Note: Descriptions are shown in the official language in which they were submitted.
Y M.
IN-SITU OIL UPGRADING VIA DEASPHALTING
3165179
45 pages
Inventors:
= Amos Ben-zvi
= Nashaat Nassar
= Paulina Morasse
= Lukemon Adetunji
FIELD OF THE INVENTION
[0001] The present invention relates to production of hydrocarbons from
a subterranean
reservoir using steam injection to enhance production, such as in a SAGD well
system, and
more particularly to use of a particle, which may be a nanoparticle, to adsorb
asphaltenes in
the subterranean reservoir to upgrade the hydrocarbons in-situ in the
subterranean reservoir.
BACKGROUND OF THE INVENTION
[0002] In-situ hydrocarbon production.
[0003] Hydrocarbons can be produced from a subterranean reservoir by hot water
or steam
(collectively referred to as steam) injection to the reservoir. This is called
in-situ production.
In general, steam injection is a technique for enhancing production of
hydrocarbons from a
subterranean reservoir to the surface by injecting steam into a reservoir to
reduce the viscosity
of hydrocarbons in the reservoir, so that the hydrocarbons flow more readily
to a producing
well.
[0004] Steam assisted gravity drainage (SAGD) is an example of steam
injection that
involves injecting steam from the surface into an upper horizontal well (an
injection well)
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disposed in the reservoir above a lower horizontal well (a production well).
The injected steam
exits the injection well and rises in the reservoir to form a steam-saturated
zone, which is
conceptualized as a "steam chamber", where hydrocarbons are heated by the
steam and thereby
reduced in viscosity. The reduced-viscosity hydrocarbons drain downward by
gravity into the
production well, and are produced to the surface.
[0005] Asphaltenes in produced hydrocarbons.
[0006] Hydrocarbons produced by steam injection may be heavy oils.
Generally, heavy oil
has a high asphaltene content. Asphaltenes are complex polar aromatic and high
macromolecules. Generally, asphaltenes are defined as the n-heptane insoluble
and
benzene/toluene soluble fraction of crude oil including heavy oil.
[0007] Asphaltenes create problems during production and handling of
heavy oil. The
viscosity of heavy oil is quite high and equipment fouling can occur due to
the presence of
asphaltenes in the oil.
[0008] Generally, upgrading is required to remove the asphaltenes. If
heavy oil could be
reliably upgraded in-situ, before being produced to surface, this would offer
a significant
benefit to producers.
SUMMARY OF THE INVENTION
[0009] In one aspect, the present invention comprises a method for
producing hydrocarbons
from a subterranean reservoir.
[0010] In particular, a broad aspect of the invention is directed to a
method for producing
hydrocarbons from a subterranean reservoir, the method comprising the steps
of: injecting
steam and injecting a silica-based asphaltene-sorbent into the subterranean
reservoir; allowing
the silica-based asphaltene-sorbent to adsorb asphaltenes from the
hydrocarbons, thereby
producing upgraded hydrocarbons and asphaltenes adsorbed to the silica-based
asphaltene-
sorbent in the subterranean reservoir; and producing the upgraded
hydrocarbons, without
producing the asphaltenes adsorbed to the silica-based asphaltene-sorbent.
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BRIEF DESCRIPTION OF THE DRAWINGS
[0011] In the drawings, like elements may be assigned like reference
numerals. The
drawings are not necessarily to scale, with the emphasis instead placed upon
the principles of
the present invention. Additionally, each of the embodiments depicted are but
one of a number
of possible arrangements utilizing the fundamental concepts of the present
invention.
[0012] Fig. 1 is a flow chart of a first embodiment of a method of the
present invention, for
production of hydrocarbons from a subterranean reservoir using a steam
assisted gravity
drainage (SAGD) well system, and using asphaltene-sorbent particles to adsorb
asphaltene in
the subterranean reservoir.
[0013] Fig. 2 is a schematic depiction of a SAGD well system that may be
used in
implementing the method of Fig. 1, along with asphaltene-sorbent particles
attached to the
subterranean reservoir.
[0014] Figs. 3A to 3F are schematic depictions of sequential stages of
the method of Fig.
1.
[0015] Fig. 3A shows a subterranean reservoir in relation to an injection
tubing and
production tubing of a SAGD well system.
[0016] Fig. 3B shows injection of a carrier fluid mixed with asphaltene-
sorbent particles
into the subterranean reservoir via the production tubing.
[0017] Fig. 3C shows injection of steam mixed with asphaltene-sorbent
particles into the
subterranean reservoir via the injection tubing.
[0018] Fig. 3D shows asphaltene-sorbent particles attached to sand in
the subterranean
reservoir, and adsorbing asphaltene molecules in the subterranean reservoir.
[0019] Fig. 3E shows hydrocarbons draining by gravity into the
production tubing, while
the asphaltene-sorbent particles with adsorbed asphaltene remain attached to
the subterranean
reservoir.
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[0020] Fig. 3F shows production of hydrocarbons to the surface via the
production tubing
string.
[0021] Fig. 4 is a schematic representation of the 1-D sand bed SAGD
setup for the
experiments.
[0022] Fig. 5 is a chart showing recovery performance from nanoparticles
and steam co-
injection into an oil sand packed bed at the temperature of 230 C.
[0023] Fig. 6 is a chart showing the C7-asphaltene content in the
produced oil in the presence
of nanoparticles.
DETAILED DESCRIPTION OF EMBODIMENTS OF THE INVENTION
[0024] Definitions.
[0025] The present invention relates to production of hydrocarbons from
a subterranean
reservoir using a hot water or steam, collectively referred to as steam,
injection operation with
in-situ upgrading of the produced hydrocarbons using silica (SiO2) as an
asphaltene-sorbent
particulate.
[0026] Any term or expression not expressly defined herein shall have its
commonly
accepted definition understood by a person skilled in the art. As used herein,
the following
terms have the following meanings.
[0027] "Subterranean reservoir" refers to a subsurface body of rock
having porosity and
permeability that is sufficient to permit storage and transmission of a liquid
or gaseous fluid.
[0028] "Steam chamber", in the context of a SAGD well system, refers to a
region a
subterranean reservoir that is in fluid and pressure communication with an
injection well and
that is subject to depletion of hydrocarbons, by gravity drainage, into a
production well that is
disposed parallel and below the injection well.
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[0029] "Steam injection operation" refers to any method of producing
hydrocarbons from
a subterranean reservoir that involves injection of heated water, usually in
the steam phase,
into the subterranean reservoir to decrease the viscosity of the hydrocarbons,
so that the
hydrocarbons flow more easily in the subterranean reservoir. Without
limitation, steam
.. injection operations include methods known in the art as steam assisted
gravity drainage
(SAGD), steam flooding or steam drive, and cyclic steam stimulation (CSS).
[0030] "Hydrocarbons" refer to hydrocarbon substances naturally
occurring in a
subterranean reservoir. Hydrocarbons may be in liquid, gaseous, or solid
phases. Without
limitation, hydrocarbons may include "heavy oil", referring to hydrocarbons
having a mass
density of greater than about 900 kg/m3under natural reservoir conditions.
Without limitation,
hydrocarbons and heavy oil may also include "bitumen" having a mass density of
greater than
about 1,000 kg/m3under natural reservoir conditions, and existing in semi-
solid or solid phase
under natural reservoir conditions. It will be understood that "hydrocarbon
production",
"producing hydrocarbons" and like terms, as used herein, do not preclude co-
production of
non-hydrocarbon substances that may be mixed with hydrocarbons such as trace
metals, and
gases such as hydrogen sulfide that may be dissolved under natural reservoir
conditions, but
exist in a gaseous phase at surface conditions.
[0031] "Asphaltene" refers to the n-heptane insoluble and
benzene/toluene soluble fraction
of heavy oil. Asphaltenes are complex polar aromatic and high macromolecules.
[0032] "Asphaltene-sorbent particle" refers to a non-metal particle that
has an affinity for
asphaltene. In embodiments, this affinity may be based on principles of
adsorption ¨ i.e., the
asphaltene-sorbent particle physically adheres and/or chemically bonds to
asphaltene. In
particular, the asphaltene-sorbent particle of interest is a non-metal, in the
group called
metalloids. In one embodiment, a useful asphaltene-sorbent particle includes
silica (Sift).
Silica is found to have an excellent affinity for asphaltene, is
environmentally acceptable and
abundant. In embodiments, the asphaltene-sorbent particle has a maximum
dimension (e.g., a
diameter) less than about 1000 nm, more particularly less than 500 nm, more
particularly less
than 250 nm. In embodiments, the asphaltene-sorbent particle is a
"nanoparticle", which as
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used herein, refers to a particle that has a maximum dimension less than 100
nm. In
embodiments, a nanoparticle may have a maximum dimension less than 50 nm, and
more
particularly less than 25 nm.
[0033] Method.
[0034] Fig. 1 is a flow chart of a first embodiment of a method of the
present invention, for
production of hydrocarbons from a subterranean reservoir using a steam
assisted gravity
drainage (SAGD) well system, and using asphaltene-sorbent particles to adsorb
asphaltene in
the subterranean reservoir. By adsorption of the asphaltene, the hydrocarbons
become
upgraded in the reservoir, before they are produced to surface. Adsorption of
the asphaltene
improves the viscosity of the hydrocarbons and simplifies handling.
[0035] Fig. 2 is a schematic depiction of a SAGD well system that may be
used in
implementing the method of Fig. 1. SAGD well systems and their principle of
operation are
well known to persons skilled in the art. The following description is
provided to facilitate
understanding of the present invention. For simplicity of illustration, Fig. 2
omits various
equipment items (e.g., steam generators, surface pumps, downhole pumps,
sealing elements
and so forth) that are commonly associated with a SAGD well system. The SAGD
well system
includes a horizontal or deviated (i.e. non-vertical) leg of an injection well
200 including an
injection tubing 202, and a horizontal or deviated (i.e. non-vertical) leg of
a production well
204 including a production tubing 206, extending from the surface 208 into a
subterranean
reservoir 210. The production well 204 is parallel to the injection well 200,
and disposed below
the injection well 200. A surface pump (not shown) is used to inject steam (as
shown by hollow
arrows) into the injection tubing 202, which exits via openings thereof, and
through openings
(e.g., a slotted liner) of the injection, well 200 into a subterranean
reservoir to create a steam-
saturated zone referred to as the steam chamber 212. In the steam chamber 212,
the injected
steam heats the hydrocarbons and thereby reduces their viscosity. The reduced-
viscosity
hydrocarbons (as shown by solid arrows) drain downward by gravity through
openings (e.g.,
a slotted liner) of the production well 204, and into the production tubing
206. The
hydrocarbons are produced to the surface via the production tubing 206.
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[0036] Fig. 3A is a schematic depiction of the injection tubing 202 and
production tubing
206 of a SAGD well system in a subterranean reservoir 210 before steam
injection. The
subterranean reservoir contains hydrocarbons, as shown by hydrocarbon
molecules 214, and
asphaltene, as shown by asphaltene molecules 216.
[0037] Referring back to Fig. 1, at step 100, a mixture of steam and
asphaltene-sorbent
particles are injected, via the injection tubing string 202, into the
subterranean reservoir. That
is, asphaltene-sorbent particles are injected in the steam phase of the SAGD
operation. Particles
220 are injected with, for example, as a mixture with or sequentially before
or after, the steam of the
SAGD operation. Fig. 3C is schematic depiction of step 100, showing steam 218
mixed with
asphaltene-sorbent particles 220 being pumped into the subterranean reservoir
210. The
asphaltene-sorbent particles 220 can be suspended in the injected steam 218
even at relatively
low flow velocities of the injected steam, because of the small size of the
asphaltene-sorbent
particles.
[0038] In one embodiment, a carrier fluid may be employed for
facilitated carrying of the
particles. A useful carrier fluid is, for example, ethyl acetate.
[0039] In one embodiment, the injected mixture is asphaltene-sorbent
particles in steam
without any solvents added thereto. While solvents have been used for some in-
situ recovery
operations, their use in this process is best minimized and avoided to address
cost and
environmental considerations.
[0040] A variety of asphaltene-sorbent particles may be used in the present
invention to
adsorb asphaltene in the subterranean reservoir. In one embodiment, the
asphaltene-sorbent
particles are based on silica (SiO2). It will be evident that the asphaltene-
sorbent particles have
to have an affinity for asphaltenes either by physical adherence or by
chemical bonding. In
fact, silica has a high affinity for asphaltene at pressure and temperature
conditions in the
.. subterranean reservoir, and relatively little to no affinity for valuable,
non-asphaltene
hydrocarbons in the subterranean reservoir under those conditions.
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[0041] The selected asphaltene-sorbent particles may be capable of
adsorbing asphaltene
over the full range of temperatures expected to be encountered in the steam
chamber of a
SAGD well system, which typically ranges from about 15 C to about 300 C. In
particular
embodiments, the asphaltene-sorbent particles may have high affinity for
asphaltene at
temperatures of about 110 C or greater, more particularly of about 200 C or
greater, and even
more particularly, of about 230 C or greater, to about 300 C. In total,
silica is effective for
asphaltene removal at a range of temperatures including up to 300 C.
[0042] The asphaltene-sorbent particles should be sized so that they can
permeate through
the pores of the subterranean reservoir, without substantially impairing
transmission of a liquid
or gaseous fluid through the subterranean reservoir. A suitable size of
asphaltene-sorbent
particles may be selected having regard to the characteristics of a particular
subterranean
reservoir. As a non-limiting example, for subterranean reservoirs containing
heavy oil in
Alberta, Canada, a suitable maximum dimension (e.g., diameter) of asphaltene-
sorbent
particles may be less than about 1,000 nm, more particularly less than about
500 nm, and even
more particularly less than about 250 nm. In some embodiments, the asphaltene-
sorbent
particles may be nanoparticles ¨ i.e., particles having a maximum dimension
(e.g., diameter)
less than about 100 nm, more particularly less than about 50 nm, and even more
particularly
less than about 25 nm.
[0043] Use of asphaltene-sorbent particles having higher surface area
per mass may
increase their efficacy in adsorption of the asphaltene. In embodiments, the
asphaltene-sorbent
particles are configured to have a surface area per mass in the range from
about 1 to about
3,000 m2/g. In some embodiments, the surface area per mass may be greater than
50 m2/g,
greater than about 100 m2/g, greater than about 250 m2/g, greater than about
500 m2/g, greater
than about 750 m2/g, and greater than about 1,000 m2/g.
[0044] Having regard to the asphaltene affinity of the selected asphaltene-
sorbent particles,
the concentration of asphaltene-sorbent particles in the mixture introduced to
the reservoir may
be selected to be effective in adsorbing asphaltene present in concentrations
in the
hydrocarbons in the subterranean reservoir, which typically range from about
20 ppm to about
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30,000 ppm and may range from 50 to 5,000 ppm. In one embodiment, the
concentration of
asphaltene-sorbent particles in the steam introduced to the formation is less
than 397 ppm or
less than 272 ppm or less than 136 ppm.
[0045] After injection of the asphaltene-sorbent particles, the
particles adsorb asphaltene
and the particles with asphaltene adsorbed thereto remain in the formation
while the valuable,
hydrocarbons are produced from the reservoir with a reduced asphaltene content
over an
untreated formation. While the invention is not intended to be bound by
theory, it is believed
that the asphaltene-sorbent particles become attached to the rock in the
subterranean reservoir
and the asphaltene adsorbs to the particles.
[0046] Therefore, for the purposes of illustration, in Fig. 1, at step 102,
the asphaltene-
sorbent particles that were injected into the subterranean reservoir in step
100, are allowed to
soak. While it is not intended that the invention be limited by theory, it is
believed that the
particles attach to the subterranean reservoir during the soak phase. This
step may be performed
without any active intervention, by allowing for contact time between the
injected mixture and
the reservoir. Relatively quiescent conditions may facilitate the binding of
the particles in the
subterranean reservoir. For example, injection of the steam may be ceased to
leave the
asphaltene-sorbent particles in the subterranean reservoir for a period of
time relatively
undisturbed. The asphaltene-sorbent particles adhere to rock, such as sand
particles, in the
subterranean reservoir. Allowing the mixture to soak, relatively undisturbed
in the reservoir
facilitates this adhesion. Fig. 3D is a schematic depiction of step 102,
showing the asphaltene-
sorbent particles 220 attached to sand particles of the subterranean reservoir
200 after cessation
of steam injection.
[0047] It is not an outright requirement to cease steam injection.
However, cessation of
steam injection may speed up the process of the asphaltene-sorbent particles
contacting
hydrocarbons in-situ and adsorbing asphaltenes from the hydrocarbons. Steam
injection does
not need to be ceased forever in this case, just stopped for a period of time.
[0048] In Fig. 1, at step 104, the asphaltene-sorbent particles are
allowed to adsorb
asphaltene in the subterranean reservoir. This step may be performed without
any active
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intervention, by allowing for relatively quiescent conditions in the
subterranean reservoir. Fig.
3D is a schematic depiction of this step showing the asphaltene-sorbent
particles 220 attached
to sand particles of the subterranean reservoir 200 and the adsorbed
asphaltene molecules 216.
While steps 102 and 104 are shown separately, there is no intervention that
separates the two
steps and they are effectively achieved by the same process of soaking.
[0049] In Fig. 1, at step 106, the hydrocarbons are allowed to drain by
gravity into the
production tubing string, while the asphaltene-sorbent particles with adsorbed
asphaltene
remain retained in, for example attached to, the subterranean reservoir. Fig.
3E is a schematic
depiction of this step showing upgraded hydrocarbon molecules 214 within the
production
.. tubing 206 while the asphaltene-sorbent particles 220 with adsorbed
asphaltene molecules 216
remain in the region of the steam chamber. The hydrocarbon molecules 214 are
upgraded,
since they contain less asphaltene than what would be produced without the
addition of the
asphaltene-sorbent particles.
[0050] In Fig. 1, at step 108, the upgraded hydrocarbons are produced to
the surface via the
production tubing. Fig. 3F is a schematic depiction of this step showing the
upgraded
hydrocarbon molecules 214 flowing to the surface via the production tubing
206.
[0051] As known to persons skilled in the art, SAGD (and other steam
injection operations
as described below) may be performed over many years with multiple cycles of a
steam
injection phase followed by a hydrocarbon production phase. Accordingly, steps
100 to 108
may be performed repeatedly in cycles, with each performance of step 100
corresponding to a
steam injection phase of a cycle, and each performance of step 108
corresponding to a
hydrocarbon production phase of the cycle. In particular, the amount or
concentration of
asphaltene-sorbent particles in the mixture that is injected into the
subterranean reservoir at
each cycle may be selectively varied, possibly to account for factors such as
the amount or
concentration of asphaltene-sorbent particles that have been previously
injected in past cycles,
or will be injected in subsequent cycles. This can be used to achieve a
variety of advantageous
effects. As one example, the concentration or amount of asphaltene-sorbent
particles that is
injected in any given cycle can be limited, with a view to incrementally
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concentration or amount of asphaltene-sorbent particles attached to the
subterranean reservoir
over multiple cycles. As another example, the concentration or amount of
asphaltene-sorbent
particles that is injected in any given cycle can be selected to control the
distribution of
asphaltene-sorbent particles in the subterranean reservoir. For instance, the
volumetric portion
of the subterranean reservoir that is "seeded" with the asphaltene-sorbent
particles can be
incrementally increased over multiple cycles. As still another example, the
concentration or
amount of asphaltene-sorbent particles in the mixture that is injected in any
given cycle can be
varied over cycles to account for varying levels of asphaltene concentration
in produced fluids
during the operation of the well, or to selectively vary the asphaltene
concentration of fluids
produced to the surface during the operation of the well.
[0052] Referring back to Fig. 1, the method may also include an optional
step 110 that is
applicable to steam injection operations, such as SAGD or steam flooding that
use two wells,
where one of the wells is an injection well for injection of steam, and the
other well is a
production well for production of hydrocarbons to the surface. At step 110, a
mixture of a
carrier fluid and additional asphaltene-sorbent particles are injected via the
production tubing
string 206 of the production well 204 into the subterranean reservoir. That
is, the production
tubing string 206 is used in a non-conventional manner to convey material from
the surface
into the subterranean reservoir. Fig. 3B is a schematic depiction of step 110,
showing the
carrier fluid 222 mixed with additional asphaltene-sorbent particles 220 being
pumped into the
subterranean reservoir. In embodiments, the carrier fluid 222 may be a liquid
such as water or
ethyl acetate. In embodiments, the carrier fluid 222 may be a gas, such as a
nitrogen or
methane. The carrier fluid may be transported to the well head of the
production well such as
by truck or other means. In like manner as the asphaltene-sorbent particles
that are injected at
step 100, the additional asphaltene-sorbent particles that are injected in
step 110 will prevent
asphaltene from being produced and cause the asphaltene contacted by the
carrier fluid/particle
mixture to be retained in the subterranean reservoir. Fig. 1, and the sequence
of Figs. 3A to 3F,
show step 110 as being performed prior to steps 100 to 108. However, it will
be understood
that step 110 may be performed periodically, and in other orders relative to
these steps, but
preferably in such an order that does not interfere with migration of
hydrocarbons to the
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production well, and production of hydrocarbons to the surface via the
production well.
Further, by use of flow control devices associated with the production well,
the carrier fluid
and additional asphaltene-sorbent particles may be injected into those
portions of the
subterranean reservoir surrounding the production well where hydrocarbons are
most likely to
.. be produced. Such locations may be predicted by persons skilled in the art,
and/or determined
empirically when the well system is in operation.
[0053] Controlled placement of asphaltene-sorbent particles.
[0054] The contact time between the hydrocarbons and the asphaltene-
sorbent particles in
the subterranean reservoir may be quite brief due to flow of steam through the
formation. As
such, creating regions of the subterranean reservoir that have higher
concentrations of steam
containing asphaltene-sorbent particles, and controlling the flow of the
steam/particulate
mixture through such regions may promote contact of the asphaltene-sorbent
particles with the
hydrocarbons and the asphaltene therein, and therefore make the most
economical and
effective use of the asphaltene-sorbent particles.
[0055] As a non-limiting example, referring back to the Fig. 2, the
injection tubing 202 may
include a plurality of steam flow control devices, including a first steam
flow control device
224 and a second steam flow control device 226, disposed at different
positions along the
subterranean reservoir. "Steam flow control device", as used herein, refers to
any mechanical
device that can be incorporated into a downhole string, and actuated to
selectively control flow
of steam out of the downhole tubing and into the surrounding wellbore. Steam
flow control
devices are known to persons skilled in the art. Steam flow control devices
may be referred to
in the art as "steam splitters", "steam diverter", "steam valves", "steam
injection mandrels",
and like terms. As a non-limiting example, a steam flow control device may
comprise a body
defining a bore, and a sleeve or other valve member that is movable relative
to the body
between alternate positions that either block or allow steam to flow out of
openings defined by
the bore. Movement of the sleeve or valve member may be actuated by means such
as shift
tools, balls, pressure differentials, or other mechanisms as known to persons
skilled in the art.
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[0056] By control of the steam flow control devices (and the use of
possible sealing
elements associated with the injection tubing 202, such as sealing elements
used for zonal
isolation), it is possible to establish pressure gradients of the steam mixed
with asphaltene-
sorbent particles 220 that are injected into the subterranean reservoir in
step 100. These
pressure gradients will affect the distribution of asphaltene-sorbent
particles 220, as the
injected steam and asphaltene-sorbent particles 220 will tend to migrate from
regions of higher
pressure to regions of lower pressure. In Fig. 2, for example, closing of the
first steam flow
control device 224 and opening of the second steam flow control device 226 may
create a
region of relatively lower pressure in the vicinity of the first steam flow
control device 224,
and a region of relatively higher pressure in the vicinity of the second steam
flow control device
226. Accordingly, asphaltene-sorbent particles 220 injected into the
subterranean formation
via the second steam flow control device 226 may tend to flow from right to
left in the drawing
plane of Fig. 2. This may result in a region having a higher concentration of
asphaltene-sorbent
particles 220 near the second steam flow control device 226, as compared with
the region near
the first steam flow control device 224. (The asphaltene-sorbent particles 220
would be
expected to become more diffuse in concentration with increased distance from
their injection
location at the second steam flow control device 226.)
[0057] Pressure gradients also tend to cause steam in the steam chamber
212 to flow from
regions of relatively high pressure to regions of relatively low pressure.
Accordingly, the steam
flow control devices or other means may also be selectively controlled to
establish a pressure
gradient that affects the flow of steam in the steam chamber 212 to regions of
the steam
chamber 212 having relatively higher concentrations of asphaltene-sorbent
particles 220. For
example, after the asphaltene-sorbent particles 220 are allowed to attach the
sand particles of
the subterranean reservoir, injection of steam (without further injection
asphaltene-sorbent
particles 220) into the steam chamber 212 may be continued. Opening of the
first steam flow
control device 224 and closing of the second steam flow control device 226 may
create a region
of relatively higher pressure in the vicinity of the first steam flow control
device 224, as
compared with the region in the vicinity of the second steam flow control
device 226.
Accordingly, steam will tend to flow from left to right in the drawing plane
of Fig. 2, so as to
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flow through the region of the steam chamber 212 in the vicinity of the second
steam flow
control device 226 having the relatively higher concentration of asphaltene-
sorbent particles
220, preferentially over other regions having relatively lower concentrations
of asphaltene-
sorbent particles 220.
[0058] Adaption to other well systems and steam injection operations.
[0059] In the embodiment of Figs. 3A to 3F, the method is implemented using a
SAGD
well system. In other embodiments, the method may be implemented for other
steam injection
operations, including cyclic steam stimulation (CSS), steam flooding or steam
drive.
[0060] As known in the art, cyclic steam stimulation typically involves
a "steam phase" of
injecting steam into the reservoir via the well, a "soak phase" of allowing
the steam to soak
into the reservoir near the well and thereby reduce viscosity of hydrocarbons,
and a "production
phase" of producing hydrocarbons to the surface from the same well. The method
of the present
invention may be implemented by: (i) injecting steam and asphaltene-sorbent
particles into the
subterranean reservoir via the well during the "steam phase". This may include
injecting a
mixture of steam and particles, mixed at surface or sequential injections of
steam and then
particles in various orders. The particles may be in a carrier fluid. Then,
(ii) allowing a "soak
phase" where the particles adsorb asphaltene in the subterranean reservoir;
and (iii) producing
the hydrocarbons to the surface via the same well during the "production
phase", without
producing the asphaltene-sorbent particles with adsorbed asphaltene that
remain attached to
the subterranean reservoir. Thus, it will be understood that the method may be
implemented
using a single well system, which may be a vertical well.
[0061] As known in the art, steam flooding or steam drive typically
involves injecting steam
into a reservoir via a first well to reduce the viscosity of hydrocarbons and
displace the
hydrocarbons toward a different second well. In contrast to SAGD, the first
well and the second
well may both be vertical wells that are horizontally spaced apart from each
other. The method
of the present invention may be implemented by: injecting a mixture of steam
and asphaltene-
sorbent particles into the subterranean reservoir via the first well; allowing
asphaltene-sorbent
particles to attach to the subterranean reservoir that is disposed
horizontally between the first
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and second wells, and adsorb asphaltene in that subterranean reservoir; and
producing the
hydrocarbons to the surface via the second well, without producing the
asphaltene-sorbent
particles with adsorbed asphaltene that are retained in the subterranean
reservoir. Thus, it will
be understood that the method may be implemented using steam flooding or steam
drive.
EXAMPLES
[0062] Materials
[0063] Heavy crude oil from applicant's resources that was used in these
examples has
9.2 +0.1 API (with a specific gravity of 1.0056 at 15.6 C), the viscosity of
78,750 cP at 25
C, and an approximate content of 10.3 wt% of asphaltenes. The nanoparticles
employed herein
is fumed silica (SiO2). The nanoparticles were in powder form with each
particle having a
maximum dimension of less than 100 nm.
[0064] Adsorption of asphaltenes
[0065] Asphaltenes were extracted from the heavy crude oil. A heavy oil
model solution
was prepare where extracted asphaltenes were dissolved in toluene.
[0066] Adsorption experiments were conducted by adding 100 mg of nanoparticle
in 10 mL
of the prepared heavy oil model solution at 25 C. The mixture was mixed under
the orbital
shaker and allowed to equilibrate for 24 h. The mixtures were left for 30
minutes and
nanoparticles with adsorbed asphaltene settled out.
[0067] 1-D physical model of sand packed bed for simulating SAGD conditions
[0068] The model SAGD set up is designed as shown in Fig. 4. Each run
starts with packing
the sand in the column, then saturate the reactor with bitumen oil using the
pump connected to
the accumulator. After that, a steam generator provides steam up to 230 C
through the coiled
tubes, steam is saturated within the reactor for different time intervals, and
the system is left to
soak for also different time intervals. The nanoparticles are injected in the
form of nanofluid
upon injecting the steam. The asphaltene content and viscosity of the oil
produced by saturating
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steam in a sand packed column with and without nanoparticles are compared to
determine the
role of nanoparticles in reducing asphaltenes precipitation or aggregation
insitu.
[0069] SAGD Displacement Experiment
[0070] In this part of the study, a 1-D sand pack model based on the
experimental setup
presented previously in Fig. 4 was used to run the SAGD experiments. The
dimensions of the
sand pack were 2.2098cm (D) by 22.42cm (L). The provided sand was washed and
sieved to
mesh size 80 then packed to the column. The pore volume was estimated from the
mass and
density of the sand. To minimize heat loses, the model was wrapped with
heating tapes and
aluminum foil then distributed with thermocouples to capture the temperature
of the entire
model. Bitumen in the transfer cell was heated up to 100 C to make it movable
and it was
saturated to the model using the Isco pump. After saturation, the reactor was
set for steam
injection with and without nanoparticles in the coil. For the SAGD experiment,
steam was
injected at a rate of 3.5mL/min cold water equivalent (CWE) and the experiment
lasted for 2 h.
For the experiment with silica nanoparticles, the nanofluids have been
formulated using
deionized water. The concentration of nanoparticles was estimated based on the
mass of
nanoparticles over the volume of total steam injected. The produced
bitumen/water emulsion
was separated by gravity and the retained bitumen samples have been analyzed
for viscosity,
API and asphaltene content.
[0071] Oil recovery
[0072] Fig. 5 shows the bitumen recovery as a function of pore volume
injection (PVI). As
seen, recovery of bitumen increased with PVI injection and continues until the
end of the
experiments. It can be interpreted that the presence of nanoparticles inside
the medium caused
the production of lighter components via in-situ adsorption and trapping of
asphaltene. A
higher concentration of nanoparticles might cause aggregation and blockage in
porous media.
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[0073] Tracing nanoparticles inside the reactor
[0074] Cryo-SEM experiments were performed to confirm the presence of
the injected
nanoparticles inside the reactor. Samples were frozen in nitrogen slush, and
then vacuum
transferred to the sample preparation chamber (Gatan ALT02500). In the prep
chamber, the
samples were held at a temperature of -150 C and fractured under vacuum.
Samples were
transferred into the evacuated SEM sample chamber via a vacuum transfer tube.
Imaging was
performed using 10keV electrons under low vacuum conditions at a pressure of
30 Pa using
dry nitrogen.
[0075] ESEM microphotographs of two selected samples from the top
(entrance of injection
point) and the middle of the reaction zone were reviewed. A higher population
of deposited
particles appeared at the top of reaction zone compared to the middle zone.
Despite the
aggregation of particles at the entrance of the reaction zone still,
nanoparticles did
propagate through the sand packed bed column and smaller particles were
observed at the
middle of the reaction zone.
[0076] Asphaltene analysis using C7
[0077] The asphaltene content in the produced oil was estimated and the
obtained solid
(asphaltene) estimations are summarized in Fig. 6.
[0078] We can see from the Fig. 6 that the asphaltene content in the
produced oil reduced
from 11.3% from the original oil sample with 0 ppm nanoparticle injection to
6.3% and 4.4%
with 136ppm and 272ppm nanoparticle, respectively. This indicates that
asphaltene adsorption
is occurring in-situ during the SAGD experiment in the presence of
nanoparticles and is
correlated with nanoparticle concentration as the asphaltene content is
decreasing in the
produced oil as the concentration of nanoparticles increases.
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[0079] Analysis of C5-asphaltenes
[0080] Experiments were performed again using a concentration of 136ppm
nanoparticles
but using C5-asphaltenes instead of C7-asphaltenes. The nanofluid was
formulated by
dispersing the selected mass fractions of nanoparticles to distilled water.
These concentrations
.. have been computed based on the mass of steam injected in the system. For
the effect of time,
steam was injected for 2 h, and early in the steam injection, 10 mL of
nanofluid was injected.
The total volume of steam injected for the 2 h was equivalent to 10.6 PV where
1 PV is
equivalent 33.8 mL of steam. This implies that a total volume of steam
injected is equivalent to
358.28 mL in the 2 h of oil production for the 10 mL nanofluid injection. Two
samples were
evaluated at two different time intervals to compare the % residual of
asphaltene and resins
produced as a function of time for the two hours of steam injection. Sample 1
was obtained
after the first 1 h after injection of 10 mL nanofluid, while Sample 2 was
obtained after 2 h for
the same nanofluid; without injection of any additional nanofluids.
[0081] The extracted residual was on average 15.6% for the 2 cycles of
nanofluid injection
in 2 h for 0 ppm of nanoparticles. For the nanoparticle injection a first one
hour of steam and
132 ppm nanoparticles, residual content at the end of 1 h dropped to 12.5%.
After the second
hour, the concentration of nanoparticles in the system reduced to 68 ppm due
to more steam
injection. The residual content after the second hour did not show any
significant change, which
is expected due to the decrease of the nano concentration in the system as
more steam is injected
into the system.
[0082] While higher concentrations of initial nanoparticle injections
were employed in
reruns of this test, the residual results did not improve significantly.
[0083] Effect of cycle injection
[0084] Effect of nanofluid cycle injection was evaluated by injecting a
pulse of 10 mL after
each 1 hour for a total of 2 h and the C5-asphaltene content in the two
samples was evaluated.
The nanofluid was formulated by dispersing the selected mass fractions of
nanoparticles to
distilled water to formulate nanofluid ranging from 66 ppm to 397 ppm. These
concentrations
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are fractions of the total steam injected for each cycle, respectively. For
the effect of the first
injection cycle, aliquots of 10 mL nanofluid were injected during the steam
injection. The total
volume of steam injected for the 1 h was still equivalent to 5.3 PV where 1 PV
is equivalent
33.8 mL of steam; this implies that a total volume of steam injected at the
end of the first cycle
is equivalent to 179.14 mL in the 1 h of oil.
[0085] It was determined that injecting the same nanofluid concentration
but at different
cycles resulted in a noticeable asphaltene reduction; the first cycle an
injection of 132ppm after
1 h resulted in 13.8% and after the second cycle with the injection of
additional 10 mL
nanofluid (66ppm) in the system, the content dropped to 10.6%. A similar trend
was observed
with the injection of 264 ppm and 397ppm, respectively as a fraction of the
total steam injected.
For the first cycle injection of 264ppm: after 1 h residual content was 13.1%
and after the
second cycle with the injection of additional 10 mL nanofluid (132ppm), the
residual content
dropped to 11%. For the first cycle injection of 397ppm: after 1 h residual
content was 17.5%
and after the second cycle with the injection of additional 10 mL nanofluid
(199ppm), the
residual content dropped to 13.5%.
[0086] Although the effect of increasing the concentration as explained
previously had no
significant effect on the asphaltene and resin reduction, with the injection
of more nanofluid
during the second cycle there was a noticeable residual reduction from the
produced oil. It is
believed that the injection of addition nanofluid after the first cycle,
provides more
.. nanoparticles to interact again with the oil in the system and more in-situ
adsorption of the
residual may take place with more steam injection that results in an
additional oil upgrade.
[0087] Interpretation.
[0088] The corresponding structures, materials, acts, and equivalents of
all means or steps
plus function elements in the claims appended to this specification are
intended to include any
.. structure, material, or act for performing the function in combination with
other claimed
elements as specifically claimed.
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[0089] References in the specification to "one embodiment", "an
embodiment", etc.,
indicate that the embodiment described may include a particular aspect,
feature, structure, or
characteristic, but not every embodiment necessarily includes that aspect,
feature, structure, or
characteristic. Moreover, such phrases may, but do not necessarily, refer to
the same
embodiment referred to in other portions of the specification. Further, when a
particular aspect,
feature, structure, or characteristic is described in connection with an
embodiment, it is within
the knowledge of one skilled in the art to affect or connect such module,
aspect, feature,
structure, or characteristic with other embodiments, whether or not explicitly
described. In
other words, any module, element or feature may be combined with any other
element or
feature in different embodiments, unless there is an obvious or inherent
incompatibility, or it
is specifically excluded.
[0090] It is further noted that the claims may be drafted to exclude any
optional element.
As such, this statement is intended to serve as antecedent basis for the use
of exclusive
terminology, such as "solely," "only," and the like, in connection with the
recitation of claim
elements or use of a "negative" limitation. The terms "preferably,"
"preferred," "prefer,"
"optionally," "may," and similar terms are used to indicate that an item,
condition or step being
referred to is an optional (not required) feature of the invention.
[0091] The singular forms "a," "an," and "the" include the plural
reference unless the
context clearly dictates otherwise. The term "and/or" means any one of the
items, any
combination of the items, or all of the items with which this term is
associated. The phrase
"one or more" is readily understood by one of skill in the art, particularly
when read in context
of its usage.
[0092] The term "about" can refer to a variation of 5%, 10%, 20%, or
25% of the
value specified. For example, "about 50" percent can in some embodiments carry
a variation
from 45 to 55 percent. For integer ranges, the term "about" can include one or
two integers
greater than and/or less than a recited integer at each end of the range.
Unless indicated
otherwise herein, the term "about" is intended to include values and ranges
proximate to the
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recited range that are equivalent in terms of the functionality of the
composition, or the
embodiment.
[0093] As will be understood by one skilled in the art, for any and all
purposes, particularly
in terms of providing a written description, all ranges recited herein also
encompass any and
all possible sub-ranges and combinations of sub-ranges thereof, as well as the
individual values
making up the range, particularly integer values. A recited range includes
each specific value,
integer, decimal, or identity within the range. Any listed range can be easily
recognized as
sufficiently describing and enabling the same range being broken down into at
least equal
halves, thirds, quarters, fifths, or tenths. As a non-limiting example, each
range discussed
herein can be readily broken down into a lower third, middle third and upper
third, etc.
[0094] As will also be understood by one skilled in the art, all language
such as "up to", "at
least", "greater than", "less than", "more than", "or more", and the like,
include the number
recited and such terms refer to ranges that can be subsequently broken down
into sub-ranges
as discussed above. In the same manner, all ratios recited herein also include
all sub-ratios
falling within the broader ratio.
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