Note: Descriptions are shown in the official language in which they were submitted.
CA 02935652 2016-07-07
HEAVY OIL EXTRACTION USING LIQUIDS SWEPT ALONG BY GAS
FIELD OF THE INVENTION
[0001] The invention is in the field of hydrocarbon reservoir engineering,
particularly
solvent-assisted recovery processes in heavy oil reservoirs.
BACKGROUND OF THE INVENTION
[0002] Some subterranean deposits of viscous hydrocarbons can be extracted
in situ
by lowering the viscosity of the petroleum to mobilize it so that it can be
moved to, and
recovered from, a production well. Reservoirs of such deposits may be referred
to as
reservoirs of heavy hydrocarbon, heavy oil, bitumen, tar sands, or oil sands.
The in situ
processes for recovering oil from oil sands typically involve the use of
multiple wells
drilled into the reservoir, and are assisted or aided by injecting a fluid
such as steam,
and/or a solvent, into the reservoir through an injection well to mobilize the
viscous
hydrocarbons for recovery through a production well.
[0003] A widely used thermal recovery process is steam assisted gravity
drainage
(SAGD) as for example disclosed in Canadian Patent No. 1,130,201 issued on 24
August 1982, in which two wells are drilled into the deposit, one for
injection of steam
and one for production of oil and water. Steam is injected via the injection
well to heat
the formation. The steam condenses and gives up its latent heat to the
formation,
heating a layer of viscous hydrocarbons. The viscous hydrocarbons are thereby
mobilized, and drain by gravity toward the production well with an aqueous
condensate.
In this way, the injected steam initially mobilises the in-place hydrocarbon
to create a
"steam chamber" in the reservoir around and above the horizontal injection
well. The
term "steam chamber" accordingly refers to the volume of the reservoir which
is
saturated with injected steam and from which mobilized oil has at least
partially drained.
Mobilized viscous hydrocarbons are recovered continuously through the
production
well. The conditions of steam injection and of hydrocarbon production may be
modulated to control the growth of the steam chamber, to ensure that the
production
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well remains located at the bottom of the steam chamber in an appropriate
position to
collect mobilized hydrocarbons.
[0004] The start-up stage of a heavy oil recovery process often involves
establishing
thermal or hydraulic communication, or both, between injection and production
wells. At
initial reservoir conditions, there is typically negligible fluid mobility
between wells due to
high bitumen viscosity. Communication is achieved when bitumen between the
injector
and producer is mobilized to allow for bitumen production. A conventional
start-up
process involves establishing interwell communication by simultaneously
circulating
steam through each injector well and producer well. High-temperature steam
flows
through a tubing string that extends to the toe of each horizontal well. The
steam
condenses in the well, releasing heat and resulting in a liquid water phase
which flows
back up the casing-tubing annulus. Alternative start-up techniques involve
creating a
high mobility inter-well path by the use of solvents, as for example described
in
Canadian Patent No. 2,698,898, or by application of pressures so as to dilate
the
reservoir sand matrix, as for example described in Canadian Patent No.
2,757,125.
[0005] In the ramp-up stage of a heavy oil recovery process, after
communication
has been established between the injection and production wells during start-
up (usually
over a limited section of the well pair length), production begins from the
production
well. Typically, a mobilizing fluid such as steam or solvent is continuously
injected into
an injection well while mobilized bitumen and water are continuously removed
from the
production well. During this period the zone of communication between the
wells may
expand axially along the full well pair length, and a chamber depleted of
hydrocarbons
grows vertically towards the top of the reservoir. The reservoir top may be a
thick shale
(overburden) or some lower permeability facies that causes the steam chamber
to stop
rising. In some processes, for example SAGD, when the interwell region over
the entire
length of the well pair has been heated and the steam chamber that develops
has
reached the reservoir top, the bitumen production rate typically peaks and
begins to
decline while the steam injection rate reaches a maximum and levels off.
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[0006] A wide variety of alternative enhanced or in-situ recovery processes
may
be used that employ thermal and non-thermal components to mobilise oil. A wide
variety of processes have been described that use hydrocarbon solvents in
addition
to steam, or in place of steam, in processes analogous to conventional SAGD,
or in
processes that are alternatives to SAGD. For example, Canadian Patent Number
2,299,790 describes methods for stimulating heavy oil production using a
propane
vapor. Similarly, Canadian Patent No. 2,323,029 describes an in situ recovery
process involving injection of steam and a non-aqueous solvent. Unheated
hydrocarbon vapours have been proposed for use to dissolve and displace heavy
oils in a process known as VAPEX (Butler and Mokrys, J. Can. Petro. Tech.
1991,30;
U.S. Pat. No. 5,407,009). Processes for cyclic steam stimulation of vertical
wells
using hydrocarbon solvents have been described (Leaute and Carey, J. Can.
Petro.
Tech., Vol. 46, No. 9, pp. 22-30, 2007). Field trials have also been reported
for
solvent assisted processes that involve the use of solvent, such as butane, as
an
addition or aid to injected steam in improving the performance of conventional
SAGD (Gupta et al., Paper 2001-126, Can. Intl. Pet. Conf., Calgary, Alberta,
June 12-
14, 2001; Gupta et al., Paper No. 2002-299, Can. Intl. Pet. Conf., Calgary,
Alberta, June
11-13, 2002;Gupta and Gittins, Paper No. 2005-190, Can. Intl. Pet. Conf.,
Calgary,
Alberta, June 7-9, 2005). Similarly, solvent assisted processes characterized
as Liquid
Assisted Steam Enhanced Recovery (LASER) have been described, in which
solvents
are used in conjunction with steam to enhance performance of Cyclic Steam
Stimulation
(CSS).
[0007] The complexities associated with heavy oil recovery processes
involving
solvents are considerable. As for example, illustrated by Canadian Patent
Application 2,660,227, which describes numerical simulations of alternative
hybrid
solvent processes. Numerical studies have suggested that simple addition of
propane to steam may be ineffective, with the propane failing to condense and
thereby acting as a noncondensable gas (Zhao, SPE 86957 presented at the SPE
International Thermal Operations and Heavy Oil Symposium , Bakersfield,
California, 2004). Further complications may be introduced in methods that
involve
varying solvent compositions over time (Gupta and Gittins J. Can. Petro. Tech.
September 2007, Vol. 46, No 9; and, Canadian Patent No. 2,462,359).
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[0008] Non-condensing gases (NCGs) may be present in heavy oil recovery
process
for a variety of reasons. In the context of alternative processes, NCGs have
been
described as offering both benefits and challenges to the optimal performance
of a
recovery processes, such as SAGD systems. For example, US Patent No. 8,596,357
describes methods for adding a buoyancy-modifying agent to injected steam,
such as
an additional NCG, to help cause NCGs to accumulate at the top of the steam
chamber.
This approach reflects the fact that NCGs tend to be light and therefore
buoyant, so that
any NCG that is liberated or generated lower in the steam chamber will tend to
rise to a
higher part of the steam chamber, and any NCG produced or released higher in
the
steam chamber will tend to remain in the upper elevations of the steam
chamber. Other
aspects of fluid dynamics in the SAGD process influence this vertical NCG
flow.
[0009] The management of NCGs in heavy oil recovery process is complicated by
the fact that gravity-dominated in situ recovery processes, such as SAGD, rely
on
vertical flow and displacement. However, given the long horizontal wells that
are
normally associated with this type of process, and the (axial) flows along the
length of
the wells, the resulting (radial or transverse) flows from reservoir to well,
and vice versa,
will tend to be non-uniform, even in a homogeneous reservoir.
[0010] In the context of the present application, various terms are used in
accordance with what is understood to be the ordinary meaning of those terms.
For
example, "petroleum" is a naturally occurring mixture consisting predominantly
of
hydrocarbons in the gaseous, liquid or solid phase, which includes various
oxygen-,
nitrogen- and sulfur- containing compounds and typically trace amounts of
metal-
containing compounds. In the context of the present application, the words
"petroleum"
"oil" and "hydrocarbon" are generally used interchangeably to refer to
mixtures of widely
varying composition, as will be evident from the context in which the word is
used. The
production of petroleum from a reservoir necessarily involves the production
of
hydrocarbons, but is not limited to hydrocarbon production. Similarly,
processes that
produce hydrocarbons from a well will generally also produce petroleum fluids
that are
not hydrocarbons. In accordance with this usage, a process for producing
petroleum or
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hydrocarbons is not necessarily a process that produces exclusively petroleum
or
hydrocarbons, respectively.
[0011] "Fluids", such as petroleum fluids, include both liquids and gases.
Natural gas
is the portion of petroleum that exists either in the gaseous phase or is in
solution in
crude oil in natural underground reservoirs, and which is gaseous at
atmospheric
conditions of pressure and temperature. Natural Gas may include amounts of non-
hydrocarbons. The abbreviation POIP stands for "producible oil in place" and
in the
context of the methods disclosed herein is generally defined as the
exploitable or
producible oil structurally located above the production well elevation.
[0012] It is common practice to segregate petroleum substances of high
viscosity
and density into two categories, "heavy oil" and "bitumen". For example, some
sources
define "heavy oil" as a petroleum that has a mass density of greater than
about 900
kg/m3. Bitumen is sometimes described as that portion of petroleum that exists
in the
semi-solid or solid phase in natural deposits, with a mass density greater
than about
1000 kg/m3 and a viscosity greater than 10,000 centipoise (cP; or 10 Pa.$)
measured at
original temperature in the deposit and atmospheric pressure, on a gas-free
basis.
Although these terms are in common use, references to heavy oil and bitumen
represent categories of convenience, and there is a continuum of properties
between
heavy oil and bitumen. Accordingly, references to heavy oil and/or bitumen
herein
include the continuum of such substances, and do not imply the existence of
some fixed
and universally recognized boundary between the two substances. In particular,
the
term "heavy oil" includes within its scope all "bitumen" including
hydrocarbons that are
present in semi-solid or solid form.
[0013] A reservoir is a subsurface formation containing one or more natural
accumulations of moveable petroleum, which are generally confined by
relatively
impermeable rock. An "oil sand" or "tar sand" reservoir is generally comprised
of strata
of sand or sandstone containing viscous petroleum, such as bitumen. Viscous
petroleum, or such as bitumen, may also be found in reservoirs whose solid
structure
consists of carbonate material rather than sand material. Such reservoirs are
CA 02935652 2016-07-07
sometimes referred to as bituminous carbonates. A "zone" in a reservoir is
merely an
arbitrarily defined volume of the reservoir, typically characterised by some
distinctive
property. Zones may exist in a reservoir within or across strata or facies,
and may
extend into adjoining strata or facies. In some cases, reservoirs containing
zones having
a preponderance of heavy oil are associated with zones containing a
preponderance of
natural gas. This "associated gas" is gas that is in pressure communication
with the
heavy oil within the reservoir, either directly or indirectly, for example
through a
connecting water zone.
[0014] A "chamber" within a reservoir or formation is a region that is in
fluid
communication with a particular well or wells, such as an injection or
production well.
For example, in a SAGD process, a steam chamber is the region of the reservoir
in fluid
communication with a steam injection well, which is also the region that is
subject to
depletion, primarily by gravity drainage, into a production well. A very wide
variety of
thermal and non-thermal recovery techniques may be used to deplete zones
within a
reservoir, to create hydrocarbon or heavy oil depleted chambers within a
reservoir.
SUMMARY OF THE INVENTION
[0015] In one aspect, the present processes utilize aspects of NCG flow
management to deliver an entrained diluent/solvent liquid (DSL) to an oil
interface within
a reservoir, such as a heavy oil interface, with the entrained DSL then acting
as a
diluent or solvent to mobilize the oil for production. Detailed simulations
have
demonstrated the ability of NCGs to effectively sweep the entrained DSL
through a
formation, in a process that may be characterized as providing liquids swept
along by
gas (LSAG). This LSAG delivery of a solvent or diluent is effective in the
absence of
energetically expensive thermal inputs of the kind that characterize SAGD or
VAPEX
processes, with no phase change imposed on the liquid in the context of
selected
embodiments of the present processes.
[0016] A wide variety of DSLs may be used in LSAG processes. For example, the
liquid phase of the LSAG fluid may include one or more hydrocarbon solvents,
such as
C3 through C10 alkanes or n-alkanes. The DSL for the LSAG fluid may be
selected on
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the basis that it is miscible with, and capable of enhancing the mobility of,
the reservoir
hydrocarbons.
[0017] In selected aspects of the present process, recovery operations may
be
carried out so as to set up a convective component to NCG flow within the
reservoir,
delivering entrained DSLs through a heavy-oil-depleted (HOD) chamber to a
peripheral
zone comprising an oil interface between a chamber-gas (CG) zone and heavy-oil-
in-
place (HOP) zone. The DSL entrained in the NCG may be injected into the
reservoir
through one or more injection wells, so as to deliver the liquid to the oil
interface by way
of a sweeping NCG flow, thereby mobilizing diluted hydrocarbons at the oil
interface.
The mobilized hydrocarbons then become part of a zone of mobile hydrocarbons,
and
the reservoir may be serviced by one or more wells mediating fluid
communication
between a surface completion and the zone of mobile hydrocarbons. For example,
wells
may be configurable to serve simultaneously or consecutively as injection
and/or
production wells. In this way, mobilized hydrocarbons and non-condensing gas
may be
recovered from the reservoir through a production well, removing heavy oil,
diluent
liquid and non-condensing gases from the reservoir.
[0018] In select embodiments, for example where the arrangement of wells is
analogous to the arrangement of wellpairs in a SAGD process, the HOD chamber
may
have a longitudinal axial dimension. This longitudinal axis is typically
defined by
horizontal wells. For example, a generally horizontal segment of a well
configured or
purposed as a production well and a generally horizontal segment of an
injection well.
The horizontal production well is typically in fluid communication with a zone
of mobile
hydrocarbons, and the horizontal injection well is generally in fluid
communication with
the HOD chamber. The horizontal injection well may be parallel to and
vertically spaced
apart above the horizontal segment of the production well. In such an
arrangement, a
diluent liquid entrained in an NCG may be injected through the horizontal
injection well
at a range of selected bottom hole injection pressures that vary between
injection points
that are spaced apart along the length of the horizontal segment of the
injection well. In
this way, an axial pressure gradient may be formed within the HOD chamber from
a
high pressure region to a low pressure region. This axial pressure gradient
may be
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orchestrated so as to deliver a diluent or solvent liquid to the oil interface
zone to
mobilize diluted hydrocarbons. Once hydrocarbons are mobilized by mixing with
the
diluent or solvent liquid, the mobilized hydrocarbons may flow downwardly and
towards
the production well in a gravity dominated process. In conjunction with this
movement of
mobilized hydrocarbons, non-condensing gases in the interface zone may be
mobilized.
For example, the NCG may be induced to flow in the axial dimension of the HOD
chamber in a convective flow motivated by an axial pressure gradient, moving
from a
high pressure region to a low pressure region. The mobilizing effects of this
LSAG
process may accordingly be arranged so as to radially expand the HOD chamber.
[0019] In alternative arrangements, injection points may be distributed on
an
injection well, and/or gas production points may be distributed on a
production well, so
that the NCG is preferentially delivered to a non-condensing gas production
region of
the formation. The NCG production region may for example reside in a low
pressure
region of the axial pressure gradient of the HOD chamber. The NCG production
region
may for example include one or more of gas production points.
[0020] In aspects of the LSAG process that involve an arrangement of wells
analogous to a typical SAGD arrangement of wellpairs, injection wells and
production
wells may each include a heel segment that is proximal to a vertical segment
of the well,
with the heel segment and vertical well bores connecting the horizontal
segments of the
wells to surface completion. These wells are also typically described as
having a toe
segment that is spaced apart from the heel by the horizontal segment of the
well. In
such an arrangement, the production well may for example include one or more
of gas
production points in the non-condensing gas production region of the
production well,
and the NCG production region of the production well may be proximal to the
heel
segment of the production well. In select implementations of the LSAG process,
an
intermediate casing point of the injector well may for example be landed at a
shallow
angle so as to increase the vertical spacing between the heel of the injector
well and the
heel of the producer well. Alternatively, the production well may include one
or more gas
production points in the non-condensing gas production region of the
production well,
and the NCG production region of the production well may be proximal to the
toe
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segment of the production well, or intermediately spaced apart from the heel
segment of
the production well and the toe segment of the production well. In a further
alternative
well arrangement that may be used to orchestrate NCG flows, an injection well
may
have a sinusoidal trajectory in longitudinal cross section, with high points
at the heel of
the injection well and between points of non-condensing gas egress from an
injector
tubing into an annulus between the injector tubing and an injector casing.
[0021] Alternative implementations of the LSAG process may involve the use of
one
or more vent wells in the reservoir, for example in fluid communication with
the HOD
chamber. Vent wells may then be used for producing non-condensing gases from
the
vent well so as to amplify the delivery of the diluent liquid to the oil
interface by way of
NCG flow.
[0022] A wide variety of alternative start-up, intermediary or subsequent
processes
may be used in conjunction with LSAG processes. For example, a HOD chamber may
be depleted of heavy oil using a thermal recovery process, such as SAGD, or a
solvent-
assisted process, prior to initiating a LSAG process.
BRIEF DESCRIPTION OF THE DRAWINGS
[0023] Figure 1 is schematic illustration of a typical SAGD well pattern,
showing
paired injector and producer well pairs, each have a heel and a toe within the
hydrocarbon rich pay zone of the formation.
[0024] Figure 2 is a cross sectional view of an exemplary completion for an
injector
well, referring to the use of slotted liners, as for example disclosed in
Canadian Patent
Application 2,616,483 of Cenovus Energy Inc. published 29 June 2008.
[0025] Figure 3 is a cross sectional view of an exemplary completion for a
production well, in a start up configuration for circulation, illustrating an
embodiment
employing gas lift.
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[0026] Figure 4a is a cross sectional view of an exemplary completion for a
production well, illustrating an embodiment employing an electric submersible
pump
(ESP) for production operations following start up. Typically, after
circulation start-up,
the 2" coiled tubing string will be removed and the well equipped with a high
temperature ESP capable of pumping fluid from the well into production
gathering
facilities.
[0027] Figure 4b is a cross sectional view of an exemplary completion for a
production well, illustrating an embodiment that represents a completion of
the type
used in simulations modeling alternative embodiments.
[0028] Figure 5 is a graph illustrating oil viscosity as a function of
temperature in a
computational model of alternative embodiments of the invention.
[0029] Figure 6 is a graph illustrating the solution gas-oil ratio as
function of
pressure at a reference temperature of 12 C in a computational model of
alternative
embodiments of the invention.
[0030] Figure 7 is a graph illustrating the oil-water relative permeability
curves in a
computational model of alternative embodiments of the invention.
[0031] Figure 8 is a graph illustrating the Oil-Gas relative permeability
curves in a
computational model of alternative embodiments of the invention.
[0032] Figure 9 is a ternary cross section through the steam chamber one
year into
a SAGD operation, where the lightest grey represents oil, intermediate shades
of grey
represent mobilized fluids and the darkest grey is gas. From left to right,
the panels
illustrate: first, Figure 9a, a plane where both the producer and injector are
slotted;
second, Figure 9b, a plane where the injector is blanked; and third, Figure
9c, a plane
where the producer is blanked. The small black arrows represent the direction
of gas
flux.
CA 02935652 2016-07-07
[0033] Figure 10 is a ternary cross section in the IK plane, slicing
through the steam
chamber approximately 5 years into the SAGD process, where the lightest grey
represents oil, intermediate shades of grey represent mobilized fluids and the
darkest
grey is gas. From left to right, the panels illustrate: first, Figure 10a, a
plane where both
the producer and injector are slotted; second, Figure 10b, a plane where the
injector is
blanked; and third, Figure 10c, a plane where the producer is blanked. The
small black
arrows represent the direction of gas flux in that plane. Note the clockwise
circulation of
NCG near the chamber edge, with little to no flow down to the producer.
[0034] Figure 11 is ternary cross section in the IK plane, slicing through
the steam
chamber near the heel of the well approximately 5 years into the SAGD process,
where
the lightest grey represents oil, intermediate shades of grey represent
mobilized fluids
and the darkest grey is gas. From left to right, the panels illustrate: first,
Figure 11a, a
plane where both the producer and injector are slotted; and second, Figure
11b, a
plane where the injector is blanked. The small black arrows represent the
direction of
gas flux in the plane. Note the same clockwise circulation of NCG near the
chamber
edge, but with flow to the production well.
[0035] Figure 12 is a graph, illustrating bitumen production rates under 5
simulated
LSAG recovery conditions, as discussed in Example 2, with sorption
coefficients (k)
varying by a factor of 8000. The recovery rates are so nearly identical that
the
production rate data is essentially indistinguishable for the 5 different
conditions.
[0036] Figure 12 is a graph, illustrating bitumen production rates under 5
simulated
LSAG recovery conditions, as discussed in Example 2, with sorption
coefficients (k)
varying by a factor of 8000. The recovery rates are so nearly identical that
the bitumen
production rate data is essentially indistinguishable for the 5 different
conditions.
[0037] Figure 13 is a graph, illustrating solvent production rates under 5
simulated
LSAG recovery conditions, as discussed in Example 2, with sorption
coefficients (k)
varying by a factor of 8000. The recovery rates are so nearly identical that
the butane
solvent production rate data is essentially indistinguishable for the 5
different conditions.
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[0038] Figure 14 is ternary cross section of a simulated reservoir of
Example 2, in
the IK plane, slicing through the depleted heavy oil chamber, where the shades
of grey
represents degrees of oil depletion falling off towards the periphery of the
heavy oil
depleted chamber.
[0039] Figure 15 is a graph illustrating data from Example 2, showing
bitumen
production rates for a LSAG process (Aerosol Bitumen) compared to bitumen
production rates for a SAGD and for a Solvent Aided Process (SAP).
[0040] Figure 16 is a graph illustrating data from Example 2, showing the
cumulative
steam-oil ratio (CSOR) for a LSAG process (Aerosol CSOR) compared to the CSOR
for
a SAGD process (SAGD CSOR) and for a Solvent Aided Process (SAP CSOR).
[0041] Figure 17 is a graph illustrating data from Example 2, showing the
course of
injection and production rates of various fluids in the course of a LSAG
process
throughout the operating period. Steam injection takes place initially, as
part of the start-
up process, and then ends. Bitumen production is relatively steady throughout
the
process. Injected DSL ("Suspended Solvent") is essentially all recovered
("Produced
Solvent"). NCG injection increases over the course of the operation ("Aerosol
Gas
(Propellant)").
DETAILED DESCRIPTION OF THE INVENTION
[0042] Processes are provided for delivering a diluent/solvent liquid (DSL)
to a
hydrocarbon deposit, such as a heavy oil, using a non-condensing gas (NCG).
The
liquid is swept along by the gas (LSAG), with the liquid being interchangeably
characterized as entrained, dispersed or suspended in the NCG. In this way,
the oil is
mobilized by mixing with the DSL, so that the mobilized oil migrates, for
example by
gravitation or by another form of displacement, to a production well. These
processes
may accordingly involve forms of gravity drainage and/or convective
mobilization in the
context of in situ recovery processes, with the flow of two-phase LSAG fluid
distributing
the DSL to the oil-in-place.
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[0043] The LSAG fluid is a combination of the DSL and NCG, and this
combination
may be provided using a variety of operational approaches. For example, the
DSL may
be introduced to the reservoir in selected volumes, or slugs, alternating with
the
sequential introduction of the NCG. The timing and volume of these sequential
fluid
introductions may be managed so as to provide the desired LSAG flow.
Alternatively,
the DSL and NCG may be introduced simultaneously, with mixing of the two
phases
occurring prior to or during introduction of the LSAG fluid to the reservoir.
The LSAG
fluid may accordingly be formed prior to entering an injection well, or within
the wellbore,
or after the NCG and DSL constituents separately exit the wellbore and then
amalgamate to form the LSAG fluid. These approaches may also be used in
combination. For example, it may be appropriate to form the DSL from multiple
constituents at the surface, with suspension or dispersion of the DSL in the
gas phase
occurring at one or more other points in the process of introducing the LSAG
fluid to the
reservoir. In accordance with the foregoing, as used herein "entrainment"
refers to a
relationship among flowing fluids, such as an NCG and a DSL, whereby the flow
path of
one fluid, such as the NCG, directs or influences the direction of the flow
path of the
other fluid, such as the DSL. Thus, entrainment can include configurations
wherein the
DSL is suspended or dispersed or intimately distributed within the NCG, as
with an
NCG/DSL aerosol or spray. Alternatively, in keeping with the reciprocal
influence on
flow paths, entrainment can include concurrent or sequential volumes, or
slugs, of NCG
and DSL.
[0044] The mixing of the DSL and NCG may involve atomization, for example the
formation of a spray or aerosol, with the DSL forming droplets as the
discontinuous
liquid phase within the continuous NCG gas phase. The LSAG fluid may
accordingly be
formed by a variety of liquid-in-gas dispersions, such as sprays of gas-
suspended liquid
particles. LSAG fluid sprays may for example be defined as having liquid
particle
diameters that are generally greater than about 10 microns. In some
implementations,
the LSAG fluid may form an aerosol, with DSL droplets in the micron to
submicron size
range that are sufficiently small that Brownian motion tends to maintain the
DSL
droplets in suspension within the NCG gas phase (Tien and Payatakes, 1979;
Richard
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Hall, May 2013, Ph.D. Thesis, Clemson University, Numbered 1-1-2013, "Aerosol
Delivery as a Method for Enhancing Remedial Application in Contaminated Vadose
Zones"). In selected embodiments, techniques may be used to stabilize DSL
droplets
within the LSAG fluid, for example by imposing or facilitating the existence
of an
electrical charge on the droplets, as for example has been described in the
context of
aerosols (Vonnegut, et al., Research in Electrical Phenomena Associated with
Aerosols,
Quarterly Report No. 4, April 15 ¨ July 15, 1961, Contract DAI8-108-405-Cm1-
852,
Arthur D. Little, Inc.). For example, droplets which exit an atomizer may be
spontaneously charged, or a charge may be imposed for example by impact on a
surface or by application of an electric field, ionizing radiation or coronal
discharge.
[0045]
The LSAG fluid flow may be orchestrated so that broad distribution of the DSL
within the reservoir is mediated by the managed NCG flow within the porous
medium of
the reservoir. In this context, it will be understood that the phase
characterizations of the
LSAG fluid flow, such as "liquid phase" and "gas phase" and "NCG" are used
herein to
describe aspects of LSAG fluid dispersion. However, it will be appreciated
that LSAG
fluid flows within the reservoir take place in the context of complex phase
equilibria, with
thermodynamic parameters dictating continuous phase changes within the LSAG
fluid,
so that these phase characterizations are not absolute. For example, a portion
of any
particular liquid phase, such as the DSL, will enter the gaseous phase in
equilibrium
with a surrounding gas phase, such as the NCG, so that the gas phase may for
example be saturated with vapour phase of the entrained liquid. Accordingly,
in selected
embodiments, the characterization of the DSL as a liquid, and the NCG as a
gas,
reflects that fact that these phase characteristics apply to the isolated DSL
and NCG
fluids over the relevant range of reservoir temperatures and pressures.
[0046] The DSL may mobilize viscous hydrocarbons by a variety of mechanisms,
for
example by being miscible with the hydrocarbons so as to reduce viscosity,
and/or by
affecting properties such as the interfacial tension of the viscous
hydrocarbons. These
mechanism do not require the imposition of a phase change on the DSL, in
contrast for
example to thermal recovery mechanisms such as SAGD or VAPEX.
14
CA 02935652 2016-07-07
[0047]
Various aspects of the invention involve the use of a non-aqueous or organic
solvent or diluent as the DSL, such as a straight or branched chain, cyclic or
aromatic
hydrocarbon, such as a C3 to C8 alkane, particularly n-alkanes or mixtures
thereof.
These DSLs may for example include one or more C3 to C10 linear or cyclic
alkanes,
alkenes, or alkynes, in substituted or unsubstituted form, or other aliphatic
or aromatic
compounds. Substituents may for example include organic substituents or
heteroatoms
such as halogens. The DSL component or mixture of components may be selected
so
that it will exist substantially in liquid form at recovery process conditions
within the
reservoir, thereby facilitating its eventual drainage by gravity, along with,
or when mixed
with, mobilized oil. Selected embodiments use n-butane as the DSL, or as the
primary
constituent of the DSL. In alternative embodiments, a mixture of solvents may
be
selected such that the mixture approximates the properties of a selected
solvent, such
as butane, such as the density-increasing and/or viscosity-reducing properties
of
butane. The DSL may for example be selected so that when mixed with a
particular
bitumen in a reservoir at a desired ratio it confers a target density on the
resulting
mobilized heavy oil mixture. The DSL may also include a variety of additives,
such as: a
surface active agent (capable of modifying the interfacial tension of
liquids), an
emulsifier, a foaming or defoaming agent, a polymer, solid particulate matter
or a
microbial agent (such as one or more bacterial or viral cultures, which is
capable of
modifying the resident reservoir fluids so that mobility of the resident
hydrocarbons is
increased). The DSL may also be in a variety of physical forms and various
stages of
the process, such as an emulsion or a foam.
[0048] The NCG component of the LSAG fluid may for example be one or more
oxidizing or non-oxidizing gases or mixtures thereof. Examples of NCGs which
are non-
oxidizing include natural gas, stoichiometric exhaust (flue) gas, methane,
nitrogen, and
carbon dioxide. Examples of non-condensing gases which are oxidizing, or
potentially
oxidizing, include air, enriched air, and oxygen. The NCG phase may be
initially
constituted in various degrees of phase equilibrium with the DSL, for example
being
supersaturated or fully saturated or partially saturated or totally
unsaturated.
CA 02935652 2016-07-07
[0049] In alternative embodiments, the injected LSAG fluid may include a
selected
amount of DSL, in combination with an NCG carrier gas, for example (by weight)
1%-
50%, 10%-40%, 20%-30% or about 25%. The relative amount of DSL may
alternatively
be below an upper limit, for example up to 50%, 40%, 30%, 20%, 10% or 5wt% by
weight; and/or above a lower limit, such as below 50%, 40%, 30%, 20%, 10% or
5wt%
by weight; or within any range defined by these upper and lower limits.
[0050] LSAG recovery techniques may be employed at a variety of stages
within the
recovery process, alone or in combination with other recovery techniques. For
example,
LSAG recovery may be initiated at start-up, with the reservoir in a pre-
development
stage (original conditions of temperature and pressure). Alternatively, LSAG
recovery
may be initiated under post start-up conditions, following a prior recovery
process or
other reservoir treatment. In addition, LSAG recovery techniques may be
applied on a
local (i.e., near-wellbore) basis, or throughout the reservoir. LSAG recovery
may
accordingly constitute one or more of the start-up, ramp-up, operational, or
blowdown
phases of a recovery process, alone or in combination with other techniques or
phases
(such as the processes described in the Background). With respect to final
stages of
recovery, LSAG processes may involve a DSL recovery step following hydrocarbon
recovery operations, to recover injected DSLs that remain in the reservoir.
This may for
example involve de-pressuring the reservoir, injection of a DSL-dry NCG,
introduction of
alternative heated fluids, or heating via electrical means.
[0051] The characteristics and constituents of the LSAG fluid may be varied
over
time during the course of a recovery process. For example, the size of the DSL
droplets
may be varied, or the relative amount of the DSL in the LSAG fluid may be
adjusted,
and the chemical components of the DSL and/or the NCG may be varied, for
example
from one stage of recovery to another.
[0052] LSAG processes may be designed to involve aspects of gravity-
dominated
fluid flow. For example, the buoyancy of the LSAG fluid may be tailored to
propel the
injected LSAG fluid upwardly, on a trajectory that brings the LSAG fluid into
contact with
resident viscous hydrocarbons along an ascending path. In turn, the
constituents of the
16
CA 02935652 2016-07-07
DSL may be selected so that, when the DSL droplets adhere to and mix with
resident
hydrocarbons, mobilizing the viscous hydrocarbons, the mobility of those
hydrocarbons
will be increased, and the density of the mobilized hydrocarbons adjusted, so
that they
drain downwardly to a receiving point, such as a production well.
Alternatively, or
additionally, an LSAG recovery process may be tailored to involve selected
convective
flow regimes, instead of or in addition to gravity-dominated flows. In these
circumstances, the path of the LSAG fluid within the reservoir may for example
include
a major horizontal or lateral component of flow.
[0053] LSAG processes may be cyclic, in the sense that the LSAG fluids are
introduced into the reservoir periodically. For example, an LSAG fluid may be
introduced and allowed to soak within the reservoir for a period of time, with
no or
reduced fluid production from the reservoir, and then reservoir fluid
production may be
revived. Cyclic process may for example involve a single well acting
sequentially as
both injector and producer, or an aggregate of such single wells.
Alternatively or
additionally, a cyclic LSAG process may be operated in which the LSAG fluid is
introduced at an injection wellbore while a nearby production well is shut in.
Following a
period of LSAG fluid injection, the injection well may be shut in. Finally,
one or more
production wells may then be opened to production of mobilised fluids. In a
further
variation, LSAG fluid injection may be alternated with injection of other
fluids. For
example, injection of a defined quantity of one or more LSAG fluids may be
followed by
a period of injection of different fluids, such as an NCG alone, in a manner
that uses the
dry NCG to sweep previously injected DSL fluids into the reservoir. In these
cyclic or
alternating processes, the chemical composition, quantity, duration, and
conditions of
state of the alternating injection fluids may be varied widely.
[0054] Various aspects of the invention involve the drilling of one or more
wells that
are situated and operated so as to form a hydrocarbon extraction chamber
within a
reservoir. This may for example include well pairs within a reservoir 11, as
illustrated in
Figure 1, in a pattern that is typically used with SAGD, with each injector
well 13, 19,
23, paired with a corresponding producer well 15, 17 and 21. In this
illustrative
arrangement, each well has a completion 14, 12, 16, 18, 20 and 22 on surface
10, with
17
CA 02935652 2016-07-07
a generally vertical segment leading to the heel of the well, which then
extends along a
generally horizontal segment to the toe of the well. In very general terms, to
provide a
general illustration of scale in selected embodiments, these well pairs may
for example
be drilled in keeping with the following parameters. There may be
approximately 5 m
depth separation between the injection well and production well. The well pair
may for
example average approximately 800 m in length. The lower production well
profile may
generally be targeted so that it is approximately 1 to 2 m above the reservoir
base. As
discussed in more detail below, the development of hydrocarbon extraction
chambers
around each well pair may be illustrated in cross sectional views along axis
24, which is
perpendicular to the longitudinal axial dimension of the horizontal segments
of the well
pairs. A wide variety of alternative arrangements of wells are also available,
for example
well pairs may be used with wedge or infill wells, and the injector and/or
producer wells
may be branches of a multilateral well, for example cooperative multilateral
wells or
"fishbone" multilateral wells. In alternative embodiments, rather than using a
well pair,
one or more single horizontal, inclined or vertical wells may be used for
injection and/or
production and/or venting, thereby adjusting the pattern of LSAG fluid flow
and
associated fluid displacement geometries. Wells may accordingly be configured
in a
wide variety of operational roles, so that the characterization of a well as
being
configured for a particular role, such as injection or production, is
indicative of the
purpose that the well serves rather than any specific mechanical or
topological feature
of the well.
[0055]
Selected aspects of the LSAG process may involve the operational control of
wells, so that the wells function in alternative roles as either sources or
sinks, for NCGs
or DSLs. For example, an accumulation of a dry NCGs in a region may interfere
with
mobilization of hydrocarbons. To counteract this effect, additional wells,
such as vent
wells, may be placed at strategic points in the reservoir so that a portion of
the NCG can
be siphoned off or produced. The produced gas may include some DSL, and the
produced gas may accordingly be processed to remove excess liquids, with
recycling of
the processed gas as NCG carrier gas, and recycling of the recovered liquids
as DSL.
18
CA 02935652 2016-07-07
[0056] In alternative embodiments, recovery processes of various kinds may
be
combined, for example with thermal start-up recovery processes being used
sequentially with processes described herein, including but not limited to,
SAGD and/or
alternative solvent aided processes (SAP), and/or "huff and puff' processes.
For
example, CA 2,844,345 to Gittins, discloses a thermal/solvent oil recovery
process for
producing hydrocarbons using a single vertical or inclined well. In particular
embodiments, LSAG processes may be preceded by alternative start-up
acceleration
techniques, for example to establish communication in the formation between an
injection means and a production means within the single well, or between
injection and
production wells. Alternatively, LSAG processes may be used as an initial
reservoir
conditioning or start-up process, to be following by subsequent recovery
processes. In
select embodiments, thermal techniques may for example be used within, or in
the
vicinity of, production wells, to increase the temperature in the region of
the production
well and thereby avoid the formation of pore-plugging gas hydrates
(clathrates).
Similarly, periodic thermal pulses may be used in conjunction with LSAG
processes, to
clear clathrates from other portions of the reservoir.
[0057] In the case of single well embodiments, fluid communication refers
to fluid
flow in the formation between the injection means (or an injection component)
and the
production means (or a production component) in the single well. For example,
the
injection and production components may be conduits, optionally tubing, and
may be
isolated from one another by way of a packer, by positioning the injection and
production means a suitable distance apart, by varying the geometry of the
tubulars
within the wellbore, by positioning the injection means in the wellbore closer
to the
surface than the production means in the case of a vertical well, or by way of
openings
or perforations in the tubing or well casing over selected wellbore
interval(s) to permit
both outlet of injected fluids and inlet of production fluids. The positioning
of the injection
and production means may be adapted depending on the particular well and
formation.
For example, processes may make use of an injection tubing string which has
openings
only at or towards one end of the horizontal well, for example at the toe end,
to permit
egress of injected fluids, and openings or perforations along the liner or
outer casing of
the wellbore to permit injection into the reservoir of mobilizing fluids over
a selected
19
CA 02935652 2016-07-07
interval of the wellbore. Positioned downstream therefrom along the casing or
liner of
that same wellbore, openings may be provided to permit production from the
reservoir
of mobile and mobilized fluids. In addition, one or more surfactants can be
used to
facilitate or accelerate a single well start-up process, or to improve fluid
communication.
[0058] Alternative aspects of the invention involve completing wells in
various
configurations. Exemplary completions for injector, producer on gas lift,
producer on
electronic submersible pump (ESP) and simulated producer are shown in Figures
2, 3,
4a and 4b respectively.
Example 1: NCG Flow Management
[0059] In accordance with various aspects of the invention, detailed
computational
simulations of reservoir behaviour have been carried out. An initial set of
simulations
illustrates various aspects of NCG flow management, illustrating that the flow
of NCGs
may be orchestrated using a wide variety of operational tools, for example by
imposing
pressure gradients within a reservoir. A further set of simulations
illustrates that NCG
flow management may be used to deliver an entrained liquid to a heavy oil
interface
within a reservoir, with the entrained liquid then acting as a diluent or
solvent to mobilize
the heavy oil for production. These detailed simulations have demonstrated the
ability of
NCGs to effectively sweep the entrained liquid through a formation, in a
process that
may be characterized as providing liquids swept along by gas (LSAG).
Simulation Grid for NCG Flow Management Modeling
[0060] A half element of symmetry was employed to ensure faster run times. The
model had 30 m pay, 3 m bypassed pay and an 800 m long well. There was 31 m of
overburden and 31 m underburden. Grid dimensions were 26 x 64 x 43, for a
total of
71,552 blocks. Block dimensions were as follows:
I ¨ direction: lm 24*2m lm (26 blocks, total length of 50 m)
J ¨ direction: 64*12.5m (64 blocks, total length of 800 m)
K ¨ direction: 16 m8m4m2m 35*1 m2m4m8m 16 m (43 blocks, total
length of 95 m)
CA 02935652 2016-07-07
[0061] The high level of discretization in the J direction was done to
model the
blanking and slotting of casing joins. A typical casing joint is approximately
12-13 m in
length.
Reservoir Properties for NCG Flow Management Modeling
[0062] The grid was populated using the following reservoir variables:
Temperature = 12 C
(1) = 0.33
Kh = 7.0 D
Kv = 4.2 D
Reference pressure of 2,400 kPa at the top of the SAGD pay
Sw = 0.215
So = 0.785
Mass Fraction Oil of Dead Oil = 0.85
Mass Fraction Oil of CH4 = 0.15
[0063] The thermal properties of the reservoir were characterized using two
rock
types. Rock type one represented clean sand and was used to populate a
selected pay,
representing the McMurray formation in Alberta, Canada (within the Mannville
Group in
the Western Canadian Sedimentary Basin). A second rock type representing shale
was
used to populate the over and underburden grid. The properties of the two rock
types
were defined with the following properties:
Rocktype 1 (Sand)
Porosity Reference Pressure = 100 kPa
Compressibility = le-6 1/kPa
Volumetric Heat Capacity 2.39e6 J/(m3*C)
Rock Thermal Conductivity = 196,820 J/(m*day*C)
Water Thermal Conductivity = 552,960 J/(m*day*C)
Oil Thermal Conductivity = 0
Gas Thermal Conductivity = 0
21
CA 02935652 2016-07-07
Rocktype 2 (Shale Overburden & Underburden)
Porosity Reference Pressure = 100 kPa
Compressibility = 1e6 1/kPa
Volumetric Heat Capacity 2.39e6 J/(m3*C)
Rock Thermal Conductivity = 146,880 J/(m*day*C)
Water Thermal Conductivity = 0
Oil Thermal Conductivity = 0
Gas Thermal Conductivity = 0
PVT Data for NCG Flow Management Modeling
[0064] The PVT model consisted of three components; water, dead oil and
methane,
with characteristics as illustrated in Figures 5 and 6.
Relative Permeability for NCG Flow Management Modeling
[0065] The oil-water relative permeability curves have the following
properties:
Connate Water Saturation = 0.2
Critical Water Saturation = 0.2
Residual Oil Saturation = 0.15
Irreducible Oil Saturation = 0.15
Max relative water permeability = 0.559
Max relative oil-water permeability = 0.95
[0066] The oil-gas relative permeability curves have the following
properties:
Critical Gas Saturation = 0.05
Residual Liquid Saturation = 0.3
Max relative gas permeability = 0.72
Max relative oil-gas permeability = 0.95
[0067] Relative permeability properties are illustrated in Figures 7 and 8.
22
CA 02935652 2016-07-07
Operating Constraints for NCG Flow Management Modeling
[0068] The simulation was initiated with a circulation phase in order to
establish inter
wellpair communication. Four numerical wellbore models (FlexwellsTM) were used
to
mimic the operation of the SAGD well pairs during this phase. Circulation
lasted for 2
months and used the following parameters and constraints for well definition
and
operation:
Producer Annulus (Producer Well)
Min Bottom Hole Pressure = 5,100 kPa
ID = 0.159m
OD = 0.178m
Producer Circulation Tubing String (Injector Well)
Max Water Rate = 150 m3/d
Max Bottom Hole Pressure = 8,600 kPa
ID = 0.078
OD = 0.089
Injector Annulus (Producer Well)
Min Bottom Hole Pressure = 4,900 kPa
ID = 0.159
OD = 0.178
Injector Coil Tubing (Injector Well)
Max Water Rate = 150 m3/d
Max Bottom Hole Pressure = 8,600 kPa
ID = 0.04
OD = 0.045
[0069] As exemplified, the SAGD operational phase begins after circulation,
takes
place at low pressure and lasts until the start of blow down. During this
period, three
numerical wellbore models were defined, with completions analogous to that
shown in
Figure 4b, with the following parameters and constraints in order to mimic
SAGD well
pair operation:
Injector Annulus (Shutin)
ID = 0.159
23
CA 02935652 2016-07-07
OD = 0.178
Injector Tubing String (Oprn)
ID = 0.104
OD = 0.134
Injector liner block 1, 1, 14 kept at 2,600 kPa via trigger
Injector Tubing String (Injector Well)
Max Bottom Hole Pressure initiated at 2,900 kPa, but later defined via
trigger
Max Water Rate = 1,200 m3/d
Tubing has 3 steam splitters at 131 m, 331 m and 581 m
1st Sub: 1 cm diameter holes, 0.8 discharge coefficient, 6 holes
2' Sub: 1 cm diameter holes, 0.8 discharge coefficient, 12 holes
3rd Sub: 1 cm diameter holes, 0.95 discharge coefficient, 32 holes
Producer Annulus (Producer Well)
Max Liquid Rate = 200 m3/d
Min Bottom Hole Pressure = 1,900 kPa
Max Steam Production = 10 m3/d CWE
[0070] Simulations carried out with the foregoing parameters to illustrate
aspects of
NCG flow management illustrated that for the first year and half of a typical
SAGD
operational period, gas flow follows a relatively consistent pattern as
illustrated in
Figure 9. Liberated NCG migrates from its place of origin to the top and edges
of the
steam chamber, where it accumulates and is eventually drawn down along the
chamber
wall to the production well. As an illustration of NCG flow management, it was
found that
blanking or slotting the production and injection liner joints can
significantly alter gas
flow. When both joints are slotted the gas behaves as previously described,
flowing
down the chamber wall to the production well. Blanking an injection joint will
alter the
flow of gas so that it flows down towards the producer along the chamber wall
and
through the center of the chamber. The lack of injection prevents steam from
displacing
the NCG and carrying it towards the chamber boundaries, simultaneously
creating a
plane of lower pressure relative to the surrounding regions. This promotes the
backflow
of gas into the chamber and down to the producer. When a joint in the
production well is
24
CA 02935652 2016-07-07
blanked, no production occurs at this location. NCG and any other fluids are
forced to
move parallel to the well pair in order to locate a slotted joint for
production.
[0071] These flow regimes exemplify means of orchestrating fluid production
in the
context of selected reservoir conditions. For example, regions where both the
injector
and producer are slotted may be used to act as regions for removing NCGs.
Computational modeling indicates that, under certain reservoir conditions,
there is little
to no NCG flow where the producer has been blanked, with gas traveling down
the
depletion chamber wall for production where the producer is slotted and down
both the
chamber wall and through the chamber where the injector is blanked.
[0072] Simulations indicate that under selected conditions the NCG flow
regime
begins to alter in a SAGD process as the steam chamber expands, for example at
approximately 2 years into the process as simulated, reflecting changes that
may occur
on alternative time lines in alternative reservoir conditions. These
simulations
demonstrate that NCG productivity of any slotted producer joints not near the
heel may
begin to diminish, with the opposite being true of any producer slotted joints
near the
heel.
[0073] In a mature SAGD system, simulations indicate that NCG continues to
accumulate at the chamber wall along the entire length of the wellpair.
However, cross
sections perpendicular to the wellpair show that the majority of NCG is in a
holding
pattern at the wall of the chamber. NCG is liberated or generated at the
bitumen steam
interface, drawn down to the bottom of the chamber wall, where it reverses
directions
and rises back to the top of the chamber. Figure 10 demonstrates that this
cycle is
repeated regardless of whether or not the injector or producer is slotted or
blanked.
[0074] The foregoing modeling is illustrative of techniques for predicting
and
managing NCG flows. For example, a selected pattern of completions may give
rise to
NCGs flowing towards the heel of a wellpair to be drawn down into a production
well.
The efficiency of gas production at the heel may accordingly be adjusted by
the
completion design of the injection well. For example, regions where the
production well
CA 02935652 2016-07-07
is slotted, but the injector is blanked, may be used to produce more gas than
those
where both wells are slotted, as illustrated in Figure 11.
[0075] In view of the foregoing understanding of NCG flows within a
reservoir, the
recovery processes described herein provides a number of modifications that
can be
made to injection and production systems in order to orchestrate NCG flows for
the
purpose of recovery processes using LSAG. In selected embodiments, LSAG
processes involve arranging the locations of fluid injection to improve
delivery of
entrained liquids by NCG mobilization.
Alternative LSAG Systems
[0076] A number of variations on typical SAGD techniques may be implemented to
orchestrate LSAG recovery processes, as described below. These approaches are
not
mutually exclusive, and any combination of these approaches may be combined in
alternative arrangements.
Adjusting the Number of Blank Joints at the Injector's Heel
[0077] LSAG systems may involve increasing the number of blanked injector
joints
and/or slotted production joints near the heel of a wellpair, to adjust fluid
flows within the
reservoir so as to deliver entrained liquids to an interface with heavy oil in
place. For
example, joints at the injector's heel, which may be slotted in the typical
SAGD
operation, may be blanked in various combinations.
High Injector Landing or Low Producer Landing
[0078] In this arrangement, the injector's intermediate casing point (ICP)
is landed at
a shallower angle higher in the reservoir, so that the heel of the injector
well is in effect
elevated and spaced further apart vertically from the heel of the producer
well. For
example, the injector's ICP may be landed at 86 degrees and several meters
above the
targeted final depth of the horizontal portion of the injector well.
Alternatively, the heel of
the production well may be landed lower in the formation. For example, the
producer's
ICP may be landed at a shallower angle lower in the reservoir, so that the
heel of the
injector well is in effect elevated and spaced further apart vertically from
the heel of the
26
CA 02935652 2016-07-07
injector well. In alternative arrangements, this may be done so as to locate
the ESP
outside of the productive pay, which may help to prevent gases from flowing
directly to
the ESP.
Sinusoidal Injector or Producer Trajectory
[0079] In this arrangement, an injection well may be drilled in a manner
mimicking a
sinusoidal wave. High spots in the well being located at the heel and between
points of
fluid egress from the tubing into the annulus between the tubing and the
casing.
Alternatively, the producer well may be drilled in a manner mimicking a
sinusoidal wave,
for example with low spots located at the heel and between points of fluid
egress at the
injection well.
Vent Wells
[0080] In this arrangement, one or more NCG vent wells may be provided
within the
reservoir to facilitate NCG mobilization. In alternative embodiments, vent
wells may
have a wide variety of locations and orientations, for example including
vertical and/or
horizontal segments. Horizontal segments of vent wells may for example be
orientated
at a strike of 0 to 90 degrees to a selected wellpair, i.e. parallel,
perpendicular or at any
intermediate angle. The trajectory of vent wells may also be varied, so that
the vent
wells are not limited to being flat or of one continuous elevation. In
selected
implementations, the vent wells may have a generally horizontal trajectory
parallel to a
wellpair, and the vent wells may be drilled from the surface. In alternative
implementations, vent wells may for example be drilled as a multilateral
branch from an
injection well. In some vent well completions, inflow control devices (ICDs),
or any other
means to restrict or prevent gas flow in that section of the wellbore, may for
example be
used to control inflow. These variables may for example be adjusted so as to
orchestrate NCG mobilization in a pattern that is conducive to LSAG delivery
of liquids
to a heavy oil interface.
Example 2: LSAG Recovery Process
[0081] This Example illustrates the simulated results of injecting a DSL
entrained in
an NSG as an LSAG fluid in a viscous hydrocarbon (i.e., oil sand) reservoir.
To illustrate
27
CA 02935652 2016-07-07
the robustness of the DSL fluid distribution under varying conditions, the
simulations
included five dramatically different sorption coefficients spanning a range of
values
which differed by a factor of 8000. The LSAG fluid consisted of methane as the
NCG
and butane as the DSL.
[0082] As illustrated in Figures 12 and 13, production performance was
essentially
identical in all five cases. Specifically, the oil rates (Figure 12) and
solvent return rates
(Figure 13) were virtually identical. Details of the reservoir properties,
well configuration
and performance results follow.
[0083] For simulation purposes, the type of reservoir into which the
aerosol was
injected was a typical rich oil sand reservoir, such as that commonly found in
the
McMurray Formation of northeastern Alberta. A summary of salient reservoir
characteristics and basic well orientation data is provided in Table 1. A half
symmetry,
live oil model was used. Block sizes were one meter in the x and z direction
and 800
meters in the y-direction.
TABLE 1: Reservoir Characteristics and Well Orientation
Oil sand thickness 20m
Porosity 33%
Horizontal permeability 6.0 D
Vertical permeability 4.2 D
Initial bitumen saturation 80%
Initial water saturation 20%
Vertical distance between horizontal 5m
injector and producer
_
Horizontal distance between well pairs 100m
[0084] A gravity-dominated recovery process operating in an oil sand was
simulated,
analogous to SAGD in terms of production and injection well configuration. In
keeping
with that approach, the vertical separation between the two horizontal wells
was five
metres. The simulations were carried out in 2D.
28
CA 02935652 2016-07-07
[0085] In anticipation of a large accumulation of NCGs within the reservoir
as a result
of LSAG fluid injection, the well configuration for this embodiment also
included a series
of vent wells completed near the top of the reservoir to siphon off excess
gas. This well
configuration is illustrated in Figure 14, which also provides a snapshot of
the bitumen
saturation at a point in time during the course of the LSAG fluid injection
process. The
vent wells were configured so that wells that are further from the injection
point had
lower production pressure and thus no short circuiting of gases occurred.
[0086] Following the application of a three-month start-up sequence in
common use
in oil sands in situ recovery operations to establish communication between
the
overlying horizontal injection well and the underlying horizontal producing
well, LSAG
fluid injection was initiated at the injector. The LSAG fluid consisted of 75
weight %
methane gas as the continuous phase and 25 weight % butane as the dispersed
liquid
droplet phase. In this illustrative embodiment, no thermal agents were
introduced into,
or induced within, the reservoir during the course of the LSAG production
process.
[0087] Performance results demonstrate that the LSAG fluid aerosol is
effective in
contacting and mobilizing viscous hydrocarbons and in facilitating bitumen
production.
This is illustrated in Figure 15 which compares bitumen production rates for
the subject
invention to the corresponding rates for a SAGD process and for a Solvent
Aided
Process (SAP), both of which are thermal steam-based processes. Note that the
oil
production curve for SAGD and SAP stops when SAGD reaches 70% recovery. For
SAP, butane was used as the solvent and was injected at 10wt% along with
steam. In
all cases maximum injection pressure was 2500kPa. The agglomeration and
adsorption
of LSAG fluid droplets into the continuous oleic phase was modeled using a
first-order
reaction as in Equation 5-8 in [Aerosol Delivery as a Method for Enhancing
Remedial
Application in Contaminated Vadose Zones, Richard Hall, Clemson University,
2013].
[0088] As indicated, bitumen production rates are lower for the LSAG
process than
for the two thermal alternatives, although cumulative bitumen production
levels are
comparable. However, as one would expect, and as illustrated in Figure 16, the
29
CA 02935652 2016-07-07
cumulative steam-oil ratio (CSOR) is dramatically lower in the case of the
aerosol LSAG
process. Figure 17 illustrates the course of injection and production rates of
the subject
invention throughout the operating period, and shows that a very large
percentage of
the injected solvent is recovered during production.
[0089] The relative uniformity of outcomes, irrespective of the choice of
sorption
coefficient in each simulation run, illustrates that effective recovery of
bitumen resources
may be achieved using a very wide variety of LSAG fluids and operational
parameters.
Conclusion
[0090] Although various embodiments of the invention are disclosed herein,
many
adaptations and modifications may be made within the scope of the invention in
accordance with the common general knowledge of those skilled in this art. For
example, any one or more of the injection, production or vent wells may be
adapted
from well segments that have served or serve a different purpose, so that the
well
segment may be re-purposed to carry out aspects of the invention, including
for
example the use of multilateral wells as injection, production and/or vent
wells. Such
modifications include the substitution of known equivalents for any aspect of
the
invention in order to achieve the same result in substantially the same way.
Numeric
ranges are inclusive of the numbers defining the range. The word "comprising"
is used
herein as an open-ended term, substantially equivalent to the phrase
"including, but not
limited to", and the word "comprises" has a corresponding meaning. As used
herein, the
singular forms "a", "an" and "the" include plural referents unless the context
clearly
dictates otherwise. Thus, for example, reference to "a thing" includes more
than one
such thing. Citation of references herein is not an admission that such
references are
prior art to the present invention. Any priority document(s) and all
publications, including
but not limited to patents and patent applications, cited in this
specification are
incorporated herein by reference as if each individual publication were
specifically and
individually indicated to be incorporated by reference herein and as though
fully set forth
herein. The invention includes all embodiments and variations substantially as
hereinbefore described and with reference to the examples and drawings.
