Note: Descriptions are shown in the official language in which they were submitted.
INJECTION CONTROL IN STEAM-SOLVENT ASSISTED PROCESS FOR
HYDROCARBON RECOVERY
FIELD
[0001] The present disclosure relates generally to hydrocarbon recovery
from
subterranean reservoirs, and particularly to injection control in in situ
steam-solvent
hydrocarbon recovery.
BACKGROUND
[0002] Steam and a solvent can be co-injected into a subterranean reservoir
of
bituminous sands (also commonly referred to as oil sands) to assist, drive, or
aid
hydrocarbon recovery from the reservoir (referred to herein as a steam-solvent
recovery process).
[0003] Typically, in a steam-solvent recovery process a desired ratio of
solvent to
steam (solvent-to-steam ratio, SSR) in the injection stream and the desired
injection
temperature and pressure are pre-determined, and the steam and solvent are
mixed
according to these pre-determined values before injection by separately
controlling the
injection rates of steam and the solvent so that the ratio of the solvent
injection rate to
the steam injection rate is the same as the desired solvent-to-steam ratio in
the
injection mixture. For example, for a given solvent injection rate (e.g. 15
t/d), the steam
injection rate may be selected and controlled (e.g. selected to be 35 t/d) to
obtain a
weight percentage of the solvent (e.g. 30 wt% solvent) in the injection
mixture that
corresponds to the desired SSR (e.g. SSR=3:7). The ratio of solvent to steam
(SSR)
may be based on weight/mass, volume, mole, or a combination thereof, and may
be
expressed or indicated in the form of relative ratios, or percentages such as
weight
percentages, volume percentages, or molar percentages.
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[0004] In a typical arrangement in a steam-solvent recovery process, an
input
stream of steam and an input stream of solvent may be provided through
separate
pipelines and mixed at a junction of the pipelines at surface before injection
into the
injection well, where the flow rate in each of the input pipeline is regulated
to achieve a
pre-selected target flow rate. The target flow rates are typically pre-
determined
according to the desired ratio of solvent to steam in the injection stream and
injection
temperature/pressure. For example, the target values of the required flow
rates in the
steam input pipeline and the solvent input pipeline for a given weight ratio
of solvent to
steam and given injection temperature can be pre-determined. A flow meter and
one
or more flow control valves are usually installed in each input pipeline for
measuring
and adjusting the flow rate in the pipeline. The flow control valve is
controlled to adjust
the flow rate based on the measured flow rate from the flow meter. For
instance, when
the measured flow rate is lower than the target value, the flow control valve
is opened
more to increase the flow rate until the flow rate reaches the target value.
When the
measured flow rate is lower than the target value, the flow control valve is
closed more
to decrease the flow rate until the flow rate reaches the target value.
SUMMARY
[0005] It has been recognized that using the flow meter to control the
steam
injection rate may be inconvenient in some situations. For instance, the flow
meter
may need to be replaced during operation for various reasons, and replacing
the flow
meter can cause delay in production and incur significant costs.
[0006] It has also been recognized that it is not necessary to use a flow
meter to
measure the flow rate of steam in a steam-solvent recovery process, and the
flow rate
of the input steam stream may be conveniently controlled based on a measured
temperature in the mixed steam and solvent to be injected.
[0007] Thus, an aspect of the present disclosure relates to a method of
injecting
steam and solvent into a subterranean reservoir to assist recovery of
hydrocarbons
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therefrom. In this method, a first stream comprising steam and a second stream
comprising a solvent is mixed to form a third stream comprising steam and the
solvent
for injection into the reservoir. A temperature in the third stream is
detected. The flow
rate of the first stream is controlled based on the detected temperature. The
third
stream is injected into the reservoir. The temperature in the third stream may
be
detected immediately after the mixing of the first stream and the second
stream. The
flow rate of the first stream may be determined indirectly based on the
detected
temperature without directly measuring the flow rate with a flow rate meter.
In an
embodiment, the first stream may be supplied for mixing through a fluid
conduit, which
includes a flow meter for measuring a fluid flow rate through the fluid
conduit within a
particular range, but the actual flow rate of the first stream is outside this
particular
range. For example, the range of the flow meter may have a lower limit, and
the flow
rate of the first stream is below the lower limit. The method may include
correlating the
temperature in the third stream with the flow rate in the first stream. A
correlation
between the temperature in the third stream and the flow rate in the first
stream may
be predetermined. The predetermined correlation may be stored and available to
a
controller for controlling the flow rate of the first stream. The steam in the
first stream
may have substantially constant pressure, temperature, and steam quality. The
solvent in the second stream may have substantially constant pressure and
temperature and may be supplied at a substantially constant rate. Controlling
of the
flow rate may comprise increasing the flow rate of the first stream when the
detected
temperature decreases, and decreasing the flow rate of the first stream when
the
detected temperature increases. The flow rate may be controlled to maintain
the
temperature in the third stream at a target temperature. The target
temperature may
be determined based on a target ratio of solvent to steam in the third stream.
The third
stream may be injected into the reservoir through an injection well
penetrating the
reservoir.
[0008] In another aspect, a system for injecting steam and solvent into a
subterranean reservoir is provided to assist recovery of hydrocarbons
therefrom. The
system comprises a first conduit for supplying a first stream comprising
steam; a
second conduit for supplying a second stream comprising a solvent; a third
conduit
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connected to the first and second conduit for mixing the first and second
streams to
form a third stream and supplying the third stream comprising steam and the
solvent
for injection into the reservoir; a temperature sensor associated with the
third conduit
for detecting a temperature in the third stream; a flow regulator in the first
conduit for
regulating a flow rate of the first stream in the first conduit; and a
controller connected
to the temperature sensor and the flow regulator for controlling the flow
regulator to
adjust the flow rate, the controller configured and programmed to control the
flow
regulator based on the detected temperature. The system may comprise a steam
source connected to the first conduit for supplying steam at constant
temperature,
pressure and steam quality. The system may comprise a solvent source connected
to
the second conduit for supplying the solvent at constant temperature and
pressure at a
constant rate. The temperature sensor may comprise a thermocouple or a
resistance
thermometer. The flow regulator may comprise a valve. The controller may
comprise a
processor or a computer. The third conduit may be in fluid communication with
an
injection well penetrating the reservoir for injecting the third stream into
the reservoir
through the injection well.
[0009] In a further aspect, there is provided a method of determining a
fluid flow
rate, which comprises mixing a first stream and a second stream to form a
third
stream, wherein the first stream flows at a first flow rate and the second
stream flows
at a second flow rate; detecting a temperature in the third stream; and
determining the
first flow rate based on the detected temperature and the second flow rate.
[0010] In another aspect, there is provided a method of regulating a fluid
flow rate,
comprising: mixing a first stream and a second stream to form a third stream,
wherein
the first stream has a first temperature and the second stream has a second
temperature different from the first temperature; detecting a third
temperature in the
third stream; and adjusting the flow rate of the first stream in response to
the detected
third temperature to control the third temperature in the third stream.
[0011] Other aspects, features, and embodiments of the present disclosure
will
become apparent to those of ordinary skill in the art upon review of the
following
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description of specific embodiments of the disclosure in conjunction with the
accompanying figures.
BRIEF DESCRIPTION OF THE DRAWINGS
[0012] In the figures, which illustrate, by way of example only,
embodiments of the
present disclosure:
[0013] FIG. 1 is a schematic side view of a hydrocarbon reservoir and a
pair of
wells penetrating the reservoir for recovery of hydrocarbons.
[0014] FIG. 2 is a schematic partial end view of the reservoir and wells of
FIG. 1.
[0015] FIG. 3 is a schematic perspective view of the reservoir and wells of
FIG. 1
during operation after a vapour chamber has formed in the reservoir.
[0016] FIG. 4 is schematic block diagram of a possible arrangement in the
surface
injection facility shown in FIG. 1, according to an embodiment of the present
disclosure.
[0017] FIG. 5 is a flow chart for an example control process of the
injection facility
of FIG. 4, according to an embodiment of the present disclosure.
[0018] FIG. 6 is a schematic block diagram of a control system for
performing the
control process of FIG. 5, according to an embodiment of the present
disclosure.
[0019] FIG. 7 is a schematic partial view of an example arrangement in a
surface
injection facility.
DETAILED DESCRIPTION
[0020] Selected embodiments of the present disclosure relate to methods of
hydrocarbon recovery from a reservoir of bituminous sands assisted by co-
injection of
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steam and solvent as mobilizing agents into the reservoir (referred to as
steam-
solvent recovery processes), and methods of control injection of steam and
solvent
into the reservoir.
[0021] In overview, it has been recognized by the present inventor(s) that
the
injection rate of steam in such a process may be conveniently controlled in
response
to a detected temperature in the injection mixture of steam and solvent,
without the
need to directly measuring the flow rate of steam before mixing with the
solvent.
[0022] Conveniently, the injection control can be carried out without an
operational
flow meter installed in the steam supply line, or directly measuring the steam
flow rate.
[0023] A control process described herein allows-continued recovery of
hydrocarbons without interruption when the steam injection rate needs to be
decreased or increased to outside the operational range of an installed flow
meter in
the steam supply line, as it is not necessary to replace the installed flow
meter with a
new flow meter with a different operational range.
[0024] A control process described herein also allows convenient automated
control of the steam injection rate.
[0025] Further, it is possible to estimate the steam flow rate based on the
detected
temperature in the mixture of steam and solvent.
[0026] An example embodiment of the present disclosure relates to a steam-
solvent recovery for recovering hydrocarbons from a subterranean reservoir as
illustrated in FIGS. 1, 2 and 3.
[0027] FIGS. 1-3 schematically illustrate a typical well pair configuration
in a
hydrocarbon reservoir formation 100, which can be operated to implement an
embodiment of the present disclosure. The well pair may be configured and
arranged
similar to a typical well pair configuration for steam-assisted-gravity-
drainage (SAGD)
operations, or a conventional steam-solvent recovery.
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[0028] The reservoir formation 100 contains viscous or heavy hydrocarbons
below
an overburden 110. Under the native conditions before any treatment, a
reservoir of
bituminous sands is typically at a relatively low temperature, such as about
12 C, and
the formation pressure may be from about 0.1 to about 4 MPa, depending on the
location and other characteristics of the reservoir. The overburden 110 may be
a cap
layer or cap rock. Overburden 110 may be formed of a layer of impermeable
material
such as clay or shale. A region in the formation 100 just below and near
overburden
110 may be considered as an interface region 115.
[0029] As used herein in various embodiments, the term "reservoir" refers
to a
subterranean or underground formation containing recoverable hydrocarbons
(oil); and
the term "reservoir of bituminous sands" refers to such a formation wherein at
least
some of the hydrocarbons are viscous or immobile in their native state, and
are
disposed between or attached to sands.
[0030] In various embodiments, the terms "oil", "hydrocarbons" or
"hydrocarbon"
relate to mixtures of varying compositions comprising hydrocarbons in the
gaseous,
liquid or solid states, which may be in combination with other fluids (liquids
and gases)
that are not hydrocarbons. For example, "viscous hydrocarbons", "heavy oil",
"extra
heavy oil", and "bitumen" refer to hydrocarbons occurring in semi-solid or
solid form
and having a viscosity in the range of about 1,000 to over 1,000,000
centipoise (mPa-s
or cP) measured at the native in situ reservoir temperature. In this
specification, the
terms "hydrocarbons", "oil", and "bitumen" may be used interchangeably unless
otherwise specified. Depending on the in situ density and viscosity of the
hydrocarbons, the hydrocarbons may include, for example, a combination of oil,
heavy
oil, extra heavy oil, and bitumen. The term "oil" when used generally may
include "light"
oil, hydrocarbons mobile at typical reservoir conditions. Heavy crude oil, for
example,
may include any liquid petroleum hydrocarbon having an American Petroleum
Institute
(API) Gravity of less than about 20 such as lower than 6 , and a viscosity
greater than
1,000 mPa.s. Extra heavy oil, for example, may have a viscosity of over 10,000
mPa.s
and about 10 API Gravity. The API Gravity of bitumen typically ranges from
about 12
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CA 3046390 2019-06-13
to about 6 or about 70 and the viscosity of bitumen is typically greater than
about
1,000,000 mPa-s.
[0031] In example embodiments, the well pair includes an injection well 120
and a
production well 130, which have horizontal sections extending substantially
horizontally in reservoir formation 100, and are drilled and completed for
producing
hydrocarbons from reservoir formation 100. As depicted in FIG. 1, the well
pair may be
positioned below and away from the overburden 110 and near the bottom of the
pay
zone or geological stratum in reservoir formation 100.
[0032] As is typical in a SAGD operation, injection well 120 may be
vertically
spaced from production well 130, such as at a distance of about 3 to 8 m,
e.g., 5 m. In
different embodiments, the distance between the injection well 120 and the
production
well 130 may vary and may be selected to optimize the operation performance
within
technical and economical constraints, as can be understood by those skilled in
the art.
In some embodiments, the horizontal sections of wells 120 and 130 may have a
length
of about 800 m. In other embodiments, the length may be varied as can be
understood
and selected by those skilled in the art. Wells 120 and 130 may be configured
and
completed according to any suitable techniques for configuring and completing
horizontal in situ wells known to those skilled in the art. Injection well 120
and
production well 130 may also be referred to as the "injector" and "producer",
respectively.
[0033] As illustrated, wells 120 and 130 are connected to respective
corresponding
surface facilities, which typically include an injection surface facility 140
and a
production surface facility 150. Surface facility 140 is configured and
operated to
supply injection fluids, including steam and at least one solvent, into
injection well 120,
and will be further described in more detail below. Surface facility 150 is
configured
and operated to produce fluids collected in production well 130 to the
surface. Each of
surface facilities 140, 150 includes one or more fluid pipes or tubing for
fluid
communication with the respective well 120 or 130.
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CA 3046390 2019-06-13
[0034] As better illustrated in FIG. 4, the surface facility 140 includes a
steam
source such as a steam generation plant 402, and a supply line such as fluid
pipe 404
connected to the steam generation plant 402 for supplying steam to injection
well 120
for injection into the reservoir formation 100. A fluid flow regulator such as
a valve 406
is provided in the fluid pipe 404 for regulating the fluid flow rate in the
fluid pipe 404.
Devices and equipment for driving steam flow and measuring steam properties
such
as steam temperature and pressure may be provided in the steam generation
plant
402 or along pipe 404, but for simplicity these devices and equipment are not
shown in
FIG. 4, as details of these devices and equipment are not necessary for
understanding
the present disclosure.
[0035] The surface facility 140 also includes a solvent source such as a
solvent
tank 412 and a supply line such as fluid pipe 414 for supplying the solvent to
the
injection well 120 for co-injection with steam. A flow regulator such as a
valve 416 is
provided in pipe 414 for regulating the fluid flow in pipe 414. A flow meter
418 is also
provided to measure the fluid flow rate through pipe 414. Optionally, a pump
420 is
provided to drive the fluid flow in pipe 414.
[0036] Valves 406, 416 may be any suitable fluid flow control valves for
use under
the particular operation conditions in a given embodiment. Existing valves
used in
steam and solvent supply lines in conventional steam-solvent recovery
processes may
be used. Valves 406 and 416 may be of the same type or be different, and may
be
selected so that valve 406 is suitable for controlling steam flow at the
expected steam
temperature and pressure ranges, and valve 416 is suitable for controlling
flow of the
particular solvent to be used.
[0037] Flow meter 418 may be any suitable fluid flow meter.
[0038] Optionally, surface facility 140 may include a heating facility (not
separately
shown) for pre-heating the solvent before injection.
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[0039] Heating devices or heat insulation (not separately shown) may also
be
provided in one or more of the supply lines (e.g. pipes 404 and 414) for
control or
maintain the temperatures of the supplied fluids such as steam and solvents.
[0040] Both pipes 404 and 414 are connected to a mixing junction 422, which
is
connected to the injection well 120 through an input pipe 424, for mixing the
steam
and solvent before the mixture of steam and the solvent is injected into the
reservoir
formation 120.
[0041] As depicted, the mixing junction 422 is located at surface. However,
in
different embodiments, the mixing junction 422 may be located at surface, near
or in
the well head of injection well 120, or inside a section of the injection well
120. The
input pipe 424 may be a separate pipe connected to the injection well, or may
be a
part of the injection well 210.
[0042] A temperature sensor 426 is provided at the mixing junction 422 or
downstream of the mixing junction 422 along the input pipe 424 for measuring
the
temperature in the mixture of steam and the solvent to be injected. The
temperature
sensor 426 may be any suitable sensor for detecting and measuring the fluid
temperature in the mixing junction 422 or in the input pipe 424 near the
mixing junction
422. For example, the temperature sensor may be selected from thermocouples,
resistance temperature detectors (RTD), thermistors, thermometers, infrared
temperature sensors, digital temperature sensors such as semiconductor based
temperature sensing integrated circuit (IC), and the like. When the mixing
junction 422
is located downhole in the injection well 120, a distributed temperature
sensing (DTS)
device may also be used to detect the temperature or temperature changes in
the
mixture of steam and the solvent.
[0043] Optionally, one or more additional supply lines may be provided for
supplying other fluids, additives or the like for co-injection with steam or
the solvent.
[0044] While not expressly depicted, it should be understood that each
supply line
may be connected to a corresponding source of supply, which may include, for
CA 3046390 2019-06-13
example, a boiler, a fluid mixing plant, a fluid treatment plant, a truck, a
fluid tank, or
the like. In some embodiments, co-injected fluids or materials may be pre-
mixed
before injection. In other embodiments, co-injected fluids may be separately
supplied
into injection well 120.
[0045] Surface facility 150 may include a fluid transport pipeline for
conveying
produced fluids to a downstream facility (not shown) for processing or
treatment.
Surface facility 150 also includes necessary and optional equipment (not
separately
shown) for producing fluids from production well 130, as can be understood by
those
skilled in the art.
[0046] Other necessary or optional surface facilities 160 may also be
provided, as
can be understood by those skilled in the art. For example, 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.
[0047] Surface facilities 140, 150 and 160 may also include recycling
facilities for
separating, treating, and heating various fluid components from a recovered or
produced reservoir fluid. For example, the recycling facilities may include
facilities for
recycling water and solvents from produced reservoir fluids.
[0048] Injection well 120 and production well 130 may be configured and
completed
in any suitable manner as can be understood or is known to those skilled in
the art, so
long as the wells are compatible with injection, and optionally recovery, of a
selected
solvent to be used in a steam-solvent recovery process as will be disclosed
below.
[0049] For example, in different embodiments, the well completions may
include
perforations, slotted liner, screens, outflow control devices such as in an
injection well,
inflow control devices such as in a production well, or a combination thereof
known to
one skilled in the art.
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[0050] FIG. 2 shows a schematic cross-sectional view of wells 120, 130 in
formation 100, and FIG. 3 is a schematic perspective view of wells 120, 130 in
formation 100 during a recovery process where a vapour chamber 360 has formed.
[0051] As illustrated, injection well 120 and production well 130, each
have a
casing 220, 230 respectively. An injector tubing 225 is positioned in injector
casing 220
and connected to input pipe 424 for receiving the mixture of steam and the
solvent to
be injected into the reservoir formation 100. The use of injector tubing 225
can be
understood by those skilled in the art, and will be described below.
[0052] For simplicity, other necessary or optional components, tools or
equipment
that are installed in the wells are not shown in the drawings as they are not
particularly
relevant to the present disclosure.
[0053] As depicted in FIG. 3, injector casing 220 includes a slotted liner
along the
horizontal section of well 120 for injecting fluids into reservoir formation
100.
[0054] Production casing 230 is also completed with a slotted liner along
the
horizontal section of well 130 for collecting fluids drained from reservoir
formation 100
by gravity. In some embodiments, production well 130 may be configured and
completed similarly to injection well 120.
[0055] In some embodiments, each well 120, 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.
[0056] In operation, wells 120 and 130 may be operated to produce
hydrocarbons
from reservoir formation 100 according to a process disclosed herein.
[0057] For example, in an embodiment the wells 120 and 130 may be initially
operated as in a conventional SAGD process, or a suitable variation thereof,
as can be
understood by those skilled in the art. In this initial process, steam may be
the only or
the dominant injection fluid.
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[0058] Alternatively, steam and a solvent may be co-injected at the start
of the
production stage after the start-up stage.
[0059] In any event, both steam and one or more solvents are injected
during at
least one period of the production stage, and the following description is
focused on
such injection period.
[0060] Steam is supplied by steam generator 402 to junction 422 through
pipe 404,
and a solvent such as propane is supplied by solvent tank 412 to junction 422
through
pipe 414, as illustrated in FIG.4. The steam flow may be driven by steam
generator
402 and regulated by valve 406. The solvent flow may be driven by pump 420 and
regulated by both valve 416 and pump 420. The solvent may be supplied to
junction
422 in the liquid phase or gas phase, or in both phases. The solvent may be
compressed during storage. In an embodiment, the solvent may be supplied to
pipe
414 as a liquid. In a different embodiment, the solvent may be stored in a
liquid state
and supplied to pipe 414 as a vapor, or heated and vaporized in pipe 414
before the
solvent is supplied to junction 422. The solvent flow rate is measured by flow
meter
418. The temperature (T) in the mixed stream and solvent after junction 422 is
detected by temperature sensor 426.
[0061] For steam-solvent co-injection, it is often necessary or desirable
to control
the solvent-to-steam ratio (SSR) in the injection stream for optimal
production
performance or other considerations.
[0062] As discussed earlier, it is possible in some cases to measure the
flow rate of
the input steam stream and the flow rate of the input solvent stream
separately using
flow meters installed in the input pipes 404 and 414 respectively, and
regulate the flow
rates using flow valves 406 and 416 to obtain the target SSR. For such a
control
process to work properly, a functional flow meter with the appropriate flow
rate
detection range is required for measuring the flow rate in pipe 404, and for
measuring
the flow rate in pipe 414. As depicted, a flow meter is not shown in the pipe
404 for
the steam stream, in which case, this process of control is not possible. Even
if a flow
meter is installed in pipe 404, if at least some of the desired steam flow
rates are
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outside the operation range of the flow meter, this process of control is also
not
adequate. It may be inconvenient or time-consuming to replace the existing
flow meter
with a flow meter with suitable detection range.
[0063] However, according to an embodiment of the present disclosure, the
steam
flow rate (R) in pipe 404 may be controlled with a control process such as
process
S500 illustrated in FIG. 5. It should be noted that the order of some of the
actions
described below with regard to process S500 may be rearranged without changing
the
result, as can be understood by those skilled in the art.
[0064] At S510, the target mixture temperature (Ti) is obtained or
determined.
[0065] The target mixture temperature Tt may be determined based on the
desired
or target SSR in the injection mixture in pipe 424. For example, for given
properties of
the steam and solvent supplied by the steam and solvent sources (e.g. steam
generator 402 and solvent tank 412), and a given target SSR (e.g., expressed
as a
target weight percentage of the solvent), the expected temperature in the
steam-
solvent mixture can be calculated as a function of the SSR.
[0066] For example, in a simple case, the temperature of a mixture of two
fluids
may be calculated as follows in Equation (1), assuming there is no phase
change
(e.g., no evaporation or condensation) and no other net energy loss/gain in
the system
during mixing:
1711 c1 4- M2 C2 T2, (1)
where "m," represents the mass of each input fluid "i", "c" represents the
specific heat
of the input fluid, "7-1" represents the temperature of the input fluid before
it is mixed
with the other fluid, and "Tfinar is the temperature of the mixture of the two
fluids.
[0067] For any given SSR (= Msolventdrnsteam = rsolventdrsteam), Equation
(1) may be
rewritten as:
Tr = [(rsolvenarstearrd C1 T1 + C2 T2,] rsteam
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= [(SSR) c/ T1 + c2 T2,) rsteam, (2)
where rsolventi and rsteam are the injection rate of solvent and steam
respectively.
[0068] Thus, in order to determine Tt, a target SSR (SSR) in the injection
stream in
pipe 414 may be determined. The SSR may be determined in consideration of a
number of factors as will be understood by those skilled in the art, and
further
explained below.
[0069] As some flow Characteristics and thermodynamic properties of steam and
solvent flows in pipe 404 and 414 can affect the dependency of Ton SSR, the
actual
relevant flow characteristics and thermodynamic properties may also be
determined or
obtained. For example, the steam temperature and pressure and steam quality
may be
measured or already known based on information obtained from the steam
generation
process at steam generator 402. It is also possible to measure actual steam
temperature and pressure in pipe 404 using suitable temperature and pressure
sensors (not shown) installed in pipe 404. The solvent temperature and
pressure may
be determined based on the storage temperature and pressure of the solvent in
storage tank 412, but may also be measured in pipe 414 using suitable sensors
(not
shown). The flow rate of the solvent stream in pipe 414 can be directly
measured
using flow rate meter 418. Some of these quantities or operation parameters
may be
obtained based on estimation or modeling and do not need to be directly
measured in
some embodiments. For example, the flow rate of the solvent may be estimated
based
on the pumping speed of pump 420 when the flow meter 418 is omitted.
[0070] As can be appreciated by those skilled in the art, the target
temperature Tt at
temperature sensor 426 can be determined based on the target SSR (SSR), and
the
relevant flow and thermodynamic characteristics and properties
determined/obtained
as described above. For example, a person skilled in the art would understand
how to
calculate the target temperature Tt for a given SSR (on the basis of weight,
volume, or
molar percentages) and the relevant flow and thermodynamic information of the
input
streams. For example, the temperature of the mixture may be affected by the
temperatures of the input steam and solvent, the SSR (or in weight/molar
percentages
CA 3046390 2019-06-13
of the solvent) in the mixture, the steam quality and the phase(s) of the
input solvent
and the phase(s) of the solvent in the mixture. As can be understood, the SSR
is
directly dependent on the flow rates of input steam and solvent.
[0071] The target temperature Tt may be previously known, and may be a
constant
over a period of time, but may also be dynamically determined in real time
from time to
time, continuously, at regular intervals, or periodically based on detected or
other input
values that may fluctuate or change over time.
[0072] It is also possible to determine the correlation between the steam
flow rate R
in pipe 404 and the temperature (T) in pipe 414 based on the known flow and
thermodynamic characteristics/properties of the input streams. This
correlation may be
calculated based on a theoretical or a simulation model, or may be empirically
determined based on experimental or field data, or may be based on both. For
example, the correlation may be completely based on calculation using known
flow
dynamic and thermodynamic relationships and measured input data. The
correlation
may be completely based on testing using direct flow rate measurements under
the
same or similar flow and thermodynamic conditions. Some correlation
information may
be extrapolated from calculations or testing data for higher or lower flow
rates.
[0073] For a given target SSRt, the target temperature Tt and target steam
flow rate
(Rt) corresponding to the target SSRt can be determined based on the
correlation.
[0074] Optionally, a correlation between the temperature in pipe 414 as
detected by
sensor 426 (T) and the steam flow rate (R) in pipe 404 may be obtained or
determined.
[0075] This correlation between T and R may be already known to the operator,
may be pre-determined once before or during process S500, or may be determined
repeatedly during process S500, as will be further discussed below. The
correlation
may be expressed as a formula (e.g. R = f (T), where "f' represents a
mathematical
function), a correlation (mapping) table or the like, and may be presented to
the
16
CA 3046390 2019-06-13
operator by any visual devices or calculated by a computer in real-time using
an
algorithm or routine.
[0076] For example, the correlation between T and R may be determined based on
the relevant flow and thermodynamic characteristics of the steam flow and
solvent flow
in pipes 404 and 414. Relevant flow and thermodynamic characteristics of a
flow may
include the temperature, pressure, and flow rate, as wells the phase state or
quality of
the fluid (e.g. vapor or liquid). For a flow of saturated steam, the steam
quality is
relevant in this context as the steam quality is related to the total enthalpy
of the steam
stream and can affect the heat transfer and resulting temperature in the steam-
solvent
mixture after the steam and solvent is mixed. Steam quality refers to the
proportion of
steam (vapor) in a saturated mixture of steam (vapor) and condensate water
(liquid).
[0077] An example of a mapping or correlation table showing the correlation
between R and T (and SSR) can be found in TABLE I in the Examples below.
[0078] At S510 and S520, steam and the solvent can be continuously supplied to
pipe 424 at junction 422 at the given solvent flow rate and an initial
(unknown) steam
flow rate, which may be typically below or slightly higher than the target
steam flow
rate (Rt), and at S520, the actual mixture temperature Ta in pipe 424 is
detected at
sensor 426.
[0079] At S530, the steam flow rate R in pipe 404 is adjusted based on the
detected Ta, and the target temperature T.
[0080] For example, the difference (AT) between the detected temperature Ta
and
the target temperature Tt in pipe 424 may be calculated, where AT = Ta ¨ T.
[0081] If AT < 0, more steam is required to provide the target SSRt, the
steam flow
rate R in pipe 404 is increased by opening up the flow valve 406.
[0082] If AT > 0, less steam is required to provide the target SSRt, the
steam flow
rate R in pipe 404 is decreased by closing down the flow valve 406.
17
CA 3046390 2019-06-13
[0083] If AT = 0, or when AT is within an acceptable range, the steam flow
rate
does not need to be adjusted, and the steam flow rate R in pipe 404 may be
maintained at a constant level, i.e., at the target temperature.
[0084] In practice, the temperature response to the steam flow rate
adjustment may
not be instantaneous, and a delay time may be required after any adjustment of
the
steam flow before the temperature T in pipe 424 is stabilized. For more
accurate flow
adjustments, AT should be calculated based on Ta detected at a time when the
temperature T in pipe 424 is substantially stable.
[0085] The process from S510 to S530 or from S520 to S530 may be repeated
until
the co-injection operation is terminated or suspended, or the control process
is no
longer needed in the recovery process.
[0086] As can be appreciated by those skilled in the art, when the steam flow
rate R
is adjusted to provide the target temperature Tt, it is expected that the SSR
in the
injection stream in pipe 424 should be the corresponding target SSR, or is
close to the
target SSR t within an acceptable tolerance range. Therefore, the process S500
in
effect adjusts the steam flow rate R to reach the target SSRt based on the
detected Ta
and a known correlation between R and SSR as reflected through Tt and the
correlation between the mixture temperature and the steam flow rate.
[0087] As is apparent from the above description of process S500, to adjust
the
steam flow rate to control the SSR in the injection stream, it is not
necessary for the
operator of the surface facility 140 to know the exact flow rate in pipe 404,
or how the
flow rate R is directly correlated to SSR. It is sufficient that the
corresponding target
temperature in the injection mixture is known, which may be obtained based on
the
correlation between the SSR and T, since the correlation between SSR and T is
dependent on R.
[0088] Process S500 may be performed manually, or automatically, or
partially
automatically.
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CA 3046390 2019-06-13
[0089] For example, a control system such as the system 600 illustrated in
FIG. 6
may be used to perform process S500.
[0090] As depicted, system 600 includes a controller 602, which may be
connected
to steam generator 402, valve 406, pump 420, valve 416, flow meter 418 and
temperature sensor 426, for controlling the operation of valves 406, 416, and
optionally steam generator 402. Controller 602 may optionally be connected to
input
devices or sensors (not shown) that can provide data or signal indicative of
the
properties of the solvent, such as temperature and other information, stored
in solvent
tank 412. The connection between any two devices may be wired or wireless, and
may
be direct or through one or more intermediate communication or control
devices, as
can be understood by those skilled in the art.
[0091] Controller 602 may include one or more processors such as
microprocessors or computing units such as one or more central processing
units
(CPU) or specialized processing circuits units. In some embodiments, a general
purpose computer may be used, and is specifically configured and programed to
perform the some of the functions and methods described herein.
[0092] For example, in some embodiments, system 600 may include a PID
(proportional integral derivative) controller for controlling temperature,
which is
connected to sensor 426 to receive the detected temperature as a feedback
input, and
outputs a control signal to close or open valve 406 as the control element.
The target
temperature value of Tt may be used as the set-point. The PID may be a digital
PID or
analog PID. In other embodiments, a PD (proportional-derivative) or PI
(proportional-
integrated) controller may be used to control the valve 406 based on the
detected
temperature, depending on the particular application.
[0093] In some embodiments, a programmable controller such as programmable
logic controller (PLC) may be included in system 600. A programmable
automation
controller (PAC) may also be included in system 600.
19
CA 3046390 2019-06-13
[0094] In some embodiments, system 600 may be configured as a distributed
control system (DCS), and may include a supervisory control computer and a
number
of controller or control units.
[0095] System 600 may also be configured to provide advanced process
control
(APC). For example, system 600 may be configured to provide multivariable
model
predictive control (MPC), including nonlinear MPC. The APC system may be based
in
part on inferential measurements of some variables, such as one or more of the
temperature and pressure of steam in pipe 404, the temperature of the solvent
in pipe
414, and the flow rate of the solvent in pipe 414.
[0096] System 600 may be configured to provide continuous control of valve
406. It
is also possible in some embodiments that system 600 is configured and
programmed
to provide sequential control where valve 406 is controlled and adjusted in
time- or
event-based automation sequences. For example, a triggering event for an
automated
control sequence may be a change of the target SSRt due to process
considerations
or any other reasons, a change in the solvent supply (e.g., batch change,
truck
change, temperature or flor rate change or the like), a change in the steam
supply
(e.g., a temperature or pressure change, or a change in steam quality), or the
like. An
automated control sequence may also be started at pre-defined times, or after
a given
time interval, or at regular time intervals.
[0097] System 600 and controller 602 may also be configured and programmed to
provide simulation-based control or optimization of the control of valve 406
for
controlling the target temperature Tt, and ultimately the SSR in the injection
stream in
pipe 424.
[0098] Suitable controllers may include controller or control systems
available from
HoneywellTM under the brand name UNISIMTm.
[0099] One or more reservoir simulation algorithms or software with fluid
transport
and heat transfer calculations may be used to provide used to provide needed
information for control.
CA 3046390 2019-06-13
[00100] As depicted in FIG. 6, system 600 may also include a computer or
processor readable storage media, such as memory 604, for storing both
processor
executable instructions and data needed to perform the control process S500
and
optionally other functions or tasks. Memory 604 may include any suitable
computer
memory devices or storage devices. In particular, memory 604 may store thereon
processor executable instructions, which when executed by a processor causes
controller 602 to perform the control process S500.
[00101] System 600 may further include input/output (I/O) interface
devices,
communication devices (not separately shown) for communication with other
connected devices, and for receiving input from a user and for outputting
control
signals or presenting information to the user.
[00102] In particular, during operation, control system 600 may receive
input from
a user for determining the target SSRt. Control system 600 may also
communicate
with the steam generator 402 or devices associated with the steam generator
402 to
obtain operation parameters and information about the input steam, such as its
temperature, pressure, steam quality, and the like.
[00103] If controller 602 is connected to input devices or sensors (not
shown)
associated with the solvent source or a solvent transportation line, such as
the solvent
tank 412 or pipe line 414, controller 602 may receive data or signal
indicative of the
properties of the solvent, such as temperature and other information, stored
in the
solvent source such as solvent tank 412, or the transported through the
transportation
line such as pipe line 414. Alternatively, such information about the solvent
may be
input by a user or operator.
[00104] Control system 600 may further communicate with flow meter 418, or
optionally pump 420, to obtain the flow rate of the solvent stream in pipe
414.
[00105] Control system 600 may communicates with temperature sensor 426
directly or indirectly, through wired or wireless connections, to receive the
temperature
feedback from temperature sensor 426. Control system 600 may receive a digital
or
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CA 3046390 2019-06-13
analogue signal from temperature sensor 426.
[00106] Optionally, control system 600 may be configured and programmed to
receive an input of the target SSRt, and in response to receiving the target
SSRt,
determine the corresponding target Tt in pipe 424 based on the target SSRt and
the
current flow and thermodynamic parameters and characteristics, such as by
calculation or by searching a data structure (e.g. mapping table) stored in
system 600.
Optionally, system 600 may be configured and programmed to receive an input
from a
user or another device that indicates the target T.
[00107] System 600 may be configured and programmed to determine a
correlation between the steam flow rate in pipe 404 and the temperature in
pipe 414
based on stored information including the flow and thermodynamic parameters
and
characteristics described herein.
[00108] To better illustrate and understand how the target SSR (Rt) or
target
temperature (Tt) may be initially selected or set, an example recovery process
is
described below by way of background with reference to the well arrangement
shown
in FIGS. 1-3.
[00109] In an example recovery process, reservoir formation 100 may be
initially
subjected to a "start-up" phase or stage, in which fluid communication between
wells
120 and 130 is established. The start-up stage may be similar to the initial
start-up
stage in a conventional SAGD process. To permit drainage of mobilized
hydrocarbons
and condensate to production well 130, fluid communication between wells 120,
130
must be established. Fluid communication 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 reservoir fluid and
removing
the 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 injection well 120 or production well
130. In
some cases, steam may be injected into, or circulated in, both injection well
120 and
production well 130 for faster start-up. For example, the start-up phase may
include
22
CA 3046390 2019-06-13
circulation of steam or hot water by way of injector casing 220 and injector
tubing 225
in combination. A pressure differential may be applied between injection well
120 and
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.
[00110] Additionally or alternatively, other techniques may be employed
during
the start-up stage. For example, to facilitate fluid communication, a solvent
may be
injected into the reservoir region around and between the injection and
production
wells 120, 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 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.
[00111] Once fluid communication between injection well 120 and production
well
130 has been achieved, oil (hydrocarbon) production or recovery may commence.
As
the oil production rate is typically low initially and will increase as the
vapour chamber
develops, the early production phase is known as the "ramp-up" phase or stage.
During the ramp-up stage, steam, with or without a solvent, is typically
injected
continuously into injection well 120, at constant or varying injection
pressure and
temperature. At the same time, mobilized hydrocarbons and aqueous condensate
are
continuously removed from production well 130. During ramp-up, the zone of
communication between injection well 120 and production well 130 may continue
to
expand axially along the full length of the horizontal portions of wells 120,
130.
[00112] As the injected fluid heats up formation 100, viscous and heavy
hydrocarbons in the heated region are softened, resulting in reduced
viscosity.
Further, as heat is transferred from steam to formation 100, steam and solvent
vapour
condense. The aqueous and solvent condensate and mobilized hydrocarbons will
drain downward due to gravity. As a result of depletion of the hydrocarbons, a
porous
region is formed in formation 100, which is referred to herein as the "vapour
chamber"
23
CA 3046390 2019-06-13
360. When the vapour chamber 360 is filled with mainly steam, it is commonly
referred
to in the art as the "steam chamber." The aqueous and solvent condensate and
hydrocarbons drained towards production well 130 and collected in production
well
130 are then produced (transferred to the surface), such as by gas lifting or
through
pumping as is known to those skilled in the art.
[00113] More specifically, during oil production a heated fluid including
steam and
solvent may be injected into reservoir 100 through injection well 120. The
injected fluid
heats up the reservoir formation, softens or mobilizes the bitumen in a region
in the
reservoir 100 and lowers bitumen viscosity such that the mobilized bitumen can
flow.
As heat is transferred to the bituminous sands, injected steam and solvent
vapour
condense and a fluid mixture containing condensed steam and solvent and
mobilized
bitumen (oil) forms. The fluid mixture drains downward due to gravity, and the
vapour
chamber 360 is formed or expands in reservoir 100. The fluid mixture generally
drains
downward along the edge of vapour chamber 360 towards the production well 130.
Condensed steam (water), liquid solvent, and oil in the fluid mixture
collected in the
production well 130 are then produced (transferred to the surface), such as by
gas
lifting or through pumping such as using an electric submersible pump (ESP),
as is
known to those skilled in the art.
[00114] As is typical, the injection and production wells 120, 130 have
terminal
sections that are substantially horizontal and substantially parallel to one
another. A
person of skill in the art will appreciate that while there may be some
variation in the
vertical or lateral trajectory of the injection or production wells, causing
increased or
decreased separation between the wells, such wells for the purpose of this
application
will still be considered substantially horizontal and substantially parallel
to one another.
Spacing, both vertical and lateral, between injectors and producers may be
optimized
for establishing start-up or based on reservoir conditions.
[00115] At the point of injection into the formation, or in the injection
well 120, the
injected fluid/mixture may be at a temperature that is selected to optimize
the
production performance and efficiency. For example, for a given solvent to be
injected
24
CA 3046390 2019-06-13
the injection temperature may be selected based on the boiling point (or
saturation)
temperature of the solvent at the expected operating pressure in the
reservoir. For
propane, the boiling temperature is about 2 C at 0.5 MPa, and about 77 C at
3 MPa.
For a different solvent, the injection temperature may be higher if the
boiling point
temperature of that solvent at the reservoir pressure is higher. In different
embodiments and applications, the injection temperature may be substantially
higher
than the boiling point temperature of the solvent by, e.g., 5 C to 200 C,
depending on
various operation and performance considerations. In some embodiments, the
injection temperature may be from about 50 C to about 320 C, and at a
pressure
from about 0.5 MPa to about 12.5 MPa, such as from 0.6 MPa to 5.1 MPa or up to
10
MPa. At an injection pressure of about 3 MPa, the injection temperature for
propane
may be from about 80 C to about 250 C, and the injection temperature for
butane
may be from about 100 C to about 300 C. The injection temperature and
pressure
are referred to as injection conditions. A person skilled in the art will
appreciate that
the injection conditions may vary in different embodiments depending on, for
example,
the type of hydrocarbon recovery process implemented or the mobilizing agents
selected, as well as various factors and considerations for balancing and
optimizing
production performance and efficiency. The injection temperature should not be
too
high as a higher injection temperature will typically require more heating
energy to
heat the injected fluid. Further, the injection temperature should be limited
to avoid
coking hydrocarbons in the reservoir formation. In some oil sands reservoirs,
the
coking temperature of the bitumen in the reservoir is about 350 C.
[00116] Once injected steam and vapour of the injected solvent enter the
reservoir, their temperature may drop under the reservoir conditions. The
temperatures
at different locations in the reservoir will vary as typically regions further
away from
injection well 120, or at the edges of the vapour chamber, are colder. During
operations, the reservoir conditions may also vary. For example, the reservoir
temperatures can vary from about 10 C to about 275 C, and the reservoir
pressures
can vary from about 0.6 MPa to about 7 MPa depending on the stage of
operation.
The reservoir conditions may also vary in different embodiments.
CA 3046390 2019-06-13
[00117] As noted above, injected steam and solvent condense in the
reservoir
mostly at regions where the reservoir temperature is lower than the dew point
temperature of the solvent at the reservoir pressure. Condensed steam (water)
and
solvent can mix with the mobilized bitumen to form reservoir fluids. It is
expected that
in a typical reservoir subjected to steam/solvent injection, the reservoir
fluids include a
stream of condensed steam (or water, referred to as the water stream herein).
The
water stream may flow at a faster rate (referred to as the water flow rate
herein) than a
stream of mobilized bitumen containing oil (referred to as the oil stream
herein), which
may flow at a slower rate (referred to as the oil flow rate herein). The
reservoir fluids
can be drained to the production well by gravity. The mobilized bitumen may
still be
substantially more viscous than water, and may drain at a relatively low rate
if only
steam is injected into the reservoir. However, condensed solvent may dilute
the
mobilized bitumen and increase the flow rate of the oil stream.
[00118] Thus, injected steam and vapour of the solvent both assist to
mobilize
the viscous hydrocarbons in the reservoir 100. A reservoir fluid formed in the
vapour
chamber 360 will include oil, condensed steam (water), and a condensed phase
of the
solvent. The reservoir fluid is drained by gravity along the edge of vapour
chamber 360
into production well 130 for recovery of oil.
[00119] In various embodiments, the solvent may be selected so that
dispersion
of the solvent in the vapour chamber 360, as well as in the reservoir fluid
increases the
amount of oil contained in the fluid and increases the flow rate of oil stream
from
vapour chamber 360 to the production well 130. When solvent condenses (forming
a
liquid phase) in the vapour chamber 360, it can be dispersed in the reservoir
fluid to
increase the rate of drainage of the oil stream from the reservoir 100 into
the
production well 130.
[00120] After the reservoir fluid is removed from the reservoir 100, the
solvent
and water may be separated from oil in the produced fluids by a method known
in the
art depending on the particular solvent(s) involved. The separated water and
solvent
can be further processed by known methods, and recycled to the injection well
120. In
26
CA 3046390 2019-06-13
some embodiments, the solvent is also separated from the produced water before
further treatment, re-injection into the reservoir or disposal.
[00121] As mentioned, vapour chamber 360 forms and expands due to
depletion
of hydrocarbons and other in situ materials from regions of reservoir
formation 100
above the injection well 120. Injected steam/solvent vapour tend to rise up to
reach the
top of vapour chamber 360 before they condense, and steam/solvent vapour can
also
spread laterally as they travel upward. During early stages of chamber
development,
vapour chamber 360 expands upwardly and laterally from injection well 120.
During
the ramp-up phase and the early production phase, vapour chamber 360 can grow
vertically towards overburden 110. At later stages, after vapour chamber 360
has
reached the overburden 110, vapour chamber 360 may expand mainly laterally.
[00122] Depending on the size of reservoir formation 100 and the pay
therein
and the distance between injection well 120 and overburden 110, it can take a
long
time, such as many months and up to two years, for vapour chamber 360 to reach
overburden 110, when the pay zone is relative thick as is typically found in
some
operating oil sands reservoirs. However, it will be appreciated that in a
thinner pay
zone, the vapour chamber can reach the overburden 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 formation has complex overburden geologies such
as
with inclined heterolithic stratification (HIS), top water, top gas, or the
like.
[00123] During a period in at least the production stage, steam and the
solvent
are co-injected into the reservoir to assist production and enhance
hydrocarbon
recovery.
[00124] In some embodiments, at early stages of oil production, steam may
be
injected without a solvent. The solvent may be added as a mobilizing agent
after the
vapour chamber 360 has reached or is near the top of the pay zone, e.g., near
or at
the lower edge of the overburden 110 as depicted in FIGS. 1 and 3 or after the
oil
production rate has peaked. The solvent can dissolve in oil and dilute the oil
stream so
as to increase the mobility and flow rate of hydrocarbons or the diluted oil
stream
27
CA 3046390 2019-06-13
towards production well 130 for improved oil recovery. Other materials in
liquid or gas
form may also be added to the injection fluid to enhance recovery performance.
[00125] The start-up, ramp-up, and production phases may be conducted
according to any suitable conventional techniques known to those skilled in
the art
except the aspects described herein, and the other aspects will therefore not
be
detailed herein for brevity.
[00126] As an example, during production, such as at the end of an initial
production period with steam injection, the formation temperature in the
vapour
chamber 360 can reach about 235 C and the pressure in the vapour chamber 360
may be about 3 MPa. The temperature or pressure may vary by about 10% to 20%.
[00127] As mentioned earlier, in a particular embodiment where propane is
used
as the mobilizing agent, the injection temperature of the steam-propane
mixture may
be about 80 C to about 250 C. In other embodiments, the injection
temperature may
be selected based on the boiling point temperature of the solvent at the
selected
injection pressure.
[00128] Of course, depending on the reservoir and the application, the
chamber
temperature and pressure may also vary in different embodiments. For example,
in
various embodiments, steam may be injected at a temperature from about 150 C
to
about 330 C and a pressure from about 0.1 MPa to about 12.5 MPa. In some
embodiments, the highest temperature in the vapour chamber 360 may be from
about
50 C to about 350 C and the pressure in the vapour chamber 360 may be from
about
0.1 MPa to about 7 MPa.
[00129] In further embodiments, it may also be possible that steam is
injected at
a temperature sufficient to heat the solvent such that the injected solvent
has a
maximum temperature of between about 50 C and about 350 C within the vapour
chamber 360.
[00130] It should be noted that the temperature in a vapour chamber varies
from
the injection well towards the edges of the vapour chamber, and the
temperature at
28
CA 3046390 2019-06-13
the chamber edges (also referred to as the "steam front") is still relatively
low, such as
about 15 C to about 25 C. The reservoir temperature can also vary from about
10 C
to the highest chamber temperature discussed above.
[00131] A suitable solvent may be selected based on a number of
considerations
and factors as discussed in the literature. The solvent should be injectable
as a
vapour, and can dissolve at least one of the viscous hydrocarbons to be
recovered
from reservoir formation 100 in the steam-solvent recovery process for
increasing
mobility of the hydrocarbons. The solvent may be a viscosity-reducing solvent,
which
reduces the viscosity of the hydrocarbons in reservoir formation 100.
[00132] It is noted that with steam injection with solvent injection can
conveniently facilitate transportation of the solvent as a vapour with steam
to the
steam front. Steam is typically a more efficient heat-transfer medium than a
solvent,
and can increase the reservoir temperature more efficiently and more
economically, or
maintain the vapour chamber at a higher temperature. The heat, or higher
formation
temperature in a large region in the formation, can help to maintain the
solvent in the
vapour phase and assist dispersion of the solvent to the chamber edges ("steam
front"). The heat from steam can also by itself assist reduction of viscosity
of the
hydrocarbons. However, injecting steam requires more heating energy and inject
steam at a too high ratio can reduce the energy efficiency of the process.
[00133] Yet, replacing steam completely with a solvent or injecting too
little
steam, may reduce recovery performance and substantially increase the amount
and
cost of the solvent to be injected.
[00134] It is thus important to balance these considerations and factors,
and
select and control the ratio of the solvent to steam carefully to achieve
optimal overall
process performance and efficiency.
[00135] In a steam-solvent recovery process, both steam and a solvent are
injected into the hydrocarbon reservoir to mobilize viscous hydrocarbons in
the
reservoir to assist recovery of hydrocarbons from the reservoir, the solvent-
to-steam
29
CA 3046390 2019-06-13
ratio (SSR) in the injection stream can be selected to optimize the production
operation and efficiency. In particular, the SSR may be limited to an
intermediate
range to balance competing factors such as solvent usage, steam usage, energy
utilization efficiency, oil recovery rate, oil recovery factor, and the like.
When selecting
the optimal SSR, the steam-to-oil ratio (SOR) and the oil production rate
should both
be considered. When determining the optimal SSR, factors that can affect the
range of
optimal SSR in a particular case may include, but are not limited to, the
enthalpy and
quality of the steam stream to be injected, the solvent to be used, the
temperature of
the solvent before injection (or mixing with the steam prior to injection),
the injection
conditions (e.g., the pressure and temperature of injection at the injection
well),
downhole conditions (e.g., pressure and temperature) in the injection well and
in the
production well, heat loss in the piping and wellbore of the injection well,
various
operation parameters and constraints such as rates of production of various
fluids from
the reservoir including gas production rates.
[00136] In an embodiment, steam is injected into the reservoir to soften
and
mobilize the native bitumen therein, thus forming a fluid containing
hydrocarbons and
water (condensed steam), which can be produced from the reservoir by an in-
situ
recovery process, such as steam-assisted gravity drainage (SAGD), or a cyclic
steam
recovery process such as cyclic steam stimulation (CSS). As will be further
detailed
below, a solvent is also co-injected as a mobilizing agent to enhance mobility
of the
oleic phase in the reservoir, which can result in increased flow rate and thus
hydrocarbon production rate. The injected mobilizing agent may also help to
reduce
the residual oil saturation in the reservoir, and reduce steam usage and
increase
energy efficiency. In some cases, the solvent when injected as a vapour may
also help
to maintain the reservoir pressure at a desired level, such as at the blowdown
or pre-
blowdown stages of the operation. The SSR (such as the molar ratio of injected
solvent-to-steam) may be selected to balance its effects on hydrocarbon
production
performance and energy efficiency of the operation, thus optimizing overall
performance and efficiency of the process. The solvent may be injected after a
period
of steam injection and a steam chamber has been developed to a substantial
size in
the reservoir. The SSR may be varied, increased or decreased overtime.
CA 3046390 2019-06-13
[00137] In an embodiment, a small amount of methane may be allowed to be
injected with the solvent or steam. Alternatively or additionally, after a
period of
injecting steam and solvent, the amount of injected solvent may be reduced and
a
non-condensable gas such as methane may be injected in addition to, or instead
of,
the solvent.
[00138] In embodiments disclosed herein, steam and the solvent are co-
injected
from the same injection well.
[00139] The hydrocarbons in the reservoir of bituminous sands occur in a
complex mixture containing interactions between sand particles, fines (e.g.,
clay), and
water (e.g., interstitial water) which may form complex emulsions during
processing.
The hydrocarbons derived from bituminous sands may contain other contaminant
inorganic, organic or organometallic species which may be dissolved, dispersed
or
bound within suspended solid or liquid material. Accordingly, it remains
challenging to
separate hydrocarbons from the bituminous sands in situ, which may impede
production performance of the in-situ process.
[00140] Conveniently, an embodiment disclosed herein can allow convenient
co-
injection of steam and solvent to achieve a target SSR and temperature without
using
a flow meter to measure the flow rate of input steam stream.
[00141] The solvent as a mobilizing agent may be used in various in situ
thermal
recovery processes, such as SAGD, CSS, steam or solvent flooding, or a solvent
aided process (SAP) where steam is also used. Selected embodiments disclosed
herein may be applicable to an existing hydrocarbon recovery process, such as
after
the recovery process has completed the start-up stage or has been in the
production
stage for a period of time.
[00142] A co-injected solvent may be any suitable solvent. For example,
suitable
solvents may include volatile hydrocarbon solvents such as butane or propane.
Other
solvents may also be used in different embodiments. However, light alkanes
such as
propane and butane may be selected for commercial field applications as they
may
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CA 3046390 2019-06-13
provide both technical and economic benefits as compared to other, heavier or
more
complicated solvents. Suitable solvents may include diluents or condensates
such as
natural gas condensates or natural gas liquids. The diluent may be selected
from
diluents suitable for use as additives to the produced hydrocarbons to
facilitate
transportation of the produced hydrocarbons by pipeline. Such diluents may be
already available on site at the surface facilities and thus can be
conveniently used as
needed with limited additional operating costs. The condensates may include
condensates produced from the same reservoir formation or a different
reservoir
formation, and thus may also be readily available on site.
[00143] As can be appreciated by those skilled in the art, in at least
some
applications the amounts or ratio of the injected solvent to injected steam
should be
carefully selected and controlled as the ratio can significantly affect the
overall
performance and efficiency of the steam-solvent recovery process.
[00144] The solvent is injected into reservoir formation 100 in a vapour
phase.
Injection of the solvent in a vapour phase allows the solvent vapour to travel
in vapour
chamber 360 and condense at a region away from injection well 120. Allowing
solvent
to travel in vapour chamber 360 before condensing may achieve beneficial
effects. For
example, when vapour of the solvent is delivered to vapour chamber 360 and
then
allowed to condense and disperse in the vapour chamber 360 particularly at or
near
the steam front (edges of vapour chamber 360), oil production performance,
such as
indicated by one or more of oil production rate, cumulative steam to oil ratio
(CSOR),
and overall efficiency, can be improved. Injection of solvent in the gaseous
phase,
rather than a liquid phase, may allow vapour to rise in vapour chamber 360
before
condensing so that condensation occurs away from injection well 120. It is
noted that
injecting solvent vapour into the vapour chamber does not necessarily require
solvent
be fed into the injection well in vapour form. The solvent may be heated
downhole and
vaporized in the injection well in some embodiments.
[00145] The total injection pressure for solvent and steam co-injection
may be the
same or different than the injection pressure during a conventional SAGD
production
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CA 3046390 2019-06-13
process. For example, the injection pressure may be maintained at between 2
MPa
and 3.5 MPa, or up to 4 MPa. In another example, steam may be injected at a
pressure of about 3 MPa initially, while steam and solvent are co-injected at
a
pressure of about 2 MPa to about 3.5 MPa during co-injection.
[00146] The solvent may be heated before or during injection 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. In any event, the
solvent
is mixed and co-injected with steam to heat the solvent to vaporize it and to
maintain
the solvent in vapour 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
vapour 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
vapour phase
as the solvent travels through the vapour chamber 360.
[00147] For example, where the selected solvent is propane, a solvent-
steam
mixture containing about 50 wt% to about 60 wt% propane and about 40 wt% to
about
50 wt% steam may be injected at a suitable temperature, such as about 180 C
to
about 215 C, and a suitable pressure such as about 3 MPa, e.g. 3.2 MPa. The
suitable steam temperature before mixing may be determined, for example,
through
techniques known to persons of skill in the art based on parameters of the
mixture
components and the desired injection temperature. For example, the enthalpy
per unit
mass of the steam-propane mixture with about 50 wt% to about 60 wt% propane
and
about 40 wt% to about 60 wt% steam may be about 8820 to about 6650 kJ/kg.
[00148] Typically, the injection pressure may be initially determined and
a
suitable solvent and suitable injection temperature and ratio of the solvent
to steam
are selected for the target injection pressure.
[00149] The solvent-to-steam ratio (SSR) may also be expressed or
indicated as
molar concentrations or molar ratio, or weight concentrations or ratio, or
volume
concentrations or ratio.
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CA 3046390 2019-06-13
[00150] For example, in selected embodiments, a molar ratio of the
injected
solvent to the injected steam in the injection fluid, also referred to as the
mobilizing
fluid, may be from 0.1 to 3. Alternatively, the injection fluid may include
about 9.3
mol% to about 88 mol% solvent and about 12 mol% to about 91 mol% steam. The
molar ratio may also be smaller than 0.1 or larger than 3, as long as a change
in the
steam injection rate is detectably reflected in the mixture temperature.
[00151] For co-injection of steam and propane, the injection fluid may
include
about 1 wt% to about 99 wt% propane and 99 wt% steam to about 1 wt% steam,
such
as about 20 to about 87 wt% propane and about 13 to about 80 wt% steam, or
about
50 to about 60 wt% propane (corresponding to about 30 to about 40 mol%
propane)
and about 50 to about 60 wt% steam. For co-injection of steam and butane, the
injection fluid may include about 1 wt% to about 99 wt% butane and 99 wt%
steam to
about 1 wt% steam, such as about 25 to about 90 wt% butane and about 10 to
about
75 wt% steam, or about 50 to about 60 wt% butane and about 50 to about 40 wt%
steam.
[00152] In some embodiments, the injection fluid or mobilizing fluid may
also
include less than about 3 wt% methane based on the total weight of the fluid.
In
selected embodiments, the injection fluid may include less than about 1 wt%
methane.
[00153] It is expected that co-injection of the solvent with steam may
result in
increased flow rate and drainage rate of the oil stream, which may lead to
improved oil
production performance, such as increased oil production rate, reduced
cumulative
steam to oil ratio (CSOR), or improved overall hydrocarbon recovery factor.
[00154] In different embodiments, co-injection of steam and the solvent
may be
carried out in a number of different ways or manners as can be understood by
those
skilled in the art. For example, co-injection of the solvent and steam into
the vapour
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 stage, the solvent content in the co-
injected
solvent and steam may be gradually decreased, and the steam content in the co-
34
CA 3046390 2019-06-13
injected solvent and steam may be gradually increased. For example, depending
on
market factors, the cost of solvent may change over the life of a steam-
solvent
recovery process. During a steam-solvent recovery process, it may be of
economic
benefit to gradually decrease/increase the solvent content and gradually
increase/crease the steam content at different periods in the process.
[00155] Solvent injection is expected to result in increased mobility of
at least
some of the viscous or heavy hydrocarbons of reservoir formation 100. For
example,
some solvents such as propane and butane are expected to dissolve in and
dilute
heavy oil thus increasing the mobility of the oil. The effectiveness and
efficiency of the
solvent depends on the solubility and diffusion of the solvent in
hydrocarbons. Slow
diffusion or low solubility of the solvent in the hydrocarbons can limit the
effect of the
solvent on oil drainage rate. Therefore, the operation conditions may be
modified to
increase solvent diffusion and solubility so as to optimize process
performance and
efficiency. The term "mobility" is used herein in a broad sense to refer to
the ability of
a substance to move about, and is not limited to the flow rate or permeability
of the
substance in the reservoir. For example, the mobility of hydrocarbons may be
increased when they become more mobile, or when hydrocarbons attached to sands
become easier to detach from the sands, or when immobile hydrocarbons become
mobile, even if the viscosity or flow rate of the hydrocarbons has not
changed. The
mobility of hydrocarbons may also be increased by decreasing the viscosity of
the
hydrocarbons, or when the effective permeability, such as through bituminous
sands,
is increased. Additionally or alternatively, increasing hydrocarbon mobility
may be
achieved by heat transfer from solvent to hydrocarbons.
[00156] Additionally or alternatively, solvent may otherwise accelerate
production. For example, a non-condensable gas, such as methane, may propel a
solvent, such as propane, downwards thereby enhancing lateral growth of the
vapour
chamber. For example, such propulsion may be part of a blowdown phase.
[00157] Conveniently, a steam-solvent recovery process where solvent is co-
injected with steam requires less steam as compared to the SAGD production
phase.
CA 3046390 2019-06-13
Injection of less steam may reduce water and water treatment costs required
for
production. Injection of less steam may also reduce the need or costs for
steam
generation for an oil production project. Steam may be produced at a steam
generation plant using boilers. Boilers may heat water into steam via
combustion of
hydrocarbons such as natural gas. A reduction in steam generation requirement
may
also reduce combustion of hydrocarbons, with reduced emission of greenhouse
gases
such as, for example, carbon dioxide.
[00158] Once the oil production process is completed, the operation may
enter
an ending or winding down phase, with a process known as the "blowdown"
process.
The "blowdown" phase or stage may be performed in a similar manner as in a
conventional SAGD process. During the blowdown stage, a non-condensable gas
may
be injected into the reservoir to replace steam or the solvent. For example,
the non-
condensable gas may be methane. In addition, methane may enhance hydrocarbon
production, for example by about 10% within 1 year, by pushing the already
injected
solvent through the chamber.
[00159] Alternatively, in an embodiment a solvent may be continuously
utilized
through a blowdown phase, in which case it is possible to eliminate or reduce
injection
of methane during blowdown. In particular, it is not necessary to implement a
conventional blowdown phase with injected methane gas, when a significant
portion of
the injected solvent can be readily recycled and reused. In some embodiments,
during
or at the end of the blowdown phase, methane or another non-condensable gas
(NCG) may be used to enhance solvent recovery, where the injected methane or
other
non-condensable gas may increase solvent condensation and thus improve solvent
recovery. For example, injected methane or other NCG may mobilize gaseous
solvent
in the chamber to facilitate removal of the solvent.
[00160] During the blowdown phase, oil recovery or production may continue
with
production operations being maintained. When methane is used for blowdown, oil
production performance will decline over time as the growth of the vapour
front in
vapour chamber 360 slows under methane gas injection.
36
CA 3046390 2019-06-13
[00161] At the end of the production operation, the injection wells may be
shut in
but solvent (and some oil) recovery may be continued, followed by methane
injection
to enhance solvent recovery. The formation fluid may be produced until further
recovery of fluids from the reservoir is no longer economical, e.g. when the
recovered
oil no longer justifies the cost for continued production, including the cost
for solvent
recycling and re-injection.
[00162] In some embodiments, before, during or after the blowdown phase,
production of fluids from the reservoir through production well 130 may
continue.
[00163] The solvent for injection may be selected based on a number of
criteria.
As discussed above, the solvent should be injectable as a vapour, and can
dissolve at
least one of the hydrocarbons to be recovered from reservoir formation 100 in
the
steam-solvent recovery process for increasing mobility of the hydrocarbons.
[00164] Conveniently, increased hydrocarbon mobility can enhance drainage
of
the reservoir fluid toward and into production well 130. In a given
application, the
solvent may be selected based on its volatility and solubility in the
reservoir fluid. For
example, in the case of a reservoir with a thinner pay zone (e.g., the pay
zone
thickness is less than about 8 m), or a reservoir having a top gas zone or
water zone,
the solvent may be injected in a liquid phase in the steam-solvent recovery
process.
[00165] Suitable solvents may include C3 to C5 hydrocarbons such as,
propane,
butane, or pentane. Additionally or alternatively, a C6 hydrocarbon such as
hexane
could be employed. A combination of solvents including C3-C6 hydrocarbons and
one
or more heavier hydrocarbons may also be suitable in some embodiments.
Solvents
that are more volatile, such as those that are gaseous at standard temperature
and
pressure (STP), or significantly more volatile than steam at reservoir
conditions, such
as propane or butane, or even methane, may be beneficial in some embodiments.
In
some embodiments, a condensate or diluent may be beneficial.
[00166] For selecting a suitable solvent, the properties and
characteristics of
various candidate solvents may be considered and compared. For a given
selected
37
CA 3046390 2019-06-13
solvent, the corresponding operating parameters during co-injection of the
solvent with
steam should also be selected or determined in view the properties and
characteristics
of the selected solvent.
[00167] Different solvents or solvent mixtures may be suitable candidates.
For
example, the solvent may be propane, butane, or pentane. A mixture of propane
and
butane may also be used in an appropriate application. It is also possible
that a
selected solvent mixture may include heavier hydrocarbons in proportions that
are, for
example, low enough that the mixture still satisfies the above described
criteria for
selecting solvents.
[00168] In some embodiments, the vapour pressure profile of the solvent
may be
selected such that the partial pressure of the solvent in a central (core)
region of the
vapour chamber is within about 0.25% to about 20% of the total gas pressure,
or the
vapour pressure of water/steam.
[00169] It may be desirable if the solvent and steam can vaporize and
condense
under similar temperature and pressure conditions, which will conveniently
allow
vapour of the solvent to initially rise up with the injected steam to
penetrate the rock
formation in the vapour chamber, and then condense with the steam to form a
part of
the mobilized reservoir fluid.
[00170] For example, in some embodiments, the solvent may have a boiling
point that resembles the boiling point of water under the steam injection
conditions
such that it is sufficiently volatile to rise up with the injected steam in
vapour form when
penetrating the steam chamber and then condense at the edge of the steam
chamber.
The boiling temperature of the solvent may be near the boiling temperature of
water at
the same pressure.
[00171] Conveniently, when the solvent has vaporization characteristics
that
resemble, closely match, those of water under the reservoir conditions, the
solvent can
condense when it reaches the steam front or the edge of the steam chamber,
which is
typically at a lower temperature such as at about 12 C to about 150 C. The
38
CA 3046390 2019-06-13
condensed solvent may be soluble in or miscible with either the hydrocarbons
in the
reservoir fluid or the condensed water, so as to increase the drainage rate of
the
hydrocarbons in the fluid through the reservoir formation.
[00172] The condensed solvent is soluble in oil, and thus can dilute the
oil
stream, thereby increasing the mobility of oil in the fluid mixture during
drainage. In
some embodiments, the condensed solvent is also soluble in or miscible with
the
condensed water, which may lead to increased water flow rate by promoting
formation
of oil-in-water emulsions.
[00173] Without being limited to any particular theory, the dispersion of
the
solvent and the steam may facilitate the formation of an oil-in-water emulsion
under
suitable reservoir conditions and also increase the fraction of oil carried by
the fluid
mixture. As a result, more oil may be produced for the same amount of, or
less, steam,
which is desirable.
[00174] A possible mechanism for improving mobility of oil is that the
solvent
can act as a diluent due to its solubility in oil and optionally water, thus
reducing the
viscosity of the resulting fluid mixture. The solvent may interact at the oil
surface to
reduce capillary and viscosity forces.
[00175] A vapour mixture of steam and the solvent may be delivered into
vapour
chamber 360 using any suitable delivery mechanism or route. For example,
injection
well 120 may be conveniently used to deliver the vapour mixture. A mobilizing
fluid or
agent may be injected in the form of a mixture of steam and solvent (e.g.,
mixed ex-
situ).
[00176] Conveniently, a process as disclosed herein may reduce overall
production costs and operation delay due to the time required to replace flow
meters.
[00177] In some embodiments, the solvent may be heated at the surface
before
injection. Additionally or alternatively, the solvent may be heated by co-
injection with
steam. For example, in an embodiment, the injection fluid or mixture may
include both
steam and the solvent at a molar ratio or molar concentrations discussed
herein. The
39
CA 3046390 2019-06-13
steam may be present in a sufficient amount and temperature to heat the
injection
mixture. Additionally or alternatively, the solvent may be heated downhole,
such as by
way of a downhole heater. In additional embodiments, the relative amount of
the
solvent in the injection fluid/mixture may also be higher or lower than the
ranges
previously mentioned.
[00178] As discussed above, the solvent may be pre-heated at surface and
delivered relatively hot into the injection well in some embodiments. In other
embodiments, the solvent may be fed into the injection well without pre-
heating at the
surface.
[00179] In some embodiments, the solvent condensed in the reservoir may be
recovered in the oleic phase, such as being produced with other produced
fluids from
the reservoir. Solvent vapour may also be recovered with a reservoir fluid in
the
gaseous phase. For example, a substantial portion of the recovered solvent may
be
recovered as a vapour from the recovered casing gas.
[00180] In some embodiments, additional or "make-up" solvent may be added
to
the injected fluid. The "make up" solvent may be the same as the recovered
solvent,
but may have a different composition as compared to the composition of the
recovered
solvent.
[00181] In some embodiments, an additive or chemical such as toluene may
be
injected during the production stage or post-production stage. Injection of
toluene may
help to reduce asphaltene precipitation. About 5 wt% toluene may be co-
injected with
steam or a solvent.
[00182] The recovered fluids from the reservoir may be separated at the
surface,
and the separated solvent may be used for re-ejection or other recycling
purposes.
[00183] In some embodiments, it may not be necessary to recycle the
injected
solvent.
CA 3046390 2019-06-13
[00184] In some embodiments, non-condensable gases (NCGs) may be
generated in the reservoir such as due to heating. Additionally or
alternatively, an NCG
may be injected as an additive in some embodiments. Conveniently, the presence
of
NCGs in the formation can enhance lateral dispersion of the solvent vapour to
spread
the solvent laterally into the reservoir formation. Increased lateral
dispersion of the
solvent is expected to assist lateral growth of the vapour chamber, and hence
enhance
oil production.
[00185] While in some of the above discussed embodiments a pair of wells
is
employed for injection and production respectively, it can be appreciated that
an
embodiment of the present disclosure may include a single well or unpaired
wells. The
single well, or an unpaired well, may be used alternately for injection or
production.
The single well may have a substantially horizontal or vertical section in
fluid
communication with the reservoir. The single well may be a well that is
configured and
completed for use in a cyclic steam stimulation (CSS) recovery process. With
the use
of a single well for injection and production, a temperature in the reservoir
may be
about 234 C to about 328 C and a pressure in the reservoir may be from about
0.5
MPa or from about 3.0 MPa to about 12.5 MPa.
[00186] To deliver a selected solvent to the production site, a modular
natural
gas liquid (NGL) injection system may be used. Such a modular system may be
designed to be relocatable to other well pads.
[00187] At the surface, the solvent may be delivered to the solvent tank
412 by a
pipeline (not shown) or by transportation trucks. When a solvent pipeline is
used, an
on-site solvent storage tank (such as solvent tank 412) may be omitted. If
trucks are
used to deliver the solvent, the trucks may offload the solvent to one or more
immobile
solvent storage bullets. When propane is used as the solvent, the storage
bullets may
be bullets suitable for storing NGL.
[00188] In some embodiments, the solvent trucks may serve as the solvent
source and the solvent may be supplied directly from a solvent track to inject
well 120
through pipe 414. In such a case, the solvent injection may not be continuous
over
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CA 3046390 2019-06-13
time, and the solvent may be batches. Such an arrangement may allow quick
offloading of the solvent from the truck.
[00189] Suitable solvent bullets may be installed as immobile bullets for
continuous injection of the solvent. In this case, the solvent may be
initially transferred
from transportation trucks to the bullets. For a medium scale surface
injection facility,
each solvent bullet may have a storage capacity of 50 metric tonnes. The
bullet may
also be specifically manufactured and configured for use with a selected
solvent such
as propane or NGL.
[00190] Pump 420 may be a standard fluid pump, or may be custom-designed
and specifically made and configured to manage propane injection at a selected
flow
rate range, such as from about 40 t/d to about 80 t/d. In some cases, the
solvent flow
rate may be controlled by the pumping speed/rate.
[00191] In practice, when the solvent is supplied using trucks, the total
amount of
the delivered solvent may be determined by measuring the weight difference of
each
truck before and after unloading the solvent. With trucks with 25-ton storage
capacity,
two or more trucks a day may be sufficient to supply the solvent at an
injection rate of
50 t/d.
[001921 _ The solvent, such as propane, may be mixed with steam upstream of
a
wellhead and the combined stream of steam and solvent may be injected into the
reservoir through an injection well. An existing NGL injection module may be
modified
to allow the steam-solvent injection point to be in close proximity to the
wellhead.
[00193] In an embodiment, a stand-alone skid may be provided. A solvent
injection pump driver may be electrically driven with the electrical power
supplied. In
various embodiments, the injection of a suitable solvent may comprise an
injection
pattern. For example, the injection pattern may comprise simultaneous
injection with
the steam or staged (e.g., sequential) injection at selected time intervals
and at
selected locations within the SAGD operation (e.g., across multiple well pairs
in a
SAGD well pad). The injection may be performed in various regions of the well
pad or
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CA 3046390 2019-06-13
at multiple well pads to create a target injection pattern to achieve target
results at a
particular location of the pad or pads. In various embodiments, the injection
may be
continuous or periodic. The injection may be performed through an injection
well at
various intervals along a length of the well.
[00194] The solvent should be suitable for practical transportation and
handling
at surface facility conditions. For example, in various embodiments, the
solvent may be
selected such that it is possible to transport and store the solvent as a
liquid prior to
providing the solvent to an injection well or reservoir.
[00195] In some embodiments, the solvent may be a liquid or in solution
prior to
being injected into the injection well. Solvents that are in a liquid phase or
in a solution
at surface conditions may be easier to handle. The solvent may be injected as
a liquid
(pre-heated or at ambient temperature) or as a vapour at the wellhead or
downhole, or
the solvent may be injected as a liquid and vaporized at the wellhead, in the
wellbore,
or downhole. The solvent may at least partially vaporize at the temperature
and
pressure of the injection steam in the injection well such that the solvent is
at least
partially vaporized prior to contact with the reservoir of bituminous sands.
[00196] The solvent should also be suitable for use under the desired
operating
conditions, which include certain temperatures, pressures and chemical
environments.
For example, in various embodiments, the solvent may be selected such that it
is
chemically stable under the reservoir conditions and the steam injection
conditions and
therefore can remain effective after being injected into the steam chamber.
[00197] The solvent may react with a material in the reservoir to improve
mobility
of oil. The reactions may involve water, bitumen, or sand/clays in the
reservoir. Some
materials in the sand or clay may act as a catalyst for the reaction. In some
embodiments, a catalyst for a desired reaction involving the solvent may be co-
injected with the solvent, or as part of an injected mobilizing fluid or
agent.
[00198] While some of the example embodiments discussed herein refer to
SAGD well configuration and operations, it can be appreciated that a solvent
may be
43
CA 3046390 2019-06-13
similarly used in another steam-assisted recovery process such as CSS. In a
CSS
operation, a single well may be used to alternately inject steam into the
reservoir and
produce the fluid from the reservoir. The single well may have a substantially
horizontal or vertical section in fluid communication with the reservoir. The
single well
may be used in a cyclic steam recovery process. With the use of the single
well for
injection and production, a temperature in the reservoir may be about 234 C
to about
328 C and a pressure in the reservoir may be from about 0.5 MPa or from about
3.0
MPa to about 12.5 MPa.
[00199] Other possible modifications and variations to the examples
discussed
above are also possible.
[00200] In some embodiments, such as when oil is recovered by a SAGD
process or SAP process, the solvent may have vaporization characteristics that
resemble vaporization characteristics of water under reservoir conditions
during
SAGD, such as at reservoir temperature and pressure, and at steam injection
conditions, such as at steam injection temperature and pressure.
[00201] Other factors that may affect selection of the solvent may include
the
type of well configuration (e.g., well pair or single well), the stage during
which the
solvent is injected (e.g., during or following start-up), the type of
reservoir (e.g.,
reservoir depth, thickness, pressure containment characteristics, or extent of
water
saturation), or the like.
[00202] Generally, a number of factors may be considered when selecting a
suitable solvent for use in various embodiments.
[00203] One factor is whether the solvent can increase the mobility of oil
in the
region. The mobility of oil may be increased when it is diluted, or when its
viscosity is
decreased, or when its effective permeability through the bituminous sands is
increased.
[00204] Thus, for the solvent to effectively function in the reservoir
fluid, its
solubility should be considered. The solvent should be sufficiently soluble in
oil, or at
44
CA 3046390 2019-06-13
least some hydrocarbons in the reservoir. For example, a solvent may be more
effective if it is more soluble in oil than in water, so that the condensed
solvent will be
mainly or mostly dissolved in the oil phase.
[00205] Another possible contributing factor is whether the solvent can
reduce
the viscosity of oil in the reservoir.
[00206] As can be appreciated, a common consideration for selecting the
suitable solvent is cost versus benefits.
[00207] A further factor for selecting a mobilizing agent is whether the
mobilizing
agent can serve as a wetting agent to increase the flow rate of oil or the
fluid mixture.
An additional factor is whether the mobilizing agent can act as an emulsifier
for
forming an oil-in-water emulsion. A further additional factor is whether the
mobilizing
agent can bring more hydrocarbons into the fluid mixture, thus increasing the
fraction
of oil carried by the fluid.
[00208] The ratio of injected solvent to steam may be provided in a number
of
ways. For example, a co-injection fluid comprising steam and a solvent may be
characterised by the weight percentages of the solvent and steam in the fluid.
This
metric may be convenient to use as the weight percentages or weight ratios do
no vary
when the pressure and temperature changes.
[00209] Alternatively, the relative amounts of the solvent and steam may
be
stated using the respective volume percentages of the components as measured
at
the standard temperature and pressure (STP), which is at 0 C and 1 atm. This
metric
is less convenient as the volume of each component in the fluid may change
with the
external or total pressure and temperature. This metric also can be misleading
when
the compared materials are in different phases at the STP. For example, this
metric
may not provide a meaningful range when the solvent is in the gas phase at the
STP,
as comparing the gas volume of the solvent to the liquid volume of water at
STP is not
very helpful.
CA 3046390 2019-06-13
[00210] A more intrinsic metric is likely the molar ratio or molar
concentration
(mol%) of the injected solvent to steam.
[00211] In various embodiments, steam and the solvent may be injected
through
multiple injection wells. For example, steam may be injected through a
horizontal well
as described above, but the solvent may be injected through a vertical well or
another
horizontal well.
[00212] In some embodiments, the SSR may be increased over time during
injection. When methane is also injected, the molar ratio of injected methane
to
injected steam may also increase over time.
[00213] As mentioned earlier, a mixture of solvents may be injected. In an
embodiment, a first solvent is initially injected into the reservoir for a
first period of
time, and then a second solvent is injected into the reservoir for a second
period of
time after the first period. The second solvent may have a smaller molecular
mass
than the first solvent. For example, butane may be the first solvent and
propane or
methane may be the second solvent. The solvent may include a mixture of
natural
gas liquids.
[00214] During injection of steam and solvent, a reservoir pressure or the
injection pressure may be reduced or decreased over time. The reservoir
pressure
may be reduced to increase the solubility of the solvent in oil.
[00215] A temperature in a production zone in the reservoir may be
controlled to
limit the temperature in the production zone to be below the bubble point
temperature
of the solvent in the produced fluid at a reservoir pressure. This may prevent
re-boiling
or refluxing of the solvent in the reservoir.
[00216] During injection, the composition of the injected fluid mixture
may be
varied over time, both in terms of the solvent or other components and in
terms of their
concentrations in the mixture.
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[00217] In an embodiment, a method of recovering hydrocarbons from a
subterranean reservoir of bituminous sands includes injecting a mobilizing
fluid into the
reservoir for mobilizing viscous hydrocarbons in the reservoir and forming a
reservoir
fluid comprising mobilized hydrocarbons and condensed mobilizing fluid, and
producing the reservoir fluid from the reservoir. The mobilizing fluid
comprises about
40 wt% to about 70 wt% steam and about 30 wt% to about 60 wt% solvent. The
solvent reduces viscosity of the viscous hydrocarbons and is more soluble in
oil than in
water, and has a partial pressure in the reservoir allowing the solvent to be
transported
as vapour with steam to a steam front. The mobilizing fluid may also include
less than
about 3 wt% methane, such as less than about 1 wt% methane. The mobilizing
fluid
may comprise about 50 wt% to about 60 wt% of the solvent. The solvent may
comprise propane.
[00218] In another embodiment, a mobilizing fluid is used in a solvent-
aided
process to produce hydrocarbons from a subterranean reservoir of bituminous
sands.
The mobilizing fluid comprises about 40 wt% to about 70 wt% steam; about 30
wt% to
about 60 wt% solvent; and less than about 3 wt% methane. The solvent reduces
viscosity of viscous hydrocarbons in the reservoir and is more soluble in oil
than in
water, and has a partial pressure in the reservoir allowing the solvent to be
transported
as vapour with steam to a steam front. The solvent may comprise propane or
butane.
The mobilizing fluid may comprise about 50 wt% to about 60 wt% propane or
butane.
The mobilizing fluid may comprise less than about 1 wt% methane.
[00219] In some embodiments, the injection fluid may include a recycled
fluid,
such as steam or a solvent which is obtained from a reservoir fluid produced
from the
reservoir. In such cases, water and an injected solvent may be separated from
oil and
other components in the recovered reservoir fluid, and may be further treated
before
re-injection into the same reservoir or another reservoir. Further treatment
may include
purification and heating of the separated water or solvent. Typically, the
recovered
reservoir fluid may include some methane. Re-injection of produced methane
into the
reservoir may have some adverse effects. For example, as methane is typically
not
condensable at reservoir conditions, the methane gas in the vapour chamber may
47
CA 3046390 2019-06-13
reduce heat transfer efficiency, hinder dispersion of steam and solvent vapour
to the
vapour chamber front, and reduce solubility of the solvent in oil at the
chamber front.
However, it is expected that re-injection of a limited amount of methane would
not
significantly reduce production performance or efficiency in some embodiments.
For
example, it may require additional equipment and operation costs to completely
remove methane from a recycled fluid before re-injection into the reservoir.
Allowing
less than about 1 wt% of methane, or even less than about 3wt% of methane, in
the
re-injected fluid may provide improved overall operational or economic
efficiency.
[00220] In some embodiments, it may not be necessary to continuously
measure
the solvent flow rate or the temperatures in the supply lines. Instead, a
correlation
between the steam flow rate (or solvent flow rate) and the mixture temperature
may be
obtained based on prior measurements at the same conditions, or results
extrapolated
from measurements at different conditions such as at lower flow rates. For
example,
reference flow rates (base-line flow rates) at different mixture temperatures
may be
obtained based on previous measurements where both the steam injection rate
and
the solvent injection rate were directly measured or otherwise determined. In
a
subsequent process, as long as the conditions of the supplied steam and
solvent
remain the same or substantially similar and one of the steam and solvent
injection
rates is known (such as directly measured), the other one of the steam and
solvent
injection rates may be determined or extrapolated based on the reference flow
rates
and the mixture temperature.
[00221] In some embodiments, it may not be necessary to measure the
absolute
temperature in the mixture of steam and solvent, as a relative change in the
mixture
temperature may be used to control the steam or solvent flow to return the
mixture
temperature to the initially set value.
[00222] In some embodiments, the injected solvent may be pre-heated before
mixing with the steam. The solvent may be pre-heated using any suitable
heating or
energy source. When the solvent is pre-heated or the solvent temperature is
increased, the steam injection rate required to obtain the same target
temperature in
48
CA 3046390 2019-06-13
the injection mixture may be reduced, and consequently the target SSR may
increase
with pre-heated solvent. The control process should take into account of the
fact that
the correlations among the desired steam injection rate, the target SSR, and
the target
mixture temperature are dependent on the solvent injection temperature.
[00223] In some embodiments, the target temperature in the injection
mixture
may be selected based on the required thermal energy requirement at a given
solvent
temperature, without expressly determining the target SSR or any weight or
volume
percentages of the solvent or steam in the mixture.
[00224] Another factor to be considered in the control process is the
steam
quality. At a lower steam quality, more steam may be required to provide the
same
required thermal energy. That is, the correlation between the steam injection
rate and
the temperature in the injection mixture is dependent on the steam quality.
Thus, the
steam injection rate may be adjusted based on a change in the steam quality,
in order
to provide the same thermal energy to the injection mixture, and maintain the
same
target temperature in the injection mixture.
[00225] In some embodiments, an additional additive may be included in the
inject mixture (injection stream), in which case, a lower or higher steam
injection rate
may be required depending on the temperature of the additive before mixing,
relative
to the temperature of the solvent. For example, if the additive is pre-heated
and has a
temperature higher than the target mixture temperature, then less steam may be
required. If the additive has a temperature below the target mixture, more
steam may
be required. As can be appreciated, the addition of an additive also changes
the
correlation between the mixture temperature and the steam injection rate.
[00226] In some embodiments, an additional additive may be included in the
injection mixture for various reasons or considerations, including to reduce
operation
costs or to improve operation performance. For example, when the cost of
generating
steam becomes relatively high as compared to including another material as a
thermal
energy source in the mixture, the other material may be added to the injection
mixture
to reduce the required amount of steam to provide the required thermal energy.
The
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CA 3046390 2019-06-13
components in the injection mixture may be selected and adjusted to meet the
target
mixture temperature based on current economic considerations.
[00227] When the correlation between the mixture temperature and the steam
injection rate (such as a baseline rate or reference rates) is established for
given
injection conditions, e.g., by simulation, calibration, testing, or
combination thereof,
steam injection rate may be controlled based on the detected mixture
temperature,
without determining or calculating the actual SSR (or any weight, volume, or
molar
percentage of steam or solvent) in the mixture.
[00228] As now can be appreciated, the embodiments described above may be
modified for application in different contexts or more generally.
[00229] For instance, an example embodiment may be related to a method of
determining a fluid flow rate in a conduit. The method may include mixing a
first stream
and a second stream to form a third stream, where the first stream flows at a
first flow
rate in a first conduit, and the second stream flows at a second flow rate in
a second
conduit. The mixed stream is flowing in a third conduit. The first and second
streams
have different temperatures. A temperature in the third stream in the third
conduit is
detected, and the first flow rate is determined based on the detected
temperature in
the third stream.
[00230] Another example embodiment may be related to a method of
regulating a
fluid flow rate in a conduit. In this method, a first stream and a second
stream are
mixed to form a third stream. The first stream has a first temperature and the
second
stream has a second temperature different from the first temperature. A third
temperature in the third stream is detected, and the flow rate of the first
stream is
adjusted in response to the detected third temperature to control the third
temperature
in the third stream.
[00231] In some embodiments, instead of estimating the flow rate of steam,
the
solvent flow rate may be similarly estimated based on the mixture temperature
when
the steam flow rate is already known or can be directly measured but a flow
meter is
CA 3046390 2019-06-13
not readily available to measure the solvent flow rate into the mixing
junction.
[00232] In some embodiments, the known or measured flow rate of the
solvent
(or steam) may vary and it is still possible to estimate the flow rate of
steam (or
solvent) based on the mixture temperature, as long as the correlation between
the flow
rates and the mixture temperature is known or not changing.
[00233] In some embodiments, it may be possible to control or regulate one
of
the two flow rates based on the mixture temperature even if the correlation is
not
expressly known or determined, as long as the correlation remains
substantially
unchanged over the control period.
[00234] To further illustrate embodiments of the present disclosure, some
non-
limiting and representative examples are discussed below.
[00235] Examples
[00236] Example I
[00237] Computer simulations were conducted to predict the required flow
rates
in a method of controlling steam and solvent co-injection as described herein.
Representative simulation results are listed in Table I. The simulated solvent
was
propane. The SSR (solvent-to-steam ratio) shown Table I is the weight ratio.
The
injection temperature (Tin) is the temperature of the mixture of steam and
solvent
immediately after mixing and before injection. The enthalpy shown in Table I
was the
calculated enthalpy in the mixture of steam and solvent. The input steam had
an initial
temperature of 240 Co, pressure of 3.2 MPa, and steam quality of about 92%.
The
input solvent (propane) had an initial temperature of 0 C .
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CA 3046390 2019-06-13
TABLE I
Target Target Mixture Steam Propane
Total
Day Propane SSR t Temperature Rate (R) Rate Injection
Enthalpy
Rate (MJ/kg)
wt% (wt) T(C ) (t/d) (t/d)
(t/d)
1 0 0 240 290 0 290 2.64
11 10 9:1 235 160 18 178 2.37
21 20 4:1 233 100 25 125 2.11
31 30 7:3 231 70 29 99 1.84
41 40 3:2 225 50 33 83 1.58
51 50 1:1 218 30 28 58 1.32
61 60 2:3 206 20 28 48 1.05
71 70 3:7 163 15 28 43 0.8
81 80 1:4 109 15 53 68 0.53
91 80 1:4 108 15 50 65 0.53
[00238] Initially, from Day 1 to Day 10, the simulated process is a SAGD
process
with injection of only steam. At Day 11, the simulated process was switched
from the
SAGD process to a steam-solvent recovery. From Day 11 to Day 50, the steam-
solvent recovery is a steam-driven process, and from Day 61 to 91, the process
is
solvent driven.
[00239] As shown, the wt% for solvent propane was increased over time from
0
wt% to 80 wt%, and the steam wt% was corresponding reduced from 100wt% to
20wt% over a period of more than 91 days.
[00240] As can be
seen from Table I, as the steam wt% (and the SSR)
decreased, the enthalpy of the solvent-steam mixture and the injection
temperature
both decreased correspondingly. There was strong correlation among the steam
injection rate, the injection temperature (Tin), and the SSR. For example, Tim
was
about 240 C in the SAGD stage (pure steam injection), and about 108 C when
the
SSR was reduced to 1:4.
[00241] Example II
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CA 3046390 2019-06-13
[00242] In a pilot process of transitioning from a SAGD process to a steam-
solvent recovery, steam and propane were co-injected through an injection well
in the
steam-solvent recovery. The well arrangement used in the pilot was as
illustrated in
FIGS. 1-3. The steam input pipe connected to the injection well was equipped
with a
flow meter, which had a lower reading limit of 70 T/d. In the SAGD process,
the steam
flow rate was above 70 T/d, such as about 290 T/d, so the flow meter was used
to
measure the steam injection rate. After the transition from the SAGD process
to the
steam-solvent recovery, the steam injection rate was eventually reduced to
below 70
T/d in order to achieve the target SSR. At this time, the steam and solvent
injection
facility was configured as illustrated in FIG. 7, and the steam flow rate was
estimated
using known correlation between the steam injection rate and the temperature
in the
mixture, which was detected at the location indicated as "Mixed Temp" in a
circle. The
SSR in the mixture was represented by the weight percentage of propane or
steam.
The flow rate of the input solvent was directly measured using a flow meter
(not
shown) and was maintained at a constant rate.
[00243] In this particular case, it would have taken about 3 months to
shut in the
operation and install a new flow meter that was able to measure flow rates
below 70
t/d, such as in the range of 15 t/d to 70t/d.
[00244] Instead of replacing the flow meter, the flow rate in the steam
injection
pipe was estimated using the expected correlation between the steam injection
rate
and the temperature of the steam-solvent mixture, which was measured using a
temperature sensor as indicated in FIG. 7. The mixture temperature was also
correlated to the SSR, and the target mixture temperature was determined based
on
the target SSR, which was in turn calculated using the steam flow rate and the
solvent
flow rate. Since the target SSR and the solvent flow rate were known (or fixed
at a
constant rate), a correlation between the measured mixture temperature and the
steam flow rate could also be established. Thus, the steam flow rate was
controlled
based on the detected temperature to achieve the target SSR. The effectiveness
of
this control method was verified at higher injection rates.
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CA 3046390 2019-06-13
[00245] To control the steam flow rate, the valve in the steam input pipe
(see
"valve" in FIG. 7) was manually adjusted to adjust the flow rate of steam
until the target
mixture temperature was achieved in the steam-solvent mixture, with the
solvent
injection rate held constant. It is expected that the valve may also be
automatically
controlled based on the detected mixture temperature.
[00246] In one test run, the solvent injection rate was held constant at 60
T/d, the
steam injection rate was adjusted to achieve the target mixture temperature at
111 C ,
in which case the steam flow rate was estimated to be 15 T/d.
[00247] It was observed that the mixture temperature was sensitive and
responsive to steam rate adjustment.
[00248] In another test run, the solvent injection rate was held constant
at 40 T/d,
and the steam injection rate was adjusted to reach a detected mixture
temperature at
190 C . The estimated steam injection rate based on the known correlation
between
the SSR and the target (detected) temperature was 27 T/d. The steam injection
flow
rate at the same valve open position was later measured directly with a steam
flow
meter, and the directly measured steam flow rate was consistent with the
estimated
flow rate based on the correlation between the SSR and the detected
temperature.
[00249] It should be noted that the above results are based on the
particular
tested conditions as specified above. Under different conditions and with
different
solvents, the results may vary.
[00250] The test results confirmed that there was a consistent and unique
correlation between the steam or solvent weight percentage (hence the SSR) in
the
injection mixture and the mixture temperature, and that the mixture
temperature is a
monotonic function of the steam injection rate. Therefore, it can be expected
that the
steam injection rate can be controlled to achieve the desired SSR based on the
detected mixture temperature when the solvent injection rate is known or
constant.
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CA 3046390 2019-06-13
[00251] CONCLUDING REMARKS
[00252] Various changes and modifications not expressly discussed herein
may
be apparent and may be made by those skilled in the art based on the present
disclosure. For example, while a specific example is discussed above with
reference to
a SAGD process, some changes may be made when other recovery processes, such
as CSS, are used.
[00253] It will be understood that any range of values herein is intended
to
specifically include any intermediate value or sub-range within the given
range, and all
such intermediate values and sub-ranges are individually and specifically
disclosed.
[00254] It will also be understood that the word "a" or "an" is intended
to mean
"one or more" or "at least one", and any singular form is intended to include
plurals
herein.
[00255] It will be further understood that the term "comprise", including
any
variation thereof, is intended to be open-ended and means "include, but not
limited to,"
unless otherwise specifically indicated to the contrary.
[00256] When a list of items is given herein with an "or" before the last
item, any
one of the listed items or any suitable combination of two or more of the
listed items
may be selected and used.
[00257] Of course, the above described embodiments are intended to be
illustrative only and in no way limiting. The described embodiments are
susceptible to
many modifications of form, arrangement of parts, details and order of
operation. The
invention, rather, is intended to encompass all such modification within its
scope, as
defined by the claims.
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