Note: Descriptions are shown in the official language in which they were submitted.
BITUMEN STORAGE IN SITU
FIELD
[0001] The present disclosure relates to in situ methods for recovering
hydrocarbons from
subterranean reservoirs. In particular, the present disclosure relates to
solvent-aided methods
that facilitate the dynamic storage of variable amounts of bitumen in situ.
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-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] A typical 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] A wide variety of alternative processes have been proposed for in
situ hydrocarbon
recovery aided by fluids or treatments other than steam, including a variety
of process that
make use of hydrocarbon solvents. Recovery processes that are aided in any way
by one or
more solvents are referred to herein as solvent-aided processes (SAP). In some
embodiments
of SAP, the injection fluid may include less than about 20 A solvent and
greater than about 80%
steam on a mass basis. Such processes may be referred to as "steam-driven
solvent-aided
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processes". In some embodiments of SAP, the injection fluid may include
between about 20 %
and about 80% solvent on a mass basis. Such processes may be referred to as
"hybrid solvent-
assisted processes". In some SAP embodiments, the injection fluid may include
greater than
about 80% solvent and less than about 20% steam on a mass basis. Such
processes may be
referred to as "substantially solvent driven or in some cases solvent-only
processes". In the
present disclosure, the term "solvent driven process (SDP)" is used to refer
to both hybrid
solvent-assisted processes and substantially solvent-only processes.
Accordingly, the injection
fluid used in a SDP typically includes greater than about 20% solvent on a
mass basis, and SAP
includes processes that make use of any amount of solvent.
[0005] The terms "steam chamber" or "production 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 disclosed for operating a well pair in a heavy oil
reservoir to facilitate
dynamic bitumen storage and production. The methods optionally involve the use
of a solvent in
the mobilizing injection fluid, with the attendant effect of varying the
composition of the stored
bitumen emulsion. Methods are provided to facilitate monitoring of stored
fluid levels and
thereby managing the level and composition of stored bitumen. The stored
bitumen is typically
in the form of a reservoir of mobilized fluids within the production chamber,
with the stored fluids
in the form of an emulsion having a controlled and variable composition. The
present processes
accordingly provide for solvent aided variable emulsion bitumen ("SAVEBit")
storage in situ.
[0007] In various aspects of SAVEBit storage, production and injection
wells are provided
for accessing the heavy oil reservoir. The production well may include a
production well surface
facility in fluid communication through a heel segment of the production well
with a generally
horizontal longitudinal production well segment within a heavy oil zone in the
reservoir, at a
production well level in the reservoir, the production well comprising a
production well casing.
Similarly, the injection well may include an injection well surface facility
in fluid communication
with a generally horizontal longitudinal injection well segment within the
heavy oil zone in the
reservoir at an injection well level in the reservoir. The longitudinal
injection well segment will
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CA 3043954 2019-05-22
generally be parallel to and vertically spaced apart above the longitudinal
production well
segment.
[0008] SAVEBit methods involve operating a well pair under a
substantially gravity-
dominated recovery process, such as a SAGD or SAP process, to form a
production chamber in
the heavy oil zone, the production chamber forming a bottom production zone in
proximity to the
horizontal longitudinal production well segment. A mobilizing injection fluid
comprising a solvent
may be injected into the heavy oil zone through the injection well to expand
the production zone
and thereby define a top of the production zone. A production fluid that
includes solvent in the
oleic phase of an emulsion may then be produced from the heavy oil zone,
through the
production well.
[0009] One or more operational parameters of the well pair may be
monitored, as an
indicator of fluid level in the production chamber, the operational parameters
for example
comprising: a heel temperature in the heel segment of the production well, a
casing gas flow
through the production well casing of the production well, a bottom hole
pressure in the
production or the injection well, and/or an oleic phase solvent measurement
reflecting relative
proportions of bitumen and solvent in the oleic phase of the production fluid.
The injecting and
producing of injection and production fluids may be adjusted based on one or
more of these
operational parameters, optionally in combination with other operational
parameters. In this way,
the SAVEBit process allows an operator to maintain a variable reservoir of
mobilized fluids in
the production chamber in fluid communication with the production well, the
reservoir of
mobilized fluids having an upper level and a lower level. Concomitantly, the
operator can
maintain a production pressure in the production chamber that supports
production of fluids
through the production well. In addition, the operator may adjust the amount
of bitumen in the
reservoir of mobilized fluids between a maximum amount of stored bitumen and a
minimum
amount of stored bitumen. The minimum amount of stored bitumen corresponding
generally to
reservoir conditions wherein the relative proportion of bitumen in the
production fluid is
minimized and the upper level of the reservoir of mobilized fluids approaches
but does not
descend below the level of the production well. The maximum amount of stored
bitumen
corresponding to reservoir conditions wherein the relative proportion of
bitumen in the
production fluid is maximized and the upper level of the mobilized fluids
approaches the top of
the production zone, or optionally does not override the level of the
injection well,.
[0010] In accordance with the foregoing approach, the well pair may for
example be
operated so as to achieve a very wide variety of alternative operational
objectives, such as to:
increase the amount of bitumen in the reservoir of mobilized fluids; decrease
the amount of
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CA 3043954 2019-05-22
bitumen in the reservoir of mobilized fluids; maintain the maximum amount of
stored bitumen;
maintain the minimum amount of stored bitumen; maximize the production of
bitumen; or
minimize the production of bitumen.
[0011] The parameters that trigger adjustments in the SAVEBit operations
may, for
example, include indicators of the market price for bitumen, and/or a
regulatory limit on an
amount of bitumen to be produced from the heavy oil reservoir.
BRIEF DESCRIPTION OF THE DRAWINGS
[0012] FIG. 1 schematically illustrates a typical well pair in a
hydrocarbon reservoir, which
can be operated to implement embodiments of the presently disclosed methods
for solvent
aided mobilized bitumen ("SAVEBit") storage in situ.
[0013] FIG. 2 schematically illustrates aspects of the well pair of FIG.
1, contacting a
hydrocarbon depleted production chamber formed within the reservoir.
[0014] FIGs. 3A and 3B illustrate exemplary process flows for SAVEBit
storage processes
in the context of a broader recovery process, that in FIG. 3A includes a SAGD
stage.
[0015] FIG. 4 is a line graph illustrating fluid flows in an exemplary
embodiment of a
SAVEBit storage process.
DETAILED DESCRIPTION
[0016] SAGD processes may be adapted for dynamic bitumen storage in situ,
by
modulating injection and production flows to store more or less emulsion at
the bottom of the
production chamber. In addition, SAGD production fluids may be stored in
depleted steam
chambers to capitalize on any residual heat in the depleted chamber. In both
cases, however,
the mobilized fluids produced by a typical SAGD process comprise a substantial
proportion of
condensed aqueous fluids, and as such the volume of bitumen in the stored
mobilized fluids is
necessarily limited.
[0017] Processes of dynamic bitumen storage involving the solvent aided
mobilized bitumen
(SAVEBit) storage methods disclosed herein overcome the storage capacity
limitations
associated with dynamic storage under SAGD conditions. The SAVEBit approach
provides
substantially more dynamic range in the available in situ storage capacity of
a given reservoir,
as solvent-aided processes produce less aqueous condensate per unit of
produced fluid.
[0018] In the SAVEBit storage methods disclosed herein, the operator may
adjust the
amount of bitumen in the reservoir of mobilized fluids between a maximum
amount of stored
bitumen and a minimum amount of stored bitumen. The minimum amount of stored
bitumen
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CA 3043954 2019-05-22
corresponds generally to reservoir conditions wherein the relative proportion
of bitumen in the
production fluid is minimized and the upper level of the reservoir of
mobilized fluids approaches
but does not descend below the level of the production well. The relative
proportion of bitumen
in the production fluid may for example be minimized by returning to a steam
driven production
process, thereby diluting a reservoir of relatively concentrated stored
bitumen that has been
generated by a SAP or SDP production process. The maximum amount of stored
bitumen
corresponds to reservoir conditions wherein the relative proportion of bitumen
in the production
fluid is maximized and the upper level of the mobilized fluids approaches the
top of the
production chamber. In some circumstances, operators may also elect to limit
the upper level of
the mobilized fluids to a level that approaches but does not override the
level of the injection
well. The heel or bottom hole temperature of the injection and/or production
wells provides an
indication of stored fluid levels, with the stored fluid in effect providing a
variable degree of
insulation between the well and the heated production chamber ¨ a rising
temperature being an
indication of falling stored fluid levels and vice versa. The amount of
production well casing gas
provides an indication of the relative extent of the gas phase in the
production fluids, and this in
turn reflects the proximity of the gas phase of the production chamber to the
production well.
Increasing casing gas production accordingly correlates with falling fluid
storage levels. An
increasing proportion of solvent in the oleic phase of the production fluid
provides an additional
indication that the upper level of the mobilized fluids is approaching the
injection well. The
bottom hole pressures of the injection and/or production wells similarly
provide an indication of
stored fluid levels, with falling bottom hole pressure being an indication
that the production
chamber is being depressurized, for example when injected solvent short
circuits to production
fluids.
[001 9] In accordance with the foregoing approach, the well pair may for
example be
operated so as to achieve a very wide variety of alternative operational
objectives, such as to:
increase the amount of bitumen in the reservoir of mobilized fluids; decrease
the amount of
bitumen in the reservoir of mobilized fluids; maintain the maximum amount of
stored bitumen;
maintain the minimum amount of stored bitumen; maximize the production of
bitumen; or
minimize the production of bitumen. In some instances, the stored fluid levels
may be allowed to
rise towards the top of the production chamber, overriding the injection well.
This is made
possible by the fact that solvent may be injected at temperatures and
pressures that are well
into the gas phase of the solvent, so that the solvent can move as a gas
through the stored fluid
into the upper portions of the production chamber (in a way that steam
cannot). In such
5
CA 3043954 2019-05-22
embodiments, solvent is injected into the stored fluids and then moves into
the pressurized
production chamber.
[0020] The parameters that trigger adjustments in the SAVEBit operations
may, for
example, include indicators of the market price for bitumen, and/or a
regulatory limit on an
amount of bitumen to be produced from the heavy oil reservoir. For example,
one approach may
involve reducing injection and produced emulsion flow, for example by 50-99%,
thereby
switching to an operational strategy of very low level "trickling" solvent-
steam injection and very
low level "dribble" solvent-steam-NCG production. In alternative embodiments,
the
accumulation of stored fluids may be monitored by a reduction in the
production casing gas flow
and a corresponding drop in production well temperature, such as the
production heel
temperature. In various embodiments, the bottom hole pressure (BHP) and/or
casing gas
production may be monitored, and in such circumstances when the production
well is entirely
flooded the mobilized fluids the casing gas flow should trend towards 0 and
the production heel
temperature will start to decline. If BHP substantially declines, it may be
advantageous to
increase solvent-steam injection to maintain conditions suitable for ongoing
production, this may
for example be evident by a BHP drop of 20, 30, 40 or 50 kPa over a 1 week
period, for
example from 3200 kPa to 3150 kPa. In some embodiments, an increase in the
intermittent
solvent content in the oleic phase of the production fluids may be used as an
indication of
solvent being injected directly into the stored fluids, in effect an
indication that the stored fluid
levels are approaching or overriding the injector. For example, an increase in
the intermittent
solvent content in the oleic phase of >5% may provide such an indicator, for
example with
propane in oil going from 50 mol /0 to 55 mol /0. The volume and level of
stored fluids may
alternatively be modeled, for example with the volume under the injection well
being determined
according to the following formula: V=0.5*a*c*h*p*s.
Where V-is the volume able to store emulsion under the injecting well
a = height from the injecting well to the lowest point of the emulsion buildup
(e.g. 5m)
c = the width of steam or steam- solvent chamber developed laterally to the
injector
h = length of the injection well
p = local porosity
s = subcool coefficient
[0021] 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"
6
CA 3043954 2019-05-22
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
disclosed herein is generally defined as the exploitable or producible oil
located above the
production well elevation.
[0022] 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.
[0023] 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 fades, 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
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CA 3043954 2019-05-22
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.
[0024] "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.
[0025] 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 of
hydrocarbons, often by gravity drainage, into a production well.
[0026] 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.
[0027] For the purpose of promoting an understanding of the principles of
the disclosure,
reference will now be made to the features illustrated in the drawings and
specific language will
be used to describe the illustrated embodiments. It will nevertheless be
understood that these
illustrated embodiments exemplify rather than limit the generality of the
present disclosure.
[0028] FIG. 1 schematically illustrates a typical well pair in a heavy
oil hydrocarbon
reservoir, which can be operated to implement embodiments of the presently
disclosed methods
for solvent aided mobilized bitumen ("SAVEBit") storage in situ. A wide
variety of alternative
configurations of injection and production wells may be adapted for
alternative implementations
of SAVEBit storage processes, for example involving production wells that are
infill wells, which
may in turn be wedgewells, and where steam or production chambers served by
particular
injection and/or production wells are distinct or have merged.
[0029] As illustrated, a reservoir 100 containing heavy hydrocarbons is
below an
overburden 110, which may also be referred to as a cap layer or cap rock. The
overburden 110
may be formed of a layer of impermeable material such as clay or shale. A
region in the
reservoir 100 just below and near the overburden 110 may be considered as an
interface region
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CA 3043954 2019-05-22
115. Under natural conditions (e.g. prior to the application of a recovery
process), the reservoir
100 is 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 SAGD wells, including an injection
well 120 and a
production well 130, are drilled into and extend substantially horizontally in
the reservoir 100 for
producing hydrocarbons from the reservoir 100. The well pair is typically
positioned away from
the top of the reservoir 100 which, as depicted in FIG. 1, is defined by the
lower edge of the
overburden 110, and positioned near the bottom of a pay zone or geological
stratum in the
reservoir 100.
[0030] As is typical of such SAGD configurations, the injection well 120
may be vertically
spaced from the production well 130, such as at a distance of about 5 m. The
distance between
the injection well 120 and the production well 130 in a SAGD well pair may
vary and may be
selected to optimize the SAGD operation performance, or to optimize
anticipated SAVEBit
storage operations. In this context, the inter-well distance represents a
parameter relevant the
volume of stored mobilized bitumen, so that a larger inter-well spacing may be
implemented to
maximize SAVEBit storage capacity within the inter-well space.
[0031] In select embodiments, the horizontal sections of the injection
well 120 and the
production well 130 may have be about 800-1000 m in length. In other
embodiments, these
lengths may be varied and the overall pattern of well pairs may vary widely.
The injection well
120 and the production well 130 may each be configured and completed according
to a wide
variety of suitable techniques available in the art. The injection well 120
and the production well
130 may also be referred to as the "injector" and "producer", respectively.
[0032] As illustrated, the injection well 120 and the production well
130 are connected to
respective corresponding surface facilities, which typically include an
injection surface facility
140 and a production surface facility 150. The injection surface facility 140
is configured and
operated to supply injection fluids, such as steam, solvent or combinations
thereof into the
injection well 120. The production surface facility 150 is configured and
operated to produce
fluids collected in the production well 130 to the surface. Each of the
injection surface facility140
and the production surface facility150 includes one or more fluid pipes or
tubing for fluid
communication with their respective wells. As depicted for illustration,
surface facility 140 may
have a supply line connected to a steam generation plant for supplying steam
for injection and a
supply connected to a solvent source for supplying the solvent for injection.
Optionally, one or
more additional supply lines may be provided for supplying other fluids,
additives or the like for
co-injection with the steam, the solvent or combinations thereof. Each supply
line may be
9
CA 3043954 2019-05-22
connected to an appropriate source of supply, which may include, for example,
a steam
generation plant, a boiler, a fluid mixing plant, a fluid treatment plant, a
truck, or a fluid tank. 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 120. In
particular, the injection surface facility 140 may be used to supply steam
into the injection well
120 in a first phase, and a mixture of steam and solvent into the injection
well 120 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 120
for injection into the reservoir 100. Optionally, the injection surface
facility 140 may include a
heating facility (not separately shown) for pre-heating the solvent before
injection.
[0033] As illustrated, the production surface facility 150 includes a
fluid transport pipeline for
conveying produced fluids to a downstream facility (not shown) for processing
or treatment. The
production surface facility 150 includes equipment for producing fluids from
the production well
130. Other surface facilities 160 may also be provided, for example the
surface facilities 160
may include one or more of a pre-injection treatment facility for treating a
material to be injected
into the formation, a post-production treatment facility for treating a
produced material, a control
or data processing system for controlling the production operation or for
processing collected
operational data.
[0034] FIG. 2 is a schematic perspective view of the injection well 120
and the production
well 130 in the reservoir 100 during a recovery process where a vapor or
production chamber
has formed. As illustrated, the injection well 120 has an injector casing 220
and the production
well 130 has a production casing 230. An injector tubing 225 is positioned in
the injector casing
220. For schematic simplicity, other necessary or optional components, tools
or equipment that
are installed in the injection well 120 and the production well 130 are not
shown in the drawings.
[0035] As depicted in FIG. 2, the injector casing 220 includes a slotted
liner along the
horizontal section of well 120 for injecting fluids into the reservoir 100.
Production casing 230 is
also completed with a slotted liner along the horizontal section of well 130
for collecting fluids
drained from the reservoir 100 by gravity (i.e. in a gravity-dominated
process). In select
embodiments, the production well 130 may be configured and completed similarly
to the
injection well 120. In select embodiments, each of the injection well 120 and
the production well
130 may be configured and completed for both injection and production, which
can be useful in
some applications as can be understood by those skilled in the art.
[0036] FIGs. 3A and 3B illustrate exemplary process flows for aspects of
SAVEBit storage
in the context of a broader recovery process. At S300, the reservoir 100 is
subjected to an initial
CA 3043954 2019-05-22
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 120 and
the production well 130. To permit drainage of mobilized hydrocarbons and
condensate to the
production well 130, fluid communication between the injection well 120 and
the production well
130 must be established. 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 120 or the production well 130. In
some cases, steam
may be injected into, or circulated in, both the injection well 120 and the
production well 130 for
faster start-up. A pressure differential may be applied between the injection
well 120 and the
production well 130 to promote steam/hot water penetration into the porous
geological 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.
[0037] Additionally or alternatively, other techniques may be employed
during the start-up
stage S300. For example, to facilitate fluid communication, a solvent may be
injected into the
reservoir region around and between the injection well 120 and the production
well 130. 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
S300 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.
[0038] Once fluid communication between the injection well 120 and the
production well 130
has been achieved, oil production or recovery may commence during stage S305.
As the oil
production rate is typically low initially and will increase as the
production/vapor chamber
develops, this early production phase is known as the "ramp-up" phase or
stage. During the
ramp-up stage S305, steam is typically injected continuously into injection
well 120, at constant
or varying injection pressure and temperature. At the same time, mobilized
heavy hydrocarbons
and aqueous condensate are continuously removed from the production well 130,
typically in
the form of an emulsion having oleic and aqueous phases. During the ramp-up
stage S305, the
zone of communication between the injection well 120 and the production well
130 may
continue to expand axially along the full length of the horizontal portions
thereof. In alternative
aspects of the SAVEBit storage process, these operations may be conducted so
as to maximize
the available inter-well volume available for bitumen storage.
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CA 3043954 2019-05-22
[0039] As injected steam heats up the reservoir 100, heavy hydrocarbons
in the heated
region are softened, resulting in reduced viscosity. Further, as heat is
transferred from steam to
the reservoir 100, steam condenses. The aqueous condensate and mobilized
hydrocarbons will
drain downward due to gravity, in a gravity-dominated process. As a result of
depletion of the
.. heavy hydrocarbons, a porous region 260 is formed in the reservoir 100,
which is referred to as
a vapor or production chamber. When the void space in a production chamber is
filled with
mainly steam, it is commonly referred to as a "steam chamber." The aqueous
condensate and
hydrocarbons drained towards the production well 130 and collected in the
production well 130
are then produced (transferred to the surface, typically as an oil in water
emulsion), such as by
.. gas lifting or through pumping as is known to those skilled in the art.
[0040] As alluded to above, the production chamber 260 is formed and
expands due to
depletion of hydrocarbons and other in situ materials from regions of the
reservoir 100 above
the injection well 120. Injected steam tends to rise up to reach the top of
the vapor chamber 260
before it condenses, and steam can also spread laterally as it travels upward.
Therefore, during
early stages of chamber development, the vapor chamber 260 expands upwardly
and laterally
from the injection well 120. During the ramp-up stage S305, vapor chamber 260
can grow
vertically towards the overburden 110.
[0041] Depending on the size of the reservoir 100 (and the pay therein)
and the distance
between the injection well 120 and the overburden 110, it can take a long
time, such as many
months and up to two years, for the vapor chamber 260 to reach the overburden
110 especially
when the pay zone is relative thick as is typically found in some operating
oil sands reservoirs.
However, in a thinner pay zone the vapor chamber 260 can reach the overburden
110 sooner.
The time to reach the vertical expansion limit can also be longer in cases
where the pay zone is
higher or highly heterogeneous, or the reservoir 100 has complex overburden
geologies such as
with inclined heterolithic stratification, top water, top gas, or other
stratigraphic complexities.
[0042] In the next stage, the reservoir 100 may be subject to a
conventional SAGD
production process S310, where the oil production rate is sufficiently high
for economic recovery
of hydrocarbons and the cumulative steam oil ratio (CSOR) continues to
decrease or remain
relatively stable. During the conventional SAGD production process S310 (or a
similar but
modified steam-driven recovery process), one or more chemical additives may be
added to
steam or co-injected with steam to enhance hydrocarbon recovery. For example,
a surfactant,
which lowers the surface tension of a liquid, the interfacial tension (IFT)
between two liquids, or
the IFT between a liquid and a solid, may be added. The surfactant may act,
for example, as a
detergent, a wetting agent, an emulsifier, a foaming agent, or a dispersant to
facilitate the
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drainage of the softened hydrocarbons to the production well 130. An organic
solvent, such as
an alkane or alkene, may also be added to dilute the mobilized hydrocarbons so
as to increase
the mobility and flow of the diluted hydrocarbon fluid to the production well
130 for improved
recovery. Other materials in liquid or gas form may also be added to enhance
recovery
performance.
[0043] The start-up stage S300, the ramp-up stage S305, and the SAGD
production
process stage S310 described above are non-limiting examples, and there are
numerous
conventional and innovative techniques known to those skilled in the art that
result in the
formation of a production chamber. In alternative embodiments, rather than
using a well pair,
one or more single horizontal or vertical wells may be used for providing a
production chamber.
For example, CA 2,844,345 discloses a process that provides a production
chamber using a
single vertical or inclined well. The process may be preceded by start-up
acceleration
techniques to establish communication in the formation between an injection
means and a
production means within the single well.
[0044] When the vapor chamber 260 grows vertically, oil production rates
normally continue
to increase, and the CSOR normally continues to decrease. Steam utilization
during such
chamber growth is relatively efficient. However, when the top front of the
vapor chamber 260
approaches or reaches the overburden 110 or the transition region 115,
vertical growth of the
vapor chamber 260 will slow down and eventually stop. While the vapor chamber
260 may
continue to grow or expand laterally, which may be at a slower pace, steam
utilization during
slow lateral growth may be less efficient. As a result, oil production rate
may reach a peak value
or plateau, and then start to decline. The CSOR may bottom out and start to
increase. Thus,
such changes in chamber growth, oil production rate and CSOR may be used as a
production
threshold for transitioning from the steam-driven process to a solvent-aided
process (SAP),
such as a solvent-driven process (SDP).
[0045] SAGD processes may be adapted for variable dynamic bitumen
storage in situ, by
modulating injection and production flows to store more or less emulsion at
the bottom of the
production chamber. In addition, oil may advantageously be stored in depleted
steam
chambers, thereby capitalizing on any residual heat ion the depleted chamber.
However, the
mobilized fluids produced by a typical SAGD process comprise a substantial
proportion of
condensed aqueous fluids, so that the volume of bitumen in the stored
mobilized fluids is
necessarily limited. Processes of dynamic bitumen storage involving SAGD
operations may
accordingly proceed or alternate with the solvent aided mobilized bitumen
(SAVEBit) storage
13
CA 3043954 2019-05-22
methods disclosed herein, with the SAVEBit approach providing substantially
more dynamic
range in the available in situ storage capacity in a given reservoir.
[0046] To initiate conditions suitable for SAVEBit storage operations,
at S315 a suitable
solvent and transition condition are selected (according to various factors
and considerations for
example as set out in CA 2,956,771) at S320 and S325 respectively. As can be
appreciated by
those skilled in the art, the selection at S320 and S325 may be performed at
any time prior to
solvent injection, and may be performed in any order depending on the
particular situation and
application.
[0047] At S320, the solvent for use in the SAP or SDP is selected or
determined 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 100.
The solvent may
be a viscosity-reducing solvent, which reduces the viscosity of the heavy
hydrocarbons in the
reservoir 100. Suitable solvents may include C2 to Clo 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.
[0048] Transitioning to the SAP or SDP process at an early stage in a
SAGD process may
be possible in some cases, but such early transition before the vapor chamber
has fully
developed vertically may limit the overall chamber growth or slow down the
initial chamber
growth. Further, when the transition occurs too early, the reservoir formation
generally contains
less heat transferred from steam and the heated region in the formation may be
relatively small.
In some embodiments, when the vapor chamber is fully developed vertically, the
amount of heat
transferred to the reservoir formation and the large region of heated area can
be quite beneficial
to the subsequent solvent-driven process. The heat, or higher formation
temperature in a large
region in the formation, can help to maintain the solvent in the vapor phase
and assist
dispersion of the solvent to the chamber front or edges. The heat from steam
can also by itself
assist reduction of viscosity of the hydrocarbons.
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CA 3043954 2019-05-22
[0049] At S330, it is determined whether the transition condition
selected at S325 has been
met. This determination may be made based on a pre-set timing or based on
measured and
predicted operational parameters and current reservoir conditions. The
determination may
involve monitoring certain selected parameters, for example, monitoring of
injection, production,
downhole parameters, or parameters of the geological formation. For example,
parameters such
as CSOR, temperatures, pressures, or the like may be monitored. Such
parameters may be
measured at, for example, the injection well 120 and/or the production well
130. Additionally or
alternatively, determining when a transition condition has been met may
involve prediction
based on indirect indicators that the condition has been met, such as based on
assumptions
derived from a model and informed by the aforementioned monitoring. In select
embodiments,
the determination may involve a consideration of the prospective timing of
future SAVEBit
storage operations, for example an indication that increased bitumen storage
may be desirable
in the future may give rise to a determination that solvent use should begin,
in order to set the
stage for future SAVEBit storage operations.
[0050] When the transition condition has been met, the initial production
process, such as a
steam-driven SAGD process, S310 is terminated and process amenable to
modulating storage
of bitumen is initiated, such as a SAP or SDP process, at S335. When the
storage-driven
process is a solvent-driven process, S335, injection of the selected solvent
into the reservoir
100 is initiated through the injection well 120. The solvent is generally
injected into the reservoir
.. 100 in a vapor phase. Injection of the solvent in the vapor phase allows
solvent vapor to rise in
the vapor chamber 260 and condense at a region away from the injection well
120. Allowing
solvent to rise in the vapor chamber 260 before condensing may achieve
beneficial effects. For
example, when solvent vapor is delivered to the vapor chamber 260 and then
allowed to
condense and disperse near the edges of the vapor chamber 260, oil production
performance,
such as indicated by one or more of oil production rate, cumulative steam to
oil ratio (CSOR),
and overall efficiency, may be improved. Injection of solvent in the gaseous
phase, rather than a
liquid phase, may allow vapor to rise in the vapor chamber 260 before
condensing so that
condensation occurs away from the injection well 120. It is noted that
injecting solvent vapor into
the vapor chamber does not necessarily require solvent be fed into the
injection well 120 in
vapor form. For example, the solvent may be heated downhole and vaporized in
the injection
well 120.
[0051] The total injection pressure for solvent and steam co-injection
during stage S335
may be the same or different than the injection pressure during the SAGD
production stage
S310. For example, the injection pressure may be maintained at between 2 MPa
and 3.5 MPa,
CA 3043954 2019-05-22
or up to 4 MPa. Alternatively, steam may be injected at a pressure of about 3
MPa in the SAGD
process S310, while steam and solvent are co-injected at a pressure of about 2
MPa to about
3.5 MPa in the SAP or SDP process S335.
[0052] In S335, 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 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.
Such a suitable steam temperature may be determined, for example, through
techniques as
known to persons of skill in the art based on parameters of the mixture
components. For
example, the enthalpy per unit mass of the aforementioned steam-propane
mixture may be
about 557 kJ/kg.
[0053] The total volume of the solvent injected during the SAP or SDP
process S335 may
be lower than the total volume of steam injected during SAGD. In S335, co-
injection of steam
and the solvent may be carried out in a number of different ways. For example,
co-injection of
the solvent and steam into the vapor chamber may include gradually increasing
the weight ratio
of the solvent in the co-injected solvent and steam, and gradually decreasing
the weight ratio of
steam in the co-injected solvent and steam. At a later time within S335, the
solvent content in
the co-injected solvent and steam may be gradually decreased, and the steam
content in the
co-injected solvent and steam may be gradually increased. For example,
depending on market
factors, the cost of solvent may change over the life of such a process.
During or after the
solvent-driven process S335, it may be of economic benefit to gradually
decrease the solvent
content and gradually increase the steam content.
[0054] In the context of the present disclosure, at various times, the
produced-fluid stream
may have an oil:water ratio of between about 20:80 and about 90:10, or any
ratio between these
values. In a SAGD phase, this ratio may for example be from about 20:80 to
about 35:65.
Following the initiation of solvent use, in a SAP phase, this ratio may for
example be from about
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CA 3043954 2019-05-22
60:40 to about 90:10, or for example alternatively about 75:25 to about 90:10,
depending on the
amount of solvent injected.
[0055] The initiation of solvent use gives rise to a surprising bitumen-
concentrating effect in
the mobilized fluid zone at the bottom of the production chamber. As
illustrated in FIG. 4, during
an exemplary SAGD operation, the initial drainage of the overall emulsion
(mainly condensed
steam and bitumen) was at about 350-500 T/d. Following the initiation of
solvent use, when
moving from a steam driven phase to a solvent driven phase, a gradual but
significant reduction
in the water cut (WC) in the produced fluids was evident, falling over time
from about 80% to
25%. After approximately 1 year of operating the SDP, the emulsion rate was at
the range of 75-
100 m3/d with a bitumen production rate of about 50-75 m3/d. These daily
production figures are
similarly reflected in hourly production figures, where the overall emulsion
production rate was
reduced from 20 m3/hr to about 4 m3/hr, with a surprisingly small decline in
the oil production
rate. As a result of this effect, with significantly less emulsion being
drained to maintain a
variable reservoir of mobilized fluids at the bottom of the production
chamber, a SAVEBit
storage process may be implemented to store a variable amount of bitumen in
situ, with the
corollary of enabling a wider dynamic range of production rates (in comparison
to a SAGD
process). In contrast, in a typical SAGD operation, when fluid production
rates are reduced,
within a relatively short period of time the limit of bitumen storage is
reached as the mobilized
fluid level rises towards the level of the injection, with the attendant risk
of quickly flooding the
injector. In a SAVEBit storage process, operations may for example be carried
out with the
production of dramatically less fluid, for example multiples of 2, 3, 4 or 5
times less production
fluid. The concentration of the bitumen in the mobilized fluid thereby
facilitates much larger
storage volumes of bitumen, for example greater than 2, 3, 4 or 5 times the
bitumen that could
be stored in a SAGD process.
[0056] An attendant advantage of the SAVEBit storage process is the ability
to maintain
production pressures within the production chamber. In a typical SAGD
operation, it is
necessary to continue pressurizing the reservoir with relatively high steam
rates. In contrast, in
a SAVEBit storage process, it is possible to maintain bottom hole pressure
(BHP) with relatively
low solvent + steam injection rates, and the attendant minimal water drainage
within the
produced emulsion.
[0057] An aspect of SAVEBit processes includes the ability to modulate
the bitumen
concentration of the stored mobilized fluids. As discussed above,
transitioning from a steam
driven process such as SAGD to a SAP or SDP process has a bitumen-
concentrating effect on
the composition of the stored mobilized fluids, as the relative amount of
water in the emulsion
17
CA 3043954 2019-05-22
falls. Conversely, following a period SAP or SDP production, operations may
transition to a
steam driven process such as SAGD to dilute the stored mobilized fluids with
water, for example
to minimize the amount of stored bitumen.
[0058] As illustrated in FIG. 4, in the summer of 2018 an operational
shut-in period was
.. initiated, and this was followed by a period of "flush" production and then
a return to previous
production rates by mid-September. The 30 day moving average oil production
shows SAGD-
like oil production rates. SAVEBit storage processes accordingly accommodate
shut-in and
flush production operations that modulate bitumen production dramatically,
while maintaining
overall oil production capacity (as evident from the area under the curve in
FIG. 4). The
operational parameter that acts as a trigger for the overall SAVEBit storage
operational strategy
may for example be market pricing for oil or regulatory restrictions on
bitumen production.
[0059] 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.
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