Note: Descriptions are shown in the official language in which they were submitted.
BLOWDOWN PRESSURE MAINTENANCE WITH FOAM
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the benefit, and priority benefit, of U.S.
Provisional Patent
Application Serial No. 62/350,783, filed June 16, 2016, the disclosure and
contents of
which are incorporated by reference herein in their entirety.
FEDERALLY SPONSORED RESEARCH STATEMENT
[0002] Not applicable.
FIELD OF THE INVENTION
[0003] The invention relates to petroleum production for heavy oil and/or
bitumen. In
particular, the invention relates to a process in which foams are used to
maintain pressure
in the mature chamber during operations at the blowdown stage of a steam-
assisted gravity
drainage (SAGD) process or other enhanced oil recovery process.
BACKGROUND OF THE INVENTION
[0004] Production of heavy oil and bitumen from a subsurface reservoir can be
quite
challenging. The initial viscosity of the oil at reservoir temperature prior
to any treatment,
is often greater than a million centipoise (cP). High viscosity oil cannot be
pumped out of
the ground using typical methods, and is often mined or processed in situ.
Surface mining
is limited to reservoirs at depths of less than about 70 meters. The majority
of bitumen
reserves, however, are present at depths that make surface mining
uneconomical. These
deeper reserves are typically produced using in-situ recovery methods.
[0005] In-situ thermal oil recovery processes such as Cyclic Steam Stimulation
(CSS) and
Steam-Assisted Gravity Drainage (SAGD) are widely used commercial processes
for
recovering oil from heavy oil/ bitumen reservoirs. These thermal processes
generally apply
heat energy to reservoir using steam or hydrocarbon solvents as the working
fluid. As
temperature in the reservoir increases, the viscosity of the heavy bitumen (or
oil) decreases
and the oil is able to flow into a production well.
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[0006] Steam-assisted gravity drainage (SAGD) is an in situ processing method
first
introduced by Roger Butler in 1973 as a means of producing heavy oil and
bitumen. SAGD
involves the use of two parallel and superposed horizontal wells (a well-pair)
that are
vertically separated by about 5 meters. (See FIG. 1). The SAGD process is
roughly
described as follows. During the first phase of a SAGD process, sometimes
referred to as
start-up, steam is circulated between the injector and the producer to
establish mobility of
fluids between the two wells. Next the production phase of SAGD begins and the
steam
injection is limited to the injector and oil is produced through the producer.
As the steam
chamber grows vertically and laterally, viscosity of the bitumen is reduced
and the bitumen
is drained to the producer below by gravity. Initially, high pressures may be
employed,
generally around 15 to 20 kPa/meter, to promote vertical development of the
steam
chamber, which promotes high drainage/production rates. As the steam chamber
matures,
the pressure of the steam chamber it may be reduced, to help mitigate the
rising steam-to-
oil ratios caused by heat losses to the overburden/thief zones on top of the
reservoir.
[0007] As an in situ recovery process, SAGD is very energy intensive largely
because the
reservoir rock and fluids must be heated enough to lower the viscosity of and
mobilize the
petroleum. Heat is also lost to over burden and under burden which may
contain, water
and gas intervals, thus reducing the thermal efficiency of the process. As a
result of being
energy intensive, SAGD requires a large capital investment in steam generation
and water
treatment facilities. The operating expense associated with the SAGD process
can also be
high due to the expense of generating steam and treating produced water. As a
result,
SAGD is typically operated until the steam-to-oil ratio (and hence the energy
intensity)
increases to the point where continued operation is either un-economical or
otherwise
impractical (e.g., incremental recovery from steam injection can no longer be
achieved).
[0008] Foam has been used in SAGD to block thief zones, decrease channeling,
and
improved oil displacement during SAGD. Foam is dispersion of gas in a
continuous water
phase with thin films (lamella), acting as a separator. Given its sensitivity
to oil distribution,
foam tends to reside in higher permeability layers with less residual oil.
Thermally stable
surfactants are essential to maintain the foam life because surfactants
stabilize lamella by
decreasing the water-gas interfacial tension. Li, et al., have reviewed how
chemical
additives and foam can enhance SAGD performance. Li et al., "Chemical
Additives and
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Foam to Enhance SAGD Performance," SPE Canada Heavy Oil Technical Conference,
9-
11 June, Calgary, Alberta, Canada (2015).
[0009] Eventually, every SAGD chamber (which may be an amalgamation of
chambers
associated with a number of injectors and producers) reaches the point at
which economic
steam injection operations become impractical. At this point, the SAGD wells
are placed
in what industry frequently refers to as "blowdown" in which steam injection
into the steam
chamber typically ceases or is significantly reduced. During blowdown,
reservoir pressure
must typically be maintained in order to continue producing oil from other
locations in the
reservoir.
[0010] Non-condensable gas (NCG) has been injected by operators to maintain
pressure in
SAGD operations during mid-late life development stages of SAGD. Meg Energy at
their
Christina Lake project has co-injected methane with steam as early as at 30%
recovery of
the drainage area 00IP. Cenovus Energy has performed multiple methane co-
injection
projects at their Foster Creek and Christina Lake projects. NCG was injected
at UTF Phase
B, during the wind-down of those wells. Multiple authors have discussed NCG
blowdown.
See, e.g., Zhao et al., "Numerical Study and Economic Evaluation of SAGD Wind-
Down
Methods," Journal of Canadian Petroleum Technology, 42(1): 53-57 (2003).
[0011] There is a need to improve SAGD methods during blowdown. Improved SAGD
blowdown is required to reduce capital expenses during late stage SAGD
operations,
improve production from nearby less mature SAGD operations, and improve oil
recovery
economics including reduced SOR, reduced NCG, and improved thermal efficiency.
SUMMARY OF THE INVENTION
[0012] The present invention generally relates to a method and system of
using/creating a
foam/colloidal dispersion/gel (collectively "foam") that occupies the depleted
void space
within a steam chamber in order to maintain pressure and improve blowdown
performance.
A significant void volume of pore space within the depleted steam chamber can
be occupied
with the use of small amounts of surfactant (or other foaming agent(s)),
water, and,
optionally, small amounts of NCG.
[0013] In some embodiments, the present invention may improve the performance
of
steam chambers that are being operated at different pressures and are in fluid
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communication with the steam chamber where foam is applied. This improved
performance is because the foam is expected to mitigate pressure or fluid
communication
(e.g., steam or NCG migration). As an example, the present invention addresses
production
problems introduced by the current technology of replacing steam with non-
condensable
gas in a mature SAGD steam chamber resulting in significant NCG migration to a
less
mature chamber or significant steam migration from the less mature chamber to
the mature
(and less productive) chamber.
[0014] In general, in one aspect, the invention features a method for
recovering petroleum
from a formation containing heavy hydrocarbons. This process may be applied to
any
enhanced oil recovery (EOR) process that has a blowdown stage where pressure
is drawn
down as the reservoir matures. Injection based oil recovery methods including
thermal
recovery, such as Cyclic Steam Stimulation (CSS), Steam Flooding, Steam-
Assisted
Gravity Drainage (SAGD), Vapor Extraction (VAPEX), Single Well SAGD (SW-SAGD),
Cross Well SAGD (X-SAGD), Foam Assisted SAGD (FA-SAGD), and the like; chemical
recovery methods such as alkali flooding, surfactant flooding, solvent
flooding, miscible
flooding including CO2 or non-condensable gas (NCG); In Situ Combustion (ISC),
Toe ¨
Heel Air Injection (THAI), Combustion Overhead Gravity Drainage (COGD) and the
like;
combinations thereof, or other recovery method that may have a blowdown
period. In
order to prevent lower pressure at the location of blowdown a foam/colloidal
dispersion/gel
(collectively "foam") is injected to occupy the depleted void space within a
reservoir
chamber in order to maintain pressure and prevent mobility into, through, or
out of the
reservoir chamber during blowdown.
[0015] In one embodiment, a foam is injected during blowdown of thermal SAGD
production comprising an injection well and a production well in fluid
communication with
the formation. In some recovery processes, the injection well may be the same
as the
production well and may include additional vertical or horizontal wells in an
interconnected well system. The method includes injecting steam into the
formation
through the injection well to form a steam chamber in the formation. The
method further
includes recovering a fluid including heavy hydrocarbons from the production
well during
the injection process. The method further includes engaging in blowdown
operations after
the steam chamber reaches maturity and a mature chamber is formed. The
blowdown
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operations include injecting a foam into the mature chamber. The injection of
the foam in
the mature chamber maintains pressure within the reservoir. The method further
includes
recovering the fluid comprising heavy hydrocarbons during the blowdown
operations,
wherein the foam injected in the mature chamber improves recovery of the
fluid.
[0016] In general, in another embodiment, the invention features a method for
recovering
petroleum from a formation containing heavy hydrocarbons. In this method, an
injection
well and a production well are in fluid communication with the formation. The
method
includes injecting a first fluid into the formation through the injection well
to form a
chamber in the formation. The first fluid is solvent(s), steam, or a
combination thereof
The method further includes recovering a second fluid including heavy
hydrocarbons from
the production well utilizing an enhanced oil recovery process and forming a
mature
chamber. The method further includes engaging in blowdown operations after the
formation of the mature chamber. The blowdown operations include injecting a
foam into
the mature chamber. The blowdown operations further include maintaining
pressure in the
mature chamber. The method further includes recovering the second fluid
including heavy
hydrocarbons during the blowdown operations.
[0017] Implementations of the invention can include one or more of the
following features:
[0018] The injection of the foam into the mature chamber can fill a void space
within the
mature chamber, can maintain pressure in the mature chamber sufficient to
continue
hydrocarbon recovery, and can maintain an elevated saturation temperature of
water
existing within the mature chamber.
[0019] The injection of the foam can maintain or increase production rates of
the second
fluid during the blowdown operations.
[0020] The injection of the foam can improve the quality of the recovered
petroleum
includes a quality characteristic selected from the group consisting of TAN
reduction,
lower sulfur content, higher API, lower viscosity, improved emulsion
characteristics,
reduction in heavy metal content, and combinations thereof
[0021] The injection of the foam into the mature chamber can include injecting
foam or a
foaming agent into the mature chamber through the injection well.
[0022] The injection of the foam into the mature chamber can include injecting
the foam
into the steam chamber through a third well where the third well is neither
the injection
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well nor the production well, but part of an interconnected well system (that
is, a set of
wells in pressure or fluid communication).
[0023] Blowdown operations can encompass numerous mechanisms for reducing
pressure
as the reservoir matures. Pressure may be reduced for blowdown by reducing the
injection
rate, injection pressure, and/or injection volume. Blowdown may also include
removing
pressure from the formation by removing gasses or liquids from the formation.
In one
embodiment, gases may be removed through a nearby vertical well at the top of
the
formation. In another embodiment, blowdown is accomplished by replacing some
or all of
the steam injection with the injection of a foam, in order to maintain steam
chamber
pressure.
[0024] Blowdown can further include injecting a non-condensable gas (such as
to achieve
a specific reservoir pressure). Alternatively, blowdown operations can further
include not
injecting a non-condensable gas.
[0025] Foam may be injected when blowdown is initiated or after blowdown has
begun.
[0026] Foam can be generated at a surface location before injecting the foam
into the
mature chamber. Foam components can be premixed on the surface prior to
injection.
Foam can also be generated sub-surface.
[0027] The step of generating the foam sub-surface can be selected from the
group
consisting of generating foam including using a downhole static mixer, foam
generation
through a perforation in the well, natural mixing in the well, in situ foam
generation in the
formation, temperature dependent foam generation, time-delayed foam
generation,
chemical/oil saturation dependent generation, foam generated through reactions
of
chemical compounds and combinations thereof.
[0028] The step of injecting the foam into the mature chamber can include
injecting a
solution including a foaming agent and generating the foam in situ in the
mature chamber.
The injection of foam can be in conjunction with steam, non-condensable gases,
such as,
but not limited to, methane or air, and may be injected in conjunction with
condensable
hydrocarbon solvents to reduce the solvent retention volumes and solvent
losses in solvent-
steam operations. Foam can be generated or maintained by injecting NCG,
surfactant, or
combinations to ensure the foam volume and pressure are sufficient.
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[0029] The step of injecting the foam into the mature chamber can include
injecting hot
water mixed with a foaming agent selected from the group consisting of
surfactants, alkali,
colloidal foams, aerosols, hydrosols, emulsions, dispersions, and combinations
thereof.
[0030] The foam can be formed from a foaming agent selected from the group
consisting
of alkyl benzene (aromatic) sulfonates, alpha/internal olefin sulfonates,
alkyl aryl
sulfonates, alkoxy sulfates, alkaline metal carbonates, bicarbonates,
hydroxides, sodium
carbonate, sodium bicarbonate, sodium hydroxide, potassium carbonate,
potassium
bicarbonate, potassium hydroxide, magnesium carbonate, calcium carbonate,
sodium
metaborate, and combinations thereof.
[0031] The method can further include selecting an foaming agent from which to
form the
foam based upon a foam characteristic selected from the group consisting of:
(a) thermal
and chemical stability at high temperatures at which these thermal recovery
processes are
operated, (b) low density and low viscosity, (c) the ability to withstand the
salinity/divalent
cations in the particular formation brine, (d) low adsorption onto rock/clay
surfaces in the
particular reservoir, (e) the ability to be non-reactive with the particular
reservoir rock
minerals and cause precipitation, (0 the ability of not negatively impacting
surface treating,
(g) the ability to be effective at the particular reservoir brine pH, (h) the
ability of not
negatively impacting the value of bitumen produced (i) low cost, and (j)
combinations
thereof.
[0032] The method can further include selecting a foaming agent from which to
form the
foam in which the foam has a low density between about 0.0006 g/cm3 and about
0.0770
g/cm3. The method can further include selecting a foaming agent from which to
form the
foam in which the foam has a low viscosity can be between about 0.01 cP and
0.022 cP.
[0033] The blowdown operations can further include utilizing the foam in a
heat
scavenging process.
[0034] The foam injected can be utilized to displace trapped heavy
hydrocarbons and drive
the heavy hydrocarbons to a condensation front or drainage interface of the
steam chamber.
[0035] The step of injecting the foam into the steam chamber can provide for a
second
steam-assisted gravity drainage process to be maintained at higher pressures
in a second
steam chamber adjacent to the mature chamber, resulting in improved recovery
and thermal
efficiency of the second chamber.
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[0036] The foam injected in the mature chamber can improve recovery of the
second fluid.
[0037] In general, in another aspect, the invention features a system for
recovering
petroleum from a formation containing heavy hydrocarbons. The system includes
an
injection well and a production well. The injection well and the production
well are in fluid
communication with the formation. The system further comprises a mature
chamber in the
formation. The mature chamber was formed by an enhanced oil recovery process.
The
mature chamber is in the blowdown phase for the enhanced oil recovery process.
The
system further includes a stream including a foam injected into the mature
chamber. The
foam in the mature chamber maintains pressure of the mature chamber and
improves
recovery of the fluid.
[0038] Implementations of the invention can include one or more of the
following features:
[0039] The enhanced oil recovery process can be selected from the group
consisting of
steam injection using (a) cyclic steam stimulation (CSS), (b) steam flooding,
(c) steam-
assisted gravity drainage (SAGD), (d) vapor extraction (VAPEX), (e) single
well SAGD
(SW-SAGD), (0 cross well SAGD (X-SAGD), (g) foam assisted SAGD (FA-SAGD), (h)
chemical recovery methods, (i) alkali flooding, (j) surfactant flooding, (k)
solvent flooding,
(1) miscible flooding, (m) in situ combustion (ISC), (n) toe¨heel air
injection (THAI), (o)
combustion overhead gravity drainage (COGD), and (p) combinations thereof
[0040] The enhanced oil recovery process is a thermal recovery process.
[0041] The foam in the mature chamber can fill void space within the mature
chamber, can
maintain higher pressure in the mature chamber, can keep saturation
temperature of water
existing within the mature chamber elevated, and can improve production rates
of the fluid
during the blowdown operations.
[0042] The system can further include a second injection well and a second
production
well, which second injection well and the second production well are in fluid
communication with the formation. The system can further include a second
chamber in
the formation. The second chamber may have been formed from a second fluid
injected
into the formation through the second injection well utilizing a second
enhanced oil
recovery process. The second chamber can be adjacent or neighboring the mature
chamber.
The foam can provide for the second enhanced oil recovery process to be
maintained at
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higher pressures in the second chamber, resulting in improved recovery and
thermal
efficiency.
[0043] The first enhanced oil recovery process and the second enhanced oil
recovery
process can be the same type of enhanced oil recovery process. Alternatively,
they can be
different types of enhanced oil recovery processes.
[0044] In general, in another aspect, the invention features a method for
recovering
petroleum from a formation containing heavy hydrocarbons. In this method, an
injection
well and a production well are in fluid communication with the formation. The
method
includes injecting steam into the formation through the injection well to form
a steam
chamber in the formation. The method further includes recovering a fluid
including heavy
hydrocarbons from the production well utilizing an enhanced oil recovery
process. The
method further includes forming a mature chamber from the steam chamber
utilizing the
enhanced oil recovery process. The method further includes engaging in a
blowdown
operation after the formation of the mature chamber. The blowdown operation
includes
injecting a foam into a mature chamber. The injection of the foam in the
mature chamber
maintains pressure of the mature chamber. The method further includes
recovering the
fluid including heavy hydrocarbons during the blowdown operation.
[0045] Implementations of the invention can include one or more of the
following features:
[0046] The method can further include selecting a transition condition for
transitioning
from the method before the step of engaging in the blowdown operation to the
step of
engaging in the blowdown operation. The method can further include determining
when
the transition condition has been met. The method can further include that,
upon
determination that the transition condition has been met, transitioning to the
step of
engaging in the blowdown operation.
[0047] The transition condition can be selected from the group consisting of
vapor
chamber growth, production performance, a pre-selected pressure below native
reservoir
pressure of the formation, a pre-selected pressure of an adjacent formation, a
pressure
below a pre-selected pressure of the formation, an environmental factor, a
market
condition, production costs, material costs, market price for hydrocarbons,
the market price
for solvents, and combinations thereof.
BRIEF DESCRIPTION OF THE DRAWINGS
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[0048] FIG. 1 (Prior Art) depicts a conventional steam-assisted gravity
drainage in an oil
sand formation.
[0049] FIG. 2 illustrates a mature SAGD steam chamber at blowdown with two
adjacent
immature SAGD steam chambers.
[0050] FIG. 3 illustrates the SAGD steam chamber at blowdown of FIG. 2 with
NCG.
[0051] FIG. 4 illustrates the SAGD steam chamber at blowdown of FIG. 2 with
foam.
[0052] FIG. 5 illustrates the SAGD steam chamber at blowdown of FIG. 2 with
foam and
with communication between an adjacent immature SAGD steam chamber.
100531 FIG. 6 illustrates a schematic view of the SAGD operation.
[0054] FIG. 7 illustrates a simulation detailing the relationship between
methane
production and MRF.
[0055] FIG. 8 illustrates a graph showing the foam heights of the compounds
tested;
[0056] FIG. 9 illustrates a simulation detailing various blowdown production
rates.
NOMENCLATURE
[0057] "Formation" as used herein refers to a geological structure, deposit,
reserve or
reservoir which includes one or more hydrocarbon-containing layers, one or
more non-
hydrocarbon layer, an overburden and/or an underburden. The hydrocarbon layers
can
contain non-hydrocarbon material, as well as hydrocarbon material. (The non-
hydrocarbon
layer can be a layer that contains only a nominal amount of hydrocarbons, such
as
mudstone). The overburden and underburden may contain one or more different
types of
low-permeability materials, for example rock, shale, mudstone wet carbonate,
or tight
carbonate.
[0058] "Petroleum deposit" refers to an assemblage of petroleum in a
geological
formation. The petroleum deposit can comprise light and heavy crude oils and
bitumen. Of
particular interest for the method described herein are petroleum deposits
which primarily
comprise heavy petroleum, such as heavy oil and petroleum.
[0059] "Injection well" or "injector" refers to a well into which a fluid is
injected into a
geological formation. The injected fluid can comprise, for example, a gaseous
mixture of
steam, NCG and/or hydrocarbon solvent. The injected fluid can also comprise a
liquid
solvent, such as a liquid hydrocarbon solvent or CS2.
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[0060] "Production well" or "producer" refers to a well from which a produced
fluid is
recovered from a geological formation. The produced fluid can comprise, for
example, a
petroleum product, such as heavy oil or bitumen.
[0061] "Horizontal drilling" refers to a process of drilling and completing a
well, beginning
with a vertical or inclined linear bore, which extends from the surface to a
subsurface
location in or near a target reservoir (e.g., gas, oil), then bears off at an
arc to intersect
and/or traverse the reservoir at an entry point. Thereafter, the well
continues at a horizontal
or nearly horizontal attitude tangent to the arc, substantially or entirely
remaining within
the reservoir until the desired bottom hole location is reached. (Of course,
the "bottom
hole" of a horizontal well is the terminus of the horizontal wellbore rather
than the
gravitational bottom of the vertical wellbore.)
[0062] A "horizontal well" is a well produced by horizontal drilling.
Horizontal
displacements of more than 8000 feet (2.4 km) have been achieved. The initial
linear
portion of a horizontal well, unless very short, is typically drilled using
rotary drilling
techniques common to drilling vertical wells. A short-radius well has an arc
with a 3-40
foot (1-12 m) radius and a build rate of as much as 30 per 100 feet (30 m)
drilled. A
medium-radius well has an arc with a 200-1000 foot (61-305 m) radius and build
rates of
8-30 per 100 feet drilled. A long-radius well has an arc with a 1000-2500
(305-762 m)
foot radius. Most new wells are drilled with longer radii, while recompletions
of existing
wells tend to employ medium or short radii. Medium-radius wells are the most
productive
and most widely used.
[0063] Horizontal wells confer several benefits. Operators are often able to
develop a
reservoir with fewer horizontal wells than vertical wells, since each
horizontal well can
drain a larger rock volume about its bore than a vertical well could. One
reason for this
benefit is that most oil and gas reservoirs are more extensive in their
horizontal (area)
dimensions than in their vertical (thickness) dimension. A horizontal well can
also produce
at rates several times greater than a vertical well, due to a higher wellbore
surface area
within the producing interval.
[0064] In some systems, the injection and production wells are vertically
aligned or in near
vertical alignment with each other. Of course, additional injection and
production wells
can be used and the placement can be varied accordingly, for example 3, 4 or 5
injection
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wells, and 2, 3 or 4 production wells. The placement need not be exact, and
can vary
according to convenience, surface structures, subsurface impediments, and
available
equipment and/or technology. Thus, placement of parallel, perpendicular, or
vertically
aligned wells, etc., is only a rough description. As example of additional
injection wells is
disclosed and taught in co-owned U.S. Patent Appl. Publ. 2012/0247760, "Dual
Injection
Points IN SAGD," published October 4, 2012, to Wheeler et al. (incorporated
herein by
reference in its entirety), which describes a method of receiving petroleum
from a
formation with at least two injection wells and one production well using
steam co-injected
with NCG and/or a hydrocarbon solvent.
[0065] In some embodiments, the first and second injection wells can be
multilateral wells,
wherein each is connected to the same vertical well bore, but branches
horizontally at
different intervals. "Multilateral well" refers to a well, which is one of a
plurality of
horizontal branches, or "laterals", from a vertical wellbore. Such wells have
at least two
such branches and allow access to widely spaced reservoir compartments from
the same
wellbore, thus saving the cost of drilling multiple vertical wellbores and
increasing the
economy of oil and gas extraction. For example, a well with a fishbone
configuration has
a single vertical wellbore and a plurality of non-vertical (e.g., horizontal),
deviated portion
connected to the vertical wellbore and extending into the formation. The non-
vertical
portions of a fishbone-configured well can further progress through the
reservoir at angles
different from the original angle of deviation.
[0066] "Ex situ processing" refers to petroleum processing which occurs above
ground.
Oil refining is typically carried out ex situ.
[0067] "In situ processing" refers to processing which occurs within the
ground in the
reserve itself. Processes include heating, pyrolysis, steam cracking, and the
like. In situ
processing has the potential of extracting more oil from a given land areas
than ex situ
processes since they can access material at greater depths than surface mines
can. An
example of in situ processing is SAGD.
[0068] "Steam-assisted gravity drainage" or "SAGD" refers to an in situ
recovery method
which uses steam to assist in situ processing, including related or modified
processes such
as steam-assisted gravity push (SAGP), and the original SAGD method as
described by
U.S. Patent No. 4,344,485, "Method For Continuously Producing Viscous
Hydrocarbons
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By Gravity Drainage While Injecting Heated Fluids," issued August 17, 1982, to
Butler.
In general, such as shown in FIG. 6, the method requires two horizontal wells
(production
well 601 and injection well 602) drilled into a reservoir 603 (illustrated in
FIG. 6 as an oil
sand formation). The wells 601-602 are drilled vertically to different depths
within the
reservoir 603 then, using direction drilling, the wells are extended
horizontally, resulting
in horizontal wells 601-602 vertically aligned to and spaced from each other.
Typically,
the production well 601 is located above the base of the reservoir but as
close as possible
to its bottom, for example between 1 and 3 meters above the base of the oil
reserve. The
injection well 602 is placed above (or nearly above) the production well 601,
and is
supplied steam from the surface (in the direction shown by steam flow 604).
The steam
exits the injection well 602, such as through slots 605 and rises, forming a
steam chamber
606 that slowly grows toward the top of the reservoir 603, thereby increasing
reservoir
temperature and reducing viscosity of the petroleum deposit. Gravity pulls the
petroleum
and condensed steam through the reservoir 603 into the production well 601 at
the bottom,
where the liquid is pumped to the surface (in the direction shown by oil flow
607). At the
surface, water and petroleum can be separated from each other.
[0069] "Non-condensable gas" or "NCG" refers to a chemical that remains in the
gaseous
phase under process conditions. For example, NCGs used during in situ
processing at a
petroleum deposit remain gaseous throughout the process, including under the
conditions
found in the fossil fuel deposit. Examples of suitable NCGs include, but are
not limited to,
air, methane (CI-14), carbon dioxide (CO2), nitrogen (N2), carbon monoxide
(CO), and flue
gas. "Flue gas" or "combustion gas" refers to an exhaust gas from a combustion
process
that exits to the atmosphere via a pipe or channel. Flue gas can typically
comprises
nitrogen, CO2, water vapor, oxygen, CO, nitrogen oxides (NO) and sulfur oxides
(S0x).
The combustion gases can be obtained by direct steam generation (DSG),
reducing the
steam-oil ratio and improving economic recovery.
[0070] "Hydrocarbon solvent" refers to a chemical consisting of carbon and
hydrogen
atoms which is added to another substance to increase fluidity and/or decrease
viscosity. A
hydrocarbon solvent, for example, can be added to a fossil fuel deposit, such
as a heavy oil
deposit or bitumen, to partially or completely dissolve the material, thereby
lowering the
resultant mixture's viscosity and enabling and enhancing the recovery of the
mixture. The
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hydrocarbon solvent can have, for example, 1 to 12 carbon atoms (C i¨C12) and
includes,
for example, butane, propane and hexane. The hydrocarbon solvent can be
introduced into
a petroleum deposit as a gas or as a liquid. Under the pressures of the
petroleum deposit,
the hydrocarbon solvent may condense from a gas to a liquid, especially if the
hydrocarbon
solvent has 2 or more carbon atoms.
[0071] "Cumulative steam-oil ratio" or "cSOR" refers to the ratio of
cumulative injected
steam (expressed as cold water equivalent, CWE) to cumulative petroleum
production
volume. The thermal efficiency of SAGD is reflected in the cSOR. Typically, a
process is
considered thermally efficient if its SOR is less than 3, such as 2 or lower.
A cSOR of 3.0
to 3.5 is usually the economic limit, but this limit can vary project to
project.
[0072] "Steam chamber", "vapor chamber" or "steam vapor chamber" refers to the
pocket
or chamber of gas and vapor formed in a geological formation by steam
injection and
includes the SAGD or SAGP process. A steam chamber can be in fluid
communication
with one or more injection wells, for example, two injection wells. During
initiation of a
SAGD process, overpressurized conditions can be imposed to accelerate steam
chamber
development, followed by prolonged underpressurization to reduce the steam-to-
oil ratio.
Maintaining reservoir pressure while heating advantageously minimizes water
inflow to
the heated zone and to the wellbore. When petroleum is continuously recovered
and the
cSOR is generally under 4, a steam chamber has likely formed. A cSOR of
generally less
than 4 implies that heat from the injected steam reaches the petroleum at the
edges of the
chamber and that the mobilized bitumen is flowing under gravity to the
production well.
[0073] "Mature Chamber" refers to a well-developed chamber (such as a well-
developed
steam chamber) in which the petroleum deposit (reservoir) has been
significantly depleted
or a desired residual oil saturation has been achieved. In one embodiment,
residual oil
saturation is reduced to the point where economic recovery can no longer be
achieved.
Once oil recovery is no longer economic, the mature chamber has typically
reached the top
of the hydrocarbon formation being produced for the reservoir interval,
diameter, width
and/or length. The mature chamber may be limited by the shape of the
hydrocarbon
formation, structures within the formation, design of the oil recovery system,
land
ownership, or a combination of factors.
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[0074] "Recovery" refers to extraction of petroleum from a petroleum deposit
or
hydrocarbon-containing layer within a geologic formation.
[0075] "EOR" refers to enhanced oil recovery techniques, including those set
forth in
Table 1 below.
TABLE 1- EOR Techniques
CSS Cyclic Steam Stimulation or "huff and puff." Steam is
injected into
a well at a temperature of 300-340 C for a period of weeks to
months. The well is allowed to sit for days to weeks to allow heat
to soak into the formation, and, later, the hot oil is pumped out of
the well for weeks or months. Once the production rate falls off,
the well is put through another cycle of steam injection, soak and
production. This process is repeated until the cost of injecting
steam becomes higher than the money made from producing oil.
Recovery factors are around 20 to 25%, but the cost to inject steam
is high.
SAGD Steam Assisted Gravity Drainage uses at least two
horizontal
wells--one at the bottom of the formation and another about 5
meters above it. Steam is injected into the upper well, and the heat
reduces the viscosity of the heavy oil. This allows the heavy oil to
drain by gravity into the lower well, where it is pumped to the
surface. SAGD is cheaper than CSS, allows very high oil
production rates, and recovers up to 60% of the oil in place.
FA-SAGD Foam assisted SAGD uses surfactant solution co-injected,
continuously or intermittently, with steam into a reservoir to
generate steam foam in place with the typical SAGD well-pair
configuration. High flow resistance is generally developed in the
interwell region that makes steam trap control much easier to
achieve. The process may divert steam flow into low permeability
zones.
VAPEX Vapor Extraction Process is similar to SAGD, but instead of
steam,
hydrocarbon solvents are injected into an upper well to dilute
heavy oil and enables the diluted heavy oil to flow into a lower
well.
ISC In situ combustion involves a burning of a small amount of
the oil
in situ, the heat thereby mobilizing the heavy oil.
THAI Toe to Heel Air Injection is an ISC method that combines a
vertical
air injection well with a horizontal production well. The process
ignites oil in the reservoir and creates a vertical wall of fire moving
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from the "toe" of the horizontal well toward the "heel", which
burns the heavier oil components and upgrades some of the heavy
bitumen into lighter oil right in the formation. Fireflood projects
are not extensively used due to the difficulty in controlling the
flame front and a propensity to set the producing wells on fire.
However, the method uses less freshwater, produces 50% less
greenhouse gases, and has a smaller footprint than other production
techniques.
COGD Combustion Overhead Gravity Drainage is another ISC method
that employs a number of vertical air injection wells above a
horizontal production well located at the base of the bitumen pay
zone. An initial Steam Cycle similar to CSS is used to prepare the
bitumen for ignition and mobility. Following that cycle, air is
injected into the vertical wells, igniting the upper bitumen and
mobilizing (through heating) the lower bitumen to flow into the
production well. It is expected that COGD will result in water
savings of 80% compared to SAGD.
EM A variety of electromagnetic methods of heating oil in situ
are also
being developed.
RF Radio Frequency heating of heavy oil/bitumen/heavy oil
reservoirs
to decrease the viscosity of the oil allowing it to flow.
Resistive Heating Generating heat by resistance methods to heat the heavy
oil/bitumen allowing it to flow and be produced.
Gas Injection A variety of gas injection methods are also used or being
developed, including the use of cryogenic gases.
CHOPS Cold Heavy Oil Production with Sand
Combo Any of the above methods can be used in combination.
[0076] "Foam" refers to a foam, colloidal dispersion, or gel. "Foaming agent"
means an
additive to water used to generate foam either above the surface before
injection or sub-
surface using a mechanical or natural mixing method. The additive can include,
but is not
limited to, colloidal foams, aerosols, hydrosols, emulsions, or dispersions.
[0077] "Blowdown" or "Blowdown Operations" refers to the final stage of
production
where steam is injection in the recovery processes ceases, is reduced, or is
replaced by
another injectant such as a non-condensable gas. "Blowdown" is initiated when
the
economics of the process no long support the instantaneous steam oil ratio, or
the desired
recovery factor has been achieved.
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[0078] The use of the word "a" or "an" when used in conjunction with the term
"comprising" in the claims or the specification means one or more than one,
unless the
context dictates otherwise.
[0079] The term "about" means the stated value plus or minus the margin of
error of
measurement or plus or minus 10% if no method of measurement is indicated.
[0080] The use of the term "or" in the claims is used to mean "and/or" unless
explicitly
indicated to refer to alternatives only or if the alternatives are mutually
exclusive.
[0081] The terms "comprise," "have," "include," and "contain" (and their
variants) are
open-ended linking verbs and allow the addition of other elements when used in
a claim.
[0082] The present invention is exemplified with respect to in situ processing
of a heavy
oil/and bitumen reservoir using at least one injection well and one production
well.
However, the systems and methods are exemplary only, and the invention can be
broadly
applied to any fossil fuel deposit and different numbers and combinations of
injection and
production wells can be used. The following examples are intended to be
illustrative only,
and not unduly limit the scope of the appended claims.
DESCRIPTION OF EMBODIMENTS OF THE INVENTION
[0083] The present invention is directed to a system and method where foams
are used
(instead of, or in addition to, NCG) to maintain pressure in a mature chamber
during
blowdown operations of a SAGD process. Foaming agents such as metal
carbonates,
bicarbonates and hydroxides, surfactants or any other colloidal foams,
aerosols, hydrosols,
emulsions or dispersions can be utilized. This process can be used in
conjunction with other
known art, such as heat scavenging in the steam chamber, or enhanced oil
recovery utilizing
foams, to displace oil in the steam chamber.
[0084] While NCG can be used to maintain or enhance pressure in a SAGD
chamber, the
inventors of the present invention have recognized that it has several
drawbacks. Two key
drawbacks are as follows:
[0085] (A) First, field operations where NCGs are injected into SAGD steam
chambers
have demonstrated that a significant amount of the injected NCG is produced
back with
the bitumen. In addition, NCG may also migrate into adjacent steam chambers
where high
concentrations of NCG may occur at the drainage interface. This NCG may act as
an
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insulator, reducing interface temperature, thus negatively impacting bitumen
drainage rates
in adjacent wells. Thus, the use of NCG requires not only a capital investment
to inject the
NCG, but also additional capital is required to hand and treat the increased
produced gas
volumes.
[0086] (B) Second, NCG-based pressure maintenance may cause interference with
nearby
steam chambers including less mature steam chambers adjacent to the well-
pairs/pads
being blowdown. This interference may take the form of material and energy
flow in or
out of the nearby steam chamber resulting in negative effect on either
production rates of
bitumen or the steam-to-oil ratio of less mature chamber in the formation.
[0087] While steam-foams have been used for diversion processes (where the
foam blocks
or diverts the steam into other parts of the reservoir for example during
steam flood
operations), the inventors of the present invention have recognized that the
use of foams in
a mature chamber during a blowdown process may further enhance recovery within
the
depleted steam chamber and to allow higher pressure operations to be
maintained in
adjacent less mature steam chambers enhancing one or more of: thermal
performance,
improving SOR, reducing NCGs use during blowdown while improving ultimate
recovery.
[0088] The foam can be generated on the surface or sub-surface and can be
injected into the
reservoir by utilizing existing horizontal injectors, delineation wells,
and/or new vertical or
horizontal wells. In one embodiment, surfactant/foaming agent solutions could
also be
injected together with a non-condensable gas or could be injected
intermittently dovvnhole to
generate foam in situ.
[0089] Water-gas foams have been used historically in conventional oil and gas
production. Aerated drilling fluids have been used for workover and remedial
well
operations. In addition, foams have been utilized to modify intervals of gas
injection in
stratified formations. They have also been used to prevent leakage through cap-
rock in gas
storage reservoirs. Some operators have attempted to use foams as a secondary
recovery
method, though applications in this realm are limited. Foams have also been
used in
production wells to mitigate water and/or gas inflow. These applications take
advantage of
the properties of foam and its behavior in a porous media.
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[0090] FIG. 2 contains an illustration of a mature chamber 201 at blowdown
nearby two
adjacent immature SAGD steam chambers 204. Each of these steam chambers has
both an
injection well 202 and a production well 203.
[0091] Traditionally, blowdown operations can include replacing some or all of
the steam
injection with the injection of a non-condensable gas (NCG) in order to
maintain steam
chamber pressure. At blowdown an incremental amount (such as 5% to 10%) of the
remaining original oil in place (00IP) in the mature chamber can be recovered.
Many
operators have suggested the use of non-condensable (i.e., air, methane, CO2,
etc.) gas
during the blowdown phase, to maintain steam chamber pressure and
temperatures, while
enhancing bitumen recovery and production rates. FIG. 3 illustrates a mature
SAGD steam
chamber 201 at blowdown with traditional NCG injection 301 from the injection
well 202
in steam chamber 201. Oil at the condensation front/drainage interface 302 is
shown in a
mature chamber 201 and immature steam chambers 204.
[0092] The present invention is a system and method for maintaining reservoir
pressure
in a mature reservoir chamber by utilizing a foam within the steam chamber,
such as shown
in FIG. 4. This can be accomplished by injecting steam or hot water and one or
more of
the following: foaming agents, surfactants, alkali, any other colloidal foams,
aerosols,
hydrosols, emulsions or dispersions with or without a non-condensable gas,
into the
reservoir. Reference number 401 show the propagation of the foam within the
mature
chamber 201. The foam can either be created in situ or the foam could be
created at surface, or
within the wellbore at the formation depth and injected into the steam
chamber. The horizontal
portion of the SAGD injector 202 can be used to inject the foam into the
mature chamber 201 as
well as, new wells or existing vertical completions that penetrate the mature
chamber.
[0093] The mechanisms involved in embodiments of the present invention can be
the
formation of foam by means of a surfactant, water, and non-condensable gas;
which will
form the foam that migrates and fills the mature chamber 201. The foam will
migrate to
the condensation face 302 of the mature chamber 201, thus occupying
significant pore
volume within the mature chamber 201. The foam continuously collapses and is
regenerated, with the mobile gases within the mature chamber 201, and is
continuously
replaced as surfactant is produced back with the production fluids at the
drainage interface
302.
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[0094] Due to heterogeneities in the reservoir, a mature chamber and immature
steam
chambers may communicate (such as at interactions 501 and 507 as shown in FIG.
5). The
NCG may have communication paths for flow (as shown in interactions 507) from
mature
chamber 201 into the immature steam chambers 204. Alternatively, or
additionally, steam
injected into the immature chamber may flow through interaction 501 into the
mature
chamber 201. The use of foam in the mature steam chamber will mitigate these
interactions 501 and 507 improving recovery and thermal efficiency of the more
immature
steam chamber.
[0095] The foam can be utilized for pressure maintenance only, or used in
combination with
other technologies such as heat scavenging (such as described in U.S. Patent
App!. Publ. No.
2014/0216739, "Heat Scavenging Method for Thermal Recovery Process," published
August 7, 2014, to Brown et al.). Other embodiments of the present invention
may utilize
the foam as a secondary/tertiary recovery method within the steam chamber to
displace
trapped bitumen/heavy oil, driving it to the condensation front/drainage
interface.
[0096] Gases that can be co-injected with water and the (chemical) agent(s)
(i.e.,
surfactants) include, but are not limited to nitrogen, methane, carbon
dioxide, propane,
butane, natural gas, and flue gas. Gases may come in the form of a gas/liquid
mixture,
including but not limited to natural gas liquids containing propane, butane,
pentane, and
hexane.
[0097] The chosen (chemical) agent(s) to create foam can have some or all of
the following
characteristics: (a) thermal and chemical stability at high temperatures at
which these
thermal recovery processes are operated, (b) low density (such as foams having
densities
between about 0.0006 g/cm3 and about 0.0770 g/cm3 (c) the ability to withstand
the
salinity/divalent cations in the particular formation brine, (d) low
adsorption onto rock/clay
surfaces in the particular reservoir, (f) the ability of not negatively
impacting surface
treating, (g) the ability to be effective at the particular reservoir brine
pH, (h) low cost and,
(i) neutral or positive impact on the value of the produced bitumen (for
example, lower
TAN, lower sulfur content, etc.).
[0098] In some embodiments, a foam/colloidal dispersion/gel is used that can
be
temperature and/or oil saturation dependent and can form in situ at the
desired temperature
and/or oil saturation.
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[0099] Thermally and chemically
stable, non-ionic, anionic, cationic and
amphoteric/zwitterionic surfactants that can be used in the present invention
include, but
are not limited to, alkyl benzene (aromatic) sulfonates, alpha/internal olefin
sulfonates,
alkyl aryl sulfonates and alkoxy sulfates. Alkaline metal carbonates,
bicarbonates and
hydroxides can include, but are not limited to sodium carbonate, sodium
bicarbonate,
sodium hydroxide, potassium carbonate, potassium bicarbonate, potassium
hydroxide,
magnesium carbonate, calcium carbonate and sodium metaborate can also be used
as
the foaming agent. The surfactant and/or alkali concentration can be varied
and determined
for the particular rock/oil/brine system. Other colloidal foams, aerosols,
hydrosols,
emulsions or dispersions that create a suitable foam can also be utilized in
embodiments of
the present invention.
[0100] As noted before, the foam can be generated at the surface or sub-
surface. Sub-
surface methods for generating foam include but are not limited to using a
downhole static
mixer, foam generation through a perforation in the well, natural mixing in
the well, in situ
foam generation in the reservoir, temperature dependent foam generation, time-
delayed
foam generation, and chemical/oil saturation dependent generation.
[0101] Foam and/or foaming agents can be injected continuously with steam or
can be
injected in slugs with or without a gas. Accordingly, injection of foam can be
implemented
as a primary or secondary operating strategy. Furthermore, the method of the
present
invention can be employed in many thermal recovery processes, including but
not limited
to, steam-drive, CSS, SAGD and SAGD lateral-drive processes, and expanding
solvent-
SAGD (ES-SAGD)/solvent assisted process (SAP).
[0102] In the SAGD process, bitumen (or oil) is produced until the
instantaneous steam-
to-oil ratio reaches a point in which economic operations can no longer be
achieved using
steam or solvent injection. As steam and solvent injection decreases, the SAGD
well-pair
transitions to "blowdown." At blowdown, the steam chamber is mature and the
addition of
foam and/or foaming agents begins. Thus, such changes in chamber growth, oil
production
rate and CSOR may be used as a threshold for transitioning from a steam-
injection
operation to a blowdown operation. Embodiments can include (a) early blowdown
with
NCG and foam (e.g., no steam after 40% recovery factor is reached and (b)
combined with
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staged NCG injection (e.g., 30% NCG by volume after 1 year, 60% NCG by volume
after
70% recovery factor, etc.) in combination with foam.
[0103] The Applicants have found that steam chamber maturity is met when any
one or
some combination of factors are met including: i) the steam chamber has ceased
substantial
growth or expansion (e.g./ when the chamber reaches the overburden), ii) when
the oil
production rate by the steam-injection process has substantially declined,
iii) when the
cumulative steam-to-oil ratio (CSOR) has substantially increased or iv) where
the recovery
factor has reached a specified threshold v) project development or regulatory
requirements
necessitate initiation of blowdown. This can include, but is not limited to,
adjacent
resource development or mechanical/geomechanical failures requiring blowdown
initiation, or vi) where the field-wide optimum for steam distribution
indicates requires
steam injection to decrease.
101041 Transition conditions may be selected based on a number of
considerations and
factors as discussed herein. Transition conditions may be selected such as to,
for example,
achieve a desirable balance between various factors and considerations
including
engineering trade-offs and economic considerations, such as vapor chamber
growth,
production performance, costs, and environmental factors. The transition
condition may be
selected to ensure that the performance or production threshold discussed
earlier has been
reached. The transition condition may be selected based on operation
experience in similar
projects at other well pads, or projections according to modeling or
simulation calculations,
or combination thereof. The transition condition may also be adjusted or
selected based on
the market conditions including production costs, material costs, and the
market values of
produced or recovered materials including market oil prices and solvent
prices. For
example, the transition conditions can include one or more of the following:
vapor chamber
growth, production performance, a pre-selected pressure below native reservoir
pressure
of the formation, a pre-selected pressure of an adjacent formation, a pressure
below a pre-
selected pressure of the formation, an environmental factor, a market
condition, production
costs, material costs, market price for hydrocarbons, and the market price for
solvents.
[0105] The present invention is thus able to maintain pressure within a mature
chamber by
filling the mature chamber volume with foam, once steam and solvent injection
is reduced,
ceased or replaced with foam, or foam and a non-condensable gas blowdown
operations
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begin. By filling the depleted chamber void space with foam, higher pressures
can be
maintained in the mature chamber, keeping the saturation temperature of water
existing
within the mature chamber elevated, and improving bitumen recovery and
production rates
during the blowdown process. By maintaining pressure within the depleted steam
chamber,
offset it is predicted that, nearby less mature steam chambers may be operated
at higher
pressures, mitigating leak-off into the lower pressure depleted mature
chambers, improving
their production performance, production rates, thermal efficiency (steam oil
ratio) and
ultimate bitumen recovery.
[0106] The present invention further overcomes issues with operating adjacent
steam
chambers at different pressures and different stages of their recovery life.
The present
invention allows each chamber to be operated such that recovery is
enhanced/maximized
and thermal efficiency (i.e., SOR) is optimized. The present invention also
mitigates costly
gas handling transportation costs, and costly facilities required to treat the
incremental gas
volumes caused by NCG blowdown.
[0107] In one embodiment, chemicals suitable to act as foaming agents in the
present
invention are Alpha Olefin Sulfonates (AOS), Alkylbenzene Sodium Sulfonates
(ABS) or
Alkyl Toluene Sulfonate (ATS) co-injected with methane to generate in-situ
foam. The
potential benefits related to the addition of these chemicals in the blowdown
stage of
operation may include: helping to eliminate facility constraints, improve
project
economics, reduce NCG injection and production during blowdown and maintain
reservoir
pressure with less NCG injected. In a further embodiment, the chemicals
suitable to act as
foaming agents are C 0 to C30- Alpha Olefin Sulfonates, toluene and benzene
based
chemicals.
[0108] The Applicants recognized that the results of the foamibility and
absorption tests
demonstrated that for each compound tested that would generate foam and
demonstrate
thermal stability at reservoir conditions, the Applicant could select
different correlations of
properties for the chemicals tested. Therefore, the in-situ generated foam
could have
customized properties based on the surfactant injected. For example, an agent
could have
lower foamibility but also lower absorption to the rock relatively to other
chemicals. These
properties enable such a foam to be generated closer to the injection well
with a lesser
degree of spreading at the higher vertical sections of the previously
developed steam
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chamber by SAGD. Furthermore, a chemical with high foamibility properties
could be
utilized in spreading to higher sections of the porous media and therefore
having slower
decay rate, thus helping the economics of the project by reduced chemicals
requirement.
EXAMPLES
[0109] Example 1 ¨ Chemical Screening
[0110] Tests were run to examine the solubility, thermal stability, and static
adsorption of
12 different compounds. Generally, the chemicals tested fell broadly into the
categories of
Alpha Olefin Sulfonate (AOS), Alkylbenzene Sodium Sulfonates (ABS) or Alkyl
Toluene
Sulfonate (ATS), toluene and benzene based chemicals.
[0111] Solubility analysis: Chemical solutions were made for each compound
using two
brines: reservoir brine and DI water. Once the solutions were prepared, they
were
evaluated for their chemical solubility condition. The chemical solution was
0.5 wt% (5000
ppm) in all the experiments.
[0112] Once the surfactant solutions were prepared their concentration was
checked by
HPLC immediately after preparation and 24 hours later to evaluate the
concentration of
dissolved chemicals as a function of salinity of the brine. The solutions were
also inspected
visually. Chemical solutions that are fully soluble at room temperature are
expected to be
more soluble at steam conditions. If the solution is not clear at room
temperature, it was
tested at higher temperatures (between 80 C to 130 C) to determine if the
solubility of the
chemical improved.
[0113] Thermal Stability: Thermal stability tests were conducted to determine
the degree
of breakdown of the chemical structure on exposure to steam. In order to
evaluate this, the
chemical solutions were evaluated for active material content at time zero as
well as at 7
days and at 21 days, to track the activity of the molecules. Thermal stability
tests were
performed using the 0.5 wt% chemical samples prepared in injection brines. The
chemical
solutions were placed in a high pressure/high temperature cell at atmospheric
conditions.
One sample of the solution was kept for direct evaluation, as "time-zero"
sample. After the
elapsed testing period, the sample was removed from the high temperature/high
pressure
conditions, cooled down and collected for evaluation.
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[0114] Static adsorption: Static absorption tests were conducted using a
reservoir rock
sample. The tests conducted were comparative and only provide relative
adsorption values
in comparison to the other chemicals tests. Disaggregated reservoir rock and
chemical
solutions were brought in contact for 72 hours under steam conditions. High
pressure and
high temperature flasks were used such that the surfactant solution had enough
contact with
the sand grains to complete adsorption. The surfactant adsorption was
determined by the
material balance of surfactant concentration remaining in the supernatant.
[0115] A summary of the results is shown in Table 2 indicating which of the
chemicals
tests demonstrated solubility under steam conditions, thermal stability at
high temperature
and high pressure, and a high degree of adsorption.
TABLE 2
Thermal Static
No. Solubility Stability Adsorption
Al X X X
A2 X X X
D2
DI
El X X
E2 X X X
F2 X X X
F1 X X X
B1 X X X
B2 X X
C2
Cl X X
[0116] Example 3 ¨ Mobility Reduction Tests
[0117] The mobility reduction factor or MRF is an indication of foam strength,
half-life,
and ability to slow down the movement of injected gas in the reservoir.
[0118] A core flood test was conducted to measure the mobility reduction
factor (MRF) in
porous media. The test was designed to mimic reservoir conditions and evaluate
the
methane rate reduction based on the foam generated. The MRF value is then
integrated into
a reservoir simulation to evaluate the impact on the overall blow down
process.
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[0119] As part of the test, various steam quality inputs were examined in
order to generate
the foam. Having a low steam quality requirement in the foam generation
process during
the blowdown phase could further enhance the environmental benefit of this
technology.
Initial simulations showed (Figure 7) that a chemical demonstrating an MRF
value of a 50
could potentially reduce methane production by 50% while maintaining similar
oil
production rates of a to typical blowdown process.
The foam model used applied representative values for the concentration of the
foaming
component, concentration of the foaming component to achieve maximum foam,
maximum oil saturation at which the foam is assumed stable, capillary number,
scaling and
reduction factors. The reservoir simulation model for SAGD included water, oil
and
methane properties as well as solid components such as shale, cement carbon
steel for
piping and sand to account for thermal conductivity and flow. The reservoir
modeled was
a 3D simulation with representative permeability, porosity and initial
saturations to Foster
Creek McMurray Formation. Oil saturation in clean sands determined from core
and open
hole log data typically ranges from 80-90%. The injection control mechanism
included
sources along the injection casing to simplify the model and the production
assumed 10 t/d
of gas phase rate passing via the ESP pump. The injection during SAGD and blow
down
stages was controlled on 3.2 mPa pressure constraint. In the model the blow
down stage
was invoked after 850 days and a foam model was integrated. The decline in
methane
production was observed as the MRF value increased suggesting a high
correlative
behavior between the methane rate and MRF value. The presence of foam showed
reduction in the mobility of the gas in the presence of aqueous and oleic
phases though not
effecting the production of oil via the producing well.
[0120] Example 4 ¨ Foam Height
[0121] Foam height tests were conducted to analyze the height of foam
generated and the
decay rate of the foam.
[0122] The foam height tests were performed in a laboratory for the 12
chemical solutions
described in Example 1 at 200 C and at a pressure of 3000 kPa. Foam was
generated in a
visual cell with a known chemical concentration. The height of the foam and
how quickly
it fell was measured. Foam height was increased to the point which the rate of
foam
generation was near equal to the rate of foam collapse. At this point the flow
of CH4 was
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stopped and foam decay rate measured. This test was conducted with and without
the
presence of reservoir oil. Foam height and how quickly it falls is an
indication of the quality
of foam generated in the reservoir. The test conducted was relative in order
to compare the
various chemical foams to each other. Ideally, a surfactant solution should
rapidly produce
a tall foam and have a slow rate of foam collapse after CH4 injection is
stopped.
[0123] The results are shown in Figure 8. Chemical solution agents A,B,C
yielded the
most competitive results for the steam condition tested in terms of for
production of foam
in the bulk medium. Agents Cl and C2 produced same height of foam in about 20
minutes.
Agents B1 and B2 produced same foam height at a slower rate (about 27
minutes), with
Agent Cl collapsing a bit slower after CH4 injection was stopped. From Agents
Al and A2
products, the rate of foam generation is almost the same for both, but the
rate of foam
collapse is slower for agent Al.
[0124] Example 5 ¨ Blowdown
[0125] A 1/2 well pair element of symmetry model was constructed to predict
the effects of
the addition of foam during blowdown on reservoir performance and gas
production. A
23m thick reservoir model was created that uses standard oilsands reservoir
parameters. A
800m long SAGD well pair was used for the cases. Under SAGD mode, the well
pair was
operated for 10 years and then methane gas was introduced with steam to
blowdown under
a co-injection scheme to the final shut in of the well at 18 years. It is
visible from the plot
shown in Figure 9 that the first slug of methane (3,500 m3/d) caused
approximately 500
m3/d of gas to be produced. The second slug of co-injected methane, at 1,300
m3/d caused
about 300 m3/d of the injected gas to be produced back. The high volume of
injected gas
being produced back causes a significant efficiency reduction at the
bottomhole pump at
the production well.
[0126] The effect of the adding surfactant to the co-injection scheme with
methane and
steam to create a foam in the reservoir was then modelled. Surfactant at 2,000
ppm (w
surfactant / w steam) was added after 10 years when methane co-injection
commenced. It
was estimated that this volume of surfactant would produce a foam mobility
reduction
factor of 25. Based on these inputs, 15% less methane is required to be
injected and 50%
less methane is produced back at the production well, a substantial reduction.
It is evident
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that the foam is significantly reducing the relative permeability to gas in
the reservoir
simulation.
[0127] While embodiments of the invention have been shown and described,
modifications
thereof can be made by one skilled in the art without departing from the
spirit and teachings
of the invention. The embodiments described and the examples provided herein
are
exemplary only, and are not intended to be limiting. Many variations and
modifications of
the invention disclosed herein are possible and are within the scope of the
invention.
Accordingly, other embodiments are within the scope of the following claims.
The scope
of protection is not limited by the description set out above, but is only
limited by the
claims which follow, that scope including all equivalents of the subject
matter of the
claims.
REFERENCES
[0128] U.S. Patent No. 4,344,485, "Method For Continuously Producing Viscous
Hydrocarbons By Gravity Drainage While Injecting Heated Fluids," issued August
17,
1982, to Butler.
[0129] U.S. Patent Appl. Publ. 2012/0247760, "Dual Injection Points IN SAGD,"
published October 4, 2012, to Wheeler et al.
[0130] U.S. Patent Appl. Publ. No. 2014/0190689, "Use of Foam with In Situ
Combustion
Process," published July 10, 2014, to Warren et al.
[0131] U.S. Patent Appl. Publ. No. 2014/0216739, "Heat Scavenging Method for
Thermal
Recovery Process," published August 7, 2014, to Brown et al.
[0132] U.S. Patent Appl. Publ. No. 2015/0159476, "Oil Recovery with Insulating
Composition," published June 11, 2015, to Warren etal.
[0133] U.S. Patent Appl. Publ. No. 2015/0198027, "Anti-Retention Agent in
Steam-
Solvent Oil Recovery," published July 16, 2015, to Wickramathilaka etal.
[0134] Butler et al., "The Gravity Drainage of Steam-heated Heavy Oil to
Parallel
Horizontal Wells," Petroleum Society of Canada. doi:10.2118/81-02-07 (1981).
[0135] Zhao et al., "Numerical Study and Economic Evaluation of SAGD Wind-Down
Methods," Journal of Canadian Petroleum Technology, 42(1): 53-57 (2003).
[0136] Li et al., "Chemical Additives and Foam to Enhance SAGD Performance,"
SPE
Canada Heavy Oil Technical Conference, 9-11 June, Calgary, Alberta, Canada
(2015).
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[0137] The disclosures of all patents, patent applications, and publications
cited herein are
hereby incorporated herein by reference in their entirety, to the extent that
they provide
exemplary, procedural, or other details supplementary to those set forth
herein.
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