Note: Descriptions are shown in the official language in which they were submitted.
DYNAMIC SOLVENT:STEAM MANAGEMENT IN HEAVY OIL RECOVERY
FIELD
[0001] The present disclosure relates to in situ methods for recovering
hydrocarbons from
subterranean reservoirs. In particular, the present disclosure relates to
solvent processes that
dynamically modulate the ratio of solvent to steam in an injection fluid, so
as to facilitate liquid
hydrocarbon recovery by managing gas evolution from mobilized fluids.
BACKGROUND
[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 hydrocarbons, heavy oil, bitumen, or oil sands. 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 and/or solvent based recovery techniques,
such as injecting
a heated fluid, typically steam, solvent or a combination thereof, into the
reservoir from an injection
well. Steam-assisted gravity drainage (SAGD) and cyclic steam stimulation
(CSS) are
representative thermal-recovery processes that use steam to mobilize
hydrocarbons in situ.
Solvent processes such as solvent-aided processes (SAP) and solvent-driven
processes (SDP)
are representative thermal-recovery processes that use both steam and solvent
to mobilize
hydrocarbons in situ.
[0003] 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
or production
chamber in the reservoir around and above the horizontal segment of the
injection and
production wells.
[0004] Some thermal recovery processes employ injection fluids that include
solvent,
optionally in combination with steam, as for example disclosed in Canadian
Patent Publication
2,956,771. Solvent-aided processes (SAP) are one such category. In the context
of the present
disclosure, SAP injection fluids comprise less than about 50% solvent and
greater than about
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Date Recue/Date Received 2020-12-17
50% steam on a mass basis. Solvent-driven processes (SDP) are another such
category. In the
context of the present disclosure, SDP injection fluids comprise greater than
about 50% solvent
and less than about 50% steam on a mass basis. Solvent-driven processes are
not widely
employed on commercial scale but, when they are, they are typically employed
as one phase in
a broader recovery profile. For example, a well may be transitioned through:
(i) a start-up phase
during which hydraulic communication is established between an injection well
and a production
well; (ii) a SAGD phase during which a production chamber expands primarily in
a vertical
direction from the injection well and mobilized hydrocarbons are recovered
from the production
well along with condensed steam; (iii) a SDP phase during which the production
chamber
expands primarily in a horizontal and/or lateral direction and mobilized
hydrocarbons are
recovered along with condensed solvent; and (iv) a blow-down phase during
which non-
condensable gas is injected to recover residual hydrocarbons and solvent.
[0005] The terms "steam chamber" or "production chamber" or "recovery
chamber"
accordingly refer to the volume of the reservoir which is saturated with
injected fluids and from
which mobilized oil has at least partially drained. Mobilized viscous
hydrocarbons are typically
recovered continuously through one or more production wells. The conditions of
mobilizing fluid
injection and of hydrocarbon production may be modulated to control the growth
of the
production chamber, for example to maximize oil production at the production
well. There are,
however, circumstances in which maximum oil production may not be the
paramount
commercial operational imperative.
SUMMARY
[0006] Methods are provided for managing the composition of injection
fluids made up of
solvent and steam, varying the solvent to steam (So:St) ratio. The adjustments
in So:St ratio
may be carried out so as to mitigate the effects of a gas, such as methane, in
particular by
managing gas dissolution in, and evolution from, mobilizing fluids that
include bitumen. These
processes may augment solvent aided or solvent driven recovery processes, in a
wide variety of
recovery stages. Aspects of these processes involve stimulating the dynamic
movement of
fluids, in effect introducing fluid flows that demonstrably facilitate
hydrocarbon recovery. In
particular, oscillations in solvent to steam ratios, which may be combined
with effective
management of fluid injection and production rates, may be carried out so as
to manage gas
and fluid movements in a chamber, including near wellbore fluid behavior, and
in select
embodiments thereby improve conformance and increase oil production rates.
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[0007] Methods are provided that facilitate bitumen production, involving
one or more long-
term periods of So:St ratio management, each long-term period of So:St ratio
management
being defined by an initial-So:St ratio and a terminal-So:St ratio and by a
long term average rate
of So:St ratio change (between the initial and terminal So:St ratios). These
long-term periods of
So:St ratio management include one or more short-term periods of oscillating
So:St ratios.
Accordingly, in this context, "long-term" and "short-term" are relative terms,
denoting
respectively periods that are temporally distinct in the sense that the long-
term periods are long
enough to include one or more of the short term periods. During short-term
periods of oscillating
So:St ratios, the So:St ratio changes at a short-term oscillation rate that is
above or below the
long-term average rate of So:St ratio change. In this way, dynamic fluid flows
are introduced on
the shorter time scale of the oscillations, which have the unexpected effect
of changing the
performance of the longer term So:St ratio management periods. In particular,
it has been
demonstrated that one or more short-term periods of oscillating So:St ratio
may be implemented
so as to: increase the rate of bitumen production during the long term period
of So:St ratio
management; and/or, reduce a solvent use to bitumen production ratio during
the long term
period of So:St ratio management (this in effect represents an improvement in
that solvent
utilization ratio ¨ achieving over the long term an improved solvent
efficiency). The rate of
bitumen production is thereby increased above the rate of bitumen production
in the absence of
the short-term period of oscillating So:St ratio.
[0008] One long-term period of So:St ratio management may be an initial
recovery period,
analogous to a rising chamber period in a SAGD operation, during which the
recovery chamber
is expanding upwardly towards an overlying zone, such as an overburden or a
poor pay zone.
The long term average rate of So:St ratio change may be positive during this
initial recovery
period, with the So:St ratio increasing on average over time.
[0009] One long-term period of So:St ratio management may be an overlying
zone heating
period, analogous to a horizontal expansion period in a SAGD operation, during
which the
recovery chamber expands under an overlying zone, such as an overburden. The
long term
average rate of So:St ratio change may be negative during the overlying zone
heating period,
with the So:St ratio decreasing on average over time. The So:St ratio may for
example decrease
during the overlying zone heating period, so as to heat to the recovery
chamber with the steam
and thereby maintain a target bottom hole pressure. In addition to efficiently
maintaining bottom-
hole pressure, using higher steam ratios during an overlying zone heating
period is an efficient
way to heat the overlying zone, such as an overburden, since steam is more
efficient than
solvent for the purpose of acting as a heating medium.
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Date Recue/Date Received 2020-12-17
[0010] Following an overlying zone heating period, a further long-term
period of So:St ratio
management may be carried out, as a recovery chamber expansion period. The
long term
average rate of So:St ratio change may be positive during the recovery chamber
expansion
period, with the So:St ratio increasing on average overtime. In alternative
embodiments, the
long term average rate of So:St ratio change may be negative during the
recovery chamber
expansion period, decreasing over time for example in scenarios where there
are permeability
barriers that block chamber enhancement. In effect, permeability barriers may
act in a manner
analogous to overburden. In such circumstances, it may be advantageous to
increase steam
concentration to implement one or more stages of conduction heating in the
presence of such
barriers (in circumstances where solvent dilution is ineffective). The actual
conditions
encountered may be complex, for example with partial barrier strata that act
as baffles that will
allow fluid flow after a period of time.
[0011] Alternative recovery processes may be combined with long-term
periods of So:St
ratio management, and with short term oscillations. For example, SAGD thermal
recovery
processes may be carried out prior to, or after, the one or more long-term
periods of So:St ratio
management. In some circumstance, for example, other thermal processes such as
SAGD may
be implemented so as to aid in solvent re-vaporization or increase solvent
retention in the
reservoir ¨ approaches that may in turn facilitate reduced steam use. This may
for example be
of use in a pre-blowdown phase.
[0012] In an alternative aspect, methods are provided for the shorter-term
So:St ratio
oscillations to increase the rate at which solvent concentrations can be
increased over a longer
term period of So:St management, in effect providing for a more expeditious
long-term period of
So:St increase, wherein the So:St increases from an initial-So:St ratio to a
greater-So:St ratio at
a long term average rate of So:St ratio increase. The long-term period of
So:St ratio increase
includes one or more of the short-term periods of oscillating So:St ratio,
during which the So:St
ratio changes at one or more short-term oscillation rates that are each above
or below the long-
term average rate of So:St ratio increase. The short-term periods of
oscillating So:St may then
be implemented so as to increase the long term average rate of So:St increase.
[0013] Short-term periods of oscillating So:St ratio may involve adjusting
production
conditions. For example, a production flow control device such as a production
pump may be
operated so as to reduce production of gas, alternative production flow
control devices may for
example include tubing inside the production liner that may be used to adjust
gas flows, for
example to force fluids to travel to the toe of the production well for
intake, similarly fluid flow
control devices (FCDs) such as inflow control devices (ICDs) and/or upset
protection ports
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Date Recue/Date Received 2020-12-17
(UPPs) may be used to prevent gas intake in order to improve pump efficiency
(all of which are
collectively available as production flow control devices).
[0014] Solvents for use in alternative aspects of the present methods may
be heated, or not,
prior to injection. Solvents may for example include C2 to C10 linear,
branched, or cyclic
alkanes, alkenes, or alkynes, substituted or unsubstituted, and may
predominantly comprises
one or more n-alkane, such as propane, butane or pentane. A wide variety of
organic and/or
inorganic additives may be included with solvents, for example as additives in
trace or small
amounts.
[0015] Methods may involve injecting the solvent and the steam through an
injection well
and producing mobilized fluids through a production well, the injection and
production wells
forming a well pair. The production well may include a production well surface
facility in fluid
communication with a generally horizontal longitudinal production well segment
in fluid
communication with the recovery chamber, the production well having a fluid-
permeable
production well casing. The injection well may similarly include an injection
well surface facility
in fluid communication with a generally horizontal longitudinal injection well
segment in fluid
communication with the recovery chamber, the longitudinal injection well
segment being
generally parallel to and vertically spaced apart above the longitudinal
production well segment.
BRIEF DESCRIPTION OF THE DRAWINGS
[0016] Figure 1 is a line graph, illustrating well head temperature,
emulsion and water cut in
an exemplified heavy oil production process.
[0017] Figure 2 is a line graph, illustrating steam injection, production
rate and producer
bottom hole pressure in an exemplified heavy oil production process.
[0018] Figure 3 is a line graph illustrating long-term solvent injection
concentration profiles
for alternative modeled process that involve relatively long term changes in
the solvent to steam
ratio, designated as Solvent Ramp-Up and Solvent Pre-Loading profiles on the
graph.
[0019] Figure 4 is a line graph illustrating shorter-term solvent injection
concentration
oscillations imposed upon longer-term changes in solvent concentration, in two
modeled
processes, designated as Solvent Pre-Loading (SPL-SDP) and Solvent Pre-Loading
Dynamic
(SPL ¨ Dynamic) profiles on the graph.
[0020] Figure 5 is a plot comparing Average Net SolvOR vs. Average SOR at
65% bitumen
recovery for three modeled process that involve shorter-term solvent injection
concentration
oscillations imposed upon longer-term changes in solvent concentration,
designated as Solvent
Date Recue/Date Received 2020-12-17
Ramp Up (SRU-SDP), Solvent Pre-Loading (SPL-SDP) and SPL ¨ Dynamic profiles on
the
graph.
DETAILED DESCRIPTION
[0021] Processes are disclosed for managing the composition of injection
fluids made up of
solvent and steam, so as to mitigate the effects of gases, including for
example methane,
propane and steam, during the solvent aided or solvent driven recovery
process. In addition to
modulating the composition of injection fluids, the rates of fluid injection
and/or production may
be modulated. By modulating the composition of injection fluids, in
combination with managing
injection and production fluid flows, the near wellbore behavior of fluids can
be improved, for
example so as to ameliorate gas coning in a production well. In these
processes, relatively long
term recovery periods are defined by solvent to steam ratios that are
optimized for large scale
characteristics of the reservoir and the recovery operation. The solvent to
steam ratio may for
example be decreased over a relatively long period, increasing the relative
amounts of steam,
so as to efficiently heat the recovery chamber. This may for example be
advantageous when the
recovery chamber is losing heat to an overlying zone, such as a poor pay zone
or an
overburden or other non-productive zone. Conversely, where less heating is
necessary, the
solvent to steam ratio may be increased to make efficient use of solvent to
mobilize bitumen in
place of more energetically expensive steam.
[0022] Simulations and pilot testing have revealed that the longer-term
recovery periods
characterized by particular solvent to steam ratios may be improved by
interspersing within the
longer periods one or more oscillations in the solvent to steam ratio. These
shorter-term
oscillations have beneficial effects that are consistent with the effective
management of gases
within the recovery chamber. These oscillations in solvent to steam ratios may
also be
combined with effective management of fluid injection and production rates. In
effect, these
varying fluid flow rates, and orchestrated solvent loadings, may be managed so
as to manage
gas movement in the chamber and thereby improve conformance and increase oil
production
rates.
[0023] The dynamics of gas behavior in recovery operations that make use of
solvents is
complex. The present processes rely on the beneficial effects that have been
shown to arise
when these systems are modulated on relatively short time frames so as to
increase the
dynamics of the system. Changing the solvent to steam ratio adds dynamics to
the system by
causing changes in the degree to which gases dissolve in mobilizing bitumen.
Under some
conditions, solvents, such as propane, decrease the solubility of NCGs, such
as methane, in the
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Date Recue/Date Received 2020-12-17
bitumen. This effect is dependent on conditions of temperature and pressure.
For example, the
solubility of propane (or more generally lower chain alkanes) generally
increases with pressure,
however, increasing pressure is typically accompanied by an increase in
temperature, and
increasing temperature will generally decrease the solubility of solvents in
the bitumen.
Typically, under reservoir conditions temperature has a dominant impact
compared to pressure.
Further complexities are introduced by diffusion rates, as opposed to
solubility changes. In
general, solubility decreases with temperature, but diffusion increases with
temperature.
Accordingly, both pressure and temperature conditions must be accounted for in
the
management of in situ gases, in the context of both solubility and diffusion
effects. Temperature
changes also change the solubility of both the solvent and NCGs in the
mobilizing bitumen.
Solvent diffusion into the bitumen phase is typically more effective with
increasing temperature,
up to a point, and less effective when the bitumen phase is cooler.
Oscillating solvent to steam
ratios accordingly drives dynamic changes in the recovery chamber. The
simulations and pilot
data presented herein illustrate that this added dynamism may be managed so as
to facilitate
bitumen recovery, in in the process reduce a solvent-use to bitumen-production
ratio, for
example during a long term period of So:St ratio management. In this way,
improvements may
be provided in a solvent utilization ratio ¨ achieving over a long term an
improved solvent
efficiency.
[0024] 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, 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
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Date Recue/Date Received 2020-12-17
disclosed herein is generally defined as the exploitable or producible oil
located above the
production well elevation.
[0025] 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 Pas) 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.
[0026] 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
characterized 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. A pay zone is a reservoir volume having hydrocarbons
that can be
recovered economically.
[0027] "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.
[0028] 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
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Date Recue/Date Received 2020-12-17
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 of
hydrocarbons, often by gravity drainage, into a production well.
[0029] As used herein, the term "about", in the context of a numerically
definable parameter,
refers to an approximately +/-10% variation from a given value. Where
numerical values are
recited herein and these values are necessarily an approximation, for example
to a given
decimal point, it is to be understood that the recital of the values imputes
the exercise of
approximation.
[0030] A wide variety of alternative configurations of injection and
production wells may be
adapted for alternative implementations of forced solvent cycling processes,
for example
involving production wells that are infill wells, which may in turn be
WedgewellsTM, and where
steam or production chambers served by particular injection and/or production
wells are distinct
or have merged.
[0031] Reservoirs containing heavy hydrocarbons are typically below an
overburden, which
may also be referred to as a cap layer or cap rock. The overburden may be
formed of a layer of
impermeable material such as clay or shale. Under natural conditions (e.g.
prior to the
application of a recovery process), the reservoir is typically at a relatively
low temperature, such
as about 12 C, and the formation pressure may be from about 0.1 to about 4
MPa (1 MPa =
1,000 Pa), depending on the location and other characteristics of the
reservoir. A pair of wells,
including an injection well and a production well, are drilled into and extend
substantially
horizontally in the reservoir for producing hydrocarbons from the reservoir.
The well pair is
typically positioned away from the top of the reservoir, which is defined by
the lower edge of the
overburden, and positioned near the bottom of a pay zone or geological stratum
in the reservoir.
[0032] As is typical of such well pair configurations, the injection well
may be vertically
spaced from the production well, such as at a distance of about 5 m. The
distance between the
injection well and the production well in a well pair may vary and may be
selected to optimize
forced solvent cycling operations. In select embodiments, the horizontal
sections of the injection
well and the production well may be about 800-2000 m in length. In other
embodiments, these
lengths may be varied and the overall pattern of well pairs may vary widely.
The injection well
and the production well may each be configured and completed according to a
wide variety of
suitable techniques available in the art. The injection well and the
production well may also be
referred to as the "injector" and "producer", respectively.
[0033] The injection well and the production well are typically connected
to respective
corresponding surface facilities, which typically include an injection surface
facility and a
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Date Recue/Date Received 2020-12-17
production surface facility. The injection surface facility may be configured
and operated to
supply injection fluids, such as steam, solvent or combinations thereof into
the injection well.
The production surface facility is configured and operated to produce fluids
collected in the
production well to the surface. In select embodiments, co-injected fluids or
materials may be
pre-mixed before injection. In other embodiments, co-injected fluids may be
separately supplied
into the injection well. In particular, the injection surface facility may be
used to supply steam
into the injection well in a first phase, and a mixture of steam and solvent
into the injection well
in a second phase. In the second phase, the solvent may be pre-mixed with
steam at surface
before co-injection. Alternatively, the solvent and steam may be separately
fed into the injection
well for injection into the reservoir. Optionally, the injection surface
facility may include a heating
facility (not separately shown) for pre-heating the solvent before injection.
[0034] The injection well typically has an injector casing and the
production well has a
production casing. An injector tubing is typically positioned in the injector
casing. The injector
casing may include a slotted liner along the horizontal section of well for
injecting fluids into the
reservoir. Production casing may also be completed with a slotted liner, a
wire wrap or a precise
punched slot screen (PPS), along the horizontal section of well for collecting
fluids drained from
the reservoir by gravity (i.e. in a gravity-dominated process). In select
embodiments, the
production well may be configured and completed similarly to the injection
well. In select
embodiments, each of the injection well and the production well may be
configured and
completed for both injection and production.
[0035] The reservoir may be subjected to an initial phase, for example as
part of a SAGD
process, referred to as the "start-up" phase or stage. Typically, start-up
involves establishing
fluid communication between the injection well and the production well. To
permit drainage of
mobilized hydrocarbons and condensate to the production well, fluid
communication between
the injection well and the production well must be established in the
interwell zone. Fluid
communication in this context refers to fluid flow between the injection and
production wells.
Establishment of such fluid communication typically involves mobilizing
viscous hydrocarbons in
the reservoir to form a mobilized reservoir fluid and removing the mobilized
reservoir fluid to
create a porous pathway between the wells. Viscous hydrocarbons may be
mobilized by heating
such as by injecting or circulating pressurized steam or hot water through the
injection well or
the production well. In some cases, steam may be injected into, or
circulated/bullheaded in, both
the injection well and the production well for faster start-up, or start-up
may be stimulated with
solvents such as toluene or xylene. A pressure differential may be applied
between the injection
well and the production well to promote steam/hot water penetration into the
porous geological
Date Recue/Date Received 2020-12-17
formation that lies between the wells of the well pair. The pressure
differential promotes fluid
flow and convective heat transfer to facilitate communication between the
wells.
[0036] Additionally or alternatively, other techniques may be employed
during the start-up
stage. For example, to facilitate fluid communication, a solvent may be
injected into the
reservoir region around and between the injection well and the production
well. The region may
be soaked with a solvent before or after steam injection. An example of start-
up using solvent
injection is disclosed in CA 2,698,898. In further examples, the start-up
phase may include one
or more start-up processes or techniques disclosed in CA 2,886,934, CA
2,757,125, or CA
2,831,928.
[0037] Once fluid communication between the injection well and the
production well has
been achieved, oil production or recovery may commence, employing one or more
iterations of
forced solvent cycling. As a result of depletion of the heavy hydrocarbons, a
porous region is
formed in the reservoir, which is referred to as a vapor or production or
recovery chamber. The
mobilized hydrocarbons drained towards the production well and collected in
the production well
are then produced (transferred to the surface), such as by gas lifting or
through pumping.
[0038] The solvent for use in the present processes may be selected based
on a number of
considerations and factors, for example as set out in CA2,956,771. The solvent
may be
injectable as a vapor, and may be selected on the basis of being suitable for
dissolving at least
one of the heavy hydrocarbons to be recovered from the reservoir. The solvent
may be a
viscosity-reducing solvent, which reduces the viscosity of the heavy
hydrocarbons in the
reservoir. Suitable solvents may include C2 to 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 as the dominant solvent,
for example
propane, butane, pentane or mixtures thereof. For a given selected solvent,
the corresponding
operating parameters during co-injection of the solvent with steam may also be
selected or
determined in view the properties and characteristics of the selected solvent.
The mass fraction
of the solvent may for example be greater than 20% and enough steam may be
added to
ensure that the injected solvent is substantially in the vapor phase. In a
given application, the
solvent may be selected based on its volatility and solubility in the
reservoir fluid.
[0039] The solvent may be heated to vaporize the solvent. For example, when
the solvent is
propane, it may be heated with hot water at a selected temperature such as,
for example, about
100 C. Additionally or alternatively, solvent may be mixed or co-injected
with steam to heat the
solvent to vaporize it and to maintain the solvent in vapor phase. Depending
on whether the
solvent is pre-heated at surface, the weight ratio of steam in the injection
stream should be high
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Date Recue/Date Received 2020-12-17
enough to provide sufficient heat to the co-injected solvent to maintain the
injected solvent in the
vapor phase. If the feed solvent from surface is in the liquid phase, more
steam may be required
to both vaporize the solvent and maintain the solvent in the vapor phase as
the solvent travels
through the vapor chamber 260. For example, where the selected solvent is
propane, a solvent-
steam mixture containing about 90 % propane and about 10 % steam on a mass
basis may be
injected at a suitable temperature, such as about 75 C to about 100 C. For
example, the
enthalpy per unit mass of the aforementioned steam-propane mixture may be
about 557 kJ/kg.
[0040] In the context of the present disclosure, at various times, the
produced-fluid stream
may have an oil:water ratio of from about 25:75 to about 90:10, depending on
the amount of
solvent injected. In some embodiments, the use of solvent may give rise to a
bitumen-
concentrating effect in the mobilized fluid zone at the bottom of the
production chamber,
compared to thermal recovery mediated by steam alone.
[0041] 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. 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. Terms such as "exemplary" or
"exemplified" are used
herein to mean "serving as an example, instance, or illustration." Any
implementation described
herein as "exemplary" or "exemplified" is accordingly not to be construed as
necessarily
preferred or advantageous over other implementations, all such implementations
being
independent embodiments. Unless otherwise stated, numeric ranges are inclusive
of the
numbers defining the range, and numbers are necessarily approximations to the
given decimal.
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, and all
documents cited in such
documents and publications, are hereby 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.
12
Date Recue/Date Received 2020-12-17
EXAMPLES
Example 1: Increased Bitumen Production Evidencing Conformance Enhancement
[0042] This Example illustrates increased bitumen production, an indication
of conformance
enhancement, by implementing an oscillation in the solvent to steam ratio as
part of a SAP
process. The exemplified alternating SAP process involved varying propane co-
injection
between 0 wt.% (SAGD), 3 wt.% and 10 wt.% for two weeks. Injection pressure
was maintained
at 3100 KPag by Automated Process Control (APC) at all times. Emulsion
production rate was
also maintained at a constant rate of 19 5m3/hr.
[0043] Figure 1 shows how the mobilized fluid level is depleted as produced
fluid
temperature rises. An approximately four degree change in well head
temperature (184 C ¨
188 C) is accompanied by a water cut to drop from 68% to 55%. The process
accordingly
involves a step of injecting less steam, with propane co-injection, while
producing approximately
the same volume of mobilized fluids (-19 5m3/hr). The resulting effect of
increasing bitumen
production, is shown in Figure 2, illustrating the increase in bitumen rate
and an attendant drop
in the water production rate. The steam injection rate line is annotated with
the changes to the
different propane concentrations (from 0%, i.e. SAGD, to 3% solvent, to 10%
solvent, with other
solvent concentration changes having yielded similar results). This increasing
bitumen rate is
putatively attributable at least partly to gas flow changes, such as
imbalances that drive NCG
flows that facilitate improved recoveries. This may in turn affect bitumen
drainage conditions, for
example steepening the angle of drainage in the recovery chamber. In this way,
oscillating
solvent concentrations (varying over a relatively short duration, in this case
about two weeks,
with other oscillation periods having yielded similar results), may be carried
out so as to
increase drainage angles thereby mediating enhanced conformance and improved
bitumen
production rates.
Example 2: Improved Solvent Efficiency
[0044] A semi-homogenous reservoir model was used to simulate processes
that involved
shorter-duration steps of solvent concentration oscillation, within the
context of longer-duration
changes in the solvent to steam ratio. The modeled solvent was propane, with
the remaining
injected fluid being steam. Reservoir horizontal permeability was fixed at
7000mD while vertical
permeability was fixed at 3500mD12. Each simulation was run to 65% recovery
factor and
stopped, hence simulation time varied for each simulation run. In all the
simulations, blowdown
was not simulated. Total cumulative injections and production were divided by
total simulation
time to give averaged values. The average net solvent injected rate was
obtained by dividing
13
Date Recue/Date Received 2020-12-17
the cumulative net solvent injected over total simulation time to get to 65%
recovery factor, while
the average oil rate was obtained by dividing the cumulative bitumen produced
by the total
simulation time. The ratio of the average net solvent injected rate and the
average net oil
produced gives the average net solvent oil ratio (SolvOR).
[0045] Figure 3 shows a schematic of alternative processes that involve
longer-duration
changes in the solvent to steam ratio, designated herein as Solvent Ramp Up
(SRU-SDP) and
Solvent Pre-Loading (SPL-SDP) injection strategies. In alternative
implementations, the discrete
time increments could for example be daily, weekly, monthly, yearly or
multiples of these time
increments. For the present Example, 3 months was chosen as the discrete time
increment. The
SRU-SDP strategy starts at 20 wt% solvent concentration after a SAGD phase and
gradually
rises (10 wt% step increases every 3 months) to 80 wt% solvent concentration
18 months after,
and then gradually drops back to 20 wt% (10 wt% decreases every 3 months) in
18 months. 20
wt% solvent concentration is then held constant for the remainder of the
simulation until 65% of
the bitumen in place is recovered. Figure 3 illustrates the long term average
rates of change in
the solvent to steam ratio. The SPL-SDP strategy is in essence a mirror image
of the SRU-SDP
strategy.
[0046] An further alternative process, designated herein as the SPL-Dynamic
process, was
implemented in a model on the following basis:
1. Check every 30 days if injection pressure is less than target (3100 kPa).
If it is,
decrease solvent injected wt% by lOwt%, if not, do nothing.
2. Continue step 1 above till solvent injection wt% is 20 wt%.
3. After step 2, check every 30 days if injection pressure is greater than the
target (3100
kPa). If it is, increase solvent injected wt% by 10 wt%, if not, do nothing.
4. Continue step 3 above till solvent injection wt% is 80 wt%.
5. Throughout steps 1 to 4, if producer pressure is every greater than 3050
kPa,
increase casing gas production by 500 std m3/d to bleed pressure.
[0047] Figure 4 compares the solvent injection concentration profiles for
SPL-Dynamic and
SPL-SDP, illustrating longer-term "V" shaped solvent concentration profiles,
having shorter-term
oscillations in solvent concentration superimposed on the long-term changes in
solvent
concentration. In the SPL-Dynamic model, immediately after the SAGD phase, the
foregoing
model parameters dictated that solvent concentration could not be maintained
at 80wt% and
accordingly dropped to 70 wt%. As modeled, this reflects a circumstance in
which sufficient
overburden surface area has been exposed post SAGD to necessitate increased
steam
injection. Also, steam injection increased at a rate of about 0.5 wt% / month
until the lowest
14
Date Recue/Date Received 2020-12-17
solvent concentration (20 wt%) was reached. This was maintained for about 5
months before
injection pressure began to increase, necessitating an increase in solvent
injection
concentration, which was then maintained at 40 wt% for almost a year before
ramping up to 70
wt%. The general "V" shaped profile of the SPL-Dynamic model, resulting from
the adoption of
the foregoing criteria, in effect lends support to the adoption of the longer
term solvent
concentration changes that are also part of the SPL-SDP profile.
[0048] Figure 5 compares the average net SolvOR as a function of net SOR
for the three
modeled solvent concentration changing strategies, illustrating that
increasing steam as a
consequence of demand (pressure loss due to heat losses) is an effective
strategy to manage
solvent injection during SDP, since SPL-Dynamic has the lowest net SolvOR of
the three. An
analysis of the excess oil rate as a function of net solvent injected, shows
SPL-Dynamic
achieves the same excess oil rate as SPL-SDP and SRU-SDP, but at significantly
lower solvent
requirement.
Date Recue/Date Received 2020-12-17
