Note: Descriptions are shown in the official language in which they were submitted.
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METHODS OF RECOVERING HEAVY OIL
FROM A SUBTERRANEAN RESERVOIR
FIELD
[0001] The present disclosure relates to methods of recovering heavy oil
from a
subterranean reservoir. In particular, the disclosure relates to methods of
recovering residual
heavy oil from a subterranean reservoir.
BACKGROUND
[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 disclosure.
Accordingly, it should be understood that this section should be read in this
light, and not
necessarily as including 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. Recovering
hydrocarbons
from such 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 formations, and the proportion
of
hydrocarbons present, among other things.
[0004] Easily harvested sources of hydrocarbons are dwindling, leaving less
conventional
sources to satisfy future energy 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 API (American Petroleum Institute) densities ranging from 8
API, or lower, up
to 20 API, or higher. The hydrocarbons recovered from less conventional
sources may include
heavy oil. However, the hydrocarbons, like heavy oil, from less conventional
sources are
difficult to recover using conventional techniques.
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[0005] Several methods have been developed to recover heavy oil from, for
example, oil
sands. Strip or surface mining may be performed to access the oil sands. Once
accessed, the oil
sands may be treated with hot water or steam to extract the heavy oil. For
subterranean
reservoirs where heavy oil is not close to the Earth's surface, heat may be
added and/or
dilution may be used to reduce the viscosity of the heavy oil and recover the
heavy oil from the
subterranean reservoir. Heat may be supplied through a heating agent like
steam. The heat
may be injected into a subterranean reservoir via an injection well. If the
heating agent is
steam, the steam may be condensed to water at the steam to cooler-oil-sands
interface in the
subterranean reservoir and supply latent heat of condensation to heat the
heavy oil in the oil
sands, thereby reducing viscosity of the heavy oil and causing the heavy oil
to flow more easily.
The heavy oil recovered from the subterranean reservoir may or may not be
produced via a
production well. The production well may be the same well as the injection
well.
[0006] A number of thermal recovery processes have been developed for the
recovery of
heavy oil from subterranean reservoirs. These processes may include cyclic
steam stimulation
(CSS), steam assisted gravity drainage (SAGD), vapor extraction process
(VAPEX), heated VAPEX,
steam flooding, steam and vapor extraction process (SAVEX), solvent-assisted
vapor extraction
with steam (SAVES), in-situ combustion, thermal enhanced oil recovery and
solvent-assisted
steam-assisted gravity drainage (SA-SAGD). The thermal recovery processes may
be cyclic
recovery processes in which there is intermittent injection of the mobilizing
fluid to lower a
viscosity of the heavy oil followed by recovery of the reduced viscosity heavy
oil.
[0007] CSS techniques that are cyclic steam stimulation techniques use
steam to lower the
viscosity of the heavy oil. The steam is injected into the subterranean
reservoir through a well
that raises the temperature of the heavy oil during a heat soak phase, thus
lowering the
viscosity of the heavy oil. As the viscosity is reduced, the heavy oil may
flow down towards the
well. The well may then be used to produce heavy oil from the subterranean
reservoir.
Solvents may be used in combination with steam in CSS processes, such as in
mixtures with the
steam or in alternate injections between steam injections. CSS processes are
described in U.S.
Patent No. 4,280,559, U.S. Patent No. 4,519,454, and U.S. Patent No.
4,697,642.
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[0008] Steam flooding is a process in which steam is injected from a series
of vertical or
horizontal injection wells and heavy oil is heated and pushed towards a series
of vertical or
horizontal production wells. Steam flooding can be used as a late life process
after a CSS
process. Solvent can be injected with steam to enhance the steam flooding
process. Further
details may be obtained, for example, from Zhihong Liu and Shane D. Stark,
"Reservoir
Stimulation Modelling of the Mature Cold Lake Steaming Operations", Society of
Petroleum
Engineers, SPE 160491, presented in Calgary, Alberta, 12-14 June 2012.
[0009] SAGD is a process where two horizontal wells (a well pair) are
completed in a
subterranean reservoir. The two wells may be first drilled vertically to
different depths within
the subterranean reservoir. Thereafter, using directional drilling technology,
the two wells may
be extended in a horizontal direction that result in two horizontal wells
(i.e., a production well
and an injection well), each vertically spaced from, but otherwise vertically
aligned with, the
other. Ideally, the production well may be located above the base of the
subterranean
reservoir but as close as practical to the bottom of the subterranean
reservoir. A horizontal
portion of the injection well may be located vertically above, such as, for
example, 10 to 30 feet
(or 3 to 10 meters) above, the horizontal portion of the production well. The
injection well may
be supplied with steam from a facility on the surface. The steam may rise from
the injection
well, permeating the subterranean reservoir to form a vapor chamber (i.e., a
steam chamber)
above the well pair. As the vapor chamber grows over time towards the top of
the
subterranean reservoir, the steam may condense at the steam to cooler-oil
sands interface,
releasing latent heat of steam, thereby reducing the viscosity of the heavy
oil in the
subterranean reservoir. The heavy oil and condensed steam may then drain
downward
through the subterranean reservoir under the action of gravity and may flow
into the
production well. After flowing into the production well, the heavy oil and
condensed steam can
be pumped to the surface. At the surface, the condensed steam and heavy oil
may be
separated, and the heavy oil may be diluted with appropriate light
hydrocarbons for
transportation by pipeline. SAGD processes are described in Canadian Patent
No. 1,304,287
and U.S. Patent No. 4,344,485.
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[0010] A number of variations of the SAGD and CSS processes have been
developed in an
attempt to increase productivity of the process. For example, U.S. Pat. No.
6,230,814 teaches
how the SAGD process can be further enhanced through the addition of solvent
with the
injected steam. The process teaches that as a planned operating pressure
declines, a molecular
weight of a solvent must be reduced in order to ensure that the solvent is
completely vaporized
at operating conditions that are planned for the SAGD process. The disclosed
approach results
in progressive exclusion of heavier solvents as lower operating pressures (and
temperatures)
are considered.
[0011] Solvents may be used in concert with steam addition, such as but
not limited to in
SA-SAGD, to increase efficiency of the steam in recovering heavy oil. U.S.
Patent No. 6,230,814,
discloses a method for enhancing mobility of heavy oil using a steam additive
(e.g., a solvent).
The method includes injecting steam and an additive into the subterranean
reservoir. The
additive includes a non-aqueous fluid, selected so that an evaporation
temperature of the non-
aqueous fluid is within about 150 C (degrees Celsius) of a steam temperature
at an operating
pressure of the process. Suitable additives include C1 to C25 hydrocarbons. At
least a portion of
the additive condenses in the subterranean reservoir. The mobility of the
heavy oil obtained
with the steam and additive combination is greater than that obtained using
steam alone under
substantially similar conditions.
[0012] Canadian Patent No. 2,769,356 discloses the use of a solvent,
pentane or hexane, or
both, as an additive to, or sole component of, a gravity-dominated process for
recovering heavy
oil from a subterranean reservoir. However, Canadian Patent No. 2,769,356
teaches that
solvents heavier than hexane (such as C7, C8, C9, etc.) are not effective in
enhancing the heavy
oil recovery process as the solvents precipitate out in the near well vicinity
and do not travel to
a vapor-liquid interface within the subterranean reservoir.
[0013] SAVEX is another process to improve productivity of a SAGD
process, as disclosed
for example in U.S. Patent No. 6,662,872. SAVEX is a combination of SAGD and
VAPEX, where
the SAGD recovery process is continued until a vapor chamber covers 25 to 75 %
of a height of
a subterranean reservoir and then steam injection is replaced with solvent
injection. The
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SAVEX process is limited to SAGD processes. SAVEX is not a follow-up process
and does not
target residual heavy oil.
[0014] SAVES is very similar to SAVEX, and one example is taught in U.S.
Patent No.
7,464,756. In a SAVES process, instead of a steam only phase at the beginning,
there is steam
and heavy hydrocarbon solvent during a first phase, which gets replaced with
steam and light
hydrocarbon solvent during a second phase. In the SAVES process, the third
phase uses
exclusively light hydrocarbon injections.
[0015] When operating some or all of the above thermal recovery processes,
unrecovered
heavy oil is left behind in the subterranean reservoir in the form of both
unswept heavy oil and
residual oil. Unswept heavy oil is heavy oil in the subterranean reservoir
that has not been
previously mobilized and as such is not in a vapor chamber. Residual heavy oil
saturations of
7-15 % have been measured in the thermal recovery processes. It would be
desirable to
recover at least some of the residual heavy oil once a thermal recovery
process is close to an
economic limit. The economic limit may be when a ratio between the heavy oil
recovered from
the subterranean reservoir and the steam injected into the subterranean
reservoir falls below a
profitable limit (e.g., when the cost of injecting the steam into the
subterranean reservoir is
greater than the value of the heavy oil recovered from the subterranean
reservoir as a result of
the injected steam). The economic limit of heavy oil recovery at which heavy
oil recovery
ceases may vary with different thermal recovery processes.
SUMMARY
[0016] The present disclosure provides methods of recovering heavy oil.
[0017] A method of recovering heavy oil from a subterranean reservoir may
comprise
injecting a mixture of steam and solvent to form a liquid comprising the heavy
oil and the
solvent in condensed form and recovering the heavy oil and at least a portion
of the solvent
from the subterranean reservoir while producing the liquid from the
subterranean reservoir.
The heavy oil is residual heavy oil. The mixture may have a concentration of
the solvent close
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to or above an azeotrope concentration for the mixture at a pressure of the
subterranean
reservoir.
[0018] A method of recovering heavy oil from a subterranean reservoir may
comprise
performing a steam-based heavy oil recovery process; injecting, at a time
equal to at least one
of during and after performing the steam-based heavy oil recovery process, a
mixture of steam
and solvent into the subterranean reservoir to form a liquid comprising heavy
oil and the
solvent in condensed form; and recovering the heavy oil and at least a portion
of the solvent
from the subterranean reservoir while producing the liquid from the
subterranean reservoir.
The mixture may have a concentration of the solvent close to or above an
azeotrope
concentration for the mixture at a pressure of the subterranean reservoir.
[0019] 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.
BRIEF DESCRIPTION OF THE DRAWINGS
[0020] These and other features, aspects and advantages of the disclosure
will become
apparent from the following description, and the accompanying drawings, which
are briefly
described below.
[0021] FIG. 1A is a graph showing saturation temperatures versus solvent
mole fractions of
three hydrocarbon solvents.
[0022] FIG. 1B is a graph showing the XY equilibrium (Pxy) curve for n-
heptane.
[0023] FIG. 2 is a black-and-white drawing of a color display produced
during a simulation
of steam/solvent recovery methods.
[0024] FIG. 3 is a graph comparing cumulative heavy oil recovered versus
time for a
conventional process and a method according to this disclosure.
[0025] FIG. 4 is a graph showing solvent injected, solvent volume remaining
in the
subterranean reservoir, and the additional volume of heavy oil recovered in
the method
according to this disclosure illustrated in FIG. 3.
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[0026] FIG.5A-5D are drawings showing the evolution of heavy oil recovery
in a
subterranean reservoir by a SAGD process; wherein 5A is a transversal view
drawing of a SAGD
vapor chamber, 5B is a RST log taken before the SAGD process, 5C is a RST log
taken at the end
of the SAGD process and 5D is a RST log after the method according to this
disclosure.
[0027] Fig. 6 is a flow diagram of a method of recovering heavy oil.
[0028] It should be noted that the figures are merely examples and no
limitations on the
scope of the present disclosure are intended thereby. Further, the figures are
generally not
drawn to scale, but are drafted for purposes of convenience and clarity in
illustrating various
aspects of the disclosure.
DETAILED DESCRIPTION
[0029] 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.
[0030] At the outset, for ease of reference, certain terms used in this
disclosure and their
meanings as used in this context are set forth. To the extent a term used
herein is not defined
below, it should be given the broadest definition persons in the pertinent art
have given that
term as reflected in at least one printed publication or issued patent.
Further, the present
techniques are not limited by the usage of the terms shown below, as all
equivalents,
synonyms, new developments, and terms or techniques that serve the same or a
similar
purpose are considered to be within the scope hereof.
[0031] A "hydrocarbon" is an organic compound that primarily includes the
elements
hydrogen and carbon, although nitrogen, sulfur, oxygen, metals, or any number
of other
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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 reservoirs to
improve gravity
drainage of liquids. Hydrocarbon compounds may be aliphatic or aromatic, and
may be straight
chained, branched, or partially or fully cyclic.
[0032] "Bitumen" is a naturally occurring heavy oil material. Generally, it
is the
hydrocarbon component found in oil sands. Bitumen can vary in composition
depending upon
the degree of loss of more volatile components. It can vary from a very
viscous, tar-like, semi-
solid material to solid forms. The hydrocarbon types found in bitumen can
include aliphatics,
aromatics, resins, and asphaltenes. A typical bitumen might be composed of:
19 weight (wt). % 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. %).
In addition bitumen can contain some water and nitrogen compounds ranging from
less
than 0.4 wt. % to in excess of 0.7 wt. %. The metals content, while small,
must be removed to
avoid contamination of the product synthetic crude oil (SCO). Nickel can vary
from less than 75
ppm (part per million) to more than 200 ppm. Vanadium can range from less than
200 ppm to
more than 500 ppm. The percentage of the hydrocarbon types found in bitumen
can vary.
[0033] "Heavy oil" includes oils which are classified by the American
Petroleum Institute
(API), as heavy oils, extra heavy oils, or bitumen. Thus the term "heavy oil"
includes bitumen
and should be regarded as such throughout this description. Heavy oil may have
a viscosity of
about 1,000 centipoise (cP) or more, 10,000 cP or more, 100,000 cP or more, or
1,000,000 cP or
more. In general, heavy oil has a API gravity between 22.302 (density of 920
kilograms per
cubic meter (kg/m3) or 0.920 grams per cubic centimeter (g/cm3)) and 10.002
API (density of
1,000 kg/m3 or 1 g/cm3). Extra heavy oil, in general, has a API gravity of
less than 10.002 API
(density greater than 1,000 kg/m3 or greater than 1 g/cm). For example, a
source of heavy oil
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includes oil sand or bituminous sand, which is a combination of clay, sand,
water, and bitumen.
The thermal recovery of heavy oil is based on the viscosity decrease of fluids
with increasing
temperature 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.
[0034] "Facility" is a tangible piece of physical equipment through which
hydrocarbon
fluids are either produced from a reservoir or injected into a reservoir, or
equipment that can
be used to control production or injection operations. In its broadest sense,
the term facility is
applied to any equipment that may be present along the flow path between a
reservoir and its
delivery outlets. Facilities may comprise production wells, injection wells,
well tubulars,
wellbore head equipment, gathering lines, manifolds, pumps, compressors,
separators, surface
flow lines, steam generation plants, processing plants, and delivery outlets.
[0035] A "reservoir" or "subterranean reservoir" is a subsurface rock, sand
or soil
formation from which a production fluid, or resource, can be harvested. The
formation may
include sand, granite, silica, carbonates, clays, and organic matter, such as
bitumen, heavy oil,
oil, gas, or coal, among others. Reservoirs can vary in thickness from less
than one foot (0.3048
meter (m)) to hundreds of feet (hundreds of meters). The resource is generally
a hydrocarbon,
such as heavy oil impregnated into a sand bed.
[0036] 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, 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.
[0037] A "fluid" includes a gas or a liquid and may include, for example,
hot or cold water,
a produced or native reservoir hydrocarbon, an injected mobilizing fluid, hot
or cold liquid
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,
hydrocarbon, solvent, steam, wet steam, gas (e.g. C1, CO2, etc.), or a mixture
of these, among
other materials.
[0038] "Permeability" is the capacity of a rock or other structure to
transmit fluids through
the interconnected pore spaces of the structure. The customary unit of
measurement for
permeability is the milliDarcy (mD).
[0039] "Pressure" is the force exerted per unit area by the gas on the
walls of the 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. "Gauge
pressure" (psig) refers to the pressure measured by gauge, which indicates
only the pressure
exceeding the local atmospheric pressure. Unless otherwise specified, the
pressures disclosed
herein are absolute pressures, i.e. the sum of gauge pressure plus atmospheric
pressure
(generally 14.7 psi at standard conditions).
[0040] "Steam-based heavy oil recovery processes" or "steam-based
processes" include
any type of hydrocarbon recovery process that uses a heat source to enhance
the recovery, for
example, by lowering the viscosity of a hydrocarbon. These processes may use
injected
mobilizing steam, either wet steam or dry steam, in admixture with solvents,
to lower the
viscosity of the hydrocarbon. Such processes may include thermal recovery
processes.
[0041] "Primary steam-based heavy oil recovery processes" or primary heavy
oil recovery
processes include any steam-based heavy-oil recovery process in which a
certain portion of the
heavy oil is left behind as residual heavy oil due to a decrease in the heavy
oil mobility within a
subterranean reservoir.
[0042] "Substantial" when used in reference to a quantity or amount of a
material, or a
specific characteristic thereof, refers 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. When a compound is indicated
as
"removed" or "substantially removed" from a mixture of compounds, it should be
understood
that there may remain such an amount of the compound in the mixture that
cannot be
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removed by the technique employed for removal. For example, fractionation may
leave small
amounts or traces of a compound intended to be removed.
[0043] A "solvent" is an agent that may dilute or dissolve heavy oil and
may reduce a
viscosity of the heavy oil. Many solvents used for heavy oil recovery, such as
single alkanes,
mixtures of alkanes and gas plant condensates, may not be solvents of heavy
oil according to a
precise or narrow definition of the term (i.e., an agent that completely
dissolves all components
of a solute below its solubility limit concentration). For example, some
solvents may not
dissolve an asphaltene component of heavy oil. These solvents do dilute the
heavy oil and as
such function as diluents. Other agents such as xylene and toluene may be
solvents in that they
may dissolve all components of the heavy oil up to a solubility limit
concentration. Solvent
includes both solvents as narrowly defined and also diluents as is understood
and accepted in
the art.
[0044] An "azeotrope" is generally understood to be a composition of
liquids having a
constant boiling point, in which a vapor phase has the same component
proportions as a liquid
phase. It follows that the components of an azeotropic composition cannot be
separated by
fractional distillation. The boiling point of an azeotropic composition may be
higher or lower
than the boiling points of any of its components. An azeotrope concentration
is a
concentration at which the liquids forming the azeotrope composition reach a
state in which
the mixture of the liquids forms the azeotrope composition.
[0045] "Residual heavy oil" generally refers to heavy oil in a vapor
chamber of a steam-
based heavy oil recovery process that becomes immobile or ceases to flow as
the recovery
process progresses, so that heavy oil remaining in the vapor chamber can no
longer be
economically recovered by the steam-based heavy oil recovery process. Metrics
may be used
for measuring the progress of the steam-based heavy oil recovery process such
as, for example,
an oil-to-steam ratio and identified values of the oil-to-steam ratio. For
example, steam-based
heavy oil recovery processes may be considered to no longer be economically
recovered and
therefore an economic limit when the metrics indicate that the value of
recovered heavy oil is
below a cost to extract the heavy oil. The economic limit of a primary steam-
based heavy oil
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recovery process may be when a metric indicates that the value of the heavy
oil recovered by
the primary steam-based heavy oil recovery process is below a cost to run the
primary steam-
based heavy oil recovery process. One example of the metric is a ratio between
the heavy oil
recovered from the subterranean reservoir and the steam injected into the
subterranean
reservoir, or an oil-to-steam ratio (OSR). For example, a SAGD process may be
considered at an
economic limit when the OSR falls below 0.2. For a cyclic steam stimulation
process, an OSR
below 0.13 may be considered to be the economic limit.
[0046] "Incremental heavy oil" is a portion of residual heavy oil that may
be recovered
after a primary production process. The primary production process may be an
initial thermal
recovery process or any process used in the first stage of recovering the
heavy oil from the
subterranean reservoir. The incremental heavy oil may be added to heavy oil
recovered by the
steam-based heavy oil recovery process that occurs during the primary
production process.
[0047] A steam-based heavy oil recovery process for recovering heavy oil
from
subterranean reservoirs may be employed as a primary production process. If
the steam-based
heavy oil recovery process is a SAGD process, a viscosity of the heavy oil
decreases due to an
injection of high temperature steam. The heavy oil temperature may warm the
heavy oil,
reducing a viscosity of the heavy oil such that the heavy oil may flow down
under the influence
of gravity. The heavy oil may drain down towards a production well and an
upwardly and
outwardly expanding vapor chamber may be formed. The vapor chamber may be
formed by
the steam penetration of the subterranean reservoir. Mobility of the heavy oil
may decrease
as the saturation of heavy oil declines in the vapor chamber. Eventually any
heavy oil remaining
may become immobile causing a certain portion of the heavy oil to be left
behind as residual
heavy oil. The residual heavy oil may amount to 10 volume (vol.%) or more of
the heavy oil
originally in the subterranean reservoir. The amount of residual heavy oil may
include any
number within or bounded by the preceding range of residual heavy oil.
Providing a method of
recovering some or all of the residual heavy oil once the primary production
process has been
substantially completed is desired.
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[0048] Steam-based heavy oil recovery processes may be operational for a
number of
years (e.g. 10 years or more) functioning as the primary production process.
Eventually a ratio
of recovered-heavy oil to steam-injected begins to fall during the steam-based
heavy oil
recovery process and becomes so low that the steam-based heavy oil recovery
process is
considered not to be economically viable. Gases may then be injected into the
subterranean
reservoir to take advantage of residual heat from the steam of the steam-based
heavy oil
recovery process, with any resulting fluids recovered from the injection of
gas being produced
for heavy oil content in the resulting fluids. The phase of the gases being
injected may be
referred to as "blowdown". Generally very little of the residual heavy oil is
recovered in this
way.
[0049] Evidence from simulation and physical models indicates that
injection of a solvent
with steam (e.g., solvent-assisted-SAGD) into a subterranean reservoir
containing heavy oil
reduces saturation of the residual heavy oil compared with SAGD alone. If a
solvent is
introduced into the steam-based process, as in SA-SAGD, a large amount of the
solvent
condensate may exist at a boundary of the vapor chamber and the subterranean
reservoir
where it can mix with the heavy oil such that the residual heavy oil in the
subterranean
reservoir is composed of heavy oil and solvent. Some or all of the heavy oil
and solvent may
continue to drain down, thereby reducing saturation of the residual heavy oil.
The net result
may be a reduction in both the heavy oil remaining in the subterranean
reservoir and an
increase in recovery relative to a steam-based process alone, in addition to
faster production
rates. Nevertheless, even in the case of SA-SAGD, some heavy oil remains
unrecovered from
the subterranean reservoir. The SA-SAGD process typically uses a small ratio
of solvent to
steam as the solvent is expensive, which may limit the extent of recovery of
the heavy oil. For
example, a mixture of heptanes and steam used for SA-SAGD may employ about 17
to 25% by
volume of the heptanes, i.e. around 2 mole (mol.) %. The amount of steam used
for SA-SAGD
may include any number within or bounded by the preceding range of steam.
[0050] The present disclosure includes methods of recovering heavy oil from
a
subterranean reservoir. More specifically, the present disclosure includes
methods of
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enhancing the recovery of heavy oil from a subterranean reservoir that may be
performed
during or after the primary production process.
[0051] The methods may include performing a steam-based heavy oil recovery
process 602
(Figure 6). The steam-based heavy oil recovery process may be the primary
production process.
The steam-based heavy oil recovery process may be performed as part of the
methods and
concurrently with the other steps of the methods. The steam-based heavy oil
recovery process
may be performed prior to the other steps of the method 600.
[0052] The methods may include injecting a mixture of steam and solvent
into the
subterranean reservoir to form a liquid comprising heavy oil and the solvent
in condensed form,
604 (Figure 6). The mixture of steam and solvent may be injected via an
injection well used
during the steam-based heavy oil recovery process. The heavy oil may be
residual heavy oil.
[0053] The mixture of solvent and steam may be injected into the
subterranean reservoir
when a steam-based heavy oil recovery process used as the primary production
process is close
to an economic limit. Injecting the mixture when the steam-based heavy oil
recovery process
used as the primary production process is close to the economic limit of the
steam-based heavy
oil recovery process may provide solvent condensates that may sweep the
residual heavy oil
from the subterranean reservoir. Sweeping the residual heavy oil may be
referred to as a
"sweeping phase." When the sweeping occurs during the primary production
process, the
"sweeping phase" may be the "sweeping phase" of the steam-based heavy oil
recovery process
used as the primary production process.
[0054] The solvent may be any material that is capable of being injected
into a
subterranean reservoir in admixture with steam so that the solvent can
condense and dilute
heavy oil within the subterranean reservoir. The solvent may be any material
that can form an
azeotrope composition with water. The solvent may be a material that can be
subsequently
recovered from the subterranean reservoir. The solvent may comprise any of the
solvents
conventionally used for steam-based heavy oil recovery processes. For example,
the solvent
may include, but is not limited to, any hydrocarbon having a carbon atom
number of C3 to C25
or higher (which may be straight-chained, branched, cyclic, aliphatic or
aromatic, or a
CA 02854171 2014-06-13
combination thereof), or any mixture of two or more such hydrocarbons in any
relative
amounts. The hydrocarbon may be an alkane. The solvent may be a gas plant
condensate.
[0055] The mixture of the solvent and steam may have a concentration of the
solvent close
to or above an azeotrope concentration for the mixture at a pressure of the
subterranean
reservoir. The concentration of solvent and steam may be selected so that
solvent is
condensed at a boundary of the vapor chamber and inside the vapor chamber to
allow the
solvent to mix with residual heavy oil throughout the vapor chamber.
[0056] For mixtures of any solvent and steam, there generally exists a
certain
concentration of solvent at which steam and solvent condense simultaneously
when the
temperature is decreased at constant pressure (i.e. at the azeotrope
concentration.) When the
amount of solvent in the mixture of steam and solvent is below the azeotrope
concentration,
steam condenses before the solvent condenses. When the amount of solvent in
the mixture of
steam and solvent is above the azeotrope concentration, the solvent condenses
before the
steam condenses.
[0057] Unlike the mixture of steam and solvent employed by the steam-based
heavy oil
recovery process used during the primary production process, the solvent used
in the mixture
may be close to or above the azeotrope concentration for the mixture at the
pressure of the
subterranean reservoir. During the primary production process, it is typically
desired that a
vapor chamber formed during the primary production process expand as much as
possible
since heavy oil within the vapor chamber is heavy oil that is mobilized for
recovery by a well of
the primary production process. Generally, during the primary production
process any injected
mixture of solvent and steam is below an azeotropic concentration and steam
condenses prior
to the solvent. During the primary production process any solvent injected may
condense at a
boundary of the vapor chamber. In the methods of the present disclosure,
solvent is
condensed at a boundary of the vapor chamber and inside the vapor chamber to
allow the
solvent to mix with residual heavy oil throughout the vapor chamber as a
result of the mixture
being close to or above the azeotropic concentration. As the mixture injected
in the method of
the present disclosure encounters cooler parts of the subterranean reservoir
at the boundary of
CA 02854171 2014-06-13
=
16
the vapor chamber, the solvent condenses before the steam, and is thus
available for mixing
with and diluting the residual heavy oil. With the solvent condensing before
the steam, the
concentration of the solvent within the vapor chamber that is available for
diluting the residual
heavy oil may be greater than that during the primary production process
because the solvent
condenses first. A liquid is formed when the mixture mobilizes heavy oil that
may drain down
to a well to be recovered from the subterranean reservoir.
[0058] Determining an appropriate concentration of solvent and steam so
that the mixture
is close to or above an azeotropic concentration may be calculated based on a
phase behaviour
of the mixture. An appropriate concentration is considered to be a lowest
ratio between
solvent and steam at which the solvent is the first component to condense.
[0059] FIG. 1A shows saturation temperatures versus solvent mole fractions
at a pressure
of 800 kPa for three solvents, namely n-pentane (n-05), n-heptane (n-C7) and n-
decane (n-C10).
In FIG. 1A, the appropriate concentration for n-heptane/steam is about 0.48
mole n-heptane
(i.e. about 48 mol. %.) For n-decane, the appropriate concentration is about
12 mol. %, and for
n-pentane, the appropriate concentration is about 87 mol. %. The use of
heavier solvents, such
as but not limited to n-decane (n-C10) and/or solvents having a carbon atom
number higher
than n-decane, may be appealing since less solvent injection will be required
to achieve similar
results.
[0060] The curves for all three solvents show inflection points at
azeotrope concentrations.
Arrow A shows the part of the curve for solvent n-C7 where water condenses
first, arrow B
shows the part of the curve where solvent condenses first, and arrow C
indicates the azeotrope
point or concentration at which there is simultaneous condensation of water
and solvent.
[0061] FIG. 1B shows the XY equilibrium (Pxy) curve for n-heptane alone at
a pressure of
800 kPa. Again, the azeotrope concentration is indicated by arrow C.
[0062] A concentration of the solvent in the mixture with steam may be up
to 3 mol. %
above the azeotrope concentration, or within the range of 1-2 mol.% above the
azeotrope
concentration. The mixture of steam of solvent may have a concentration of
solvent slightly
below the azeotrope concentration, in an attempt to inject less solvent into
the subterranean
CA 02854171 2014-06-13
17
reservoir, while benefiting from the azeoptrope concentration. A slightly
lower concentration
of the solvent in the mixture may be as low as 1 mol.% below the azeotrope
concentration, but
preferably closer to the azeotrope concentration. The concentration of the
solvent may be any
number within or bounded by the preceding range. While a mixture of steam and
solvent
employed may have any concentration of solvent close to or above the azeotrope
concentration, higher concentrations of solvent may introduce more of the
solvent into the
subterranean reservoir. Higher concentrations may be desirable for achieving
more dilution of
residual heavy oil, but undesirable because greater amounts of potentially
expensive solvents
may then be required. Moreover, the less solvent that is injected into the
subterranean
reservoir, the less solvent there remains in the subterranean reservoir for
subsequent removal.
[0063] The mixture may be injected into the subterranean reservoir at a
pressure higher
than the pressure of the subterranean reservoir. The mixture may be injected
below a pressure
at which a matrix of the subterranean reservoir may fracture. The mixture may
be injected into
the subterranean reservoir at a temperature above a boiling point of the
mixture having the
solvent close to or above the azeotrope concentration.
[0064] The mixture of steam and solvent may be injected into the
subterranean reservoir
at a time equal to at least one of during and after performing the steam-based
heavy oil
recovery process. Referring to Fig. 6, step 602 of performing a steam-based
heavy-oil recovery
process may be performed before or during step 604 of injecting the mixture of
steam and
solvent. Injecting the mixture of steam and solvent at a time equal to during
the steam-based
heavy oil recovery process may slow down the steam-based heavy oil recovery
process.
Slowing down the steam-based heavy oil recovery process may allow steam from
the steam-
based heavy oil recovery process to penetrate further into the subterranean
reservoir. Further
steam penetration may increase an amount of heavy oil that can be recovered
during the
steam-based heavy oil recovery process prior to the economic limit of the
steam-based heavy
oil recovery process being reached. When the mixture is injected during the
steam-based
heavy oil recovery process, there may be a reduction in down time between the
steam-based
CA 02854171 2014-06-13
,
18
heavy oil recovery process reaching the economic limit and the methods of the
present
disclosure commencing.
[0065] The steam-based heavy oil recovery process used as the primary
production process
may be performed until the amount of heavy oil recovered from the subterranean
reservoir
starts to decline. The amount of heavy oil recovered may be considered as
starting to decline
when the OSR falls below the economic limit.
[0066] The mixture may be injected at a time equal to immediately after the
steam-based
heavy oil recovery process used as the primary production process is carried
out on the
subterranean reservoir. A steam-based heavy oil recovery process may operate
at a high
temperature (e.g., 180 to 250 Celsius ( C)). The temperature may be any number
within or
bounded by the preceding range. There may be a delay between the end of the
steam-based
heavy oil recovery process and the injection of the mixture of steam and
solvent. If injection of
the mixture of steam and solvent immediately follows the steam-based heavy oil
recovery
process, the subterranean reservoir may be at an elevated temperature that is
above an
original temperature of the subterranean reservoir (e.g. 5 to 12 C). The
temperature may be
any number within or bounded by the preceding range. The elevated temperature
may be
helpful in reducing the viscosity of the residual heavy oil.
[0067] The subterranean reservoir may be left to cool from the operating
temperature of
the steam-based heavy oil recovery process before injecting the mixture, in
which case heat
may have to be reintroduced to bring the subterranean reservoir up to a
temperature close to
the azeotrope temperature of the mixture resulting in greater expenses and
delay. A small
time delay between stopping the steam-based heavy oil recovery process and
injecting the
mixture may have an effect of allowing the subterranean reservoir to cool from
the operating
temperature of the steam-based heavy oil recovery process. The cooling of the
subterranean
reservoir from the operating temperature of the steam-based heavy oil recovery
process to an
azeotrope temperature will depend on the operating temperature as well as the
solvent used in
the mixture, which determines the azeotrope temperature. For example, the
subterranean
reservoir may be cooled from the operating temperature of the steam-based
heavy oil recovery
CA 02854171 2014-06-13
=
19
process (e.g. 180 C or more) to a temperature around the azeotrope temperature
(e.g., about
160 C for heptane at 800kPa (as shown in figure 3)). The temperature may be
any number
within or bounded by the preceding range. The cooling in the above example of
20 C may
require a period of one or two months, but may occur even if the mixture is
injected
immediately because a smaller volume of steam may be employed which may allow
cooling to
take place. The injection of the mixture may be continued until the ratio of
heavy oil in the
liquid from the subterranean reservoir declines below a predetermined value,
based on, for
example, the OSR.
[0068] A shut-in period may be detected in the steam-based heavy oil
recovery process
used as the primary production process. The mixture of steam and the solvent
may be injected
during the shut-in period. A steam-based heavy oil recovery process may
encounter one or
more shut-in periods. A shut-in period may occur when injection of steam is
ceased during the
steam-based heavy oil recovery process. Steam can become unavailable for
various reasons
during the operation of the steam-based heavy oil recovery process, for
example, due to
problems in steam generation. To maintain recovery of the heavy oil, injection
of a high
concentration of solvent may be carried out as a shut-in period treatment. Any
concentration
of solvent may be contemplated, and may be as high as pure solvent (100%). At
a time equal to
at least one of during or after performing the steam-based heavy oil recovery
process, the
method of recovering heavy oil may be carried out, which may also recover any
high
concentration of solvent that could be left from the shut-in period treatment.
[0069] The methods may include recovering the heavy oil and at least a
portion of the
solvent from the subterranean reservoir by producing the liquid from the
subterranean
reservoir, 606 (Figure 6). The liquid may be produced via a production well
used during the
steam-based heavy oil recovery process.
[0070] As a concentration of the solvent increases, so does a cost of using
the solvent.
However, the solvent may be at least partially recovered to make the methods
more
economical overall, which is called the "follow-up phase". Some of the solvent
may be
produced in the mixture of heavy oil and solvent and may be recovered at the
surface (e.g. by
CA 02854171 2014-06-13
fractionation) or the solvent may be left in admixture with the heavy oil to
make the product
more easily pumpable for transportation by pipeline. Solvent still remaining
in the
subterranean reservoir after recovery of the heavy oil has finished may be
stripped from the
subterranean reservoir in several ways.
[0071] A vapor of an inexpensive solvent may be used instead of steam to
recover the
solvent from the mixture. The inexpensive solvent may be a solvent that is
readily available at a
site of facilities of the steam-based heavy oil recovery process. The
inexpensive solvent may be
for example, a by-product of the steam-based heavy oil recovery process that
may be used as a
solvent without further processing. In contrast, an expensive solvent may be a
solvent that is
based on a by-product that requires further processing before it can be used
as a solvent, such
as by isolating, separating or purifying. The expensive solvent may be a
material that is not
commonly available at the site of facilities of the steam-based heavy oil
recovery process.
[0072] The inexpensive solvent may condense at the boundary of the vapor
chamber, wash
down and mix in the mixture. The mixture of solvents may then be produced and
separated at
the surface until mainly the inexpensive solvent appears in the produced
fluids. The
inexpensive solvent may displace the expensive solvent. The inexpensive
solvent may be
introduced in the form of a liquid, which again mixes with the original
solvent and may be
produced. The liquid may be heated or not, but the use of a heated solvent may
be better to
achieve delivery, mixing and production. A non-condensable gas may be
introduced into the
subterranean reservoir to push any residual original solvent, in liquid or
vapor form, to the
boundary for better draining and production. The methods of removing or
displacing original
solvent described above may be applied together in some cases. For example,
steam may first
be injected and may be followed by the injection of a non-condensable gas.
[0073] Heat may be introduced into the subterranean reservoir (e.g. by
injecting a hot
fluid.) The heat may vaporize any residual solvent in the subterranean
reservoir. The vapor
may migrate to the boundary of the vapor chamber and condense and drain down
so that the
residual solvent may be produced via the production well. The hot fluid
employed may be a
condensable vapor, such as steam, that delivers latent heat of condensation to
the residual
CA 02854171 2014-06-13
21
solvent as it condenses in the reservoir. The fluid for recovering the solvent
may be a gas or
vapor having a temperature above a boiling point of the solvent within the
subterranean
reservoir. The fluid for recovering the solvent may be a gas or vapor able to
displace the
solvent from the subterranean reservoir. The fluid for recovering the solvent
may be steam, a
solvent for heavy oil, a non-condensable gas, a steam-solvent mixture having a
solvent
concentration below the azeotrope concentration of the steam-solvent mixture,
or any
combination of steam-solvent mixture and non-condensable gases. Examples of
non-
condensable gases that may be employed in the above methods as stripping
fluids include, but
are not limited to, methane (Cl), ethane (C2), carbon dioxide, nitrogen, or
any mixture of two
or more of the above gases in any relative amounts.
[0074] A solvent stripping fluid may be employed in the follow-up phase.
Steam or a
steam-solvent may be employed as the stripping fluid and may be injected, or
co-injected, into
the subterranean reservoir. When a steam-solvent mixture is employed, the mole
fraction of
solvent is such that the concentration is well to the left of the azeotrope as
identified in FIG. 1A
(i.e. about 0 ¨ 2 mol.% for n-heptane.) Solvent-steam mixtures in such
proportions may
reintroduce the heat and phase behavior environment required to vaporize the
residual solvent
in the subterranean reservoir, move it toward the vapor chamber boundaries,
and produce the
solvent back from the subterranean reservoir. High solvent recoveries may be
achieved, which
may make the method economically appealing.
[0075] Recovering of the solvent may be ceased when an amount of the
solvent recovered
from the subterranean reservoir falls below a predetermined value.
[0076] A blowdown may be performed after the recovering the at least a
portion of the
solvent. Performing the blowdown may comprise injecting a non-condensable gas
into the
subterranean reservoir, producing an additional liquid comprising an
additional portion of the
solvent and additional heavy oil mobilized by the non-condensable gas and
recovering the
additional portion of the solvent and the additional heavy oil from the
additional liquid.
[0077] A simulation was created for which n-heptane was chosen as the
injected solvent.
The simulation was created using software designed to model reservoir
conditions. In this
CA 02854171 2014-06-13
22
simulation, a SAGD process was run in a 2-D homogenous Cold Lake reservoir for
about 10
years (as a conventional production process), followed by about 2 years of
injection of 50
mole% heptane and 50 mole% steam (as a sweeping phase), followed by a year of
steam
(alone) injection before blow-down (as a follow-up phase). No attempt was made
to optimize
the procedure in this case. However, as can be seen from FIG. 2, which
illustrates the results, a
reduction of oil saturation was demonstrated and, as a result, a clear
increase in heavy oil
recovery would be achieved by methods of the present disclosure as compared to
conventional
processes.
[0078] FIG. 2 compares oil saturation resulting from conventional SAGD
(panel [II]) to the
method of recovering residual heavy oil (panel [1]). The darker shades in
panel [I] indicate a
much lower saturation approaching 0.0 with smaller areas of higher saturation,
whereas the
lighter shades of panel [II] indicate a residual heavy oil content closer to
0.22 with smaller areas
of higher saturation.
[0079] FIG. 3 is a graph comparing cumulative oil recovered versus time for
these two
simulated cases. It can be seen that in the late stages of the operation, the
methods of the
present disclosure resulted in higher cumulative heavy oil recovery.
[0080] FIG. 4 is a graph showing solvent injected, solvent volume remaining
in the
subterranean reservoir, and the additional volume of heavy oil recovered
during the method of
recovering residual heavy oil. The curve for solvent volume remaining clearly
shows that much
of the solvent was recovered. The solvent recovery after one year of steam
injection is about
95%. The additional volume of heavy oil produced was substantial.
[0081] A test may be performed to determine the amount of heavy oil
remaining in the
subterranean reservoir after the steam-based heavy oil recovery process used
as the primary
production process. The test may involve a reservoir saturation tool (RST) log
test or a coring
sample that can be directly tested. The test may provide an indication of
saturation of heavy oil
in the subterranean reservoir. Results of the test may be compared with
results from similar
tests that may have been performed prior to the steam-based heavy oil recovery
process or
during the steam-based heavy oil recovery process. The comparison of test
results between
CA 02854171 2014-06-13
23
the different times can give an indication of how much heavy oil has been
recovered from the
subterranean reservoir and how much heavy oil remains in the subterranean
reservoir. The
amounts of residual heavy oil in the subterranean reservoir, the costs of
solvent, stripping
fluids, etc., and the expected returns from any residual heavy oil thus
recovered may determine
the suitability of the method for recovering residual heavy oil. For
subterranean reservoirs
containing amounts of residual heavy oil up to 30 vol.% of the original
deposits, typically 20%,
or as low as 5-10%, the methods of this disclosure may result in the recovery
of up to 80-90% of
the residual oil produced by the primary heavy oil recovery process of
production. The
recovery percentage may be any number within or bounded by the preceding
range.
[0082] FIG. 5A-5D are drawings showing the evolution of the recovery of
heavy oil in a
subterranean reservoir 2 by a SAGD process by a known monitoring method such
as an RST.
FIG. 5A is a transversal view drawing of a vapor chamber 4, showing an
injection well 6 and a
production well 8. The drawing also shows an observation well 10 from which a
RST log is
taken. The drawings 5B-D illustrate RST logs at different time. The y-axis is
in function of the
depth of the vapor chamber 4. The heavy oil 12 is shown as oblique lines and
water 14 is
shown as vertical lines. FIG. 5B is an RST log at time zero, before the SAGD
process. The heavy
oil recovery has not started and the space is mainly occupied by heavy oil.
FIG. 5C is an RST log
at the end of the SAGD process. The heavy oil 12 left as residual heavy oil is
shown. FIG. 5D is
an RST log after the method according to this disclosure. It shows that a
portion of the residual
heavy oil from the SAGD process has been recovered.
[0083] It should also be understood that numerous changes, modifications,
and
alternatives to the preceding disclosure can be made without departing from
the scope of the
disclosure. The preceding description, therefore, is not meant to limit the
scope of the
disclosure. Rather, the scope of the disclosure is to be determined only by
the appended claims
and their equivalents. It is also contemplated that structures and features in
the present
examples can be altered, rearranged, substituted, deleted, duplicated,
combined, or added to
each other.
