herein. Although the infill well as illustrated in Figures 4D and 4E
is shown
located near the bottom of the reservoir, it may be installed at any vertical
level within the
reservoir between two well pairs. In the embodiment shown in Figure 4D, the
existing or
-27 -
CA 2974711 2017-07-27
installed infill well is utilized as an NCG/vaporized solvent production well
for the late life
solvent recovery processes herein. Here, the two adjacent existing injection
wells (601) are
converted to NCG injection wells. Similar as described in prior Figures 4A-4C,
in this
embodiment, a substantial amount of NCG is injected into now converted NCG
injection
wells. After injecting the NCG, at least a portion of the solvent in the
reservoir chambers
(610) begins to vaporize due to a decrease in the partial pressure of the
solvent in the vapor
phase (as used here "solvent" to also include the solvent components,
especially the lower
boiling point solvent components). Instead of condensing and moving down the
reservoir
chambers as discussed in the production cycle (to be recovered by the lower
located
production wells), a significant portion of the solvent in the reservoir
chambers vaporizes and
moves upward through the reservoir chambers while additionally moving with a
horizontal
component direction toward the infill well (630) which has been installed as,
or has been
converted to a NCG/vaporized solvent production well. The majority of the NCG
and
recovered vaporized solvent are recovered through the now NCG/vaporized
solvent
production well (prior infill well) and the existing production wells (605)
continue to produce
mainly liquid solvent recovery as well as additional heavy oil (bitumen). This
embodiment
herein utilizes at least two existing production injection wells as a now
converted NCG
injection wells and an infill well as an NCG/vaporized solvent production
wells as described
above. This creates an NCG/vaporized solvent sweep flow pattern (625) as shown
in Figure
4D. It is herein noted in the embodiments described herein that the
NCG/vaporized solvent
production well(s) may also recover liquid phase solvent from the subterranean
reservoir.
Alternatively, in embodiments, one or more of the existing production wells
(605) can be
converted to an NCG injection well.
[00106] Figure 4E illustrates a similar configuration and method of operation
as shown in
Figure 4D, but in this embodiment, a substantial amount of NCG is injected
into the infill
well (630) which has been installed as, or converted into an NCG injection
well. The existing
injection wells (601) have been converted into NCG/vaporized solvent
production wells,
which now recover the majority of the NCG and recovered vaporized solvent,
while the
existing production wells now recover the majority of the liquid solvent as
well as heavy oil
(bitumen). However, alternatively (not shown), the two adjacent existing
production wells
(605) can be converted to NCG/vaporized solvent production wells. This
embodiment herein
utilizes at least two existing production or injection wells as now converted
NCG/vaporized
solvent production wells and at least one infill well as an NCG injection well
as described
above. This creates an NCG/vaporized solvent sweep flow pattern (625) as shown
in Figure
4E.
[00107] State-of-the-art reservoir production modeling was performed to
show the
improved solvent recovery rates in conjunction with the flood embodiment of
the present
invention, as well compare the solvent recovery rates and efficiencies to
conventional
techniques for solvent recovery utilizing steam, such as in a Steam-Assisted
Gravity Drainage
- 28 -
CA 2974711 2017-07-27
(SAGD) process. In this modeled comparison, the NCG injection process was
utilized in
conjunction with a solvent vapor extraction (VAPEX) process, at near end-of-
life (i.e., "late
life") reservoir conditions. For the comparison models, the reservoir
temperature, reservoir
pressure and well spacing all were modeled at the same value. = In this
example, the model
utilized a two well pair configuration which basis for the model is simply
illustrated in Figure
5. Here, an existing injection well (shown as 601 on the right hand side of
Figure 5) is
converted to an NCG injection well, and an existing injection well (shown as
601 on the left
hand side of Figure 5) is converted to an NCG/vaporized solvent production
well. Illustrated
here, the existing production wells (shown as 605 on the bottom of Figure 5)
are also
converted to liquid production well (solvent and as well as heavy oil). The
pressure at the
NCG injection well is increased (and/or the pressure at the NCG/vaporized
solvent
production well is decreased) such that the pressure (P2) at the NCG injection
well as shown
in Figure 5 is greater than the pressure (P1) at the NCG/vaporized solvent
production well.
The NCG is injected through the now converted NCG injection well and NCG and
vaporized
solvent are produced by the now converted NCG/vaporized solvent production
well. Heavy
oil and primarily liquid solvent are additionally produced from the production
wells (620).
[00108] The NCG injection case as shown in Figures 6B and 6C were operating a
thermal
VAPEX process, followed by a late life process consisting of injecting NCG gas
according to
an embodiment herein. The solvent used in all of the models was a mixture of
essentially C3-
C9 hydrocarbons which exemplifies a typical solvent mixture utilized in a
solvent-based
heavy oil recovery process (such as VAPEX, or SA-SAGD process). The NCG
utilized in the
models was a 50%/50% by mole mixture of C1 (methane) and CO2 (carbon dioxide)
which is
exemplary of a production gas that may be used, readily obtainable, or easily
obtainable, in
reservoir heavy oil recovery processes. The models were run after the
reservoir had been in
thermal VAPEX service, and Figures 6B and 6C show the solvent production rates
from the
start of the late life recovery processes described herein (i.e., start of NCG
injection).
[00109] As can be seen by comparing Figures 6A, 6B and 6C, the process
according to the
invention in the inter-well pair flooding model shows a significant increase
in the solvent
recovery in both the gas phase and the liquid phase over the single well pair
steam injection
of the prior art, as well as the single well pair NCG injection embodiment of
the present
invention. This NCG flood embodiment, utilizing a flood (or "sweep") from at
least one
well pair to at least another well pair in the reservoir, resulted in
significant enhancement in
solvent recovery in both the gas phase and the liquid phase, as well as the
total solvent
recovery (sum of gas and liquid phase solvent recovery). Additionally, it can
be seen that in
this multiple well pair embodiment of the present invention that there is a
significant increase
in the overall solvent recovery rate (i.e., the sum of the "liquid" and "gas"
production lines),
especially on the front-end of the timeline resulting in a very short
timeframe required for
near full recoverable solvent production.
[00110] This results in not only additional solvent recovered, but more
solvent recovered
- 29 -
CA 2974711 2017-07-27
in a significantly shorter amount of time when utilizing the methods herein.
Figure 7 further
illustrates the significant impact of using this embodiment of solvent
recovery in a VAPEX
process for late life solvent recovery. In Figure 7, it can be seen in the
inter-well pair NCG
flood model of the present invention, that a higher solvent recovery compared
to steam
injection case (SAGD mode) and NCG injection in single well pair configuration
is achieved.
Additionally, it can be seen that the inter-well pair NCG flood embodiment of
the present
invention can achieve very high total solvent recovery, and notably, it can
also be seen that
this recovery plateau is reached in a very short time frame in the inter-well
pair NCG flood
case.
[00111] While not wishing to be held to any particular theory, as discussed
prior, it is
believed that significantly more solvent can be achieved by converting the
solvent into a
vapor phase and recovering the solvent as a vapor. It is further believed that
while steam
injection provides heat and vaporize the liquid solvent from depleted chamber,
the
condensation of the steam and solvent at the edge of the chambers results in
solvent to be
recovered as a draining liquid through only the bottom production wells which
is a slower
process. In the present invention both converted injection wells, as well as
existing
production wells can be utilized for production, wherein a substantial amount
of the existing
liquid solvent that remained in the reservoir is now produced and recovered in
a vapor phase.
Also, it is believed that in the present invention, a significant amount of
solvent in the
reservoir is converted to vapor, leaving a smaller volume of the liquid
solvent in the well,
which is much more difficult to displace and achieve high solvent recovery in
the liquid
phase. As such, the present invention offers significant improvements in
solvent recovery
over the conventional methods in the art.
[00112] In another embodiment of the present invention, the solvent recovery
processes
herein can be utilized in a reservoir containing one or more wells or well
pairs preferably
under a gas cap. Figure 8 illustrates this embodiment in a five well pair
arrangement similar
to those described in the production life stages discussed with respect to
Figures 4A, 4B and
4C, wherein the well(s) are operating under a natural or induced gas cap. The
production
process and elements (600) through (620) operate in a similar manner to as
described in
Figure 4A during normal production life of the reservoir under solvent
assisted gravity
drainage conditions. In this embodiment, a gas cap may be naturally present,
or it may
already have been established in the reservoir, or may be established as a
step in performing
the processes as described in this embodiment. In the cases where the
facilities for a gas cap
may already be established in the reservoir, facilities for injecting and
maintaining the gas
cap may be utilized or modified for the present NCG gas cap expansion
description.
[00113] In Figure 8, an embodiment of a late life production/solvent recovery
NCG gas
cap flood configuration according to the invention herein is illustrated as
follows. In this
embodiment, during late life production, the existing injection wells (601)
are shut in. A
stream containing a substantial amount of NCG is injected into the top of the
reservoir
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through injection facilities in fluid communication with the top of the
reservoir, such as, and
preferably when, gas cap injection facilities are already in place during the
production phase.
As illustrated in Figure 8, an existing gas cap, or newly established gas cap,
now containing
NCG and vaporized solvent, is expanded via dropping the reservoir pressure or
injection of
the NCG containing stream and flows in a pattern (630) from the top of the
reservoir through
the reservoir chamber(s) to the production well(s) (605). NCG, heavy oil,
liquid solvent and
vaporized solvent are recovered via the production well(s) which have been
converted to
NCG/vaporized solvent production well(s) (605). As per prior embodiments, the
NCG may
comprise any gas that is non-condensable under the reservoir pressure and
temperature
conditions. The NCG may also be heated prior to injection to improve solvent
recovery. The
NCG may also use existing stored heat in the reservoir to obtain an increase
in temperature to
improve solvent recovery. In such embodiment, the reservoir temperature is
raised during the
normal thermal heavy oil production cycle of the reservoir, which increases
heavy oil
production and in these illustrated late life cycles, provides additional
heating to the injected
NCG in the present solvent recovery processes.
1001141 Returning to Figure 8, in this embodiment, a substantial amount of NCG
is
injected into the reservoir through existing, or newly installed gas cap
injectors. These
injectors are preferably located at, or near, the top of the reservoir. After
injecting the NCG,
at least a portion of the solvent in the reservoir chambers (610) begins to
vaporize due to an
induced decrease in the partial pressure of the solvent (as used here to also
include the solvent
components, especially the lower boiling point solvent components). The gas
cap is extended
in volume and begins to push downward with the NCG and now vaporized solvent
in the
reservoir chambers (610). Instead of condensing and moving down the reservoir
chambers as
discussed in the production cycle (to be recovered by the lower located
production wells),
some of the solvent begins vaporizing and is expanded/pushed downward towards
the
production wells which are now utilized as the NCG/vaporized solvent
production well(s)
(605). This floods additional liquid solvent and bitumen to NCG/vaporized
solvent
production well(s) as well as vaporized solvent and NCG which are also
recovered from the
NCG/vaporized solvent production well(s). Alternatively, or in conjunction
with the
converted existing production well(s) (605), at least one, or all of the
existing injection wells
(601) may be converted to NCG/vaporized solvent production well(s). This
embodiment
herein utilizes at least one existing injection well or at least one existing
production well as a
now converted NCG/vaporized solvent production well. This embodiment creates
an
NCG/vaporized solvent gas cap expansion flow pattern (1025) as shown in Figure
8. While
the process and the models for the gas cap expansion are described herein
wherein the
existing injection wells (601) are converted to NCG/vaporized solvent
production wells and
the existing production wells (605) are utilized as liquid production wells
(solvent and as well
as heavy oil), in alternative embodiments herein, one or more, including all,
of the production
wells (605) can be converted to NCG/vaporized solvent production wells. In
some
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CA 2974711 2017-07-27
embodiments of the gas cap expansion processes disclosed herein, both the
existing injection
wells (601) and the existing production wells (605) can be converted to
NCG/vaporized
solvent production wells.
[00115] State-of-the-art reservoir production modeling was performed to
show the
improved solvent recovery rates in conjunction with the gas cap expansion
embodiment of
the present invention, as well as to compare the solvent recovery rates and
efficiencies to
conventional techniques for solvent recovery utilizing steam injection, such
as in a Steam-
Assisted Gravity Drainage (SAGD) process. In this modeled comparison, the NCG
injection
process was utilized in conjunction with a solvent vapor extraction (VAPEX)
process, at late
life (i.e., near end-of-life) reservoir conditions. For the comparison models,
the reservoir
temperature, reservoir pressure and well spacing all were modeled at the same
value. In this
example, the model utilized a two well pair configuration which basis for the
model is simply
illustrated by using only two of the well pairs shown in Figure 8. Here, the
existing injection
wells (shown as 601 in Figure 8) are shut in, and existing production wells
(shown as 605 in
Figure 8) are converted to an NCG/vaporized solvent production well. NCG is
injected at the
top of the reservoir using existing facilities, modified facilities, and/or
newly installed
facilities to allow the injection of the NCG stream into the top of the
reservoir. As the gas
cap expands/grows in the reservoir, NCG and now vaporized solvent is
expanded/pushed
downwards in the reservoir chambers (610) as shown by the NCG/vaporized
solvent gas cap
expansion flow pattern (1025) as shown in Figure 8. Liquid solvent, vaporized
solvent, NCG
and bitumen are recovered from the NCG/vaporized solvent production well(s)
(605). For
simplicity and consistency, we will refer to the recovery or production wells
in this gas cap
expansion recovery embodiment by the term "NCG/vaporized solvent production
wells" even
though these wells, preferably existing production wells, will be used to
recover liquid
solvent, vaporized solvent, NCG and bitumen.
[00116] As noted, the model was run with a two well pair model and the results
are shown
in Figure 9. The "Gas Cap Expansion" case was run utilizing NCG as the gas cap
injection
gas. The gas cap (either naturally occurring or established otherwise) was
assumed to consist
of C1 hydrocarbon which may be considered to exemplify a typical gas cap in
heavy oil
reservoirs after the solvent-assisted gravity drainage process and beginning
of the late life
solvent recovery process. The solvent used in the model was a mixture of
essentially C3-C9
hydrocarbons which exemplifies a typical solvent mixture utilized in a solvent-
based heavy
oil recovery process (such as VAPEX, or SA-SAGD process). The NCG utilized in
the
models was a 50%/50% by mole mixture of C1 (methane) and CO2 (carbon dioxide)
which is
exemplary of a production gas that may be used, readily obtainable, or easily
obtainable, in
reservoir heavy oil recovery processes. The existing injection wells were
modeled as shut in.
All products measured from the model were recovered, from the two converted
NCG/vaporized solvent production wells.
[00117] Figure 9 shows the solvent recovery rate (in liquid equivalents)
of the solvent (in
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CA 2974711 2017-07-27
=
both liquid and gas components) for this gas cap expansion model. Figure 9
illustrates the
total solvent recovery for this model as a function of time as compared to the
case of the
inter-well pair NCG flood. As can be seen from the model results shown in
Figure 9, the gas
cap expansion embodiment of the present invention resulted in very high
solvent recovery in
a very short time. As seen in Figure 9, the outcome of gas cap expansion
scheme is very
favorable, and is similar to the inter-well pair NCG flood case. =
[00118] While not wishing to be held to any particular theory, as
discussed prior, it is
believed that even though the majority of the solvent is recovered in the
liquid phase, that
significantly more solvent can be recovered, as compared to conventional
methods (such as
steam injection/SAGD) due to the vaporization of the solvent, and thereby
creating a vapor
expansion in the reservoir chambers promoting recovery of the liquid phase
solvent in the
NCG/vaporized solvent production wells. The NCG not only provides a driving
expansion/push, but also promotes additional expansion of gas in the reservoir
chambers by
reducing the partial pressure of the solvent in the reservoir chambers,
thereby vaporizing a
significant portion of the solvent into a gas phase. In contrast, it is
believed that SAGD
solvent recovery (which relies primarily on steam injection/gravity drainage)
of the prior art
does not promote solvent vaporization/expansion. While the steam injected in
SAGD
provides some heat to promote solvent vaporization, the condensation of steam
with solvent
on the edge of the chamber drives the solvent to a liquid phase draining to
the production
well which is a slower solvent recovery process as compared to the present gas
cap expansion
solvent recovery invention.
[00119] These state-of-the-art reservoir production models were also used to
compare the
use of the current methods and embodiments for solvent recovery vs. the
conventional
approach of switching to SAGD methods for solvent recovery in a late life
solvent assisted
gravity drainage operation (such as SA-SAGD or VAPEX processes). Here, similar
well
configurations as utilized in the examples for the sweep (or "flood") and gas
cap expansion
embodiments herein which results are in shown in Figures' 7 and 9,
respectively were
compared with taking the same reservoir configurations and applying SAGD for
late life
solvent recovery. The comparative results between these embodiments of the
invention and
the steam injection/SAGD solvent recovery methods are shown in Figure 10. Here
it can be
seen that both the flood (sweep) configuration and the gas cap expansion
configuration of
the present invention resulted in very similar solvent recovery rate profiles.
The same
reservoir model, run under conventional late life steam injected gravity
drainage (SAGD)
process achieved far less total solvent recovery. Additionally, while the
conventional SAGD
method recovered slightly more total heavy oil (bitumen) from the reservoir,
the Produced
Bitumen to Retained Solvent ratio (PBRS) was still low due to the large amount
of
unrecovered solvent left in the reservoir as a result of this method. In
significant contrast,
the methods of the present invention were able to surprisingly achieve very
high PBRS,
which results in not only significant overall cost savings, but significantly
more efficient use
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of solvents in the overall production & solvent recovery process of reservoir
use and natural
resources management.
[00120] In preferred embodiments herein, the solvent may be a single
hydrocarbon
compound or a mixture of hydrocarbon compounds having a number of carbon atoms
in the
range of C1 to C30+. The solvent may have at least one hydrocarbon in the
range of C3 to C12
and this at least one hydrocarbon may comprise at least 50 wt. A of the
solvent. The mixture
may have aliphatic, naphthenic, aromatic, and/or olefinic fractions. The
solvent may
comprise at least at least 50 wt. % of one or more C3-C12 hydrocarbons, at
least 50 wt. % of
one or more C4-C10 hydrocarbons, at least 50 wt. % of one or more C5-C9
hydrocarbons, or a
natural gas condensate or a crude oil refinery naphtha.
[00121] In preferred embodiments, the reservoir operating pressure may be 5-
95% of a
fracture pressure of the reservoir, or 0.2 to 5 MPa, or 1 to 2.5 MPa.
Preferably, the reservoir
pressure is measured at the injection well(s).
[00122] In preferred embodiments, the injection temperature of the gas phase
dilution
agent may be from 10 to 250 C or 50-150 C. Preferably, the temperature of the
gas phase
dilution agent is measured at the injection well. In other "preferred
embodiments, the
reservoir temperature may be from 50 to 250 C or 75-150 C. Preferably, the
reservoir
temperature is measured at the injection well(s).
[00123] In preferred embodiments, the solvent recovery process is performed on
a
reservoir that has been subjected to a solvent-assisted gravity drainage
process, which
comprises injecting steam and hydrocarbon solvent mixture into the reservoir.
In this
embodiment, the range of solvent concentration may be 5 to 40 % cold liquid
equivalent
volume in SA-SAGD processes or it may be 80 to 100 % by volume in H-VAPEX
process.
In these processes, a steam and hydrocarbon solvent mixture is injected into
the subterranean
reservoir in a vapor phase, wherein the hydrocarbon solvent volume fraction in
the steam and
hydrocarbon solvent mixture is 0.01-100% at injection conditions. In Azeo-
VAPEX
processes, the steam and hydrocarbon solvent mixture is within 30%+/-, 20%+/-,
or 10%+/-
of the azeotropic solvent molar fraction of the steam and the hydrocarbon
solvent as
measured at the reservoir operating pressure. Alternatively, the hydrocarbon
solvent molar
fraction of the combined steam and solvent mixture is 70-110%; 70-100%, 80-
100%, or 90 to
100% of the azeotropic solvent molar fraction of the steam and hydrocarbon
solvent mixture
as measured at the injection conditions. Preferably, the injection conditions
should be the
temperature and pressure of the subterranean reservoir at the injection
well(s).
Industrial Applicability
[00124] The systems and methods disclosed in the present disclosure are
applicable to the
oil and gas industry.
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[00125] It
is believed that the following claims particularly point out certain
combinations
and subcombinations that are novel and non-obvious.
Other combinations and
subcombinations of features, functions, elements and/or properties may be
claimed through
amendment of the present claims or presentation of new claims in this or a
related
application. Such amended or new claims, whether different, broader, narrower,
or equal in
scope to the original claims, are also regarded as included within the subject
matter of the
present disclosure.
=
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