Note: Descriptions are shown in the official language in which they were submitted.
HEAVY OIL SOLVENT RECOVERY PROCESSES USING ARTIFICIALLY INJECTED
COMPOSITE BARRIERS
FIELD OF THE INVENTION
[0001] The invention is in the field of hydrocarbon reservoir engineering,
particularly
recovery processes that make use of solvents in heavy oil reservoirs.
BACKGROUND OF THE INVENTION
[0002] Hydrocarbons in some subterranean deposits of viscous hydrocarbons
can
be extracted in-situ by lowering the viscosity of the hydrocarbons to mobilize
them so
that they 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 (previously) 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 thermal recovery techniques, such as injecting a heated fluid,
typically steam,
into the reservoir from an injection well. One process of this kind is steam-
assisted
gravity drainage (SAGD), involving a horizontal well pair to facilitate steam
injection and
oil production.
[0003] The SAGD process is in widespread use to recover heavy hydrocarbons
from
the Lower Cretaceous McMurray Formation, within the Athabasca Oil Sands of
northeastern Alberta, Canada. The geology of this region is emblematic of the
geological complexities associated with many heavy oil bearing formations. In
general
terms, a thick sequence of marine shales and siltstones of the Clearwater
Formation
unconformably overlies the McMurray Formation in most areas of northeastern
Alberta.
In some areas, glauconitic sandstones of the Wabiskaw member are present at
the
base of the Clearwater. The Grand Rapids Formation overlies the Clearwater
Formation, and quaternary deposits unconformably overlie the Cretaceous
section. The
pattern of hydrocarbon deposits within this geological context is complex and
varied,
and includes zones disposed towards the top or bottom of heavy oil deposits
that have
distinct fluid mobility characteristics. These zones include, for example, top
water zones,
bottom water zones, gas caps (including top gas zones that have been produced,
and
therefore have reduced pressure), neighbouring chambers depleted of oil, and
lower
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permeability fades that present significant vertical and/or horizontal fluid
flow barriers.
Collectively these zones may be called "lean" or "thief' zones, reflecting the
effect of
these zones on hydrocarbon recovery processes that use an injected fluid to
improve
mobility of the oil. In some cases, more than one such secondary zone may be
present.
[0004] Atypical SAGD process is disclosed in Canadian Patent No. 1,130,201
issued on 24 August 1982, in which the functional unit involves two wells that
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 hydrocarbons to create a "steam chamber" in the reservoir around and
above
the horizontal segment of the 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
typically 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 and to ensure that the production well remains located at the
bottom of
the steam chamber in an appropriate position to collect mobilized
hydrocarbons.
[0005] A wide variety of alternative enhanced or in-situ recovery processes
may be
used that employ thermal and non-thermal components to mobilize oil. For
example, 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
No.
2,299,790 describes methods for stimulating heavy oil production using a
propane
vapor. 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).
VAPEX, warm VAPEX and hybrid VAPEX approaches have been addressed in a
technology brief (James, L. A., et al. J. Can. Petro. Tech., Vol. 47, No. 4,
pp. 1-7, 2008).
Processes for cyclic steam stimulation of vertical wells using hydrocarbon
solvents have
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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). 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).
[0006] The complexities associated with heavy oil recovery processes
involving
solvents are considerable, as for example, illustrated by Canadian Patent
Application
No. 2,660,227, which describes numerical simulations of alternative 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). These considerable solvent flow complexities
are
further exacerbated by geological features such as lean zones or thief zones
towards
the top or bottom of the reservoir, which provide avenues for solvent to
dissipate away
from a recovery zone, or otherwise impede the effective flow of solvents and
mobilized
hydrocarbons.
[0007] 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. In the context of the
present
application, the words "petroleum" and "hydrocarbon" are used to refer to
mixtures of
widely varying composition. The production of petroleum from a reservoir
necessarily
involves the production of hydrocarbons, but is not limited to hydrocarbon
production
and may include, for example, trace quantities of metals (e.g. Fe, Ni, Cu, V).
Similarly,
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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. "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 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.
[0008] 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
1,000 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.
[0009] 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 "oil sands" reservoir is generally
comprised of strata
of sand or sandstone containing petroleum. A "zone" in a reservoir is 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
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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. A pay zone is a reservoir volume having hydrocarbons
that can
be recovered economically.
[0010] "Thermal recovery" or "thermal stimulation" refers to enhanced oil
recovery
techniques that involve delivering thermal energy to a petroleum resource, for
example
to a heavy oil reservoir. There are a significant number of thermal recovery
techniques
other than SAGD, such as cyclic steam stimulation (CSS), in-situ combustion,
hot water
flooding, steam flooding and electrical heating. In general, thermal energy is
provided to
reduce the viscosity of the petroleum to facilitate production.
[0011] A "chamber" within a reservoir or formation is a region that is in
fluid/pressure
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.
[0012] "Reservoir compartmentalization" is a term used to describe the
segregation
of a petroleum accumulation into a number of distinct fluid/pressure
compartments. In
general, this segregation takes place when fluid flow is prevented across
sealed
boundaries in the reservoir. These boundaries may for example be caused by a
variety
of geological and fluid dynamic factors, involving: static seals that are
completely sealed
and capable of withholding (trapping) petroleum deposits, or other fluids,
over
geological time; and dynamic seals that are low to very low permeability flow
barriers
that significantly reduce fluid cross-flow to rates that are sufficiently slow
to cause the
segregated chambers to have independent fluid pressure dynamics, although
fluids and
pressures may equilibrate across a dynamic seal over geological time-scales
(Reservoir
compartmentalization: an introduction, Jolley et al., Geological Society,
London, Special
Publications 2010, v. 347, p. 1-8). A reservoir compartment may be
hydraulically
confined, so that fluids are prevented from moving beyond the compartment by
sealed
boundaries confining the compartment.
CA 3008545 2018-06-15
SUMMARY OF THE INVENTION
[0013] The present disclosure involves the production of hydrocarbons,
using a
buoyant solvent, from a reservoir compartment that has been sealed with an
artificial
composite seal, the artificial composite seal being formed by the combined
effect of an
injected blocking agent and in-situ bitumen, so that the barrier is a
functional composite
of blocking agent and bitumen. The buoyant solvent may for example be a light
hydrocarbon solvent, and is selected on the basis that it is miscible with,
and capable of
enhancing the mobility of, the reservoir hydrocarbons. As such, the solvent is
deployed
as a mobilizing fluid, comprising for example one or more C3 through C10
linear,
branched, or cyclic alkanes, alkenes, or alkynes, in substituted or
unsubstituted form, or
other aliphatic or aromatic compounds. Select embodiments may for example use
an n-
alkane, for example n-propane or n-butane. The mobilizing fluid comprising the
buoyant
solvent may be injected at a relatively low temperature, for example at or
below 140 C.
The use of relatively low mobilization temperatures is advantageous because it
reduces
the need for thermal resiliency in the barrier, thereby facilitating the
composite seal that
is necessary to contain the relatively buoyant solvent.
[0014] In select embodiments, processes are provided for mobilizing fluids
in a
subterranean formation that includes a hydrocarbon reservoir bearing heavy
oil, the
reservoir having a primary heavy oil compartment hydraulically connected to
(in fluid
communication with) an overlying secondary zone of reduced (for example
substantially
lacking) heavy oil saturation compared to the primary compartment, such as a
gas
zone, a water zone, a neighbouring chamber depleted of oil, or a zone
including lower
permeability facies that present significant vertical and/or horizontal fluid
flow barriers. A
blocking agent may be injected, for example as a fluid, so that it hardens to
form a
laterally disposed composite seal juxtaposed to a heavy oil saturated top
portion of the
primary heavy oil compartment. The blocking agent may for example be a
polymeric
resin, such as an epoxy resin, a phenolic resin, or a furan resin, and may
also be
formed with gels or waxes. The blocking agent may include a polymeric resin, a
gel, a
wax, or a combination thereof. The secondary zone may have a sufficient
mobility to
allow the blocking agent to be injected, for example, the blocking agent may
have an
injected viscosity of about 100 cP - 800 cP The blocking agent may be injected
through
one or more blocking agent injection (or injector) wells, which may for
example include
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CA 3008545 2018-06-15
sidetracks or laterals, so that the composite seal circumferentially engages
with
underlying adjacent heavy oil in the primary heavy oil compartment. The
circumferential
engagement may have a wide variety of geometries, each reflecting a pattern in
which
the perimeter of the composite seal is positioned with respect to an
underlying layer of
bitumen so as to contain a buoyant solvent from migrating into the secondary
zone. In
effect, the composite seal and the underlying adjacent heavy oil together form
an at
least partially solvent-resistant permeability barrier in the reservoir (being
partially
solvent-resistant in that the permeability barrier enhances the retention of
solvent in the
primary compartment during recovery operations, compared to a degree of
solvent loss
that would be experienced in the absence of the barrier). In this way, the
artificial barrier
acts to hydraulically confine the primary heavy oil compartment.
[0015] Before or after injecting the blocking agent, a solvent-based
recovery
technique may be applied to the primary heavy oil compartment to mobilize
heavy oil
therein and form a recovery zone depleted of heavy oil. In the course of
recovery
operations, a mobilizing fluid is applied to the primary heavy oil compartment
to deliver
a buoyant solvent to the primary heavy oil compartment. Subsequently, the
buoyant
solvent rises within the primary heavy oil compartment as the recovery zone
expands,
the buoyant solvent being confined at the top of the primary heavy oil
compartment by
the composite seal.
[0016] The integrity of the composite seal and permeability barrier may be
monitored, for example by measuring conditions in the blocking agent injection
well that
reflect the hydraulic isolation of the primary heavy oil compartment from the
secondary
zone. Monitoring of this kind may disclose a breach in the integrity of the
composite seal
or the permeability barrier, and in that circumstance further steps of
injecting blocking
agent may be undertaken to augment the composite seal and the permeability
barrier.
There may be other reasons for injecting additional blocking agent from time
to time, so
that the process may involve multiple temporally discrete injection steps.
[0017] The solvent-based recovery technique may for example be a solvent-
only
recovery technique, or may include a staged hybrid recovery technique
comprising a
thermal recovery stage, such as SAGD, and a solvent recovery stage. The
solvent-
based recovery technique may for example involve a reduced-temperature solvent
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CA 3008545 2018-06-15
recovery stage, for example being carried out below a temperature of at or
below about
140 C.
BRIEF DESCRIPTION OF THE DRAWINGS
[0018] Figure 1 is a schematic illustration of a typical heavy oil recovery
well pattern,
showing paired injector (injection) and producer (production) wells (well
pairs), each well
having a heel and a toe within the hydrocarbon rich pay zone of the formation.
[0019] Figure 2 is schematic illustration of Cretaceous stratigraphy of the
Athabasca
oil sands.
[0020] Figures 3A and 3B are schematic illustrations of artificially
compartmentalized heavy oil reservoirs.
[0021] Figure 4 is a longitudinal cross section through a modeled
reservoir.
[0022] Figure 5 is a close-up view of a portion of the modeled reservoir of
Figure 4.
[0023] Figure 6 is a graph showing the oil production rate for two
simulated recovery
conditions, with and without an artificial permeability barrier installed.
[0024] Figure 7 is a graph showing the cumulative oil production comparison
for two
simulated recovery conditions, with and without an artificial permeability
barrier
installed.
[0025] Figure 8 is a graph showing the cumulative solvent (denoted as "gas"
in the
Figure) injection comparison for two simulated recovery conditions, with and
without an
artificial permeability barrier installed.
[0026] Figure 9 is a graph showing the cumulative solvent (denoted as "gas"
in the
Figure) production comparison for two simulated recovery conditions, with and
without
an artificial permeability barrier installed.
[0027] Figure 10 is a graph showing the net solvent to oil ratio comparison
for two
simulated recovery conditions, with and without an artificial permeability
barrier
installed.
[0028] Figure 11 is a schematic illustration showing a top plan view of an
artificial
barrier injection well configuration, with laterals, for example spaced 10-15m
apart. The
solvent injection and production wells are not shown, being beneath the
central blocking
agent injector well.
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CA 3008545 2018-06-15
[0029] Figure 12 is a schematic illustration showing a top plan view of an
artificial
barrier injection well configuration, with sidetracks, for example spaced 20-
50m apart
and 35-50m in length. The solvent injection and production wells are not
shown, being
beneath the central blocking agent injector well.
[0030] Figure 13 is a schematic illustration showing a top plan view of an
artificial
barrier injection well configuration, with a plurality of injectors positioned
about a
circumference of a primary heavy oil compartment of a reservoir. The solvent
injection
and production wells are not shown, being beneath the central blocking agent
injector
well.
[0031] Figure 14 is a particle size analysis plot for a sample of sand used
for
cementitious material injection testing.
DETAILED DESCRIPTION OF THE INVENTION
[0032] Various aspects of the invention may involve the drilling of well
pairs within a
reservoir 11, as illustrated in Figure 1, with each injector well 13, 19, 23,
paired with a
corresponding producer well 15, 17 and 21. Each well has a completion 14, 12,
16, 18,
20 and 22 on surface 10, with 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
horizontal length. The lower production well profile may generally be targeted
so that it
is approximately 1 to 2 m above the heavy oil reservoir base. The development
of
steam 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.
[0033] As illustrated in Figure 2, the stratigraphy of the Athabasca oil
sands varies
geographically, and in places includes oil sand deposits that are separated by
distinct
barrier layers, such as marine shales. Figure 3A is a cross sectional view
along axis 24
of Figure 1, illustrating a hydrocarbon reservoir in which a primary heavy oil
compartment 30 is hydraulically separated from a secondary zone 40 by an
artificial
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CA 3008545 2018-06-15
permeability barrier 32, made up of a functional composite seal of the
injected blocking
agent in sealing engagement with underlying bitumen, so that under oil
recovery
conditions the flow of an injected buoyant solvent across the permeability
barrier is
restricted. An overlying natural top seal is not shown, but typically present,
being in
place prior to setting the blocking agent at the thief/bitumen zone interface
and initiating
hydrocarbon recovery operations. The natural top seal typically defines the
top of the
top thief or secondary zone.
[0034] In some embodiments, during a hydrocarbon recovery operation, oil
may be
depleted from a bitumen zone, including oil from a portion of a bitumen zone
that is
associated with an artificial permeability barrier. In effect, this means that
the artificial
permeability barrier may be modified over time. For example, at first the
permeability
barrier may be formed from the composite seal and top portions of the
underlying
bitumen zone that are then subject to recovery; as the hydrocarbon recovery
operation
progresses, the barrier may remain in place, formed from the composite seal
and the
sands/residual oil remaining in the top portion of the underlying bitumen
zone.
Alternatively, if blocking agent is injected some time after the commencement
of the
hydrocarbon recovery process, the initial artificial permeability barrier may
be formed
between the composite seal and a somewhat depleted top portion of the
underlying
bitumen zone. Similarly, there are circumstances where there is a risk of
solvent losses
into an adjacent steam chamber/solvent chamber depleted of oil. In such
circumstances, the blocking agent may be injected into the depleted area at
the
interface with the bitumen. Alternatively, for example in the case of lower
permeability
facies with fluid flow barriers, the blocking agent may be injected into a
region of the
bitumen zone if the lean zone (being part of the bitumen zone) has sufficient
mobility
(beyond the cold in-situ bitumen zone), the mobility being sufficient to allow
the injection
of a blocking agent, for example a blocking agent having a viscosity of about
100 cP ¨
800 cP.
[0035] In the embodiment illustrated in Figure 3A, a solvent-based recovery
technique is applied to the primary heavy oil compartment 30, forming recovery
chamber 28 around injection well 19, to mobilize heavy oil for production
through
production well 17. Solvent applied to the primary heavy oil compartment 30 by
way of
recovery chamber 28 is prevented from entering the secondary zone 40 by the
artificial
CA 3008545 2018-06-15
permeability barrier 32, which is formed by injection of blocking agent
through blocking
agent injection wells 35.
[0036] Figure 3B is a schematic cross sectional view of a hydrocarbon
reservoir in
which a buoyant solvent is injected into a primary heavy oil compartment 50
from an
injection well 66 forming a recovery chamber 70 by mobilizing heavy oil for
production
through a production well 68. The primary heavy oil compartment 50 is overlaid
by a
secondary zone 52 which is capped by a natural top seal 56. The primary heavy
oil
compartment 50 contacts the secondary zone 52 at an interface 54. As indicated
by the
dashed lines at the periphery of Figure 3B, the secondary zone 52 expands
laterally
beyond the primary heavy oil compartment 50 such that, absent the presence of
an
artificial barrier, loss of buoyant solvent to the secondary zone 52 may be
substantial.
To mitigate such a loss, the secondary zone 52 is partitioned into a proximal
portion 72
and a distal portion 74 by a first artificial permeability barrier 58 and a
second artificial
permeability barrier 62. Having regard to the three-dimensional nature of the
reservoir
shown in cross section in Figure 3B, the artificial barriers 58 and 62 may be
part of a
continuous barrier such that the proximal portion 72 may be segregated from,
and
horizontally enclosed by, the distal portion 74. The artificial permeability
barriers 58 and
62 are functional composite seals formed by blocking agent injected through
blocking
agent injection wells 60 and 64, respectively, such that the blocking agent is
in sealing
engagement with underlying heavy oil and the overlying natural top seal 56.
One
example of well configuration which may be suitable for such an application is
schematically depicted in Figure 13. Under oil recovery conditions, the flow
of an
injected buoyant solvent is not restricted across the interface 54 but is
restricted across
artificial permeability barriers 58 and 62 such that injected buoyant solvent
is
substantially retained within the primary heavy oil compartment 50 and the
proximal
portion 72 of the secondary zone 52. As such, loss of buoyant solvent to the
distal
portion 74 of the secondary zone 52 is reduced. Those skilled in the art will
appreciate
that reducing loss of the buoyant solvent to the distal portion 74 of the
second zone 52
is in comparison to a degree of solvent loss that would be experienced in the
absence
of an artificial permeability barrier.
[0037] In alternative embodiments, the relative positions of primary and
secondary
zones may be varied. In practice, these adjoining compartments will typically
have a
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CA 3008545 2018-06-15
complex geometric relationship, with at least some vertical and horizontal
components
offset. The artificial barrier may accordingly assume a variety of alternative
geometries,
all of which serve the functional requirement of providing a composite bitumen-
blocking
agent seal that serves to confine a buoyant solvent at the top of a primary
recovery
zone.
[0038] An alternative geometry of primary and secondary zones relates to
the
existence of bottom zones, such as bottom water. This may be of particular
relevance in
"thin" primary recovery zones, for example less than 15 m thick (for example 5-
15 m or
5-12 m thick), in which solvent losses to either or both a top and bottom
thief zone may
be anticipated due to the confined area of primary recovery. In the case of a
top
thief/secondary zone, the blocking agent (having one or more components) can
spread
and descend within the formation primarily under the impetus of gravity, to
form a
composite seal engaged with the underlying bitumen zone (ultimately creating
the
artificial permeability barrier). In the case of a bottom thief/secondary
zone, similar
approaches may be taken that do not rely on gravity in the same way. For
example,
similar blocking agents may be adapted to create the artificial permeability
barrier in a
bottom thief zone scenario. For example, a carrier gas (such as nitrogen) may
be used
as a component of the injected blocking agent (either entrained with the
blocking agent
or injected separately) to provide buoyancy to the blocking agent. The
blocking agent
injection well or wells may similarly be adapted for a bottom thief/secondary
zone, for
example being positioned as close as possible to the overlying bitumen zone,
which
may for example involve the increased use of blocking agent injector well
laterals or
sidetracks, so as to ameliorate the loss of blocking agent to the base of the
bottom
water zone. In some bottom thief/secondary zone embodiments, even a partial
permeability barrier between the bitumen and the bottom thief zone may be used
to
reduce solvent losses. In some embodiments, an artificial permeability barrier
may
reduce heat loss to the lean zone, may reduce the loss of bitumen to the lean
zone, or a
combination thereof. Accordingly, embodiments are provided in which a
composite seal
and permeability barrier are placed between a primary recovery compartment and
one
or both of an adjoining upper and lower secondary zone.
[0039] The present recovery processes may be initiated by delineating the
characteristics of a subsurface bitumen reservoir, for example using
observation wells
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and seismic survey information. This delineation will identify secondary zones
that may
interfere with the efficiency of a solvent-based recovery operation in an
adjoining
primary heavy oil compartment.
[0040] Secondary zones of potential concern may for example include top
water
zones, which give rise to the potential for fluid communication between the
secondary
zone and the underlying bitumen zone as a consequence of a recovery operation.
During recovery operations, an injected buoyant solvent, being less dense than
the
reservoir fluids, will rise in the recovery chamber (and spread laterally to
an extent). In
this circumstance, it is desirable to hydraulically isolate the top water zone
from the
lower bitumen zone where the recovery process is taking place. In the absence
of a
composite seal, the top water may drain towards the bitumen recovery zone,
particularly
if the recovery zone is operated at a lower reservoir pressure than the
secondary zone.
This draining of top water towards the well pair will cool the reservoir and
make the
solvent-based recovery process significantly less efficient.
[0041] If the bitumen recovery zone is being operated at a higher pressure
than the
top water secondary zone during the recovery process, the injected solvent may
rise
into the top water zone and increase the reservoir pressure, filling the
available pore
space until the top water zone is in pressure equilibrium with the bitumen
zone. The
volume of solvent required to reach pressure equilibrium represents an
inefficient
solvent loss, reducing the efficiency of the solvent-based bitumen recovery
process.
[0042] In alternative embodiments, the secondary zone may be a "lean" zone
at the
top of the reservoir, for example being devoid of appreciable amounts of
recoverable
bitumen. The pore space of a lean zone may contain connate reservoir water
(for
example on the order of 20% v/v), residual bitumen (for example 20% v/v) and a
significant concentration of natural gas (for example 60% v/v). The exact
concentrations
of the lean zone may of course vary significantly. The lean zone may for
example be in
pressure equilibrium with the underlying bitumen zone (i.e. at the same
reservoir
pressure) during the start of the recovery process. Alternatively, the lean
zone may
have been pressure depleted, and it may therefore be at a significantly lower
pressure
than the heavy oil zone. In both cases, the injected solvent from the recovery
process
can rise into the lean zone, in which case the efficiency of the solvent-based
recovery
13
CA 3008545 2018-06-15
process is reduced due to these losses. In the case where the lean zone has
been
pressure depleted prior to the recovery process, the solvent losses may be
significant.
[0043] Alternatively, the offending secondary zone may include fluid flow
barriers,
including but not limited to clasts, bridges, baffles, low permeability
regions and barriers
that may cause the solvent to become trapped above barriers, between barriers,
or a
combination thereof, making the solvent unable to drain mobilized oil towards
the
production well of the recovery process. This "trapping" of the solvent with
respect to
these barriers and in these low permeability regions causes the efficiency of
the solvent-
based recovery process to be significantly reduced, as the solvent and
mobilized oil is
lost to these barrier zones.
[0044] An aspect of some of the processes described herein is the drilling
and
completion of a recovery well pair, as for example shown in Figure 1, for
example with
well pairs drilled approximately 800 to 1,000 m long, with approximately 5 m
in vertical
separation.
[0045] In addition to the recovery well pair, the aspects of the processes
disclosed
herein involve the use of a blocking agent injector well. The blocking agent
injector well
may be a vertical well or a horizontal well. A horizontal blocking agent
injector well may
for example be drilled in the same vertical plane above the recovery well
pair. In terms
of vertical placement, the blocking agent injector may be drilled at the start
of the
offending secondary zone, i.e. the depth/height in the formation at which the
zone
begins/interfaces with the bitumen zone. The blocking agent injector may be
advantageously placed as close as possible to the bitumen zone, while still
being in the
offending secondary zone. In this way, the blocking agent injector may be
placed in a
zone that has sufficient mobility for a blocking agent to be injected, whereas
the
underlying bitumen zone may not have sufficient mobility (e.g. prior to the
hydrocarbon
recovery process) to allow for the injection of the blocking agent. Placement
of the
blocking agent injector just above the bitumen zone in a top thief zone
scenario allows
the underlying bitumen zone (which has no practical mobility to fluids
injected at
pressures below the formation fracture pressure) to act as a barrier that
prevents the
blocking agent from dropping in the reservoir when the blocking agent is
injected. In
select embodiments, the blocking agent may for example be placed within 40cm
to lm
of the bitumen zone. The blocking agent may accordingly tend to spread out
laterally
14
CA 3008545 2018-06-15
when injected adjacent to the bitumen zone, for example at the top of the
bitumen
recovery zone, forming a seal. The blocking agent thickness may for example be
about
cm to 50 cm, and may be thinner or thicker at certain points depending on the
reservoir geology or how the blocking agent is injected. The blocking agent
injector may
for example be completed either open hole, if the secondary zone is competent,
or with
a liner to prevent the hole from sluffing in during blocking agent injection
or hydrocarbon
recovery operations. The blocking agent may for example be injected in a
variety of
scenarios, which may be combined: (1) inject blocking agent prior to
initiating
hydrocarbon recovery; (2) initiate hydrocarbon recovery and at a later time
inject
blocking agent; (3) inject blocking agent before or after hydrocarbon recovery
is initiated
and then re-inject the blocking agent later as needed. In select embodiments,
the well
pair may be operated without an artificial barrier in place, while monitoring
the influence
of the secondary zone on recovery operations, for example to determine the
extent to
which solvent is lost. This may for example take place for 3 to 6 months, or
to a point at
which losses of the solvent are meaningful, for example if the solvent to oil
ratio rises
significantly, or above a desired threshold (such as > 4), at which point the
injection of
the blocking agent may be undertaken.
[0046] An aspect of some of the present processes involves drilling and
completion
of blocking agent lateral wells or sidetrack wells. In some embodiments, the
lateral wells
may be drilled on either side of the blocking agent injector, e.g. in the form
of a multi-
lateral horizontal blocking agent injector well, before the recovery process
begins. In
alternative embodiments, the sidetrack wells may be drilled from and
incrementally
spaced along the horizontal segment of the blocking agent injector well at an
angle from
the blocking agent injector well. These or other blocking agent injector well
configurations and associated completions may be implemented so as to ensure a
composite seal prior to the commencement of the recovery process.
Alternatively, the
laterals or sidetracks may be added to the blocking agent injector well when
required
during hydrocarbon recovery operations as the recovery chamber grows
laterally.
Changes to the blocking agent injector well(s), injection of blocking agent,
or both, may
be included in an iterative process that takes place throughout oil recovery
operations.
The laterals may for example be approximately the same length as the blocking
agent
injector well. The horizontal (lateral) spacing between the blocking agent
injector well
CA 3008545 2018-06-15
and the first lateral and all subsequent lateral injectors may be determined
by how far
the blocking agent spreads laterally. For example, if the injected blocking
agent travels
approximately 5 m laterally from the blocking agent injector (in a horizontal
direction)
before hardening, the first lateral may be drilled 10 m away from the central
blocking
injector. In practice, the distance of blocking agent travel may be assessed
empirically.
The total number of laterals required may be determined based on the spacing
between
recovery well pairs. For example, if the spacing between recovery well pairs
is 100 m,
then four to five laterals, spaced 10 m apart may be required on either side
of the
blocking agent injector. Alternatively, in some embodiments, only the blocking
agent
injector may be required. In alternative embodiments, other injector well
configurations
may be used. As a first example, an injector well configuration may comprise a
vertically
spaced, perpendicular injector (with respect to the well pair), with or
without sidetracks.
As a second example, a plurality of blocking agent injector wells may be
provided
around a circumference of a primary heavy oil compartment of a reservoir. One
example of such a well configuration is schematically depicted in Figure 13
where
blocking agent injector wells 80, 81, 82, and 83 are provided around a
circumference of
primary heavy oil compartment. As Figure 13 is shown in plan view, only the
lateral
sections of the wells 80, 81, 82, and 83 are depicted. Such a well
configuration may be
utilized for applications where it is desirable to isolate the primary heavy
oil
compartment from part, but not all, of a secondary zone of reduced heavy oil
saturation.
A reservoir comprising a primary heavy oil compartment overlaid by a shallow
but
horizontally-expansive gas cap is one instance where such a well configuration
may be
utilized. In such a reservoir, hydraulic isolation may be substantially
achieved by forming
a composite seal that creates a substantially horizontal perimeter around the
primary
heavy oil compartment and that penetrates up to a ceiling of the shallow gas
cap. The
composite seal may substantially partition the gas cap into a proximal portion
and a
distal portion, wherein the proximal portion of the gas cap is hydraulically
connected to
the primary heavy oil compartment and wherein the distal portion is
hydraulically
isolated from the proximal portion of the gas cap and the primary heavy oil
compartment. In such instances, a buoyant solvent may be substantially
retained within
the primary heavy oil compartment and the proximal portion of the gas cap.
This may
reduce the amount of blocking agent required to provide for hydraulic
isolation. Of
16
CA 3008545 2018-06-15
course, in embodiments wherein a plurality of blocking agent injector wells
are provided
around a circumference of a primary heavy oil compartment, the dimensions of
the
blocking agent injector wells may vary. For example, in an embodiment where a
single
well pad comprises eight wells that are 1000 m long and spaced 100 m apart,
the
plurality of blocking agent injector wells may form a generally rectangular
circumference
with a length of about 1050 m and a width of 900 m. As a further example, in
an
embodiment where four well pads, each comprising ten wells that are 1000 m
long and
spaced 100 m apart, are situated as quadrants of a square, the plurality of
blocking
agent injector wells may form a generally square circumference with a length
(width) of
about 2200 m. Configuration of the blocking agent injector will generally be
selected so
as to generate a large enough barrier to prevent significant solvent losses
during the
hydrocarbon recovery operation.
[0047] Aspects of the processes described herein involve the initial
injection of
blocking agent into a secondary zone from a blocking agent injector well. The
initial
injection may for example take place prior to the commencement of the solvent-
based
recovery process in the bitumen zone. The blocking agent may for example be
delivered to the blocking agent injector well at pressures below the reservoir
fracture
pressure, so as not to induce additional pathways for solvent to escape in the
offending
secondary zone once the blocking agent is injected into the secondary zone. In
select
embodiments, this pressure is designated the "maximum blocking agent injection
pressure". In select embodiments, as much blocking agent as possible may be
injected
into the reservoir until the maximum blocking agent injection pressure is
reached. In
embodiments in which the blocking agent injector is a horizontal well, the
blocking agent
may be distributed to the secondary zone with coil tubing or an alternative
tubing
deployment mechanism (e.g. a jointed tubing string). Such tubing deployment
mechanisms may also be employed in embodiments in which the blocking agent
injector is a vertical well. Injection may accordingly commence at the toe of
the
horizontal blocking agent injector, and as the pressure in the near wellbore
area
increases from the injection, the coil (or other) tubing may be pulled back as
injection
continues until the heel of the horizontal well is reached. Following
injection of the
blocking agent, material in the horizontal wellbore of the blocking agent
injector may be
displaced with a suitable completion fluid that will not degrade the blocking
agent.
17
CA 3008545 2018-06-15
[0048] Monitoring equipment, such as one or more bottomhole pressure
recorders,
may then be placed in the blocking agent injector, and/or in one or more of
the lateral or
sidetrack wells. The bottomhole pressure recorders may also advantageously
have a
temperature gauge.
[0049] Aspects of the processes disclosed herein involve the injection of
blocking
agent through lateral and/or sidetrack wells. The blocking agent may for
example be
delivered to and injected through each lateral and/or sidetrack well using the
same
methodology and approach disclosed above. A mud motor equipped with a gyro
type
location identification device may for example be used to steer the coil
tubing into each
lateral well and/or sidetrack well to place the blocking agent. Again, the
blocking agent
may be distributed from toe to heel in each lateral well and/or sidetrack
well. As
discussed above, one or more bottomhole pressure recorders may be provided in
one
or more lateral wells and/or sidetrack wells, just as in the blocking agent
injector. The
measurements, such as pressure and temperature, from the blocking agent
injector,
laterals and/or sidetracks may for example be transmitted to the surface, in
real time or
otherwise. In addition, the blocking agent injector well and/or the lateral or
sidetrack
wells may be completed so as to remain open to reservoir flow, such that a
sample of
what is in the wellbore may be produced to surface and analyzed.
[0050] The operation of the recovery well pair may for example include
initial start-up
steps of solvent circulation or pre-heating of the reservoir, transitioning to
a gravity
dominated solvent-based recovery process. The bottomhole pressure recorders
and
temperature gauges in the blocking agent injection wells may then be
monitored. An
increase or decrease in pressure or temperature may provide an indication, for
example
in a top thief zone scenario, of solvent flow from below (pressure and
temperature may
increase) or flow from the offending secondary zone into the bitumen zone
(pressure
may remain constant or decrease and temperature may decrease). Fluid samples
may
be periodically obtained from the surface wellhead or downhole from the
blocking agent
injector wells to verify the composition of the fluids in the region of the
composite seal.
For example, detection of an increase in solvent concentration may indicate
that the
injected seal has been breached and remediation may be required. The blocking
agent
may be periodically re-injected through the blocking agent injectors to re-
establish a
18
CA 3008545 2018-06-15
seal that may have been breached or to strengthen selected areas of the
composite
seal.
[0051] In some embodiments, it may be desirable to drill only the blocking
agent
injector initially. With monitoring, any loss in efficiency of the recovery
operations may
then be taken as an indication to re-enter the blocking injector and add
laterals and/or
sidetracks.
[0052] The blocking agent may be tailored to specific conditions of heavy
oil
recovery. For example, the solvent-based recovery process may advantageously
be
carried out at a selected maximum temperature, for example of at most 140 C.
This
maximum temperature reflects a range of possible reservoir pressures, for
example
from 2,000-3,500 kPa, or from 500-7,500 kPa, thereby creating conditions at
which a
buoyant solvent can be injected in the vapour phase. A relatively low
temperature
solvent-based recovery process may be advantageous in order to preserve the
integrity
of the composite seal. The integrity of the seal relies as well on the
placement of the
blocking agent as close as possible to the underlying bitumen reservoir. This
is
particularly important because when solvent escapes from the underlying or
overlying
bitumen reservoir into a lean or secondary zone, the mobility of the solvent
may
significantly increase. In an embodiment, due to the low mobility of the
bitumen
reservoir to the injected blocking agents, at least prior to initiating
hydrocarbon recovery,
the underlying bitumen layer acts as a floor on which the blocking agent can
spread out
and then provide a seal against solvent permeability from the underlying
bitumen
reservoir or fluid permeability from the offending secondary zone.
[0053] Specific conditions of heavy oil recovery may involve the use of
particular
solvents. The buoyant solvent may for example be a light hydrocarbon solvent,
and may
be selected on the basis that it is miscible with, and capable of enhancing
the mobility
of, the reservoir hydrocarbons. As such, the solvent may be deployed as a
mobilizing
fluid, comprising for example one or more, polar or non-polar, C3 through C10
linear,
branched, or cyclic alkanes, alkenes, or alkynes, in substituted or
unsubstituted form, or
other aliphatic or aromatic compounds (alternatively 03-C7). Select
embodiments may
for example use an n-alkane, for example n-propane or n-butane. The mobilizing
fluid
comprising the buoyant solvent may be injected as a vapour, for example at a
relatively
low temperature, for example at or below 140 C. In select embodiments, a polar
19
CA 3008545 2018-06-15
solvent-based or a heavier solvent-based hydrocarbon recovery process may be
used
with selected blocking agents.
Aspects of the present processes may use blocking agents that are resins that
can be
thermally set or chemically set.
[0054] In practice, the deployment of the blocking agent may involve the
following
aspects. A fluid feed rate may be established into the reservoir with either a
hot water
that has been viscosified with a polymer or any other viscous heated fluid,
such as a
mineral oil. This pre-heating fluid may advantageously have some viscosity
(for example
100+ cP) to prevent it from leaking into the bitumen reservoir. Sufficient
heated fluid is
injected into the secondary zone to establish a high enough temperature to
thermoset
the resin after it is injected. For some resins, a target temperature may for
example be
40 C ¨ 45 C. The resin or another blocking agent may then be injected into the
heated
secondary zone. The viscosity of the blocking agent may be selected or
adjusted to be
sufficiency low for it to be injected at pressures below reservoir fracture
pressures. The
blocking agent may then be thermoset in the pre-heated area of the secondary
zone, for
example within a time period such as 60 minutes. The time frame for
thermosetting and
further hardening of the resin may be shorter or longer depending on the
particular
blocking agent and reservoir conditions.
[0055] For a chemically set resin, a pre-heating fluid may also be injected
into the
secondary zone to provide sufficient heat for the chemical reaction to take
place within a
selected period of time, for example within 12-24 hours or 1-7 days. The resin
or
another blocking agent may then be injected into the heated secondary zone.
The
viscosity of the blocking agent may be selected or adjusted to be sufficiency
low for it to
be injected at pressures below reservoir fracture pressures. A chemical
activating agent
may then be injected to cure the resin. The time frame for setting or curing
and further
hardening may be shorter or longer depending on the particular blocking agent
and
reservoir conditions.
[0056] Injection of the blocking agent may not require pre-heating of the
secondary
zone. Injection of the blocking agent may involve combining the blocking agent
with a
carrier fluid at surface or prior to delivering the combination to the surface
facilities or
wellhead. Examples of carrier fluids may include water or a polar or non-polar
CA 3008545 2018-06-15
hydrocarbon solvent (e.g. a lighter alkane solvent or heavier alkane solvent
mixture
such as a natural gas condensate), or a combination thereof.
[0057] Blocking agents may for example include resins, namely epoxy resins,
phenolic resins, or furans. Epoxy resins are almost exclusively thermoset.
Phenolic
resins have been used extensively in steam flooding applications and are
generally not,
or moderately, sensitive to water. Phenolic resins are generally activated in
the reservoir
by an acidic or basic chemical activating agent. Furans may be chemically set
with an
acid. Certain phenolic resins and furans may set without secondary zone pre-
heating.
[0058] Resins, once set, may harden through a marked increase in viscosity
and
preserve this rigidity at temperatures that are relevant for solvent-based
recovery
operations, for example remaining thermally stable up to 140 C. Blocking
agents may
be selected so as to be solvent resistant when hardened, in particular being
resistant to
breaking down in the presence of the solvents used in low temperature solvent-
based
hydrocarbon recovery processes.
[0059] The blocking agent may for example be oleophobic to repel the
injected
solvent (in liquid or gas phase) and other gases (e.g., methane) from entering
the
secondary zone. Where the offending secondary zone is a top water zone, a
blocking
agent may be used that resists both solvents and water infiltration. For
example, the
blocking agent may be formed from a mixture of a binary resin containing both
oleophobic and hydrophobic components to repel both solvent invasion from the
underlying bitumen zone and water invasion from the top water zone,
respectively. Such
a binary blocking agent may also be suitable for a bottom water zone with an
overlying
bitumen zone. Other blocking agents that may be employed include oilfield
cements,
waxes and crosslinked gels. Oilfield cements (e.g. micro cements) may be
injected into
pore systems and are thermally stable up to about 140 C. Oilfield cements may
include
cementitious materials having a variety of viscosities, densities, pH values,
and SiO2
contents. For example, the cementitious material may have a viscosity of
between
about 7 mPa.s and about 13 mPa-s, a density of between about 0.7 kg/L and
about 1.3
kg/L, a pH value of between about 8 and about 12, and a SiO2 content of
between
about 12 wt.% and about 18 wt.%. MasterRoc MP 325 is an example of a
cementitious
material that may be included as a component of a blocking agent composition
that
21
CA 3008545 2018-06-15
comprises an oilfield cement (MasterRoc is a registered trademark of
Construction
Research & Technology GmbH, Trostberg, Germany).
[0060] Epoxy resins are generally based on a phenolic chemical structure; a
common epoxy resin is bisphenol A epoxy resin and is a product of the reaction
between epichlorohydrin and bisphenol A. The bisphenol A epoxy resin or other
blocking agents may be obtained commercially. One or more chemical activating
agents
(sometimes referred to as curing agents, hardeners, catalysts, or cross-
linkers
depending on the intended physical or chemical reactivity) may be added to the
epoxy
resin or another blocking agent before it is pumped into the blocking agent
injection
well. When the resin and chemical activating agent are exposed in the blocking
agent
injection well to the heat from pre-heating the well and secondary zone, the
resin may
start to cure and harden. A typical hardener is diethylenetriamine, and a
catalyst such
as an amine or carboxylic acid may further be added. After the one or more
chemical
activating agents are added the resin may further be cut with a mutual
solvent, such as
ethyleneglycolmonobutyl ether (EGMBE) to lower the viscosity of the resin to
allow it to
be pumped down hole at low pressure and enter the pre-heated formation. The
solvent
generally does not affect the curing and hardening of the resin, and may be
selected so
that it allows the resin to be injected and appropriately placed. Other
suitable epoxy
resins may for example include bisphenol F epoxy resins or aliphatic epoxy
resins,
including high temperature resistant resins.
[0061] Two common phenolic resins include novolac resins and resol resins.
A
novolac resin involves an acid catalyst to cure and harden the resin while a
resol resin
involves an alkaline (or basic) catalyst to cure and harden the resin.
Novolacs are
soluble in organic solvents like alcohols and acetone, but not in water, which
make them
particularly useful in top or bottom water zones to prevent top or bottom
water from
invading the bitumen zone. Resols on the other hand have at least partial
solubility in
water.
[0062] Furan resins, more properly called furyl alcohol resins, are almost
exclusively
cured and hardened through the use of an acid catalyst. At very high
temperatures the
polymerization reaction may be explosive and control of the reaction is
accordingly
important in oilfield applications.
22
CA 3008545 2018-06-15
[0063] As described above, blocking agents such as resins that are
thermoset or
chemically set may involve the addition of an acid or alkali curing agent
(which acts as a
catalyst to start the curing and hardening reaction) and this addition may
occur at
surface prior to delivering the blocking agent to the blocking agent injector
well. The
resin and the one or more chemical activating agents may be shipped separately
to the
surface facilities or wellhead. The resin and the one or more chemical
activating agents
may be mixed at surface and then immediately injected into the pre-heated
secondary
zone via the blocking agent injector well. Injecting the mixture quickly may
be helpful so
as to avoid the final product setting-up at surface or in, for example,
injection tubing in
the injection well. The injection tubing may be pre-heated to assist in
delivery of the
mixture to the secondary zone. In an alternative embodiment, a resin or other
blocking
agent may be injected into the secondary zone, followed by injection of one or
more
suitable chemical activating agents as a mixture or by injection in series.
Where a
physical change, a chemical reaction, or both, are required to form the
composite seal,
such a change and/or reaction may be delayed until the blocking agent has at
least
partially spread out in the secondary zone by adjusting the timing and/or
sequence of
injection of one or more blocking agent components.
[0064] Crosslinked gels are generally based on acrylates or acrylamides. In
terms of
acryalmides, hydrolyzed polyacrylamides are often used. Crosslinks may for
example
be formed by metals like aluminum citrates, or other organic crosslinkers such
as
phenol, hydroquinone, or phenyl acetate.
[0065] In the case of a gel or acrylamide system, the cross-linker may be
mixed with
the hydrated gel or acrylamide at surface prior to injection downhole. The
cross-linking
reaction generally starts immediately and some cross-linking as the mixture is
injected
is acceptable; however, waiting for too long before injection of the mixture
may lead to
undesirable reactions with oxygen and free radical degradation.
[0066] A crosslinked gel that is temperature resistant to 140 C may for
example be
made from both inorganic and organic gels, such as partially hydrolyzed
polyacrylamide
(HPAM, anionic), crosslinked with either a metal (chromium or aluminum, such
as in the
form of aluminum citrate) or an organic crosslinker (such as an aldehyde).
Gels may for
example be periodically re-applied through the blocking agent injector(s), as
gels tend
not to be as rigid and long lasting as resins.
23
CA 3008545 2018-06-15
[0067] An aflernative blocking agent may comprise an ultra-high melting
point
petroleum wax, or a wax based on another substance, and the wax may for
example be
heated to lower the viscosity of the wax and then injected into the reservoir
to the
desired location in the secondary zone. The wax may then "set-up" at the
native
temperature of the secondary zone.
[0068] Relatively hard microcrystalline synthetic waxes, for example
derived from a
Fisher-Tropsch process may be useful. These are synthetic waxes produced from
the
polymerization of carbon monoxide at high temperatures. The melting point (the
point at
which the wax would lose its effectiveness as a blocking agent) may for
example be in
the 115-120 C range. These waxes may be suitable as part of a binary mixture,
injected
along with other blocking agents such as resins, in embodiments in which these
waxes
are provided so as to repel water. The combination of a wax and a resin may
for
example be adapted to yield both oleophobic and hydrophobic properties.
[0069] In an embodiment, the composite seal may for example be a polymer
generated by injecting a blocking agent comprising a monomer and an initiator
either as
a monomer-initiator mixture or sequentially. In an alternative embodiment, the
composite seal may be generated by making use of the constituents of the thief
zone
itself, for example by relying on reactivity of the blocking agent with water
in a water
zone to aid in generating the composite seal. For example, if stock acrylamide
is the
monomer, the polymerization reaction may be initiated by a reduction-oxidation
initiator
such as AMPS (ammonium persulphate) or TEMED (tetramethylethylene diamine). In
such embodiments, when used in small batches, heat may not be required. The
reaction is typically a free radical polymerization via the AMPS or TEMED of
stock
acrylamide, to make polyacrylamide. In some embodiments, a select degree of
hydrolysis may be achieved, for example 20-40%, to provide a selected HPAM
(hydrolyzed polyacrylamide). The HPAM may optionally be cross-linked, for
example
with aluminum citrate. For this reaction to occur, free water must generally
be present,
as would be the case for example in a top water or bottom water situation. In
effect, the
HPAM acts as a thickener. In a gas lean zone, water may be injected before the
blocking agent to provide any necessary free water for this reaction, before
injecting the
acrylamide followed by the free radical initiator AMPS or TEMED.
24
CA 3008545 2018-06-15
[0070] In accordance with the foregoing discussion of alternative blocking
agents,
suitable resins and gels are generally compounds that require curing
(involving a
second chemical agent, heat, or both), which reflects a chemical reaction
(usually
polymer crosslinking) that takes place when two or more components are
combined to
form the composite seal and create a permeability barrier where the
thief/secondary
zone meets the bitumen zone. For example, a resin combined with one or more
chemical activating agents generates the blocking agent.
[0071] Resins not only cure, but harden (become more solid) and may
continue to
harden further in the presence of heat during the solvent-based hydrocarbon
recovery
process in the bitumen zone. Gels are different from resins, and may or may
not harden
along with curing, typically they will not harden to the same extent as resins
(and are
accordingly typically less solid when formed into a composite seal). Waxes do
not
require curing; rather, they are melted by heating and injected into the
thief/secondary
zone, and then allowed to cool to solidify (freeze). As used herein, the terms
"set",
"setting" or "setting-up", as in "thermosetting" or "chemical setting" of a
polymer or
compound, have a functional meaning to the effect that the injected blocking
agent
undergoes changes in some physical or chemical characteristic as it forms the
material
that makes up the composite seal as part of the permeability barrier. For
example, a
blocking agent may set (stiffen) before it fully hardens.
[0072] Selecting a suitable blocking agent having one or more components
may
include testing or evaluating compounds that undergo a change in viscosity,
density or
solidity at native thief zone or reservoir conditions, post pre-heating of the
thief zone, or
at the conditions of a solvent-based recovery process occurring in the
underlying
bitumen zone at a temperature up to 140 C. Suitable blocking agents may be
selected
based on characteristics including thermal stability, chemical stability,
strength,
permeability, or a combination thereof. Suitable blocking agents may be stable
under a
range of pressures, e.g. 500 ¨ 7,500 kPa. Suitable blocking agents may be
selected
based on an understanding of chemical thermodynamic and transport mechanisms
and
how a particular blocking agent may be expected to disperse after it is
injected into the
secondary zone. Suitable blocking agents may be selected based on how the
blocking
agent(s) will function within a porous geological formation.
CA 3008545 2018-06-15
[0073] Testing the characteristics of potential blocking agents may include
tests
conducted at different temperature and pressure conditions to establish
suitable
reaction kinetic parameters; assessing compatibility, resistance, or
permeability to
water, solvents, hydrocarbons, or solution gas; testing time frames for
setting, curing, or
hardening; or a combination thereof. The characteristics of potential blocking
agents
may be tested to understand the effect of reservoir impurities (e.g. dissolved
solids in
the reservoir formation water or clay minerals that may be present in the
quartz
reservoir matrix) on the physical or chemical reactions involved in creating a
composite
seal.
[0074] Suitable blocking agents may be selected based on compatibility of
the
composite seal with the solvent(s) for hydrocarbon recovery, formation water
and
solution gas. Suitable blocking agents may have an appropriate setting,
curing, or
hardening time such that premature setting, curing, or hardening around the
blocking
agent injector well is minimized or prevented.
[0075] Tests may be carried out to select appropriate blocking agents for
particular
embodiments. For example, tests may establish the set-up (or setting) time of
a
selected blocking agent, being the length of time that it takes the material
to set-up after
the hardener or curing agent is added at a given temperature. Similarly, the
set-up
temperature of a selected blocking agent may be established as the temperature
needed for the selected material to set-up. Tests may similarly establish how
the
concentration of the material impacts the set-up temperature and/or time.
Accelerants or
delayers may be tested to demonstrate a desired effect, such as delaying the
set-up
until the material is sufficiently transported into the reservoir. Gel or
resin strength may
be established in assays that may be characterized as a gel yield test. For
example, in a
pressurized test apparatus, assays may be conducted to determine the
compressive
strength of the gel or resin, i.e. the degree of compression before yielding.
Tests of this
kind may for example take place at room temperature for screening purposes,
and then
at blocking agent injection temperatures and pressures. In these tests, two
fluids may
be used, one on either side of the gel, one side being at higher pressure than
the other
side.
[0076] Gel or resin strength may for example be tested in porous media, for
example
using conditions that mirror the lean zone reservoir conditions. In tests of
this kind, the
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blocking agent may be injected and allowed to cure and harden within a similar
time
frame as to what would be used in the field at reservoir conditions. The
volume of
barrier material may for example fill approximately 1/2 to 2/3 of the pore
volume of a test
core. The solvent may then be injected into the core at pressure (at the
injection side)
and the amount of solvent that leaks through the barrier may be measured on
the
production side of the core. The pressure may for example be ramped up on the
injection side until the barrier eventually yields.
[0077] A 3D physical model test may be used to assess blocking agents, and
which
mimics the reservoir recovery process on a very small scale, for example a
1/32 or a
1/64 scale. Some or all of the intended blocking agent injection wells, for
example
including laterals or sidetracks, may be added to a model that includes a
solvent injector
and producer well pair. Parameters that may be modeled in this way include
comparisons of the solvent to oil ratio with the barrier in place versus not
having the
barrier in place.
Examples
[0078] Detailed computational simulations of reservoir behaviour have been
carried
out to exemplify various aspects of composite seal performance, illustrating
that an
artificial permeability barrier may be used in conjunction with buoyant
solvents to
recover heavy oil while avoiding the loss of solvent to a thief zone. A 3D
reservoir
simulation model was used to simulate the effects of the solvent loss
prevention
performance of the composite seal. A horizontal well pair of 800 m in
horizontal length
was constructed in a simulated reservoir having 15 m of thickness from the
under
burden to the over burden. The vertical separation between the lower
horizontal
production well and the upper horizontal injection well was 5 m. Horizontal
permeability
in all cells in the model was set to 10,000 md while vertical permeability was
set to
7,000 md. Porosity was 33%. A well pair configuration using 4 outflow control
devices in
the injection well was used. The depth of the reservoir was approximately 475
m below
surface. The reservoir pressure in both the underlying bitumen zone and the
top lean
gas (thief) zone was 2,800 kPa. Live oil Athabasca bitumen properties for the
subsurface McMurray formation were used. The solvent that was injected in the
simulation was pure propane; standard propane properties from the Gas
Processors
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CA 3008545 2018-06-15
Suppliers Association Engineering Data Book were used. The simulated reservoir
is
illustrated in Figures 4 and 5, in which:
1 = horizontal production well, directed into the page
2 = horizontal injection well, directed into the page
3 = underlying bitumen formation:
permeability X,Y,Z = 10,000 md
porosity = 33%
oil saturation = 80%
water saturation = 20%
gas saturation = 0%
4 = top lean gas zone:
permeability X,Y,Z = 7,000 md
porosity = 33%
oil saturation = 20%
water saturation = 20%
gas saturation = 60%
= location of blocking agent in permeability barrier
permeability X,Y,Z = 50 md
porosity = 12%
[0079] In a first set of reservoir simulations, communication between the
injector and
producer was established via steam circulation. Communication could also be
established, for example, by solvent circulation, by downhole electrical
heaters, or by
other methods of well start-up as would be understood by a person of skill in
the art.
Following the establishment of communication between the injector and
producer, the
well pair was then placed on operation; heated propane was injected at 100 C
and
approximately 4,200 kPa. A maximum gas phase injection rate of 63,200 m3/d of
propane was set at surface. At the production well, a constraint of 2,800 kPa
was set.
Produced gas was not constrained. In Figures 6-10, this simulation is referred
to as "No
Barrier".
[0080] A further simulation model included the effects of injection of a
blocking
agent. The blocking agent was modelled as a 10 cm thick interval lying at the
base of
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the top lean gas zone as shown in Figure 5. The blocking agent interval
(composite
seal) was introduced in the simulation model prior to the commencement of
hydrocarbon recovery operations, and the interval had a permeability of 50 md
in the x,
y and z directions and a porosity of 12%. The simulation with the blocking
agent interval
present is designated as the "50 md Barrier" case in Figures 6-10. The
blocking agent
interval was modelled with some permeability (albeit 200 times less than the
surrounding matrix) to allow for some fluid flux through the artificial
permeability barrier.
Although a substantially complete seal between the top lean zone and the
underlying
(or overlying) bitumen reservoir may be provided, this may not always be
feasible due to
local reservoir heterogeneity, imperfect placement of the blocking agent and
local
significant pressure gradients which may cause the blocking agent interval to
yield. The
present simulations illustrate that even an imperfect artificial permeability
barrier
provides substantial benefits.
[0081] Figure 6 illustrates that early in the life of the hydrocarbon
recovery operation
(up to about 200 days in this simulation), the presence of the artificial
permeability
barrier significantly enhanced the oil rate. In the modelled reservoir, the
thief zone was
confined, so that it became saturated with solvent during this early time
frame and
thereafter the secondary zone no longer acted as a thief zone. In practice,
thief zones
may not be constrained in this way, and the advantages of the composite seal
may be
therefore be prolonged. In the constrained environment of the model, overall
oil
production was ultimately the same between the case with the barrier and the
case with
no barrier, as shown in Figure 7, although slightly better with the barrier up
to about
1,500 days.
[0082] The amount of solvent (propane) injected into the reservoir and then
produced back is shown in Figures 8 and 9. Again, in the constrained thief
zone model,
there was minimal difference between the case with the artificial barrier
interval and the
case with no barrier. Somewhat more solvent was injected and produced overall
in the
case with the barrier compared to the case with no barrier; however, this
additional
solvent requirement was offset by the reduction in net solvent to oil ratio,
as shown in
Figure 10.
[0083] Figure 10 dramatically illustrates the efficiency of the barrier.
The net solvent
to oil ratio is defined as the (Cumulative Gas (Solvent) Injected - Cumulative
Gas
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(Solvent) Produced) divided by the Cumulative Volume of Oil Produced. A low
solvent
to oil ratio reflects a more efficient solvent-based hydrocarbon recovery
process. As
illustrated, in the absence of the barrier, the presence of a top lean gas
zone caused the
solvent to oil ratio to increase, reflecting an inefficient use of the buoyant
solvent due to
secondary zone losses. The blocking agent injection well or wells may
accordingly be
utilized for monitoring undesirable migration of fluids across the artificial
permeability
barrier and the integrity of the composite seal. If fluid migration is
detected, additional
blocking agent (e.g., resin, gel, wax, chemical activating agent, or a
combination
thereof) may be introduced to replenish the composite seal and/or to re-seal
the artificial
permeability barrier and this replenishing and/or re-sealing process may be
repeated
multiple times.
[0084] Laboratory-scale tests were completed to evaluate physical
characteristics
(e.g. dispersability and compressive strength after setting) of blocking
agents
comprising cementitous materials. A one-gallon sample of dry sand was analyzed
to
determine particle size distribution. Results from the analysis are shown in
Figure 14.
The sand was mixed with a 1 wt. % brine solution (NaCI) in a sand:brine ratio
of about
4.9:1.0 in order to simulate the expected density of the sand under reservoir
conditions.
The sand/brine composition was packed into two 38 mm diameter PVC tubes each
measuring approximately 1 m in length. MasterRoc MP 325 was injected into the
tubes
at pressures between 1.5 bar (21.76 psi) and 3.5 bar (50.76 psi). The
MasterRoc MP
325 was allowed to penetrate the sample until it began to exhibit gelation at
which point
the injection was stopped and the sample was left to cure for 28 days. After
this period,
the MasterRoc MP 325 was determined to have penetrated approximately 80% of
the
length of the PCV tubes and the compressive strength was determined to be 263
kPa.
After 56 days, the compressive strength of the sample was reevaluated and
found to be
347 kPa. After 84 days, the compressive strength of the sample was reevaluated
and
found to be 379 kPa. Additional tests demonstrated that the 1% brine solution
served as
an accelerator for the MasterRoc MP 325.
[0085] 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 or production wells may be adapted
from well
CA 3008545 2018-06-15
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 or single injection-production wells as injection and/or
production wells. For
instance, in some embodiments a hydrocarbon recovery production well drilled
into a
bottom water zone may be utilized as a blocking agent injector well. 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.
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