Note: Descriptions are shown in the official language in which they were submitted.
CA 02937710 2016-07-29
VERTICAL STAGING WITH HORIZONTAL PRODUCTION IN HEAVY OIL
EXTRACTION
FIELD OF THE INVENTION
[0001]
The invention is in the field of hydrocarbon reservoir engineering,
particularly
the arrangement and operation of wells 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 in a formation 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, oil sands,
or
(formerly) tar 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 mobilizes 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
well remains located at the bottom of the steam chamber in an appropriate
position to
collect mobilized hydrocarbons.
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[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.
[0006] A wide variety of alternative enhanced or in situ recovery processes
may be
used that employ thermal and non-thermal components to mobilize oil. A wide
variety of
processes have been described that use hydrocarbon solvents in addition to
steam, or
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CA 02937710 2016-07-29
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] 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
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.
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[0008] 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
hydrocarbons is not necessarily a process that produces exclusively petroleum
or
hydrocarbons, respectively.
[0009] "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.
[0010] 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
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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.
[0011] 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 (formerly) "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
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.
[0012] 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
[0013] Aspects of the invention involve hydrocarbon recovery from heavy oil
reservoirs that take advantage of a particular geometry of injection and
production wells.
CA 02937710 2016-07-29
In select embodiments, a hydrocarbon recovery zone bearing a heavy oil may be
characterized as having a longitudinal axis formed by:
i) a horizontal production well (analogous in some embodiments to a
SAGD production well); and,
ii) a plurality of vertical injection wells that are horizontally offset
along
the longitudinal axis of the recovery zone, each injection well terminating at
an
injection well bottom that is juxtaposed to and vertically spaced apart above
the
horizontal segment of the production well.
In this arrangement, the production well is characterized by having one or
more
horizontal segments, or dimensions, that extend along the longitudinal axis of
the
recovery zone. In addition to those horizontal segments or dimensions,
production wells
may have a very wide variety of trajectories, for example with vertical or
lateral
deviations. Similarly, the vertical injection wells are characterized as
having a vertical
component of well trajectory, and this may be within the context of a wide
variety of
radial or horizontal deviations. The plurality of injection wells may for
example be
characterized as having generally parallel vertical segments, with this
conceptual
generality of well alignment permitting a very wide range of deviations from
geometrically true parallel alignment.
[0014] In one aspect of the invention, an arrangement of vertical injection
wells along
the longitudinal axis of a horizontal production well permits the initiation
of
contemporaneous mobilization and production of heavy oil. This may be
accomplished
by injecting an injection fluid, such as steam, water and/or solvent, through
the injection
wells to injection points proximal to the injection well bottoms, which are
situated just
above the horizontal producer. The injection fluid then mobilizes heavy oil in
the vicinity
of the production well, with mobilized heavy oil flowing by a gravity
dominated process
to the production well. In this way, an expanding recovery zone forms a
chamber
depleted of hydrocarbons, such as a steam chamber, which may be formed between
each injection well bottom and the production well.
[0015] Once hydrocarbon production is initiated, the injection points of
one or more
injection wells may be vertically re-arranged, so that in a selected injection
well the
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CA 02937710 2016-07-29
injection point moves upwardly away from the horizontal segment of the
production well,
within the expanding chamber depleted of hydrocarbons. Injection and
production of
fluids may be continued, recovering mobilized heavy oil from the reservoir
through the
production well while injecting the injection fluid through the injection
points, so that the
expanding chambers depleted of hydrocarbons associated with a plurality of
injection
wells coalesce to form one or more common chambers.
[0016] In select embodiments, the reservoir may include a plurality of
vertically
spaced apart stratified recovery zones, the stratified recovery zones each
being
separated by one or more heterogeneous barriers, designated herein as barrier
strata,
in the formation. The barrier strata may for example be defined as having
reduced
permeability compared to adjacent recovery zones. These low permeability zones
may
for example include mud drapes, clasts, sandy inclined heterolithic
stratification (IHS),
muddy IHS, mudstone and/or shales. In formations of this kind, the step of
vertically re-
arranging the injection points of one or more injection wells may involve
moving the
injection point in an injection well from below a barrier strata to above a
barrier strata.
The plurality of vertically spaced apart stratified recovery zones may for
example
include recovery zones in two or more geological formations, such as zones
within the
Wabiskaw and McMurray formations, Alternatively, the recovery zones may be
present
within a single heterogeneous geological formation. In some embodiments, one
or more
injection arms may be drilled on an existing vertical well, and the injection
point in that
injection well may be moved from below a barrier strata to a position in the
new injection
arm above the barrier strata. In this way, an arm or sidetrack from an
existing vertical
well may be used to circumvent a barrier strata. To facilitate the
identification of barrier
strata, and provide a variety of data that may be used to optimize recovery
processes,
aspects of the process may involve data logging one or more of the injection
wells to
obtain stratigraphic information about the formation. This may for example
take place
before, during or after recovery processes.
[0017] Horizontal segments of a production well may for example be drilled
by
ranging from one vertical well to the next along the longitudinal axis of the
recovery
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CA 02937710 2016-07-29
zone. Alternatively, one or more of the vertical wells may be drilled by
ranging to the
horizontal segment of the production well along the longitudinal axis.
[0018] In alternative aspects of the process, fluids may be produced
through one or
more of the injection wells, for example using the injection wells as vent
wells to vent
non-condensing gases from collection points within an upper portion of the
recovery
zone.
BRIEF DESCRIPTION OF THE DRAWINGS
[0019] Figure 1 is a schematic illustration of a well pattern in
longitudinal cross
section, showing four vertical injector wells paired with a horizontal
(denoted "Hz")
producer well within the hydrocarbon rich pay zone of the formation.
[0020] Figure 2 is a schematic cross sectional view of an elevated
injection point in
a vertical injection well.
[0021] Figure 3 is a schematic illustration of a simulated 3D model of a
stratified
heavy oil reservoir, showing areas of differing permeability and fluid
saturation as is
typical of various oil sand reservoirs, such as the Grand Rapids, Clearwater,
Wabiskaw
and McMurray formations in Alberta, Canada. Porosity is indicated as shown on
the
scale provided.
[0022] Figure 4 is a schematic illustration of a localized redirection in a
vertical well,
to circumvent a barrier zone in a stratified formation.
[0023] Figure 5 is a ternary cross section through the longitudinal axis of
a typical
SAGD well pair, 100 days into a simulated circulatory start-up process,
illustrating the
temperature profile within the reservoir.
[0024] Figure 6 is a ternary cross section through the longitudinal axis of
a typical
SAGD well pair, as illustrated in Figure 5, 50 days into a simulated SAGD
process,
illustrating the growing steam chamber in temperature profile within the
reservoir.
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[0025] Figure 7 is a series of three cross sections through the
longitudinal axis of a
reservoir undergoing production using four vertical injector wells working in
concert with
a horizontal production well, showing successive stages of steam chamber
development in temperature profile, at 20, 100, and 250 days following
initiation of
recovery operations.
[0026] Figure 8 shows two cross sections through the longitudinal axis of
reservoirs,
illustrating oil saturation after 508 days in reservoirs undergoing
alternative production
operations, with the top section showing oil saturation in a reservoir
undergoing
recovery using four vertical injector wells working in concert with a
horizontal production
well, and the bottom section showing oil saturation using a typical SAGD
recovery
operation.
[0027] Figure 9 illustrates the temperature profile in a cross section
through the
longitudinal axis of a heterogeneous reservoir undergoing production using
four vertical
injector wells working in concert with a horizontal production well,
illustrating the effects
of moving a steam injection point above an impermeable shale zone in one of
the
vertical wells (second from left).
[0028] Figure 10 shows two cross sections through the longitudinal axis of
reservoirs, illustrating oil saturation after 508 days in heterogeneous
reservoirs having
an impermeable shale zone undergoing alternative production operations, with
the top
section showing oil saturation in a reservoir undergoing recovery using four
vertical
injector wells working in concert with a horizontal production well, and the
bottom
section showing oil saturation using a typical SAGD recovery operation, with
the shale
zone in the region of the second from left vertical well as illustrated in
Figure 9.
[0029] Figure 11 is a graph illustrating cumulative oil production (COP) in
alternative
production scenarios, with curves from top to bottom in the legend showing COP
for:
SAGD production in a homogeneous reservoir; vertical injectors with horizontal
9
CA 02937710 2016-07-29
production (VIHP) in a homogeneous reservoir; SAGD production in a
heterogeneous
reservoir; and VIHP in a heterogeneous reservoir.
[0030] Figure 12 is a graph illustrating cumulative steam injection (CSI)
in
alternative production scenarios, with curves in the legend showing CSI for:
SAGD
steam injection in a heterogeneous reservoir; vertical injectors with
horizontal
production (VIHP) in a homogeneous reservoir (broken line overlapping CSI for
vertical
injectors with horizontal production (VIHP) in a heterogeneous reservoir); and
SAGD
steam injection in a homogeneous reservoir.
[0031] Figure 13 is a graph illustrating cumulative steam to oil ratio
(CSOR) in
alternative production scenarios in a heterogeneous reservoir (results for the
homogeneous reservoir were essentially the same).
DETAILED DESCRIPTION OF THE INVENTION
[0032] Aspects of the invention involve staging of hydrocarbon recovery from
heavy
oil reservoirs, re-configuring vertical injection wells to cooperate
differently over time
with a horizontal production well. For example, in an initial start-up stage
of production,
the vertical injection wells may be operated with fluid injection points in
close proximity
to the horizontal producer, and this has been found to accelerate oil
production, with
mobilization and production of oil being generally contemporaneous. In this
way, lengthy
and energetically expensive start-up processes, for example circulation, may
be
avoided.
[0033] Once hydrocarbon production is initiated, the injection points of
one or more
injection wells may be re-arranged. This may be particularly advantageous in
heterogeneous reservoirs, as for example illustrated in Figure 3 (and
described in Hein
et al., Earth Sciences Report 2000-07, An Atlas of Lithofacies of the McMurray
Formation, Athabasca Oil Sands Deposit, Northeastern Alberta: Surface and
Subsurface). In reservoirs of this kind, recovery zones may be stratified,
each being
separated by one or more heterogeneous barrier strata in the formation. In
this
CA 02937710 2016-07-29
circumstance, vertical wells that are to be used in recovery processes as
injection wells
may also be used as stratigraphic wells, with data logging in one or more of
the vertical
wells providing stratigraphic information about the formation, before, during
or after
recovery processes (as for example described in Tittman, Geophysical Well
Logging:
Excerpted From Methods of Experimental Physics, Elsevier, Dec 2, 2012).
Additional
stratigraphic wells may also of course be used to provide this kind of
information about
a particular formation. As schematically illustrated in Figure 4,
stratigraphic information
of this kind may be used to determine optimal localized redirection of the
vertical wells
based on geology, for example to circumvent an impermeable strata, as
illustrated.
Alternatively, this stratigraphic information may be used to determine optimal
positioning
of steam injection points, for example facilitating the movement of the
injection point in
an injection well from below a barrier strata to above a barrier strata.
[0034] In alternative aspects of the invention, a wide variety of drilling
techniques
may be used, including directional drilling techniques (as for example
described in Chin
et al., Measurement While Drilling (MWD) Signal Analysis, Optimization and
Design,
John Wiley & Sons, Apr 16, 2014). For example, horizontal segments of a
production
well may for example be drilled by ranging from one vertical well to the next
along the
longitudinal axis of the recovery zone. Alternatively, one or more of the
vertical wells
may be drilled by ranging to the horizontal segment of the production well
along the
longitudinal axis. In a further alternative aspect of the invention, one or
more vertical
wells may be paired with an existing horizontal well, for example, a
multilateral well, an
infill well, or a well drilled using Wedge WellTM technology (as for example
described in
Canadian Patent No. 2,591,498). This may be advantageous in retrofitting
existing wells
or facilities associated with heterogeneous reservoirs.
[0035] A wide variety of well completions may be used in alternative aspects
of the
processes described herein (as for example described in Renpu, Advanced Well
Completion Engineering, Gulf Professional Publishing, Aug 23, 2011; or, in
Speight, J.,
Heavy Oil Production Processes, Gulf Professional Publishing, Mar 5, 2013).
For
example, in alternative aspects of the process, fluids may be produced through
one or
more of the injection wells, for example using the injection wells as vent
wells to vent
11
non-condensing gases from collection points within a selected zone, such as an
upper portion of
the recovery zone.
[0036] In select embodiments, the barrier may separate recovery zones in
different geological
formations or within a single formation, and the step of vertically re-
arranging the injection points
of one or more injection wells may involve moving the injection point in an
injection well from
below the barrier to above the barrier. Fluids may be produced through one or
more of the
injection wells, for example using the injection wells to drain the fluids for
recovery through a
production well.
[0037] Various aspects of the invention may involve the use of a wide variety
of injection fluids,
for example being heated or not heated. Water, steam and/or nonaqueous or
organic solvents or
diluents may for example be used. Non-aqueous injection fluids may for example
include straight
or branched chain, cyclic or aromatic hydrocarbons, such as a C3 to C 10
linear or cyclic alkane,
particularly n-alkanes or mixtures thereof, 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. Injection fluids 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).
Example: Vertical Injection Staging with Horizontal Production
[0038] In accordance with various aspects of the invention, detailed
computational
simulations of reservoir behaviour have been carried out. Figure 1 illustrates
aspects of this
computation model, showing a modeled well pattern in longitudinal cross
section, showing 4
vertical injector wells 12 paired with a horizontal producer well 14 within
the hydrocarbon rich
pay zone of the formation, and further illustrating a first configuration 16
with injecting close to
the Hz producer and a second configuration 18 with injection from higher
points in the vertical
direction. Aspects of the model involve vertically repositioning fluid
injection points, as
schematically illustrated in Figure 2 where an embodiment is illustrated in
which steam
injection 20 is occurring 5 meters above the producer, particularly in the
context of
heterogeneous reservoir environments, as illustrated in Figure 3. These
12
Date recue/Date received 2023-05-04
CA 02937710 2016-07-29
detailed simulations have demonstrated the ability to expedite the initiation
of oil
production and adapt recovery techniques to improve production in
heterogeneous
reservoirs, using a process involving vertical injection with horizontal
production (VIHP).
Simulation Models: SAGD and VIHP
[0039] SAGD:
Reservoir Components: fluid water, bitumen, methane, sand non-permeable
shale.
Reservoir X,Y,Z -50 m, 800 m, 30 m; Initially, reservoir at T=12 C, P=3 MPa,
Sw=20% (water saturation), So=80% (oil saturation), methane within oleic phase
is
16%; Permeabilities (in darcys): X,Y,Z: 6 d, 6 d, 5 d and porosity at 33%.
Sw=60%,
So=40%. Overburden and underburden are coupled vertically to the reservoir.
Completions: Injector casing length 800 m with outer diameter at 177.8e-3 m
and
inner diameter at 159.4e-3 m. Injector tubing with outer diameter at 134.3e-3
m and inner
diameter at 100.5e-3 m. Production casing length 800 m with outer diameter at
177.8e-3
m and inner diameter at 159.4e-3 m. Both injector and producer casing fully
perforated
with injector skin at 2 and c_factor at 0.75 and producer skin at 50 and
c_factor at 0.75
to account for suitable fluid transmissibility.
[0040] VIHP:
Reservoir Components: fluid water, bitumen, methane, sand, non-permeable
shale.
Reservoir X,Y,Z -50 m, 800 m, 30 m; Initially, reservoir at T=12 C, P=3 MPa,
Sw=20%, So=80%, methane within oleic phase is 16%; Permeabilities: X, Y, Z: 6,
6, 5 d
and porosity at 33%. Sw=60%, So=40%. Overburden and underburden are coupled
vertically to the reservoir.
Completions: Production casing length 800 m with outer diameter at 177.8e-3 m
and inner diameter at 159.4e-3 m. The producer casing fully perforated with
injector skin
at 2 and c_factor at 0.75 and producer skin at 50 and c_factor at 0.75 to
account for
suitable fluid transmissibility.
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CA 02937710 2016-07-29
[0041] The fluid injection pattern during the start-up phase was different
for SAGD
and VIHP. In VIHP, start-up was carried out by injecting 100 tonnes/day (t/d)
of steam
about 1 m above the horizontal producer for 50 days. In SAGD, start-up was
carried out
by injecting and circulating about 5000 tonnes of steam (half symmetry model)
in the
injection and production wells (as illustrated in Figure 5). A person of skill
in the art will
understand that SAGD start-up circulation rates may be higher (as for example
described in Yuan, J.-Y. & McFarlane, R., Journal of Canadian Petroleum
Technology,
January 1, 2011, pp. 20-32, Society of Petroleum Engineers).
[0042] Steam injection in the operational phase of both the SAGD and VIHP
operations was equilibrated, in the sense that the SAGD steam injection rates
were also
used to inject steam via the re-positioned (elevated) vertical injectors. In
effect, the
steam injected in the SAGD operation, which passed through 4 multi-splitter
flow control
devices (FCDs), was introduced via the 4 vertical wells. In the operational
phase of
SAGD, steam is injected at the heel of the injector tubing and controlled on
3.1 MPa
injection. Trickle sources with insignificant stimulation rate were introduced
to enhance
flow via the steam splitters (subs), and these were shut in after 20 days. The
four multi-
splitters were placed at 20e-3 m, 28e-3 m, 40e-3 m, and 56.57e-3 m, introduced
in
sections 3, 7, 11, and 15 of the injector tubing respectively, with discharge
coefficients
at 0.7, 0.73, 0.81, and 0.95 respectively. The producer was controlled on gas
production of 10 m3/day to allow fluid buildup around the producer with a sub-
cool of at
least 10 C. The production constraint did not change during all simulations.
The
temperature profile of the SAGD steam chamber after 550 days is shown in
Figure 6.
[0043] Figure 7 illustrates the modeled VIHP steam chamber development, with
the
steam injection points initially 1 m above the horizontal producer for 50
days, and then
re-positioned upwardly to injection points 5 m above the horizontal segment of
the
producer (also illustrated in Figure 1). As illustrated, VIHP initially
developed localized
steam chambers, and at this stage the production well was producing condensed
water
with bitumen essentially contemporaneously with start-up of injection. As
modeled, the
producer was able to produce a bitumen-water emulsion 10 days after initiating
steam
14
CA 02937710 2016-07-29
injection through the vertical wells, with the producer constraint at steam
production of
tid.
[0044] Figure 8 provides a comparison of the oil saturation profiles
achieved by
SAGD and VIHP operations at 508 days. As illustrated, VIHP (top frame of
Figure 8)
recovers oil more rapidly at the upper sections of the reservoir than SAGD
(bottom
frame of Figure 8).
[0046] To model a heterogeneous reservoir, a non-permeable block was
introduced
as a variation on the homogeneous simulation set-up, both for the SAGD and the
VIHP
injector cases. As illustrated in Figure 9, one aspect of this adaptation is
the ability in
VIHP to adjust an injection point to position it above an impermeable barrier
layer.
Figure 10 illustrates the effect of this adaptation, showing accelerated oil
production by
VIHP (top panel) compared to SAGD (bottom panel) in the heterogeneous
reservoir
environment.
[0046] The numerical results of the SAGO and VIHP simulations are provided in
the
graphs of Figures 11, 12 and 13. By 500 days, in both heterogeneous and
homogeneous simulations, oil production was accelerated by about 20% using
VIHP
compared to SAGD. The VIHP method initially required more steam to be
injected,
compared to the circulation phase of SAGD. Consequently, by 500 days 13% more
steam was injected in VIHP compared to SAGD. The overall cumulative steam to
oil
ratio (CSOR) in both VIHP and SAGD declined over time, from about 2 for SAGD
to
about 1.75 for VIM:). In alternative embodiments, steam injection in VIHP may
of course
vary. In this Example, a very generous amount of steam of 100 t/d was injected
for the
first 50 days. Similar studies showed that, in alternative processes, about 60
t/d per well
could be injected to achieve pseudo-steam chambers development with
communication
between the injectors and the horizontal producer.
Conclusion
[0047] 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. The invention includes all
embodiments and variations substantially as hereinbefore described and with
reference to the examples and drawings.
16
Date recue/Date received 2023-05-04
