Note: Descriptions are shown in the official language in which they were submitted.
PAT 104297-1
PROCESS FOR PRODUCING HYDROCARBONS FROM A SUBTERRANEAN
HYDROCARBON-BEARING FORMATION
Technical Field
[0001] The present invention relates to the production of hydrocarbons
such
as heavy oils and bitumen from a hydrocarbon-bearing formation including a
lean
zone disposed above.
Background
[0002] Extensive deposits of viscous hydrocarbons exist around the world,
including large deposits in the northern Alberta oil sands that are not
susceptible to
standard oil well production technologies. The hydrocarbons in reservoirs of
such
deposits are too viscous to flow at commercially relevant rates at the virgin
temperatures and pressures present in the reservoir. For such reservoirs,
thermal
techniques may be utilized to heat the reservoir to mobilize the hydrocarbons
and
produce the heated, mobilized hydrocarbons from wells. One such technique for
utilizing a horizontal well for injecting heated fluids and producing
hydrocarbons is
described in U.S. Patent No. 4,116,275, which also describes some of the
problems
associated with the production of mobilized viscous hydrocarbons from
horizontal
wells.
[0003] It is common practice to categorize petroleum substances of high
viscosity and density into two categories, "heavy oil" and "bitumen". For
example,
some sources define "heavy oil" as a petroleum that has a mass density of
greater
than about 900 kg/m3. Bitumen is sometimes described as that portion of
petroleum that exists in the semi-solid or solid phase in natural deposits,
with a
mass density greater than about 1,000 kg/m3 and a viscosity greater than
10,000
centipoise (cP; or 10 Pa.$) measured at original temperature in the deposit
and
atmospheric pressure, on a gas-free basis. Although these terms are in common
use, references to heavy oil and bitumen represent categories of convenience
and
there is a continuum of properties between heavy oil and bitumen. Accordingly,
references to heavy oil and/or bitumen herein include the continuum of such
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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. One thermal method of recovering viscous
hydrocarbons utilizing spaced horizontal wells is known as steam-assisted
gravity
drainage (SAGD). In general, a SAGD process may be described as including
three
stages: the start-up stage; the production stage; and the wind-down (or
blowdown)
stage. The production stage may be described as including further stages such
as,
for example, a ramp-up stage and a plateau stage.
[0004] In the SAGD process, pressurized steam is delivered through an
upper,
horizontal, injection well (injector), into a viscous hydrocarbon reservoir
while
hydrocarbons are produced from a lower, parallel, horizontal, production well
(producer) that is near the injection well and is vertically spaced from the
injection
well. The injection and production wells are situated in the lower portion of
the
reservoir, with the producer located close to the base of the hydrocarbon
reservoir
to collect the hydrocarbons that flow toward the base of the reservoir.
[0005] The SAGD process is believed to work as follows. The injected
steam
initially mobilizes the hydrocarbons to create a steam chamber in the
reservoir
around and above the horizontal injection well. The term steam chamber is
utilized
to refer to the volume of the reservoir that is saturated with injected steam
and
from which mobilized oil has at least partially drained. As the steam chamber
expands, viscous hydrocarbons in the reservoir and water originally present in
the
reservoir are heated and mobilized and move with aqueous condensate, under the
effect of gravity, toward the bottom of the steam chamber. The hydrocarbons,
the
water originally present, and the aqueous condensate are typically referred to
collectively as emulsion. The emulsion accumulates such that the liquid /
vapor
interface is located below the steam injector and above the producer. The
emulsion
is collected and produced from the production well. The produced emulsion is
separated into dry oil for sales and produced water, comprising the water
originally
present and the aqueous condensate.
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[0006] Such processes, however, are complicated in hydrocarbon-bearing
formations that are in fluid communication with a lean zone. Zones disposed
towards the top of heavy oil or bitumen deposits may have distinct fluid
mobility
characteristics. These zones include, for example, top water zones or gas caps
(including top gas zones that have been produced, and therefore have reduced
pressure). Collectively these zones may be called "lean" or "thief" zones,
reflecting
the effect of these zones on hydrocarbon recovery processes that use an
injected
fluid to improve mobility of the oil. An example of a lean zone includes a
water
aquifer lying above the hydrocarbon-bearing formation. In such cases, an
expanding steam chamber in the reservoir may breach, or hydraulically contact
the
aqueous fluid zone such that water flows into the steam chamber, cooling the
steam chamber or even quenching the process.
[0007] Techniques may be employed to displace the aqueous fluid with a
non-
condensable gas, e.g., air, prior to the steam chamber establishing fluid
communication with the aqueous fluid, thus reducing the chance of quenching
the
process and improving recovery.
[0008] Because of complications relating to the presence of water or the
introduction of further gas into the steam chamber, recovery of hydrocarbons
from
such hydrocarbon-bearing formations may be relatively low as unrecovered
viscous
hydrocarbons spaced laterally from the injection and production wells are left
unmobilized.
[0009] Improvements in recovery of hydrocarbons are desirable.
Summary
[0010] According to an aspect of an embodiment, a process is provided for
recovering hydrocarbons from a reservoir of a subterranean hydrocarbon-bearing
formation, the reservoir having a top gas zone. The process includes injecting
a
mobilizing fluid into an injection well disposed in a lower portion of the
hydrocarbon-bearing formation to create a chamber in the hydrocarbon-bearing
formation, producing the hydrocarbons from the hydrocarbon-bearing formation,
injecting a solvent vapour or liquid into the gas zone, and, after the chamber
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reaches the gas zone, discontinuing mobilizing fluid injection into the
injection well,
wherein the solvent spreads laterally to form a solvent blanket above the
chamber,
and condenses at lateral edges of the solvent blanket, delivering liquid
solvent to
the hydrocarbon-bearing formation to mobilize the hydrocarbons.
[0011] The process may include displacing, utilizing a gas, aqueous fluid
in an
aqueous fluid zone of the hydrocarbon-bearing formation, to form the gas zone.
The solvent may be injected via a de-watering well utilized to produce aqueous
fluid
from the aqueous fluid zone during the displacing. A boundary of the gas zone
and
aqueous fluid may be maintained by producing aqueous fluid from a well near
the
boundary and re-injecting the aqueous fluid at a location in the aqueous fluid
zone,
away from the gas zone. Maintaining the boundary may be discontinued after
reaching a target hydrocarbon production from the reservoir and the solvent
injection discontinued. Hydrocarbon production may also be discontinued after
reaching the target hydrocarbon production from the reservoir. At least some
solvent injected may be recovered as the solvent vapour, produced, for
example,
via the de-watering well utilized to produce aqueous fluid from the aqueous
fluid
zone during the displacing and utilized for injecting the solvent.
[0012] The solvent may be superheated solvent vapour to create the
solvent
blanket above the chamber.
[0013] The mobilizing fluid may be steam. Optionally, the mobilizing
fluid
may include a further solvent vapour. The process may include monitoring the
chamber and, based on the monitoring, determining a rate of growth of the
chamber. A time at which the solvent injection begins may be based on the rate
of
growth of the chamber.
[0014] Mobilizing fluid injection into the injection well is discontinued
in
response to the chamber breaching the gas zone. The injection well may be shut
in
in response to the chamber breaching the gas zone. Production of hydrocarbons
from the hydrocarbon-bearing formation continues after shutting in the
injection
well.
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[0015] A gas, such as methane, that is less dense than the solvent may be
injected into the gas zone after reaching a target hydrocarbon production. At
least
some solvent injected as the solvent vapour may be produced via a production
well
utilized to produce the hydrocarbons.
[0016] According to another aspect, a process for removing fluids from a
hydrocarbon reservoir utilizing an injection well extending into the
hydrocarbon
reservoir and a production well extending near a bottom of the reservoir is
provided. The process includes injecting a mobilizing fluid into the reservoir
through the injection well, creating a mobilizing fluid chamber and producing
a
portion of the fluids via the production well, injecting a solvent into a top
gas zone
above the hydrocarbon reservoir after the mobilizing fluid chamber breaches
the
top gas zone, and discontinuing injecting the mobilizing fluid to create the
mobilizing fluid chamber and recovering a further portion of the fluids via
the
production well.
Brief Description of the Drawings
[0017] Embodiments of the present disclosure will be described, by way of
example, with reference to the drawings and to the following description, in
which:
[0018] FIG. 1 is a schematic sectional view through a reservoir,
illustrating
horizontal segments of wells utilized in a hydrocarbon recovery process in
accordance with one example of the present disclosure;
[0019] FIG. 2A is a flowchart illustrating a process of recovering
hydrocarbons
from a hydrocarbon-bearing formation, in accordance with an embodiment of the
present disclosure;
[0020] FIG. 2B is a flowchart illustrating a process of recovering
hydrocarbons
from a hydrocarbon-bearing formation, in accordance with another embodiment of
the present disclosure;
[0021] FIG. 3 is a diagram illustrating the displacement of aqueous
fluid, also
referred to as de-watering, over 500 days of operation in accordance with an
example of the process of FIG. 2A;
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[0022] FIG. 4 is a diagram illustrating initial development of a steam
chamber
in accordance with an example of the process of FIG. 2A;
[0023] FIG. 5 shows the commencement of propane injection and growth of
the steam chamber in accordance with an example of the process of FIG. 2A;
[0024] FIG. 6 shows the spread of propane in the gas zone in accordance
with
an example of the process of FIG. 2A;
[0025] FIG. 7 is a graph showing oil recovery for the process in
accordance
with an example of the process of FIG. 2A;
[0026] FIG. 8 is a graph showing oil production rates over time for an
800m
long production well in accordance with an example of the process of FIG. 2A;
[0027] FIG. 9 is a graph showing cumulative produced water to oil ratio
(PWOR) in accordance with an example of the process of FIG. 2A;
[0028] FIG. 10 is a graph showing a comparison of the energy equivalent
steam to oil ratio (eCSOR) for a SAGD process and for an example in accordance
with the process of FIG. 2A;
[0029] FIG. 11 is a graph showing a comparison of total time to achieve a
60% oil recovery for the processes compared in FIG. 10;
[0030] FIG. 12 illustrates a method in which propane recovery is carried
out
in accordance with an example of the process of FIG. 2A.
Detailed Description
[0031] For simplicity and clarity of illustration, reference numerals may
be
repeated among the Figures to indicate corresponding or analogous elements.
Numerous details are set forth to provide an understanding of the examples
described herein. The examples may be practiced without these details. In
other
instances, well-known methods, procedures, and components are not described in
detail to avoid obscuring the examples described. The description is not to be
considered as limited to the scope of the examples described herein.
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[0032] The disclosure generally relates to a process for recovering
hydrocarbons from a reservoir of a subterranean hydrocarbon-bearing formation,
the reservoir having a top gas zone. The process includes injecting a
mobilizing
fluid into an injection well disposed in a lower portion of the hydrocarbon-
bearing
formation to create a chamber in the hydrocarbon-bearing formation, producing
the
hydrocarbons from the hydrocarbon-bearing formation, injecting a solvent
vapour
or liquid into the gas zone, and, after the chamber reaches the gas zone,
discontinuing mobilizing fluid injection into the injection well, wherein the
solvent
spreads laterally to form a solvent blanket above the chamber, and condenses
at
lateral edges of the solvent blanket, delivering liquid solvent to the
hydrocarbon-
bearing formation to mobilize the hydrocarbons. A solvent blanket refers to a
layer
above the chamber in which the space is primarily dominated by solvent vapour.
[0033] As noted above, embodiments of the present disclosure include the
injection of a mobilizing fluid, such as steam, to create a mobilizing fluid
chamber.
A "chamber" within a reservoir or formation is a region that is in
fluid/pressure
communication with a particular well or wells, such as an injection or
production
well. For example, in a SAGD process, a steam chamber is the region of the
reservoir in fluid communication with a steam injection well, which is also
the
region that is subject to depletion, primarily by gravity drainage, into a
production
well.
[0034] 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 or bitumen are associated with zones
containing a preponderance of natural gas. This "associated gas" is gas that
is in
pressure communication with the heavy oil or bitumen within the reservoir,
either
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directly or indirectly, for example through a connecting water zone. A pay
zone is a
reservoir volume having hydrocarbons that can be recovered economically.
[0035] In the present example, the process is generally described in
relation
to SAGD. The present process may be successfully implemented with other
processes that utilize steam, such as processes involving solvent and steam,
also
referred to as a solvent-aided process (SAP), or cyclic steam stimulation
(CSS), or
solvent-based processes that utilize solvent as a mobilizing fluid.
[0036] In the SAGD process, well pairs, each including a hydrocarbon
production well and a steam injection well are utilized. A hydrocarbon
production
well includes a generally horizontal segment that extends near the base or
bottom
of the hydrocarbon reservoir. The injection well also includes a generally
horizontal
segment that is disposed generally parallel to and is spaced generally
vertically
above the horizontal segment of the hydrocarbon production well.
[0037] During SAGD, steam is injected into the injection well to mobilize
the
hydrocarbons and create a mobilizing fluid (steam) chamber in the reservoir,
around and above the generally horizontal segment. In addition to steam
injection
into the steam injection well, light hydrocarbons, such as the C3 through C10
alkanes, either individually or in combination, may optionally be injected
with the
steam such that the light hydrocarbons function as solvents in aiding the
mobilization of the hydrocarbons. The volume of light hydrocarbons that are
injected may be relatively small compared to the volume of steam injected, for
example up to about 20 weight % solvent. The addition of light hydrocarbons is
referred to as a solvent-aided process (SAP). Alternatively, or in addition to
the
light hydrocarbons, various non-condensing gases, such as methane, natural
gas,
carbon dioxide, air, nitrogen, or a combination thereof, may be injected.
Viscous
hydrocarbons in the reservoir are heated and mobilized and the mobilized
hydrocarbons drain under the effect of gravity. Fluids, including the
mobilized
hydrocarbons along with connate water and condensed steam (aqueous
condensate), are collected in the generally horizontal segment. The fluids may
also
include gases such as steam and production gases (e.g., methane, hydrogen
sulfide) from the SAGD process.
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[0038] A simplified schematic sectional view illustrating horizontal
segments
of injection and production wells utilized in a hydrocarbon recovery process
in
accordance with one example is shown in FIG. 1. For the purpose of the present
example, a reservoir 106 of about 20 meters in depth is illustrated. An
aqueous
fluid zone 108, or aquifer, of about 5 meters in depth overlies the reservoir
106.
[0039] Such top water zones are of potential concern because they give
rise
to the potential for fluid communication between the top water zone and the
underlying bitumen zone as a consequence of a hydrocarbon recovery operation.
The top water may drain towards the bitumen recovery zone, particularly if the
recovery zone is operated at a lower reservoir pressure than the top water
zone.
This draining of top water towards the well pair will cool the reservoir and
make the
solvent-based recovery process significantly less efficient.
[0040] If the bitumen recovery zone is being operated at a higher
pressure
than the top water zone during the recovery process, the injected steam (which
may include solvent) may rise into the top water zone and increase the
reservoir
pressure, filling the available pore space until the top water zone is in
pressure
equilibrium with the bitumen zone. The volume of steam (which may include
solvent) required to reach pressure equilibrium represents an inefficient
injected
fluid loss, reducing the efficiency of the bitumen recovery process.
[0041] In the example of FIG. 1, two pairs of injection and production
wells
are illustrated and are spaced apart by about 100 meters. Each of the
production
wells 102 includes a generally horizontal segment that extends near the base
or
bottom 104 of the hydrocarbon reservoir 106. Each injection well 110 also
includes
a generally horizontal segment that is disposed generally parallel to and is
spaced
generally vertically above the horizontal segment of a respective one of the
hydrocarbon production wells 102. In the present example, the injection wells
110
are spaced about 5 meters above respective ones of the production wells 102
and
are utilized to inject mobilizing fluids into the reservoir, creating a
mobilizing fluid
chamber in the reservoir.
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[0042] FIG. 1 illustrates two pairs of injection and production wells.
The
present process may be carried out with additional or fewer pairs of injection
and
production wells. According to one example, the process may be carried out
utilizing a single pair of injection and production wells.
[0043] In addition to the injection wells 110 and production wells 102,
aqueous fluid displacement wells are also utilized to displace the aqueous
fluid in
the aqueous fluid zone 108 disposed above the reservoir 106, replacing it with
a
gas. The aqueous fluid displacement wells extend to a location near a bottom
of
the aqueous fluid zone 108, near the interface of the reservoir 106 with the
aqueous fluid zone 108. These aqueous fluid displacement wells include an
aqueous fluid production well 114 and non-condensable gas injection wells 116.
The aqueous fluid production well 114 is utilized to remove the aqueous fluid
from
the region above the injection wells 110 and production wells 102 and the non-
condensable gas injection wells 116 inject a non-condensable gas such as air
to
replace the aqueous fluid. The non-condensable gas is injected at a suitable
pressure to create a gas zone, also referred to as a de-watered zone.
[0044] Fence wells, including producers 122 and re-injectors 124 are also
utilized to maintain a non-condensable gas/aqueous fluid boundary near the
edge
of the gas (de-watered) zone. The producers 122 remove aqueous fluid ingress
into the gas zone from the boundary and the re-injectors 124 are utilized to
re-
inject the aqueous fluid removed utilizing the producer 122, into an area of
the
aquifer away from the gas zone.
[0045] The locations of the non-condensable gas injection wells 116
relative
to the fence wells and relative to the injection wells 110 and production
wells 102 is
shown as one example. Other relative locations of wells may be successfully
implemented. For example, each of the non-condensable gas injection wells 116
may be located closer to the nearest fence wells, and thus laterally spaced
farther
from the near injection well 110 and production well 102.
[0046] A flowchart illustrating a process of recovering hydrocarbons from
a
subterranean hydrocarbon-bearing formation including an oil (thief) zone
above,
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such as the reservoir 106 shown in FIG. 1, is provided in FIG. 2A. For
example, the
present method may be employed for recovering hydrocarbons from a reservoir
that has an aqueous fluid zone disposed above, or a reservoir that has a gas
zone,
referred to as a gas cap, disposed above. The process may contain additional
or
fewer subprocesses than shown or described, and parts of the process may be
performed in a different order.
[0047] In the example of an aqueous fluid zone above the reservoir, a
volume
of the aqueous fluid in the aqueous fluid zone is displaced by a non-
condensable
gas, such as air at 202 (FIG. 2A). The aqueous fluid is displaced utilizing
the fluid
production well 114 and the non-condensable gas is injected through the gas
injection wells 116. The volume that is displaced or de-watered, is filled
with gas
and the gas is maintained in the gas zone that is created, utilizing the
producer
wells 122 on the outer perimeter of the gas zone. The producer wells 122
remove
water ingress into the gas zone and the water is reinjected, utilizing the re-
injection
wells 124, into the aqueous fluid zone 108 that exists away from the gas zone,
thus
generally maintaining the gas zone. While some aqueous fluid may still remain,
the
majority of the aqueous fluid is displaced by the non-condensable gas.
[0048] In the example of a gas zone disposed above the reservoir, no
displacement of aqueous fluid is carried out to form a gas zone above the
reservoir.
The pore space of such a gas zone may contain connate reservoir water (for
example on the order of 20% v/v), residual bitumen (for example 20% v/v) and a
significant concentration of natural gas (for example 60% v/v). The exact
concentrations of the gas zone may vary significantly. The process of the
present
disclosure may be utilized with a de-watered zone, an intact gas zone, and a
depleted gas zone.
[0049] A hydrocarbon recovery process such as SAGD or a solvent-aided
process is initiated in which the mobilizing fluid, such as steam, is injected
in an
injection well and the mobilized fluids drain down to the lower well from
which they
are produced to the surface. The mobilizing fluid that is injected may be
steam
that is injected into the reservoir utilizing the injection wells 110 to
create a
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mobilizing fluid chamber and to mobilize the hydrocarbons in the reservoir at
204 of
the process illustrated in FIG. 2A.
[0050] The mobilized hydrocarbons are produced, along with connate water
and condensed steam (aqueous condensate), utilizing production wells 102 at
206.
The horizontal segments of the injection and the production well pairs are
generally
located in a lower portion of the hydrocarbon-bearing formation, i.e., closer
to a
base than the top of the hydrocarbon-bearing formation, as illustrated in FIG.
1.
[0051] Reference is made herein to injection and production well pairs.
The
injection well 110 and the production well 102 may be physically separate
wells.
Alternatively, the production well and the injection well may be housed, at
least
partially, in a single physical wellbore, for example, a multilateral well.
The
production well and the injection well may be functionally independent
components
that are hydraulically isolated from each other, and housed within a single
physical
wellbore.
[0052] The mobilizing fluid chamber growth may be monitored and, based on
the results of monitoring, a rate of growth of the mobilizing fluid chamber
may be
determined. In response to determining at 208 that the mobilizing fluid
chamber is
close to the gas zone, the process continues at 210. Alternatively, the
process may
continue at 210 after injection of mobilizing fluid into the injection wells
for a period
of time sufficient to cause the mobilizing fluid chamber to grow close to the
gas
zone.
[0053] One or more of the fluid production wells 114 (only one shown in
FIG.
1) are switched to injecting solvent vapour at a temperature above the
saturation
temperature of the solvent at 210 (FIG. 2A). The vaporized solvent is injected
at a
suitable rate to maintain the de-watered gas zone pressure, diffuse away from
the
well through the gas zone, and create a solvent blanket over a zone targeted
for
hydrocarbon recovery by the well pairs in the reservoir at 210. Alternatively,
a
liquid solvent may be injected, optionally with a non-condensing gas to
facilitate
diffusion of the liquid solvent through the gas zone.
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[0054] The distance between mobilizing fluid chamber and the gas zone
that
is considered "close" at 208, may vary depending on several factors, including
the
rate of growth of the mobilizing fluid chamber. The solvent injection at 210
is
started at a time sufficient to create a layer when the mobilizing fluid
chamber
breeches the lean zone. For example, the steam chamber may be allowed to get
very close to the lean zone, e.g., 1 m to 5 m, if the equipment utilized to
pump the
solvent is capable of pumping solvent quickly. Solvent may be injected well in
advance of the mobilizing fluid chamber breeching the lean zone to ensure that
the
solvent is in place. Such injection, well in advance of the mobilizing fluid
chamber
reaching the lean zone, however is less economically efficient as the solvent
is not
utilized until the mobilizing fluid chamber reaches the lean zone.
[0055] The process of injecting mobilizing fluid via the injection well
110 and
producing hydrocarbons via the production well 102 continues until the
mobilizing
fluid chamber formed by the injection of the mobilizing fluid, breaches the
gas zone
above. As indicated above, the mobilizing fluid chamber growth may be
monitored
at 212 and, in response to determining that the mobilizing fluid chamber has
breached the gas zone at 212, the process continues at 214. The breach of the
gas
zone may be detected or may be determined or estimated based on the rate of
growth of the mobilizing fluid chamber.
[0056] The injection of mobilizing fluid into the reservoir via the
injection
wells 110 is discontinued at 214 and the injection wells 110 are shut in.
Production
of hydrocarbons via the production wells 102 continues, however. The pressure
within the reservoir to drive the hydrocarbon production is maintained by the
injection of the solvent in the gas zone.
[0057] Thus, the injection of mobilizing fluid may be discontinued when
breach of the gas zone is detected, determined, or estimated. Alternatively,
injection of the mobilizing fluid may continue for a period of time after
breach of the
gas zone is detected, determined, or estimated. Injection of the mobilizing
fluid
may continue for months or even up to two years after breach of the gas zone.
Continued injection of mobilizing fluid, such as steam is desirable in
applications in
which heat is injected to sustain the process for the duration of the solvent
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injection. For example, in the case in which fluid communication is
established
between the mobilizing fluid chamber and the aqueous fluid zone or gas zone
early
in the process, continued injection of mobilizing fluid, such as steam, is
desirable to
provide heat and thus to increase the size of the mobilizing fluid chamber.
[0058] During an initial period after breach of the gas zone by the
mobilizing
fluid chamber, for example, in the case of a SAGD or a solvent-aided process
(SAP),
enhanced oil and water production rates may occur as the mobilizing fluid
chamber
cools. After such a transition period, the ratio of produced water to produced
oil
decreases steadily as eventually the only water that is produced is the
connate
water and water that bypasses the fence wells in the lean zone.
[0059] After desired oil recovery is achieved, the operation may be
switched
to a solvent recovery phase at 216 to recover solvent from the reservoir.
Solvent
vapour or liquid injection is discontinued. Recovery of the solvent may be
accomplished utilizing any one of several methods. For example, if the portion
of
the reservoir and aqueous fluid zone is isolated, pressure boundary control at
the
fence wells is discontinued, allowing the aqueous fluid to enter the oil
depleted
zones. The fluid production well 114, also referred to as a de-watering well,
that
was utilized to inject the solvent, may be switched over to gas production,
i.e., the
same well that was utilized for water production is repurposed and utilized
for gas
production. As the chambers fill up with water, the solvent vapors are pushed
out
of the fluid production well 114, to the surface.
[0060] Alternatively, the fence wells may still be utilized to maintain
the
pressure isolation while fluid production well 114, which was utilized to
inject the
solvent, is switched to injecting a gas that is less dense than the solvent.
For
example, the fluid production well 114 may be switched to injecting an NCG
such as
methane or natural gas. Because natural gas is lighter than commercial
solvents,
the natural gas preferentially stays at the top while pushing the residual oil
and
solvent towards the production well 102 at the bottom of the reservoir,
facilitating
production of the residual oil and solvent via the production well 102. With
both
steam and solvent injection having been terminated by this point in the
process,
injection of the NCG commences the blowdown stage of operations.
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[0061] Thus, an existing well, namely the fluid production well 114, may
be
utilized to recover the solvent. Use of an existing well is advantageous. A
further
well, other than the fluid production well 114, however, may be utilized to
recover
the solvent.
[0062] The solvent that is injected at 210 may be any suitable solvent,
including light hydrocarbons such as alkanes. Solvents having 2 to 8 carbon
atoms
per molecule, such as ethane, propane, butane, pentane, hexane, heptane, or
octane may be utilized.
[0063] Solvent injection may commence any time after the top water zone
is
displaced with gas, and before the steam chamber breaks through. The solvent
injection may be timed to distribute the solvent to condense at the edges of
the
chamber when the chamber is at its largest volume and communicates with the
gas
zone.
[0064] The solvent diffuses and cools in the gas zone, condenses, and
enters
the mobilizing fluid chamber. The injection of solvent vapour facilitates
movement
of the solvent laterally within the gas zone, to edges of the mobilizing fluid
chamber, where the solvent is beneficial. Once inside the chamber, liquid
solvent
absorbs latent heat from the reservoir and achieves thermodynamic equilibrium
with a portion of the solvent dissolving in the oleic phase in the reservoir
and the
remainder of the solvent re-vaporizing.
[0065] Typical oil recovery from SAGD reservoirs that include a top
aqueous
fluid zone ranges from about 40-600/0 depending upon the thickness, or depth,
of
the reservoir. Additional recovery is limited by higher steam to oil ratios
(SORs)
rendering the process uneconomic. In a hydrocarbon recovery process as
described
with reference to FIG. 2A, much higher oil recoveries may be realized as a
more
uniform propagation of the mobilizing fluid chamber, which, in the example of
SAGD is a steam chamber, in the lateral direction is achieved as a result of
hydrocarbon mobilization by solvent dilution. Dissolution of solvent in
bitumen
reduces the viscosity and enhances mobility of the oleic phase.
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[0066] In the above-described example, the aqueous fluid is displaced to
form
a gas zone as the aqueous fluid is produced through the producer wells 122 on
the
outer perimeter of the gas zone that is formed. Alternatively, the aqueous
fluid
may be produced after fluid communication of the aqueous fluid zone with the
mobilizing fluid chamber is established, as illustrated in FIG. 2B. Many of
the
processes in the flowchart illustrated in FIG. 2B are similar to those
described
above with reference to FIG. 2A and are therefore not described again in
detail.
Similar reference numerals are utilized in FIG. 2B to describe similar
processes.
[0067] Mobilizing fluid, such as steam in the case of SAGD, is injected
utilizing
the injection wells, such as the injection wells 110, to create a mobilizing
fluid
chamber and to mobilize the hydrocarbons in the reservoir at 204. The
mobilized
hydrocarbons are produced, along with connate water and condensed steam
(aqueous condensate), utilizing production wells, such as the production wells
102,
at 206. When the aqueous fluid zone is breached by the mobilizing fluid
chamber
at 220, the aqueous fluid is drained into the mobilizing fluid chamber, to the
production well 102 at or near the bottom of the mobilizing fluid chamber.
Aqueous
fluid may optionally be displaced by non-condensable gas as the aqueous fluid
drains via the mobilizing fluid chamber. Thus fluid communication of the
aqueous
fluid zone with the mobilizing fluid chamber is already established when the
gas
zone is formed. Solvent is then injected, as indicated at 210. Injection of
the
mobilizing fluid may continue for a period of time after fluid communication
of the
aqueous fluid zone with the mobilizing fluid chamber is established. The
period of
time may be, for example, months or even years to continue to provide heat to
the
hydrocarbon-bearing formation. The injection of mobilizing fluid is
discontinued at
216 and a solvent recovery process may be carried out at 216.
Modelling
[0068] Reservoir simulations were performed to demonstrate the process. A
live oil simulation model with methane dissolved in bitumen at reservoir
conditions
was utilized with Northern Alberta oil sands reservoir properties.
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[0069] As an example, a relatively low pressure solvent such as propane
may
be injected in a vapor form at about 45 C. For the purpose of the reservoir
simulations, the propane was superheated to about 55 C injection temperature.
Thus, in the early stages of injection, while the gas zone into which the
vapor was
injected was at a relatively cool temperature, (e.g., about 12 C), the propane
did
not condense in the vicinity of the fluid production well 114 through which
the
solvent vapour was injected.
[0070] Simulation parameters utilized are included in Table 1 below.
j Table 1: Key Simulation Parameters
Rich Pay thickness 20m
Lean Zone thickness 5m
Well Spacing 100m
Well Length 2m
Element of Symmetry Full
Model grid Block Dimensions lm wide x 2m thick x
lm long
Porosity 0.35
Reservoir Temperature 12 C
Reservoir Pressure 1300kPa
Initial Oil Saturation (rich pay) 80%
Initial Oil Saturation (lean zone) 20%
Vertical Permeability 8 darcies
Horizontal Permeability 10 darcies
Methane mole fraction in Oleic Phase 0.075
Oil API 8.0
Well Completions
[0071] The modelling was carried out utilizing grid blocks with
properties
selected to simulate a hydrocarbon reservoir with a top aquifer. The edge of
the
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lean zone was populated by grid blocks with infinite porosity to simulate the
water
aquifer. Well pairs in the hydrocarbon-bearing formation, also referred to as
rich
pay, were spaced 100m apart. Initial water saturation in the aqueous fluid
zone,
also referred to as the lean zone, was 80% while the initial oil saturation in
the rich
pay was 80%.
[0072] The general layout of wells and formation was as illustrated in
FIG. 1.
A 400m wide pattern was simulated with a 5m thick (depth) mobile water aquifer
at
the top and a 20m thick (depth) rich pay zone at the bottom. Water saturation
in
the aquifer was 80% while water saturation was 20% in the rich pay. Active de-
watering was achieved utilizing a combination of fence wells, including the
producers 122 and the re-injectors 124 for maintaining a pressure boundary, a
fluid
production well 114, and a gas injection well 116.
Results
[0073] FIG. 3 shows the results of displacing the aqueous fluid, also
referred
to as de-watering, over 500 days of operation. The process of displacing of
the
aqueous fluid, or de-watering, removed most of the water from a targeted zone
though some water remained behind. In other simulations, the process of
displacing
the aqueous fluid was continued for longer durations of time but showed
similar
results. At least some of the water that is not displaced is expected to be
produced
during a recovery operation.
[0074] After 500 days of de-watering, SAGD was commenced in the 2
horizontal well pairs, i.e., the production wells 102 and the steam injection
wells
110, near the bottom of the rich pay. In a commercial operation, de-watering
and
SAGD start-up may overlap at least partially in time; prior to communication
of the
mobilizing fluid chamber, which in this example is a steam chamber, with the
gas
zone, the processes are generally independent of each other.
[0075] FIG. 4 shows the initial development of the steam chamber.
Approximately 230 days into SAGD operations, the steam chamber developed to
within 3m of the bottom of the aqueous fluid zone. The intent of the initial
recovery
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process was to create communication between the steam chamber in the rich pay
with the de-watered gas zone.
[0076] At 230 days, the two gas injection wells 116 were shut in and the
fluid
production well 114 was converted into a well for propane injection. The fence
wells continued to operate to maintain the boundary. Propane was injected at
55 C, which was about 10 C superheated with respect to the saturation
temperature for propane at the reservoir pressure. FIG. 5 shows the
commencement of propane injection and simultaneous growth of the steam
chamber (at 20 days of propane injection). Although propane was injected with
superheat, the propane quickly cooled down and condensed not too far away from
the well 114 through which the propane was injected. This was expected as the
gas
zone was at a much cooler temperature of 12 C.
[0077] Solvent utilization and recovery is important in any solvent-aided
or
solvent-based recovery process. The much cooler lean zone causing condensing
of
the propane is advantageous for the recovery process. At the outer edges of
the
propane blanket within the gas zone, the propane condenses. The gas zone
effectively acts as a "bubble" within the aqueous fluid zone. The injected
propane
stays within the bubble. By controlling the injection rate, and hence
pressure, of
propane, the spread of propane may be controlled to cover the targeted oil
recovery volume and without the solvent spreading out much further.
[0078] FIG. 6 shows that after 50 days of propane injection, spread of
propane in the gas zone then covered the positions of the two well pairs in
the rich
pay. At this time, the steam chamber just breached the gas zone.
[0079] After establishing communication between the steam chamber and the
gas zone, steam injection was discontinued, thus switching overall to a
solvent
process. The initial process created a steam chamber that expanded towards the
gas zone and created a preferential flow path for the solvent in the gas zone.
[0080] The two steam injection wells 110 in the rich pay were shut in,
leaving
three wells operating, including, the fluid production well 114 utilized for
propane
injection, and the two production wells 102 at the bottom of the rich pay. A
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pressure drive was thus created between the fluid production well 114 utilized
for
propane injection and the production wells 102 which were each about 54m apart
diagonally from the fluid production well 114. This was in contrast to the
pressure
drive in SAGD where the injection and production wells of a well pair are
typically
roughly 5m apart.
[0081] FIG. 7 shows oil recovery for the process, after discontinuing
steam
injection, with time (from top to bottom, up to a total process time of 2950
days or
about 8 years). During the transition period, in which the process was
switched
over to solvent injection without steam injection, enhanced hydrocarbon
production
rates were observed for some time as propane cooled down the steam chamber and
accelerated condensation of steam. Lower temperatures also increased
solubility of
the propane that entered into the steam chamber. Additionally, oil that was
mobilized by propane in the gas zone also drained down into the steam chamber.
The efficiency of propane utilized as a solvent is indicated by the fact that,
over an
8 year period, almost all the recoverable oil in the 100m spacing between the
two
SAGD well pairs was produced. At 8 years, the "drainage slope" of fluids in
the
reservoir reached the fence wells, which were laterally 150m away from either
production well 102.
[0082] FIG. 8 shows the oil production rates (m3/day) over an 8 year
period.
The rates are shown for an 800m long production well 102. As shown, production
during SAGD averaged about 200m3 oil per day. The oil produced during SAGD is
dependent on permeabilities in the reservoir, however. During the transition
period, elevated production rates were observed. After the transition period,
steady
production rates averaging about 150m3 per day were observed for the next 6.5
years. In a conventional SAGD process, as the steam chamber develops further
away from the production wells 102, steam to oil ratios increase rapidly and
typically after about 60% oil is recovered, the wells are switched over to the
blowdown stage. In the present process, steady production rates were observed
for
a significantly longer period of time as shown in FIG. 8.
[0083] FIG. 9 shows the cumulative produced water to oil ratio (PWOR) and
illustrates an advantage of the process described herein over SAGD alone.
Water to
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oil ratios were higher for the initial SAGD and transition periods. After the
transition period, however, PWOR dropped to a small fraction of the produced
oil as
only connate water and the small amounts of water that bypassed the fence
wells
were produced. Excluding the SAGD and transition periods, cumulative PWOR was
0.18 for the post-transition period solvent process.
[0084] In addition to very low PWOR, which advantageously facilitates the
use
of smaller water handling facilities, the energy intensity of the present
process
(denoted SAGD+Propane in FIG. 10 and FIG. 11) and the time to produce the same
amount of oil were reduced by comparison to SAGD, as shown in FIG. 10 and FIG.
11, respectively. Specifically, simulations showed that the equivalent steam
to oil
ratio, CSOR, on an energy basis for SAGD was 3 on a cumulative basis for 60%
of
oil recovery, while the equivalent CSOR (eCSOR) was only 0.49 for the present
process. In addition, it took 10 years to recover the oil in SAGD but only 4.7
years
for the present process.
[0085] Economics of a solvent recovery process (solvent-aided or solvent-
based) depend on solvent recovery / recycling because the solvent utilized is
relatively expensive. Table 2 below summarizes the solvent material balance
for
the present process at the 600/o oil recovery mark:
Table 2: Propane Material Balance
1 _________________________________________________________
Propane produced back 1 82%
1
1
Propane retained in the reservoir 16%
Propane produced at the fence 2%
wells
Injected solvent to oil ratio 2.2
[0086] Propane remaining in the reservoir at end of the process is
recoverable
utilizing one or more of several methods. One method is illustrated in FIG. 12
in
which, pressure maintenance utilizing the fence wells at the outer edges of
the de-
watered zone was discontinued, thus allowing aquifer water to ingress into the
depleted reservoir. The fluid production well 114 that was utilized for
propane
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injection into the gas zone was then utilized for propane production and
remaining
propane was produced to surface as the depleted reservoir filled up with
water.
[0087] Alternatively, a non-condensable gas may be injected into the
fluid
production well 114 that was utilized for propane injection. The gas, being
lighter
than propane, pushes the propane and additional residual oil to the production
wells
102 at the bottom of the reservoir.
[0088] The described embodiments are to be considered in all respects
only
as illustrative and not restrictive. The scope of the claims should not be
limited by
the preferred embodiments set forth in the examples, but should be given the
broadest interpretation consistent with the description as a whole. All
changes that
come with meaning and range of equivalency of the claims are to be embraced
within their scope.
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