Note: Descriptions are shown in the official language in which they were submitted.
HYDROCARBON RECOVERY WITH CONTROLLED INJECTION RATES OF
SOLVENT AND STEAM
FIELD
[0001] The present disclosure relates generally to hydrocarbon recovery,
and
particularly to in situ solvent-aided hydrocarbon recovery.
BACKGROUND
[0002] Hydrocarbon resources such as bituminous sands (also commonly
referred to as oil sands) present significant technical and economic recovery
challenges due to the hydrocarbons in the bituminous sands having high
viscosities
at initial reservoir temperature. Some subterranean deposits of viscous
hydrocarbons
can be extracted in situ by increasing the mobility of the hydrocarbons so
that they
can be moved to, and recovered from, a production well penetrating a formation
of
the hydrocarbons. Reservoirs of such deposits may also be referred to as
reservoirs
of heavy hydrocarbons, heavy oil, bitumen, tar sands, bituminous sands, or oil
sands.
For example, such reservoirs include deposits as may be found in Canada's
Athabasca oil sands.
[0003] The in situ processes for recovering oil from heavy or viscous
hydrocarbon
reservoirs typically involve the use of one or multiple wells drilled into the
reservoir,
and are assisted or aided by injecting a heated fluid such as steam or solvent
into the
reservoir formation from an injection well.
[0004] For example, a known in situ process for recovering viscous
hydrocarbons
is the steam-assisted gravity drainage (SAGD) process. A typical
(conventional)
SAGD process utilizes one or more pairs of vertically spaced horizontal wells.
For
example, various embodiments of the SAGD process are described in CA 1,304,287
and related US 4,344,485.
[0005] In a SAGD process, steam is injected through an upper, horizontal,
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CA 3052491 2019-08-19
injection well into a viscous hydrocarbon reservoir while hydrocarbons are
produced
from a lower, parallel, horizontal, production well vertically spaced
proximate to the
injection well. The injection and production wells are typically located near,
but some
distance above, the bottom of a pay zone in the hydrocarbon deposit. The
injected
steam initially heats and mobilizes the in situ hydrocarbons in the reservoir
around
the injection well. Mobilized hydrocarbons will drain downward due to gravity,
leaving
a volume of the formation at least partially depleted of the hydrocarbons. The
pores in
the depleted volume of the formation, from which mobilized oil has at least
partially
drained, are then filled with fluids containing mainly injected steam, and the
depleted
volume is thus commonly referred to as the "steam chamber". As steam injection
and
gravity drainage continue, the steam chamber will continue to grow, expanding
both
upwardly and laterally from the injection well. As the steam chamber expands
upwardly and laterally from the injection well, more and more viscous
hydrocarbons
in the reservoir are gradually heated and mobilized, especially at the margins
of the
steam chamber where the steam condenses and heats a layer of viscous
hydrocarbons by thermal conduction. The mobilized hydrocarbons (and aqueous
condensate) drain under the effects of gravity towards the bottom of the steam
chamber, where the production well is located. The mobilized hydrocarbons are
collected and produced from the production well. In a SAGD process, additional
injection or production wells, such as a well drilled using Wedge WeIlTM
technology,
may also be provided.
[0006] Alternative processes aided by fluids other than steam have also been
proposed. For example, solvent-aided processes (SAP) and a process known as
the
vapour-extraction (VAPEX) process have been proposed. In SAP, both steam and a
solvent may be used to aid recovery. VAPEX utilizes a solvent vapour, instead
of
steam, to reduce the viscosity of viscous hydrocarbons. In a proposed VAPEX
process, a solvent, such as propane, is injected into the reservoir in the
vapour phase,
to form a vapour-filled chamber within the reservoir. The solvent vapour
dissolves in
the oil around the vapour chamber and the resulting solution drains, driven by
gravity,
to a horizontal production well placed low in the formation. The solvent
vapour, at or
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near its dew point, is injected simultaneously with hot water from a
horizontal well
located at the top of the reservoir. See, Butler et al., "A New Process
(VAPEX) for
Recovering Heavy Oils Using Hot Water and Hydrocarbon Vapour", Journal of
Canadian Petroleum Technology, 1991, vol. 30, issue 1, pages 97-106.
[0007] US 6,662,872 discloses a combined steam and vapour extraction process
(SAVEX), where steam is injected until an upper surface of the steam chamber
has
progressed to 25 to 75 percent of the distance from the bottom of the
injection well to
the top of the reservoir, or until the recovery rate of hydrocarbons is about
25 to 75
percent of the peak predicted recovery rate using SAGD. When the condition is
met,
steam injection is suspended and replaced with solvent vapour injection (the
VAPEX
process). One of the goals in modifying existing SAGD and other steam-assisted
processes is to reduce the steam to oil ratio (SOR) or the cumulative SOR
(CSOR),
as the SOR or CSOR is commonly considered an important metric for assessing
the
performance and efficiency of a steam-assisted recovery process. Replacing
steam
with solvent vapour and hot water as in the VAPEX or SAVEX process is expected
to
reduce CSOR. However, another important measure of the performance of an oil
recovery process is the oil production rate, which indicates how fast oil can
be
produced from the reservoir. The proposed VAPEX or SAVEX processes are
expected to result in significant reduction in peak oil production rate.
[0008] It has also been proposed in CA 2,893,221 to inject both steam and
a
diluting agent to assist hydrocarbon recovery from bituminous sands. For
example, it
has been suggested that a mobilizing composition comprising 75-98 vol%
diluting
agent and 2-25 vol% steam at the standard temperature and pressure (STP) may
be
used in a gravity drainage process for recovering viscous oil from an
underground
reservoir. Bench-scale gravity drainage tests and simulation tests were
performed
using n-heptane and pentane as the diluting agents. The results were assessed
based on the cumulative bitumen recovery, cumulative injected diluting agent,
and
diluting agent left in the reservoir.
[0009] CA 2,956,771 discloses a hybrid recovery process to recover heavy
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hydrocarbons from a subterranean reservoir, which includes steam-dominant and
solvent-dominant processes. In the steam-dominant process, the weight
percentage
of steam in the injection fluid is more than about 70 wt%. In the solvent-
dominant
process, a solvent and steam are co-injected into the vapour chamber, where
the
weight ratio of co-injected solvent vapour to co-injected steam is higher than
3/2. The
solvent may include propane, butane, pentane, hexane, heptane, or octane. When
propane is used as the solvent, the weight percentage of propane in the co-
injection
mixture may be higher than 70 wt%.
[0010] Instead of a well pair, one or more single horizontal well or
vertical wells
may be utilized for injection and production in in situ hydrocarbon recovery
processes
such as, but not limited to, SAGD, SAP, cyclic steam stimulation (CSS), or
fluid
flooding processes. For example, CA 2,844,345 discloses a single vertical or
inclined
well thermal recovery process. CA 2,868,560 discloses a single horizontal well
for
injection and production in thermal or solvent recovery processes. These
single well
processes may be preceded by start-up acceleration techniques to establish
communication in the formation between openings in the single well that have
been
configured to allow for both injection and production. An assembly for
coupling a
high-pressure steam pipeline, a produced hydrocarbon emulsion pipeline, and a
produced gas pipeline to a single well may be employed for facilitating
injection and
production.
[0011] It is desirable to provide improved solvent-aided processes for
commercial
applications.
SUMMARY
[0012] It has been recognized that to optimize commercial or pad-wide
applications of solvent-aided processes (SAP), the injected solvent to steam
ratio
should be selected based on a number of factors including not only the
cumulative oil
recovered, the cumulative solvent injected, and the solvent left in the
reservoir, but
also additional factors such as the process energy efficiency and process
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effectiveness. For example, on the one hand, when the injected steam to
solvent ratio
is too high, the energy efficiency may be low. Alternatively, when the
injected steam
to solvent ratio is too low, the process effectiveness such as oil production
may be
affected. Further, for different solvents the optimal ranges of ratios may be
different
due to the different properties of the solvents.
[0013] Thus, in an aspect of the present disclosure, the range of solvent
to steam
ratios in a SAP process is selected based on consideration of a number of
factors as
discussed herein. In particular, the enthalpy of the mixed solvent and steam
in the
injection fluid is taken into account, and a process is provided herein to
adjust the
injection rates at least in part based on enthalpy considerations for
optimizing or
balancing both recovery process performance and efficiency.
[0014] Further, while an optimal range of the solvent to steam ratio may
be
predicted and estimated based on theoretical modeling, calculation, or
simulation, in
practice, the solvent to steam ratio may be adjusted or fine-tuned according
to a
process as described herein.
[0015] In an embodiment of the present disclosure, a method of controlling
injection rates in a process for recovering hydrocarbons from a subterranean
reservoir of bituminous sands comprises: (a) injecting steam and a solvent
into the
reservoir at an injection pressure, the steam being co-injected at a steam
injection
rate and the solvent being co-injected at a solvent injection rate, the
injection rates
being selected to inject the solvent at a selected solvent weight percentage
based on
the total weight of injected steam and injected solvent at a selected value of
the
injection pressure; (b) reducing the steam injection rate; (c) monitoring a
change in
the injection pressure over a period of time after (b); (d) in response to a
decrease of
the injection pressure over the period of time, increasing the solvent
injection rate or
the steam injection rate to increase the injection pressure back to the
selected value.
Specifically, the solvent injection rate is increased if a threshold condition
has not
been met, or, the steam injection rate is increased if the threshold condition
has been
met. The threshold condition may be met if (1) the decrease of the injection
pressure
CA 3052491 2019-08-19
is higher than a first threshold, or (2) an increase in the solvent injection
rate needed
to return the injection pressure to the selected value is higher than a second
threshold, or (3) the decrease of the injection pressure is at least about 3
or about 4
times of a previous decrease in the injection pressure in response to a same
amount
of reduction in the steam injection rate. The first threshold may be about 1%
to about
10% of the selected value of the injection pressure. The second threshold may
be
less than about 50% of the reduction in the steam injection rate in (b). The
solvent
may comprise propane, or butane. The solvent may comprise a plurality of
solvents.
The steam and solvent may be co-injected at a temperature from about 80 C to
about
250 C. The selected value of the injection pressure may be from about 2.5 MPa
to
about 3.5 MPa. The steam and solvent may be injected as a mixture comprising
steam and the solvent. The steam and solvent may be injected through an
injection
well and the hydrocarbons may be produced through a production well. The
injection
well and the production well may have terminal sections that are substantially
horizontal. The injection well and the production well may form a well pair,
and may
be arranged and completed for a steam-assisted gravity drainage (SAGD)
process.
The injection pressure may be determined based on a measured bottom hole
pressure in the injection well.
[0016] In another embodiment, a method of recovering hydrocarbons from a
subterranean reservoir of bituminous sands comprises injecting steam and a
solvent
into the reservoir at a pre-selected injection pressure, the steam being co-
injected at
a steam injection rate and the solvent being co-injected at a solvent
injection rate;
increasing a ratio of the solvent injection rate to the steam injection rate
over time to
above a transition threshold value, wherein when the ratio is increased to
above the
transition threshold value, (i) an increase in the solvent injection rate
required to
compensate for a corresponding decrease in the steam injection rate to
maintain the
pre-selected injection pressure becomes higher than about 50% of the
corresponding
decrease in the steam injection rate, or (ii) a production rate of
hydrocarbons from the
reservoir is reduced by at least about 5% within about a week; in response to
determining that the ratio has been increased to above the transition
threshold value,
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CA 3052491 2019-08-19
decreasing the ratio to below the transition threshold value; and producing
from the
reservoir hydrocarbons mobilized by injected steam and solvent. Changes in the
steam injection rate and the solvent injection rate may be monitored, and the
method
may include determining whether the ratio has been increased to above the
transition
threshold value based on the changes in the steam injection rate and the
solvent
injection rate. The transition threshold value may be selected such that when
the
ratio is higher than the transition threshold value, the increase in the
solvent injection
rate required to compensate for the corresponding decrease in the steam
injection
rate is higher than about 50% of the corresponding decrease in the steam
injection
rate. The solvent may comprise propane and the transition threshold value may
be
less than about 4. The transition threshold value may be about 1 to about 1.5.
The
solvent may comprise butane and the transition threshold value may be less
than
about 2, such as being about 1. The steam and solvent may be co-injected at a
temperature from about 80 C to about 250 C. The method of any one of claims 15
to
22, wherein the pre-selected injection pressure is from about 2.5 MPa to about
3.5
MPa. Steam and the solvent may be injected as a mixture comprising steam and
the
solvent. The steam and solvent may be injected through an injection well and
the
hydrocarbons may be produced through a production well. The injection well and
the
production well may have terminal sections that are substantially horizontal.
[0017] In a further embodiment, a method of recovering hydrocarbons from a
subterranean reservoir of bituminous sands comprises injecting steam and a
solvent
into the reservoir; determining a transition threshold, wherein when a ratio
of injected
solvent to injected steam is increased to above the transition threshold, an
increase
in the injected solvent required to compensate for a corresponding decrease in
the
injected steam becomes higher than about 50% of the corresponding decrease in
the
injected steam; controlling the solvent injection rate and the steam injection
rate so
that the ratio of solvent injection to steam injection is maintained below the
transition
threshold; and producing from the reservoir hydrocarbons mobilized by injected
steam and solvent.
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[0018] 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
description of specific embodiments of the disclosure in conjunction with the
accompanying figures.
BRIEF DESCRIPTION OF THE DRAWINGS
[0019] In the figures, which illustrate, by way of example only,
embodiments of the
present disclosure:
[0020] FIG. 1 is a schematic side view of a hydrocarbon reservoir and a
pair of
wells penetrating the reservoir for recovery of hydrocarbons.
[0021] FIG. 2 is a schematic partial end view of the reservoir and wells
of FIG. 1.
[0022] 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.
[0023] FIG. 4 is a schematic partial section view of the wells and the
vapour
chamber in the reservoir of FIG. 3.
[0024] FIG. 5 is a simulated two-dimensional phase diagram for selected
solvents.
[0025] FIGS. 6A and 6B are data graphs showing representative relationship
between cumulative steam injected and the weight or molar percent of injected
propane respectively.
[0026] FIGS. 7A and 7B are data graphs showing representative relationship
between cumulative oil production and the weight or molar percent of injected
propane respectively.
[0027] FIGS. 8A and 8B are data graphs showing the optimal ranges of the
weight
or molar percent of propane in the injection fluid.
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CA 3052491 2019-08-19
[0028] FIG. 9 is a flowchart for a process of controlling the solvent to
steam ratio,
illustrating an embodiment of the present disclosure.
[0029] FIG. 10 is a line graph showing representative simulation results
of
adjusting injection rates to achieve selected solvent weight percentages at a
constant
injection pressure.
[0030] FIG. 11 is a line graph showing the correlation between the solvent
injection rate and the solvent weight percent in the injection fluid based on
the data
represented in FIG. 10.
[0031] FIG. 12 is a line graph showing the correlation between the steam
injection
rate and the solvent weight percent in the data of FIG. 10.
[0032] FIG. 13 is a line graph showing the correlation between the solvent
injection rate and the enthalpy of the injected fluid.
[0033] FIG. 14 is a line graph showing the correlation between the steam
injection
rate and the enthalpy of the injection fluid.
[0034] FIG. 15 is a line graph showing the relationships among the
injection rates
and oil production rate
[0035] FIG. 16 is a line graph showing the relationship among the butane
requirement and the butane to steam weight ratio.
[0036] FIG. 17 is a line graph showing representative simulation results
of oil
production as a function of injection rates and butane to steam weight ratio.
[0037] FIG. 18 is a line graph showing the representative bottom hole
pressures
(BHP) measured during an example process.
[0038] FIG. 19 is a data graph showing test results of the effects of
adjusting
solvent and steam injection rates on the bottom-hole-pressure.
9
CA 3052491 2019-08-19
DETAILED DESCRIPTION
[0039] Selected embodiments of the present disclosure relate to methods of
hydrocarbon recovery from a reservoir of bituminous sands assisted by
injection of
steam and solvent as a mobilizing agent into the reservoir.
[0040] In overview, it has been recognized by the inventor that in a
solvent-aided
recovery process where both steam and a solvent are injected into a
hydrocarbon
reservoir to mobilize viscous hydrocarbons in the reservoir to assist recovery
of
hydrocarbons from the reservoir, the solvent-to-steam 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.
[0041] It should also be noted that the optimal ranges of SSR may vary
among
different solvents. However, it is expected the ranges of optimal SSR may be
similar
for similar solvents such as light alkanes, including propane and butane,
which are
most volatile at the typical operating conditions of the processes discussed
herein.
[0042] In selected embodiments, a solvent-aided process (SAP), such as a
solvent-driven process (SDP), is performed with injection of both steam and a
solvent,
CA 3052491 2019-08-19
and the solvent and steam injection rates are adjusted based on at least
consideration of enthalpy adjustment and optimization. In some embodiments,
the
SDP may commence following approximately one to two years of operation by a
steam-assisted gravity drainage (SAGD) process.
[0043] In a typical SDP, the injection fluid includes steam and the
selected solvent
with the weight percentage of the solvent (also referred to as the "solvent
weight
percent" or "solvent wt%" herein) being from about 50 wt% to about 95 wt%.
[0044] In an embodiment of the SDP disclosed herein, a value or range of
the
optimal enthalpy in the steam-solvent injection fluid or in the thermodynamic
steam/solvent chamber system is determined, and the steam and solvent
injection
rates are adjusted to obtain an injection fluid with an enthalpy of the
optimized value,
or within an optimal range as determined. In other words, the injection rates
(both
steam injection rates and solvent injection rates) are adjusted or controlled
to meet
the enthalpy (or heat energy) requirement for injecting the steam and solvent
vapor at
a pre-selected injection pressure and a suitable injection temperature. The
injection
rates are also controlled to reduce steam usage within the constraints set
forth in this
disclosure, including the requirement to provide or deliver the required heat
content
by steam to allow efficient chamber development and oil production.
[0045] As can be appreciated by those skilled in the art, the overall
enthalpy (h) of
a fluid mixture of steam and a solvent may be expressed by Equation (1)
h= Ha Ya + Hb Yb (1)
where Ha is the enthalpy of steam, Ya is the mass fraction of steam in the
mixture, Hb
is the enthalpy of the solvent and yb is the mass fraction of the solvent.
[0046] The enthalpy (h) can be considered a measure of the overall energy in
the
injected fluid, which is provided by way of heat by the components in the
mixture,
where each component has it is corresponding enthalpy.
[0047] Equation (1) may be included or incorporated by incorporating this
11
CA 3052491 2019-08-19
equation into a reservoir simulation model and adjusting the mass (or weight)
fractions of the components for steam and solvent co-injection. In particular,
an
injection model may be provided according to the parameters provided in Table
I
below.
[0048] 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 injected or 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) is 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.
[0049] In an embodiment, a small amount of methane may 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.
[0050] Steam and the solvent may be injected from the same injection well
or may
be injected from different injection wells. For example, steam may be injected
in a
horizontal well and solvent may be injected from a vertical well, or a well
placed
12
CA 3052491 2019-08-19
between two adjacent steam chambers.
[0051] In various embodiments, the term "reservoir" refers to a
subterranean or
underground formation comprising recoverable oil (hydrocarbons); and the term
"reservoir of bituminous sands" refers to such a formation wherein at least
some of
the hydrocarbons are viscous or immobile, and are disposed between or attached
to
sands.
[0052] 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, "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 (mPas or cP) measured at
original in situ reservoir temperature. In this specification, the terms
"hydrocarbons"
and "oil" are used interchangeably, which may or may not include heavy oil or
bitumen depending on the context. Depending on the in situ density and
viscosity of
the hydrocarbons, the hydrocarbons in a reservoir may comprise, for example, a
combination of heavy oil, extra heavy oil and bitumen. Heavy crude oil, for
example,
may be defined as 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 mPas. Oil may include, for example, hydrocarbons mobile at
typical reservoir conditions. Extra heavy oil, for example, may be defined as
having a
viscosity of over 10,000 mPas and about 100 API Gravity. The API Gravity of
bitumen
ranges from about 12 to about 6 or about 7 and the viscosity is greater
than about
1,000,000 mPas.
[0053] A person skilled in the art will appreciate that a formation or
reservoir of
bitumen sands at its initial (or original) conditions (e.g., natural
temperature or
viscosity) has not been treated with heat or other mobilizing means. Instead,
it is in its
original or natural condition, prior to the recovery of hydrocarbons.
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CA 3052491 2019-08-19
[0054] The hydrocarbons in the reservoir of bituminous sands occur in a
complex
mixture comprising 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.
[0055] Production performance may be improved when a higher amount of oil
is
produced within a given period of time, or with a given amount of injected
steam
depending on the particular recovery technique used, or within the lifetime of
a given
production well (overall recovery), or in some other manner as can be
understood by
those skilled in the art. For example, production performance may be improved
by
increasing the amount of hydrocarbons recovered within the steam chamber,
increasing drainage rate of the fluid or hydrocarbon from the steam chamber to
the
production well, or both.
[0056] Faster oil flow or drainage rates can lead to more efficient oil
production,
and the increase in the flow or drainage rate of reservoir fluids within the
formation
can be indirectly indicated or measured by the increase in the rate of oil
production.
Techniques for measurement of oil production rates have been well developed
and
are known to those skilled in the art.
[0057] Conveniently, an embodiment disclosed herein can improve production
performance, such as in a manner described below.
[0058] 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
14
CA 3052491 2019-08-19
stage for a period of time.
[0059] Also, with a gravity-dominated process, such as SAGD, a start-up
process
is required to established communication between the injector and producer
wells. A
skilled person in the art would be aware of various techniques for start-up
processes,
such as for example hot fluid wellbore circulation, the use of selected
solvents such
as xylene (as for example described in CA 2,698,898 to Pugh, et al.), the
application
of geomechanical techniques such as dilation (as for example described in CA
2,757,125 to Abbate, etal.), or the use of one or more microorganisms to
increase
overall fluid mobility in a near-wellbore region in an oil sands reservoir (as
for
example in CA 2,831,928 to Bracho Dominguez, et al.). An embodiment of the
present disclosure may be employed in combination with any of these start-up
techniques.
[0060] A suitable solvent may be propane or butane. 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 provide both
technical
and economic benefits as compared to other, heavier or more complicated
solvents.
Suitable solvents for different embodiments may also include natural gas
liquids
(NGLs).
[0061] When selecting a solvent as the mobilizing agent, the following
factors may
be considered. The mobilizing agent should reduce viscosity of at least some
viscous
hydrocarbons in the reservoir and be more soluble in oil than in water. In
selected
embodiments, the mobilizing agent, when condensed in the reservoir, may dilute
oil
such that it may enhance the mobility of oil or the reservoir fluid in the
reservoir and
accelerate the flow rate of the fluid or oil from the steam chamber to the
production
well, as compared to a typical SAGD operation where only steam is used.
[0062] The mobilizing agent also should have a relatively lower boiling
temperature at the operating pressures so that it can be injected as a vapour
and has
a partial pressure in the reservoir allowing it to be transported as vapour
with steam
CA 3052491 2019-08-19
to a steam front, as will be further described below.
[0063] Critically, the amount or ratio of the injected solvent as compared
to
injected steam should be carefully selected as the ratio can significantly
affect the
overall performance and efficiency of the recovery process. It has also been
recognized that the optimal ranges of the volume percentages of injected
solvents
and steam can vary widely depending on the types of solvent used, and in
particular
their thermodynamic properties. Detailed consideration and specific ranges are
discussed herein. Example processes for selecting a suitable ratio of steam
injection
rate to solvent injection rate are also provided herein.
[0064] As can be appreciated, the ratio of steam to solvent in the
injection fluid, or
the ratio of solvent to steam in the injection fluid, may be alternatively
expressed or
used in various forms. For example, the ratios may be expressed in terms of
injection
rates, which may be measured in weight/time, volume/time, or mole/time. The
ratios
may also be indicated by other metrics which have known relationships and
correlations with the injection rates at given conditions. For example, the
ratios may
be alternatively indicated by the weight percentage of the solvent or steam,
on the
basis of the total weight of the solvent and steam in the injection fluid.
[0065] In selected embodiments, the solvent is vapourizable at the
operational
pressure and temperature near the injection well and in the central region of
the
vapour chamber, which has been heated by steam to an elevated temperature, so
that the solvent can enter the reservoir in the vapour phase and can remain in
the
vapour phase until the solvent vapour reaches the vapour chamber front. The
solvent
is also substantially condensable at the edges, margins or boundaries of the
vapour
chamber, where the local temperature is significantly lower than the
temperature in
the central region of the vapour chamber. The condensed solvent is capable of
dissolving hydrocarbons such that the condensed solvent (liquid solvent) can
reduce
the viscosity of the hydrocarbons, or increase the mobility of the
hydrocarbons, which
will assist to improve the hydrocarbon drainage rate and therefore hydrocarbon
production rate. There are a number of underlying mechanisms for increasing
16
CA 3052491 2019-08-19
mobility of hydrocarbons in the reservoir formation as can be understood by
those
skilled in the art. A suitable solvent may be selected to assist drainage of
hydrocarbons based on any of these mechanisms or a combination of such
mechanisms.
[0066] For example, a solvent may be selected based on its ability to
reduce the
viscosity of hydrocarbons, to dissolve in the reservoir fluid, or to reduce
surface and
interfacial tension between hydrocarbons and sands or other solid or liquid
materials
present in the reservoir formation. The solvent may act as a wetting agent or
,
surfactant. When oil attachment to sand or other immobile solid materials in
the
reservoir is reduced, the oil mobility can be increased. The solvent may
function as
an emulsifier for forming hydrocarbon-water emulsions, which may help to
improve oil
mobility with water in the reservoir. Suitable solvents may include volatile
hydrocarbon solvents such as butane or propane, as will be further described
below.
[0067] FIG. 1 schematically illustrates 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 SAGD operations.
[0068] As illustrated, the reservoir formation 100 contains viscous
hydrocarbons
below an overburden 110. Under natural conditions before any treatment,
reservoir
formation 100 is at a relatively low temperature, such as about 12 C, and the
formation pressure may be from about 0.1 to about 4 MPa, depending on the
location
and other characteristics of the reservoir.
[0069] 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 is drilled and completed for producing hydrocarbons from
reservoir formation 100. As depicted in FIG. 1, the well pair is typically
positioned
away from the overburden 110 and near the bottom of the pay zone or geological
stratum in reservoir formation 100, as can be appreciated by those skilled in
the art.
17
CA 3052491 2019-08-19
[0070] As is typical, 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. The distance
between the
injection well and the production well 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.
[0071] 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.
[0072] 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, such as steam and solvent, into injection
well 120.
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.
As depicted for illustration, surface facility 140 may have a supply line
connected to a
steam generation plant for supplying steam for injection, and a supply
connected to a
solvent source for supplying the solvent for injection. Optionally, one or
more
additional supply lines may be provided for supplying other fluids, additives
or the like
for co-injection with steam or the solvent. Each supply line may be connected
to an
appropriate source of supply (not shown), which may include, for example, a
steam
generation plant, a boiler, a fluid mixing plant, a fluid treatment plant, a
truck, a fluid
18
CA 3052491 2019-08-19
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. In particular, surface facility
140 is used to
supply steam and a selected solvent into injection well 120. The solvent may
be
pre-mixed with steam at surface before co-injection. Alternatively, the
solvent and
steam may be separately fed into injection well 120 for injection into
formation 100.
Optionally, surface facility 140 may include a heating facility (not
separately shown)
for pre-heating the solvent before injection.
[0073] As illustrated, surface facility 150 includes a fluid transport
pipeline for
conveying produced fluids to a downstream facility (not shown) for processing
or
treatment. Surface facility 150 includes necessary and optional equipment for
producing fluids from production well 130, as can be understood by those
skilled in
the art.
[0074] 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. 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.
[0075] 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 recovery of
the
selectable solvent to be used in a solvent-aided process as will be disclosed
below.
[0076] For example, in different embodiments, the well completions may
include
19
CA 3052491 2019-08-19
perforations, slotted liner, screens, oufflow 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.
[0077] 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.
[0078] 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, the use of which can be understood by those skilled in the art and will
be
described below. 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.
[0079] 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.
[0080] 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.
[0081] 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.
[0082] In operation, wells 120 and 130 may be operated to produce
hydrocarbons
from reservoir formation 100 according to a process disclosed here.
[0083] 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.
CA 3052491 2019-08-19
[0084] Alternatively, steam and a solvent may be co-injected at the start
of the
production stage after the start-up stage.
[0085] 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.
[0086] In an example process, reservoir formation 100 is 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
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.
[0087] 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.
21
CA 3052491 2019-08-19
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.
[0088] Once fluid communication between injection well 120 and production
well
130 has been achieved, oil production or recovery may commence along with the
formation of a vapour chamber. The oil production rate is typically low
initially and will
increase as the vapour chamber develops; this 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. 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.
[0089] As the injected fluid heats up formation 100, 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 and a fluid
mixture
containing condensed steam and solvent and mobilized bitumen (oil) forms. This
mixture will drain downward due to gravity towards production well 130 and is
collected and then produced (transferred to the surface), such as by gas
lifting or
through pumping as is known to those skilled in the art.. 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" 360. When the vapour chamber 360 is filled with
mainly steam, it is commonly referred to in the art as the "steam chamber."
[0090] 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. This process is
22
CA 3052491 2019-08-19
schematically illustrated in FIG. 4. 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.
[0091] 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.
[0092] 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 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
different solvents, 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 about 0.6 MPa to about 5.1
MPa or up to about 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
23
CA 3052491 2019-08-19
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
(e.g., SAGD, CSS) 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.
[0093]
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.
[0094] 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
24
CA 3052491 2019-08-19
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.
[0095] 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.
[0096] 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.
[0097] After the reservoir fluid is removed from the reservoir 100, the
solvent and
water in the produced fluids 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 some embodiments, the solvent is also
separated from the produced water before further treatment, re-injection into
the
reservoir or disposal.
[0098] 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
CA 3052491 2019-08-19
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.
[0099] 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 an
extended
period of time, such as several months and up to about two years, for vapour
chamber 360 to reach overburden 110, when the pay zone is relatively thick
(greater
than about 15m) as is typically found in some operating oil sands reservoirs.
However,
it will be appreciated that in a thinner pay zone (for example, less than
10m), 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 thicker or
highly
heterogeneous, or the formation has complex overburden geologies such as with
inclined heterolithic stratification (HIS), top water, top gas, or the like.
[00100] During a period in at least the production stage, steam and the
solvent are
injected into the reservoir to assist production and enhance hydrocarbon
recovery.
[00101] 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
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.
[00102] 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.
26
CA 3052491 2019-08-19
[00103] 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%.
[00104] 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.
[00105] 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.
[00106] 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.
[00107] 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
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
C to the highest chamber temperature discussed above.
[00108] A suitable solvent may be selected based on a number of considerations
and factors as discussed herein.
27
CA 3052491 2019-08-19
[00109] The solvent should be injectable as a vapour, and can dissolve at
least
some of the hydrocarbons to be recovered from reservoir formation 100 during
the
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.
[00110] 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.
[00111] 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.
[00112] It is thus important to balance these considerations and factors, and
select
the ratio of the solvent to steam carefully to achieve optimal overall process
performance and efficiency.
[00113] The solvent is injected (enters) 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,
28
CA 3052491 2019-08-19
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.
Alternatively, the solvent may be injected into another well or other wells
for more
efficient delivery of the solvent to desired locations in the reservoir. The
additional
well(s) may include a vertical well, a horizontal well, or a well drilled
according to the
well drilled using Wedge WellTM technology.
[00114] 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
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. Other injection
pressures may also be possible in different embodiments.
[00115] 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. Additionally or
alternatively, solvent may be mixed or co-injected with steam to heat the
solvent to
vaporize it and to maintain the solvent in 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.
29
CA 3052491 2019-08-19
[00116] For example, where the selected solvent is propane, a solvent-steam
mixture containing about 40 wt% to about 50 wt% propane and about 50 wt% to
about 60 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. 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 injectian temperature. For example, the enthalpy per unit mass
of the
steam-propane mixture with about 40 wt% to about 50 wt% propane and about 50
wt%
to about 60 wt% steam may be about 8820 to about 6650 kJ/kg.
[00117] 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.
[00118] It may be more convenient to assess the solvent-to-steam ratio by
their
molar concentrations or the molar ratio.
[00119] 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.
[00120] For propane, the injection fluid may include about 20 to about 87 wt%
propane and about 13 to about 80 wt% steam; such as about 40 to about 50 wt%
propane (corresponding to about 20 to about 30 mol% propane) and about 60 to
about 50 wt% steam, which corresponds to a molar ratio of propane to steam of
about 0.26 to about 0.42. For butane, the injection fluid may include about 25
to about
90 wt% butane and about 10 to about 75 wt% steam; such as about 40 to about 50
wt%
butane and about 50 to about 60 wt% steam, which corresponds to a molar ratio
of
butane to steam of about 0.2 to about 0.3.
[00121] In some embodiments, the injection fluid or mobilizing fluid may also
include less than 3 wt% methane based on the total weight of the fluid. In
selected
CA 3052491 2019-08-19
embodiments, the injection fluid may include less than 1 wt% methane.
[00122] 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.
[00123] 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-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
hybrid
steam-solvent process. During or after the solvent-driven process, it may be
of
economic benefit to gradually decrease the solvent content and gradually
increase
the steam content.
[00124] Solvent injection is expected to result in increased mobility of at
least some
of the viscous hydrocarbons of reservoir formation 100. For example, some
solvents
such as propane and butane are expected to dissolve in and dilute 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
31
CA 3052491 2019-08-19
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.
[00125] 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.
[00126] Conveniently, a solvent-driven process where solvent is co-injected
with
steam requires less steam as compared to the SAGD production phase. 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.
[00127] Injection Control
[00128] In an embodiment of the present disclosure, during operation, the
solvent
and steam injection rates may be controlled in a process as illustrated in
FIG. 9.
[00129] At stage S900, steam and the solvent are co-injected into the
reservoir 100
at a selected initial injection pressure through the injection well 120. The
initial
injection pressure may be selected as described elsewhere herein. The
injection
pressure may be measured at the well head of injection well 120 or downhole in
injection well 120, or calculated or determined based on the input/source
pressure of
32
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the steam and the input/source pressure of the solvent, and the initial
temperatures of
the steam and the solvent before they are mixed.
[00130] The steam and solvent injection rates are separately controlled and
monitored. For example, the steam and solvent injection rates and the
injection
temperatures may be controlled and monitored at surface facilities 140.
[00131] Initially, the steam injection rate and the solvent injection rate are
selected
such that in the injected stream, which includes both injected steam and
injected
solvent, the solvent weight percentage (based on the total weight of injected
steam
and injected solvent) is at a pre-selected value, at the given selected
injection
pressure.
[00132] At stage S910, the steam injection rate is reduced. The steam
injection rate
may be reduced at a selected time based on any number of factors or
considerations,
some of which are discussed herein elsewhere. For example, one reason for
reducing the steam injection rate is to see if the steam injection can be
reduced
without significantly affecting oil production, so as to improve energy
efficiency.
[00133] The amount of reduction in the steam injection rate may be selected
based
on the particular situation. The amount of reduction in the steam injection
rate may be
selected based on the weight percent relative to previous steam injection rate
or
relative to solvent injection rate. For example, if the injection rate for
steam is 30 t/d
an expected reduction could be to evaluate a 20 t/d injection rate and examine
the
corresponding drop in pressure. Additionally, the reduction in steam injection
rate for
each iteration could be between about 10% to about 20%, or about 20% to about
50%. For example, if the injection rate for steam is 30 t/d an expected
reduction could
be by about 20%. The 26 lid steam injection rate will be evaluated for the
pressure
drop and the steam or solvent injection rate could be adjusted accordingly to
mitigate
pressure drop.
[00134] After the steam injection rate has been reduced at S910, the injection
pressure is monitored over a period of time, at stage S920. It may be expected
that
33
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the injection pressure may not respond instantaneously after the reduction of
the
steam injection rate, and the injection pressure may respond and stabilize
after a
period of time, such as about a week or more. See for example, the results
shown in
FIG. 18.
[00135] At S930, if no decrease or significant decrease in the injection
pressure is
observed after a suitable period of time, the steam injection rate may be
reduced
again, such as by the same amount as before at S910. For example, if the
injection
rate for steam is 20 t/d an expected reduction could be to evaluate a 15 t/d
injection
rate and examine the corresponding drop in pressure. In some cases, a drop in
injection pressure (or bottom hole pressure) by about 50 kPa or about 1.5%
within a
week may be considered a significant drop in pressure.
[00136] If a significant decrease of the injection pressure has been observed
over
the period of time as determined at S930, the solvent injection rate or the
steam
injection rate will be increased to bring the injection pressure back to the
initial
selected value.
[00137] Whether to increase the solvent injection rate or the steam injection
rate for
this purpose will depend on if a threshold condition has been met, as
determined at it
is further determined at S940. Possible threshold conditions will be described
in more
details below.
[00138] If the threshold condition has been met at S940, the steam injection
rate is
increased to increase the injection pressure at S950.
[00139] If the threshold condition has not been met, the solvent injection
rate is
increased to increase the injection pressure at S960.
[00140] When the threshold condition has not been met, after the injection
pressure
is brought back to the initial value by increasing the solvent injection rate
at S960, the
process may be repeated to further reduce the steam injection rate, until the
threshold condition is met.
34
CA 3052491 2019-08-19
[00141] Conveniently, this process allows reducing, even minimizing, the steam
injection rate or the weight ratio of steam in the injection fluid, or
correspondingly
increasing the weight ratio of the solvent in the injection fluid, while still
providing
sufficient heat energy to the injected solvent or the injection fluid to
maintain
production performance at the desired level.
[00142] It has been realized that to achieve the performance and efficiency
objectives described herein various suitable threshold conditions may be used
for the
assessment at stage S940.
[00143] In some embodiments, the threshold condition may be that the injection
pressure has decreased by a certain amount or percentage. For example, the
threshold condition may be that the injection pressure has dropped by an
amount that
is higher than a threshold pressure, or by a percentage that is higher than a
threshold
percentage. In a specific example embodiment, the threshold percentage may be
about 1% to about 10% of the initial injection pressure. To illustrate, if the
initial
injection pressure is 3.5 MPa, the threshold pressure for the pressure decease
may
be 0.35 MPa, or 0.035 MPa.
[00144] In at least some situations, it may be expected that a large decrease
of the
injection pressure in response to a reduction in the steam injection rate
indicates that
the reduced steam injection rate is too low and is insufficient to meet the
energy
requirements for efficient oil production. For instance, if a large portion of
the solvent
is in the liquid phase before the solvent reaches the chamber front, which may
occur
if there is insufficient heat energy in the injection fluid, production
performance can be
negatively affected. Thus, the drop in the injection pressure can provide a
good
indicator of the solvent phase state in the injection fluid.
[00145] Another possible threshold condition is based on whether there is an
observed substantial reduction in the hydrocarbon (oil) production rate due to
an
injection rate change. For example, when the solvent injection rate is
reduced, the oil
production rate may decrease if other operating conditions remain unchanged.
One
CA 3052491 2019-08-19
of the reasons for reducing the solvent injection rate may be to manage the
production of the injected solvent in the gas phase through the production
well. To
compensate for possible reduced BHP and oil production rate due to reduction
in the
solvent injection rate, the steam injection rate may be increased. For
example,
assuming the initial solvent injection rate is 40 T/d, the initial steam
injection rate is 10
T/d, and the initial injection pressure (or BHP) is about 3.2 MPa, when the
solvent
injection rate is reduced to 25 T/d, the BHP may be expected to decrease by
about
100 kPa within about one week, and the oil production rate may be expected to
drop
by at least 5%. In this example, if the steam injection rate is increased to
20 T/d with
the solvent injection rate at 25 T/D, the BHP and oil production rate may be
maintained at the previous levels with the solvent injection rate of 40 T/d.
However, if
it is observed that the BHP is still decreasing with the increased steam
injection rate,
a further increase in the steam injection rate to, e.g. 30 T/d, may be helpful
to
maintain the BHP at or near the original level. Further, with increased steam
injection,
the overall production rate of the liquid phase (emulsion) may increase, with
a
corresponding increase of the oil production rate, thus restoring the oil
production
rate to the original level.
[00146] In an example embodiment, a suitable threshold condition for
increasing
the steam injection rate instead of the solvent injection rate is that the
reduction in the
oil production rate is about 5% or higher within a selected time period, such
as about
a week. The threshold condition may also be that there are both a reduction in
the oil
production rate by at least 5% and a significant decrease in the BHP.
[00147]
In different embodiments, the order of the actions shown in FIG. 9 may be
changed. In different embodiments, multiple threshold conditions may be used.
[00148] For example, if after S960, it is determined that the increase in the
solvent
injection rate needed to return the injection pressure to the initial selected
value is
higher than a pre-selected threshold, then the solvent injection rate may be
reduced
and the process goes back to S940 with the determination that a threshold
condition
has been met, and the steam injection rate is correspondingly increased at
S950. In a
36
CA 3052491 2019-08-19
specific example, the pre-selected threshold may be the same amount as the
reduction in the steam inject rate at S910, or may be less than about 50% of
the
reduction in the steam inject rate. For instance, the pre-selected threshold
may be
less than 10%, or less than 20%, or less than 30%, or less than 40% of the
reduced
amount in the steam inject rate.
[00149] Alternatively, the process may proceed from stage S930 directly to
S960 to
see how much increase in the solvent injection rate is required to return the
injection
pressure back to the initial value, and then make a determination at S940, as
indicated by the dash line route in FIG. 9.
[00150] In a further embodiment, after one cycle of the process as illustrated
in FIG.
9, a subsequent cycle of the process is performed. The steam injection rate
may be
reduced by the same amount or percentage in both cycles at S910. In such an
embodiment, another threshold condition may be that the same amount of
reduction
in the steam injection rate leaded to different decreases in the injection
pressure. For
instance, the threshold condition may be that the injection pressure decreased
significantly more in a subsequent cycle than in an earlier cycle, such as
when the
subsequent decrease in pressure is 3 to 4 times more than the earlier decease.
As an
example, the injection pressure may drop from 3.2 MPa to 3.19 MPa within one
week
due to a decrease in the steam injection rate, with a decrease of 10 kPa in
injection
pressure. Following an additional reduction in the steam injection rate by the
same
amount, the injection pressure may drop from 3.19 MPa to 3.15 MPa within one
week,
with a decrease of 40 kPa in injection pressure. In this example, the
subsequent
decrease in pressure is 4 times (or 400%) of the earlier decrease. Such a
sharp
increase in the injection pressure change may be used as a threshold condition
to
stop decreasing the steam injection rate and start adjusting the solvent
injection rate.
[00151] In the process as illustrated in FIG. 9, the steam and solvent may be
co-injected at a temperature from about 80 C to about 250 C, and at the
injection
pressure from about 2.5 MPa to about 3.5 MPa. The steam and the solvent may be
injecting as a mixture of steam and the solvent. The injection pressure may be
37
CA 3052491 2019-08-19
determined based on a measured bottom hole pressure in the injection well 120.
[00152] In another embodiment, the injection rates are controlled as follows.
The
ratio of the solvent injection rate to the steam injection rate is increased
over time to
above a transition threshold value, by adjusting the relative injection rates.
It is then
determined if, when the ratio is increased to above the transition threshold
value, an
increase in the solvent injection rate required to compensate for a
corresponding
decrease in the steam injection rate to maintain the pre-selected injection
pressure,
or to maintain a desired level of hydrocarbon production, or to achieve
another
pre-set condition as will be discussed further below, becomes higher than a
selected
fraction of the corresponding decrease in the steam injection rate. The
selected
fraction may be less than about 10%, about 20%, about 30%, about 40%, or about
50%. In response to determining that the ratio has been increased to above the
transition threshold value, the solvent injection rate is decreased to
decrease the ratio
to below the transition threshold value.
[00153] In this embodiment, changes in the steam injection rate and the
solvent
injection rate may be monitored, and whether the ratio has been increased to
above
the transition threshold value may be determined based on the changes in the
steam
injection rate and the solvent injection rate. The solvent may be propane and
the
transition threshold value may be less than 4, such as being about 3. If the
solvent is
butane, the transition threshold value may be about 2 or less, such as being
about 1.
[00154] In a further embodiment, a transition threshold may be determined,
where
when a ratio of injected solvent to injected steam is increased to above the
transition
threshold, an increase in the injected solvent required to compensate for a
corresponding decrease in the injected steam becomes higher than the
corresponding decrease in the injected steam. The solvent injection rate and
the
steam injection rate may be controlled so that the ratio of solvent injection
to steam
injection is maintained below the transition threshold. Hydrocarbons mobilized
by
injected steam and solvent are produced from the reservoir.
38
CA 3052491 2019-08-19
[00155] Either during the initial selection of the injection rates at S900 or
for
subsequent adjustment of the injection rates, the steam and solvent injection
rates
may be selected or determined in view of the current market costs for the
injected
solvent and the current costs and availability of other input material or
resources such
as the electricity costs and availability of steam generated at a given site,
in addition
to other operational factors disclosed herein. The different factors may be
assessed
with the aid of computer technology. For example, general or specifically
designed
computer software or algorithms may be used to analyze input data to provide
predicted optimal operation parameters. The computer software or algorithm may
utilize artificial intelligence and machine learning techniques to
holistically and
dynamically assess multiple relevant factors and input information, and
continuously
improve the assessment outcomes based on previous or past results. The data
analysis and injection rate adjustment may be fully or partially automated,
depending
on the particular application and requirements.
[00156] Blowdown
[00157] 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 about 1 year, by
pushing
the already injected solvent through the chamber.
[00158] 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
39
CA 3052491 2019-08-19
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.
[00159] 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.
[00160] 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.
[00161] In some embodiments, before, during or after the blowdown phase,
production of fluids from the reservoir through production well 130 may
continue.
[00162] 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
solvent-driven process for increasing mobility of the hydrocarbons.
[00163] 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 solvent-driven process.
[00164] Suitable solvents may include C3 to C5 hydrocarbons such as, propane,
CA 3052491 2019-08-19
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.
[00165] For selecting a suitable solvent, the properties and characteristics
of
various candidate solvents may be considered and compared. For a given
selected
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.
[00166] For example, the phase diagrams of the solvents may be helpful for
such
selection. FIG. 5 shows 2-dimensional (2D) pressure-temperature phase diagrams
of
propane, butane, pentane, hexane, heptane, and octane. As can be seen, at a
given
pressure, the boiling points of different solvents are different, and at a
given
temperature the saturation vapour pressures of different solvents are
different. Thus,
suitable operating temperatures and pressures may be selected for a given
solvent in
view of such phase diagrams. In particular, the injection temperature should
be
sufficiently high and the injection pressure should be sufficiently low to
ensure most
of the solvent will be injected in the vapour phase into the vapour chamber.
In this
context, injection temperature and injection pressure refer to the temperature
and
pressure of the injected fluid in the injection well, respectively. The
temperature and
pressure of the injected fluid in the injection well may be controlled by
adjusting the
temperature and pressure of the fluid to be injected before it enters the
injection well.
The injection temperature, injection pressure, or both, may be selected to
ensure that
the solvent is in the gas phase upon injection from the injection well into
the vapour
chamber.
[00167] Solvents may be selected having regard to reservoir characteristics
such
41
CA 3052491 2019-08-19
as, the size and nature of the pay zone in the reservoir, properties of fluids
involved in
the process, and characteristics of the formation within and around the
reservoir. For
example, a relatively light hydrocarbon solvent such as propane may be
suitable for a
reservoir with a relatively thick pay zone, as a lighter hydrocarbon solvent
in the
vapour phase is typically more mobile within the heated vapour chamber.
[00168] Additionally or alternatively, solvent selection may include
consideration
of the economics of heating a selected particular solvent to a desired
injection
temperature.
[00169] For example, as can be appreciated by those skilled in the art,
lighter
solvents referenced in FIG. 5, such as propane and butane, can be efficiently
injected
in the vapour phase at relatively low temperatures at a given injection
pressure. In
comparison, efficient pure steam injection in a SAGD process typically
requires a
much higher injection temperature, such as about 200 C or higher.
[00170] Heavier solvents typically also require a higher injection
temperature. For
example, pentane may need to be heated to about 190 C for injection in the
vapour
phase at injection pressures up to about 3 MPa. In comparison, a light solvent
such
as propane may be injected at temperatures as low as about 50 to about 70 C
depending on the reservoir pressure.
[00171] 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.
[00172] 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.
42
CA 3052491 2019-08-19
[00173] 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.
[00174] 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.
[00175] 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
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.
[00176] 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.
[00177] 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.
43
CA 3052491 2019-08-19
[00178] 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.
[00179] 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), or separate streams may be injected into the injection well 120 for
mixing in
the injection well 120.
[00180] Conveniently, a process as disclosed herein may reduce overall
production
costs while improving production performance, as compared to conventional SAGD
processes or conventional SAP processes.
[00181] In some embodiments, injection pressure may be controlled using the
same techniques as used in conventional SAGD or SAP. Alternatively, different
or
additional techniques may be used for injection pressure control during
different
stages or periods in the recovery operation.
[00182] 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 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.
[00183] As discussed above, the solvent may be pre-heated at surface and
delivered relatively hot into the injection well in some embodiments. In other
44
CA 3052491 2019-08-19
embodiments, the solvent may be fed into the injection well without pre-
heating at the
surface.
[00184] 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.
[00185] 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.
[00186] 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.
[00187] 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.
[00188] In some embodiments, it may not be necessary to recycle the injected
solvent.
[00189] In some embodiments, a separate vertical well may be introduced into
the
reservoir for injection of a solvent, or steam and solvent.
[00190] 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
CA 3052491 2019-08-19
enhance oil production.
[00191] 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.
[00192] 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.
[00193] At the surface, the solvent may be delivered by a pipeline or by
trucks. If
trucks are used to deliver the solvent, the trucks may offload the solvent,
for example
propane, to immobile NGL storage bullets, from which the solvent may be
injected
into the reservoir with one or more pumps. While the solvent may also be
injected
directly from mobile trucks into the injection well, quick offloading of the
solvent from
trucks may result in batch injection. Immobile bullets may be used if
continuous
injection of the solvent is desirable and the solvent is initially provided by
trucks. For a
medium scale facility, immobile 50-tonne solvent bullets may be used, which
may be
manufactured and configured specifically for propane storage. Additionally,
injection
pumps may be manufactured following a standard pump manufacture process, or
may be custom-designed and made to manage propane injection from about 40 t/d
to
about 80 t/d. In practice, the amount of solvent delivered may be determined
by
measuring the weight of each truck before and after unloading to monitor the
weight
change. For propane injection at a rate of about 50 t/d, two or more trucks
may be
sufficient.
46
CA 3052491 2019-08-19
[00194] 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.
[00195] 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 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.
[00196] In various other embodiments, the steam may be injected from one
injection well and the solvent may be injected from another injection location
(e.g.,
through a solvent delivery conduit). For example, in various embodiments, the
injection may involve top loading of the solvent from another injection
location. In
various embodiments, an existing steam injector may be converted or adapted
for
injecting a solvent, or a new injector may be provided to inject the solvent.
For
example, the solvent may be injected from a nearby well drilled using Wedge
WellTM
technology or through a new injection well located at the top of the reservoir
formation (near overburden 110). The solvent may also be injected through a
gas cap
or overburden 110. Another possibility is to inject the mobilizing agent
through a
vertical well located in the vicinity of the vapour chamber. In various
embodiments,
the mobilizing agent may be injected at various stages of a thermal in situ
recovery
process such as SAGD. In various embodiments, the injection of a particular
solvent
(e.g., having a particular stability, vaporization property, etc.) may be
tailored to the
47
CA 3052491 2019-08-19
particular conditions of the reservoir or a reservoir portion into which the
solvent is to
be injected.
[00197] 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.
[00198] 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.
[00199] 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.
[00200] 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.
[00201] While some of the example embodiments discussed herein refer to SAGD
well configuration and operations, it can be appreciated that a solvent may be
48
CA 3052491 2019-08-19
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.
[00202] Other possible modifications and variations to the examples discussed
above are also possible.
[00203] Further, factors affecting the transportation of the solvent in the
reservoir
need to be considered. For example, for effective delivery of the solvent to
the
periphery of the vapour chamber, it is desirable that the solvent has a
sufficient partial
pressure in the steam chamber but can condense with steam at the periphery of
the
steam chamber.
[00204] As can be understood by a person skilled in the art, vapour pressure
of a
substance refers to the pressure exerted by a vapour in thermodynamic
equilibrium
with its condensed phases (solid or liquid) at a given temperature in a closed
system.
The vapour pressure of any substance usually increases non-linearly with
temperature according to the Clausius¨Clapeyron relation. The vaporization
characteristics of a substance may be expressed or indicated using vapour
pressure
curves or profiles which show the relation between the partial pressure of a
substance and the temperature and total pressure. The composition of the
mixture in
which the substance is placed can also affect the partial pressure. In
selected
embodiments, the solvent may have a vapour pressure curve that does not
deviate
from the vapour pressure curve of water by, for example, about 10% to about
30% at
a given condition. Vapour pressures of a given compound may be known, measured
using known methods, or calculated based on known theories including, for
example,
equations such as the Clausius-Clapeyron equation, Antoine's equation, the
49
CA 3052491 2019-08-19
Peng-Robinson (PR) equation, the Soave-Redlich-Kwong (SRK) equation, the
Wagner equation, or other equations of state.
[00205] 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.
[00206] 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.
[00207] Generally, a number of factors may be considered when selecting a
suitable solvent for use in various embodiments.
[00208] 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.
[00209] 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
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.
[00210] Another possible contributing factor is whether the solvent can reduce
the
viscosity of oil in the reservoir.
[00211] As can be appreciated, a common consideration for selecting the
suitable
solvent is cost versus benefits.
CA 3052491 2019-08-19
[00212] 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.
[00213] 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.
[00214] 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.
[00215] A more intrinsic metric is likely the molar ratio or molar
concentration
(mol%) of the injected solvent to steam.
[00216] 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.
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CA 3052491 2019-08-19
[00217] 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.
[00218] 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.
[00219] 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.
[00220] 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.
[00221] 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.
[00222] 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; 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
52
CA 3052491 2019-08-19
transported as vapour with steam to a steam front. The mobilizing fluid may
also
include less than 3 wt% methane, such as less than 1wt% methane. The
mobilizing
fluid may comprise about 40 wt% to about 50 wt% of the solvent. The solvent
may
comprise propane.
[00223] 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 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 40 wt% to about 50 wt% propane or
butane.
The mobilizing fluid may comprise less than 1 wt% methane.
[00224] 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 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%
53
CA 3052491 2019-08-19
of methane, in the re-injected fluid may provide improved overall operational
or
economic efficiency.
[00225] The steam heats the solvent and the heat and solvent are expected to
sustain steam chamber growth in the reservoir. The technology can potentially
significantly lower the cumulative steam-to-oil ratio and water treatment
costs
associated with steam generation. The absolute amount of GHG emissions which
is
correlated with energy intensity and enthalpy requirement could also be
reduced by
40%, while making new in situ projects more economical due to lower capital
requirements associated with reduction in water-treatment and steam-
generation.
With injection of the hot solvent substantial steam generation capacity will
be simply
redirected towards the development of other pads.
[00226] Other features, modifications, and applications of the embodiments
described here may be understood by those skilled in the art in view of the
disclosure
herein.
[00227] The following examples are provided to further illustrate embodiments
of
the present invention, and are not intended to limit the scope of the
disclosure.
[00228] Example I
[00229] Computer simulations have been conducted to predict expected recovery
performance and energy efficiency with different compositions of the injection
fluid.
Representative simulation results are discussed next.
[00230] In this example, computer simulations were performed to investigate
the
optimal ratio or concentrations of propane and steam in a solvent-aided
recover
process. The simulations were based on the following understandings. It is
expected
that sufficient steam is needed to ensure the tested solvent is sufficiently
volatile so
the solvent can be transported as vapour with steam at the reservoir
conditions. This
factor may be used to provide a lower limit for the steam molar ratio or
weight
concentration, or the upper limit for the solvent ratio or weight
concentration.
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CA 3052491 2019-08-19
[00231] Simulation tests confirmed that increasing the steam content in the
injected
fluid can increase oil production rate or recovery factor, but also increase
energy
usage.
[00232] It is known in the industry to measure energy efficiency based on the
produced steam-to-oil ratio (SOR) or the cumulative SOR (cSOR). Some
conventional processes were desired to minimize the SOR or cSOR.
[00233] However, it has been recognized by the inventor, and confirmed by
simulation results, that there is an optimal solvent-to-steam ratio (or ratio
range) for
balancing different performance and efficiency factors and achieving overall
optimal
process performance and efficiency, including minimizing the SOR or cSOR for a
given solvent, and optimizing the operating pressure, reservoir conditions
(e.g.,
bitumen composition), steam heating energy (e.g,. quality/superheat,
pressure), and
the like.
[00234] For example, simulation tests confirmed that increasing the solvent
concentration in the injection fluid may lead to improved energy efficiency,
but if the
concentration of the solvent is too high it may negatively affect oil
production. As a
result, maximizing the solvent content does not always result in the maximum
project-wide oil production rate. This is especially true for a project with a
fixed
steam generation capacity.
[00235] It is expected that, in some embodiments, the operating pressure in
the
reservoir can also be used as a constraint in simulation studies to predict or
determine the optimal solvent to steam ratio. In some simulations, the
operating
pressure may be varied and the injection rate of the mixed solvent and steam
may be
used as a constraint.
[00236] As an example, simulations were conducted based on a model in which
propane was used as the solvent and was co-injected with steam. The simulated
solvent concentration in the mixture of solvent and steam was 30 wt% to 80
wt%, or
about 15 mol% to about 62 mol%. The modelled reservoir was 800 m long, 100m
CA 3052491 2019-08-19
wide, with a 20 m thick pay zone. The modelled reservoir also has the
following
characteristics:
[00237] Oil saturation: 80%.
[00238] Water saturation: 20%.
[00239] Initial reservoir conditions: initial reservoir pressure = 2.5 MPa;
initial
reservoir temperature = 11 C.
[00240] Injection fluid formed by mixing (i) saturated steam of quality of one
(1) and
(ii) liquid propane at 0 C.
[00241] Injection pressure: 3 MPa.
[00242] Production constraints: gas production rate = 2 ton/day; downhole
pressure in the production well = 2.4 MPa.
[00243] Maximum production flow rate: 1100 ton/day.
[00244] Reservoir porosity: 0.33
[00245] Reservoir Permeability: kh = 3 darcy; k = 1.3 darcy.
[00246] FIGS. 6A and 6B show representative simulation results of the
cumulative
injected steam after 600 days of co-injection and oil production as a function
of the
weight percent of the injected solvent (FIG. 6A), or the molar percent of the
injected
solvent (FIG. 6B).
[00247] As can be derived from the simulation test results, with more solvent
injection, water usage may be decreased but the oil production rate may also
decrease, so that the optimal energy efficiency may only be obtained within a
limited
range of the solvent to steam ratio, which may vary depending on the
properties of
the particular reservoir, the operating pressure, the particular solvent and
its
properties, the properties of the injected steam (e.g. steam saturation and
pressure),
and the like.
[00248] FIGS. 7A and 7B show representative simulation results of the oil
56
CA 3052491 2019-08-19
production after 600 days of oil production as a function of the weight
percent of the
injected solvent, or the molar percent of the injected solvent (FIG. 7B). As
can be
seen, when more solvent is injected, the oil production performance decreases
for
the particular tested reservoir conditions and the tested solvent.
[00249] Thus, for an overall optimal operation, both steam usage (energy
efficiency)
and oil production performance need to be considered, such as using a plot
similar to
that shown in FIG. 8.
[00250] FIGS. 8A and 8B show representative simulation results for both
produced
oil and the produced steam-to-oil ratio (SOR), as functions of the weight
percent of
injected propane, or the molar percent of the injected solvent (FIG. 8B). As
can be
appreciated, generally a low SOR operation will produce more oil than a high
SOR
operation for a fixed steam capacity. As can be seen from FIGS. 8A and 8B, the
ranges for balanced optimization of SOR and oil production are about 40 to
about 50
wt% propane, or about 20 to about 30 mol% propane. These ranges correspond to
solvent-to-steam ratio (SSR) of about 0.15 to about 0.35.
[00251] 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. When selecting from different solvents with similar
molecular
structures and properties, it may be more useful to define the optimal range
of the
solvent ratio or concentration. in terms of the solvent's molar ratio or molar
concentration in the injected fluid, or on the basis of total injected solvent
and steam.
[00252] Example II. Simulation with propane and steam co-injection
[00253] Simulation calculations were performed to predict operation parameters
and conditions for a test process with co-injection of steam and propane (as
the
solvent) through the injection well of a pair of SAGD wells after a period of
SAGD
operation.
[00254] In the simulated model, the simulated steam and solvent injection
rates
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CA 3052491 2019-08-19
were adjusted during a period of oil production. Representative injection
rates over a
period of 10 days are listed in Table I, which also shows the corresponding
weight
percentages of propane in the injected fluid and the temperature of the
injected fluid
(T) at the respective injection rates. The simulated injection pressure was
3.2 Mpa,
and the injections rates were adjusted to always maintain the injection
pressure at a
contact value of 3.2 MPa. The enthalpy values shown in Table I are the total
enthalpy
of the injection fluid which includes both steam and propane, and are
calculated using
Equation (1). The steam rate and propane rate refer to the steam injection
rate and
propane injection rate respectively. The assumption for propane enthalpy in
gaseous
phase that at 0 C the enthalpy is 377 kJ/kg and at 100 C the enthalpy is 557
kJ/kg.
The steam quality of steam is 92% with the corresponding enthalpy of 2.64
MJ/kg.
Thus, considering the mixing rule one could assume the very little energy is
being
delivered by propane or a solvent relatively to steam especially during cold
weather.
The initial temperature of propane injected could be 0-50 C and the initial
temperature of the steam injected could be 240 C as seen in FIG.5 which shows
various vapor pressure phase behaviors where steam performs very similarly to
hexane in the chart. Steam will have to be at 230-250 C to be injected at
gaseous
phase at 3000 kPa bottom hole pressure condition. The mixing temperature when
injecting 1.22 T/hr of steam and 1.7 T/hr of propane could be 188.9 C .
[00255] The enthalpy delivered by propane before mixing with steam could be
ignored considering severe weather condition at the operating site and the
actual
propane enthalpy in gaseous phase which is at 0 C the enthalpy is 377 kJ/kg
and at
100 C the enthalpy is 557 kJ/kg. For example, the mixed enthalpy for 10 wt%
propane and 90 wt% steam could be 2.37 Mj/kg. Assuming propane at 100 C with
enthalpy of 557 kJ/kg at 10 wt% the mixed enthalpy is about 2.376 Mj/kg. Thus,
the
assumption that very little energy is delivered by propane relatively to steam
is
confirmed. Another example, the mixed enthalpy for 40 wt% propane and 60 wt%
steam could be 1.58 Mj/kg as shown in the table below. At 50 wt% propane
injection,
the energy intensity for the recovery process is cut by 50% in comparison to a
SAGD
recovery scheme.
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CA 3052491 2019-08-19
Table I.
Days of Propane Steam
Rate Propane Rate Enthalpy
Production (wt%) (t/d) (t/d) (MJ/kg) (C )
445 0 290 0 2.64 240
455 10 160 18 2.37 235
465 20 100 25 2.11 233
475 30 70 29 1.84 231
485 40 50 33 1.58 225
495 50 30 28 1.32 218
505 60 20 28 1.05 206
515 70 15 28 0.79 163
525 80 15 53 0.53 109
535 80 15 50 0.53 108
[00256] Representative simulation data is also shown in FIG. 10. Some
correlations among the listed data in Table I are shown in FIGS. 11, 12, 13
and 14.
[00257] Based on the data shown in Table I and FIGS. 10-14, it can be
determined
that, for injection of steam and propane in the simulated model, the solvent
weight
percent of about 50 to about 60 wt% and steam weight percent of about 50 to
about
40 wt% may be selected as the optimal injection rate ranges, which correspond
to the
solvent injection rate of about 28 T/d and the steam injection rate of about
20 to about
30 T/d in this particular simulated model.
[00258] In reaching the above determination, a number of factors may be
considered as discussed below.
[00259] As can be seen in Table I and FIGS. 10-14, the correlation between the
solvent weight percent and each of the solvent injection rate (FIG. 11) and
the steam
injection rate (FIG. 12), and the correlation between the enthalpy of the
injected fluid
and each of the solvent injection rate (FIG. 13) and the steam injection rate
(FIG. 14)
are all non-linear.
[00260] It can be observed from FIG. 11 that when the solvent weight percent
is
increased from about 30 wt% to about 70 wt%, the solvent injection rate may be
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CA 3052491 2019-08-19
maintained at a relatively constant value, about 30 T/D, or about 28 to about
33 T/d.
However, to further increase the solvent weight percent to above about 70 wt%,
a
substantial increase in the solvent injection rate is required. This trend
indicates that
injecting the solvent in the range of about 30wt% to about 70wt% would be more
efficient from the solvent usage perspective. Further, as illustrated in this
example,
when the solvent weight percent is within the range of about 30wt% to about
70wt%,
the weight percent value may be conveniently adjusted by adjusting the steam
injection rate without substantial adjustment of the solvent injection rate.
As can be
observed from FIG. 16, under the appropriate conditions, slightly increase the
steam-to-solvent ratio in the injection fluid by increasing the steam
injection rate can
significantly reduce the overall amount of the solvent required for effective
and
efficient hydrocarbon production.
[00261] From FIG. 12, it can be observed that the required steam injection
rate
decreases quickly when the solvent weight percent is increased from 0 wt% to
about
30 wt%. When the solvent weight percent is increased from about 30 wt% to
about 60
wt%, the steam injection rate may still be decreased but at a substantially
slower rate.
When the solvent weight percent is above about 60 wt% (and up to at least
about 80
wt% as illustrated in FIG. 12), the required steam injection rate is
substantially
constant. From the illustrated results, it may be expected that injecting
solvent at a
weight percent below about 60 wt% would be more efficient for reducing steam
usage.
[00262] Combining the two factors discussed above, it may be expected that the
optimal solvent weight percent for the simulated model is about 50 wt% to
about 60
wt%. To achieve the maximum steam reduction within this range, the solvent
weight
percent may be selected to be about 60 wt%.
[00263] Without being limited to any particular theory, it is expected that
the above
observed trends are at least in part due to the enthalpy requirement
adjustment when
the injection rates are adjusted. In particular, the steam provides heat (and
thus
enthalpy) to the injection fluid mixture so reducing the steam weight percent
in the
CA 3052491 2019-08-19
injection fluid would reduce the total enthalpy per unit weight in the
injection fluid. The
solvent (propane in this example) consumes heat upon mixing with steam and
thus
does not add, but reduces the overall enthalpy in the injection fluid mixture.
When the
solvent injection rate is at a certain level, there is a minimum steam
injection rate that
is required to provide the necessary heat to maintain suitable injection
conditions
(including the injection pressure and injection temperature) so that the
solvent will be
injected as a vapor at the selected or desired injection pressure. For
example, in the
simulated model, when the solvent injection rate is about 28 T/d or higher,
the steam
injection rate needs to be at least 15 T/d in order to provide the needed heat
(enthalpy). At this point, further increasing the solvent injection rate would
increase
the weight percent of the solvent in the injection fluid, but would not lead
to any
further reduction in the steam injection rate. Further increasing the solvent
injection
rate would increase solvent usage and associated costs, but have less or
little impact
on reducing steam usage or energy consumption.
[00264] These effects can be seen from FIGS. 13 and 14. From FIG. 13, it may
be
observed that the enthalpy drops more quickly when the solvent injection rate
is
within the range of about 25 T/d and about 30 T/d (such as 28 T/d), and drops
less
quickly when the solvent injection rate is higher than about 35 T/d.
[00265] As can be observed from FIG. 14, the effect on enthalpy reduction by
reducing the steam injection rate is less when the steam injection rate is
high, but
becomes more pronounced when the steam injection rate is approaching a minimum
threshold. As can be seen in FIG. 14, at higher steam injection rates, the
slope of the
curve is more flat, which means that the ratio of enthalpy reduction over the
steam
injection rate reduction is relatively lower at higher steam injection rates.
For example,
the relative ratio of steam inject rate reduction percentage over the enthalpy
reduction percentage (R) at 10 wt% solvent is about 4.4 (R = 4.4). This ratio
R
reduces gradually to about 1.7 (R = 1.7) at 60 wt% solvent, and to about 1 (R
= 1) at
70 wt%. For every 10 wt% increase in the solvent weigh percent, the percentage
of
steam inject rate reduction decreases from about 44% (at 10 wt% solvent) to
about
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25% (at 70 wt% solvent), and eventually to 0% reduction (at above 70 wt%
solvent).
Both the ratio R and the relative percentage of steam injection rate reduction
over
unit reduction of the solvent weight percent may be used as metrics for
assessing the
threshold condition to select the suitable steam and solvent injection rates.
In this
example, the threshold value of R may be selected to be 1.5, based on overall
consideration of the simulation results, and the threshold condition is
considered to
be met when R is less than 1.5. Based on this condition, the maximum suitable
solvent weight percentage in this example is about 60 wt%, and the
corresponding
solvent injection rate is about 28 T/d.
[00266] Another possible threshold condition may be that the relative steam
injection rate reduction per unit solvent weight percent increase is less than
about 25
to 30%. Based on this criteria, the maximum suitable solvent weight percentage
in
this example is also about 60 wt%, and the corresponding solvent injection
rate is
about 28 T/d.
[00267] A further possible criterion for the threshold condition may be the
relative
ratio of the increase in solvent injection rate over the reduction in the
steam injection
rate. For instance, in the present example, the percentage of increase in the
solvent
injection rate is less than 20% per 10wt% increase in the solvent weight
percent
when the solvent weight percent is below about 60 wt%, but is more than 100%
when
the solvent weight percent is increased from 70 wt% to 80 wt%. The ratio of
reduction
in steam injection rate over the increase in solvent injection rate is higher
than about
in the range of 10 wt% to 60 wt% solvent but is almost zero above 70 wt%
solvent.
Thus, a further threshold condition may be that the ratio of the reduction in
the steam
injection rate over the required increase in the solvent injection rate to
compensate
the steam reduction is more than at least 1, such as more than 2, more than 3,
more
than 4, or more than 5.
[00268] As a specific example, this ratio may be 1. In practice, for example,
if it is
found that the reduction in steam rate from 25 T/d to 22 T/d requires an
increase in
the propane injection rate from 35 T/d to 40 T/d to compensate this steam
reduction
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to inject at the same injection pressure, i.e., the ratio is 3 T/d over 5 T/d,
or 3/5 < 1, it
can be determined the threshold condition has been met, and the steam
injection rate
should be maintained at 25 T/d/, and the solvent injection rate should remain
at 35
T/d.
[00269] Another practical metric to assess the threshold condition is to
monitor the
drop in the injection pressure for the same amount of reduction in the steam
injection
rate, while the solvent injection rate has remained unchanged or has been
increased
in an attempt to return to the original injection pressure. For example, if
the pressure
reduces from the steady state pressure sharply and substantially after a
reduction in
the steam injection rate, much more pronounced than in previous reductions of
the
steam rate by similar amounts or percentages, it may indicate that a threshold
condition has been reached and the steam rate has been reduced too much.
[00270] As noted above, in this example the simulation results indicate that
the
optimal weight percentages of propane (solvent) to steam may be 60 wt% propane
and 40 wt% steam in the simulated model. As compared to at 80 wt% solvent, 5
to 15
t/d of additional steam rate may be needed to reduce the solvent weight
percent to
about 60 wt% or 50 wt%, but the corresponding reduction in the solvent
injection rate
is about 20 t/d, from about 50 t/d to about 28 t/d.
[00271] Based on an analysis of enthalpic adjustment, the optimal injection
rates
may be selected to be about 28 t/d of propane and about 20-30 t/d of steam at
the
above noted operation conditions.
[00272] Under the simulated conditions in this simulation model, a solvent
driven
process (SDP) may be operated with about 60 wt% solvent and about 40 wt% steam
in the injection fluid mixture at an injection temperature of about 206 C. At
these
conditions, the enthalpy value of the injection fluid mixture is 1.05 MJ/kg.
[00273] If solvent to steam ratio in the injection fluid mixture is increased,
so the
injection fluid mixture contains approximately 70 wt% solvent and 30 wt%
steam, the
temperature of the inject fluid mixture would be about 163 C with an enthalpy
of 0.79
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MJ/kg.
[00274] If the fluid mixture contains approximately 80 wt% solvent and 20 wt%
steam, the injection temperature of the fluid mixture is going to be 108 C
with an
enthalpy value of 0.528 MJ/kg.
[00275] Under the simulated conditions, during a typical SAGD operation, where
the injection fluid contains 100 wt% steam and 0 wt% solvent, the enthalpy
requirement is 2.64 MJ/kg and the approximate injection temperature is 240 C.
[00276]
For the simulation discussed above, it is assumed that the steam quality
is 92%.
[00277] From the above, the reduction of enthalpy requirement from pure steam
injection is reduced by 58% when the injection fluid contains 60 wt% solvent
and 40
wt% steam, by 68% for 70 wt% solvent and 30 wt% steam, and by 78% for 80 wt%
solvent and 20 wt% steam.
[00278] When the solvent weight percent is increased from 70 wt% to 80 wt%,
the
energy requirement is reduced by about 10%. However, the corresponding
increase
in the solvent injection rate is about 90% (from 28 t/d to 53 t/d). Thus, this
10%
reduction in the energy requirement requires a relative high cost, and is not
optimal.
[00279] An embodiment disclosed herein thus allows enthalpic adjustment in the
SDP or another similar solvent-based process. The adjusted optimal value in
this
example from an economic perspective may be to inject 28 t/d of propane and 15
t/d
of steam with the enthalpic reduction of 68%.
[00280] From the simulation results, it can be expected that an optimized
enthalpic
adjustment in the simulated SDP after 5 years of initial production can result
in 50%
reduction in the solvent (propane) injection requirement. In a simulation
calculation, it
was found that the cumulative solvent injection may be reduced to about 8,000
tonnes under an optimized process where the enthalpy requirement is optimized
as
described above, from about 16,000 tonnes as required under an un-optimized
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process at a higher solvent injection rate. In both the optimized and un-
optimized
processes, the cumulative oil production achieved is similar at about 150,000
tonnes,
where the oil production by the non-optimized process is higher by only about
4%.
[00281] In a practical application, an embodiment disclosed herein may be
implemented by monitoring the bottom hole pressure (BHP), ramping up the
solvent
injection rate and reducing a steam injection rate with control until a
desired threshold
condition has been reached. An initial steady state of the operation
conditions and
parameters may be achieved in a solvent driven phase where the injection fluid
contains, for example, 51 wt% solvent (propane) and 49 wt% steam, with
corresponding propane injection rate of 35 t/d and corresponding steam
injection rate
of 33 t/d, and the bottomhole pressure maintained at 3.15 MPa.
[00282] Once the steady state is achieved, the steam injection rate can be
reduced
while closely monitoring the BHP reading. The steam injection rate reduction
may be
scheduled to decrease the steam injection rate by 10% every 3 days from the
initial
level of 33 t/d. Measures to increase the injection pressure need to be taken
when the
bottom hole pressure responds to reduction in steam rate with a sharp decline,
for
example, dropping from 3.15 MPa to 3.1 MPa within several days. In such
situations,
additional increase in the solvent injection rate may be required, or the
steam
injection rate may be increased to the previous level, which may be desirable
depending on the particular situation.
[00283] Based on the present example, if the solvent propane injection rate is
35
t/d and the steam injection rate is 33 t/d, it is possible to further reduce
the steam
injection rate to 15 t/d. After such dramatic reduction in the steam injection
rate, the
bottom hole pressure reading may drop by 50 kPa or 1.5%. In response, the
steam
injection rate may be increased back to about 20 t/d to about 33 t/d range and
maintain the enthalpic adjustment at a new steady state without increasing
propane
injection. An alternative response is to increase the propane injection rate
to 40 T/d.
[00284] Pressurizing the reservoir back to a previous level may be implemented
by
CA 3052491 2019-08-19
increasing steam or solvent injection rate for about a week. Once the steady
state is
reached, the operator controls the injection rates to meet the energy
requirements
and desired performance targets. For example, in a particular situation, the
operator
may choose to inject propane at 35 t/d and steam at 27 t/d, with a solvent to
steam
weight ratio of about 56/44.
[00285] As can be seen in Table I, for the given input steam and solvent
sources,
the injection temperature, which is the temperature of the injection fluid
(mixture of
the source steam and solvent), is dependent on the solvent weight ratio, and
decreases from about 240 C to about 110 C when the solvent content is
increased
from 0 wt% to 80 wt%. It is expected that when the temperature is decreased to
a
certain threshold, such as below 70 C, the heat provided by injected steam may
become insufficient for vaporizing the solvent or maintain the solvent in the
gas
phase during injection. For example, a portion of the solvent may be in the
condensed liquid phase. Thus, the injected solvent may not be as fully
utilized as at a
higher temperature. Further, more solvent is required to make up the required
gas
pressure to maintain the desired injection pressure at a lower temperature.
Consequently, a jump in the required solvent injection rate may be observed as
discussed above. Additionally, when the injection rate of steam is reduced, a
higher
percentage of the injected steam may condense during injection. When the steam
injection rate is too low, most of the injected steam may be in the liquid
phase and
little is left in the gaseous phase. For example, when the steam weight
percentage in
the injected stream is 10 wt%, with 90 wt% of solvent in the injected stream,
about 93%
of the injected steam may condense upon mixing with the solvent, assuming the
steam quality is 92%, the enthalpy is 0.264 Mj/kg, the pressure is 3.2 MPa and
the
temperature of the mixture is between 65 C and 100 C. Therefore, in some cases
under the right conditions, it may be expected that a slight increase in the
steam
injection rate can significantly increase the injection pressure without
requiring
substantial increase in the solvent injection rate.
[00286] Example Ill Simulations with steam and butane as the solvent
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[00287] A similar simulation study was conducted for an SDP with controlled
injection of steam and butane as the solvent.
[00288] FIG. 15 shows representative simulation results for steam-butane
co-injection and the cumulative injection requirement and the corresponding
oil
produced. In FIG. 15, "60/40" and "80/20" refers to the solvent to steam ratio
expressed as weight percent of solvent over steam. That is "60/40" indicates
60 wt%
solvent and 40 wt% steam in the injection mixture, and "80/20" indicates 80
wt%
solvent and 20 wt% steam. The steam injection rate, solvent injection rate and
oil
production rate at each solvent to steam ratio are shown.
[00289] As can be see, for the weight ratio of 60/40, the butane injection
rate was
increased gradually until the weight ratio reaches about 60 wt% butane to
about 40
wt% steam, after 600 days of ramping up. For the 80/20 case, the ramp up in
the
solvent butane injection rate to the selected 80 wt% butane and 20 wt% steam
takes
about 1,000 days. As can also been seen, when the butane to steam ratio is
increased from 60/40 to 80/20, the solvent injection rate increases steeply
while both
steam injection and oil production exhibited modest increase.
[00290] Table II shows the steam-butane cumulative injection requirement and
the
corresponding oil produced at 900, 1100 and 1300 days. The overall percentage
change in steam, oil and butane is also provided.
Table II.
Solvent-to-Steam Solvent-to-Steam Weight Percent of Change in
rates
Weight Ratio = 60/40 Ratio = 80/20
Time Steam Oil Butane Steam Oil Butane Steam Oil Butane
(days) (kT) (kT) (kT) (kT) (kT) (kT) (%) (%) (%)
900 78 46 10 78 46 10 0 0 0
1100 81 55 18 81 56 22 0 2 22
1300 88 60 27 92 66 60 5 10 122
[00291] Around 900 days, the solvent to steam ratio being implemented remains
unchanged. The increase of the solvent to steam ratio to 80/20, occurred later
in the
process, at 1,000 days mark. At 1100 days the 80/20 case yielded 2% in oil
production but also 22% increase in butane injection requirement. At 1300, the
steam
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injection requirement increased by 5%, the oil produced increased by 10% but
the
solvent butane injection rate increased by a substantial amount (percentage),
i.e.,
122%. Therefore, the enthalpic adjustment methodology for butane co-injection
advocates a solvent steam ratio lower than 80/20 (by weight percent) due to
the
significant increase in the solvent required to pressurize the reservoir and
allow oil
production. The 60/40 solvent steam injection fluid is more beneficial in this
case as
the solvent injection requirement is 50% lower despite the delay in oil
production by
about 10%.
[00292] FIG. 16 shows representative simulation results of the required
solvent
(butane) amount at different butane-to-steam weight ratios for a given
production
period. As can be seen from FIG. 16, at 1800 days of production, 68 kt of
butane is
required for butane to steam weight ratio at 70/30, 32 kt of butane is
required for a
weight ratio of 50/50, and 43 kt of butane is require for a weight ratio of
60/40.
[00293] FIG. 17 shows representative simulation results of the oil production
as a
function of the injection rates. For 1800 days of production operation, with
the solvent
to steam ratio in the injection fluid being 70/30, 80 kt of oil is produced;
with 50/50 or
60/40 solvent to steam weight ratios, the oil production is about 72 kt.
[00294] These results demonstrate that other solvents such as butane may be
used to replace propane in selected embodiments disclosed herein.
[00295] FIG. 18 shows representative changes in the injection pressure in
response to injection rate adjustments. The injection pressure was measured
based
on the BHP (bottom hole pressure) in the injection well. The injection
parameters
were adjusted as shown in FIG. 18. One of the factors considered for adjusting
the
injection parameters was to avoid short-circuiting of gaseous propane through
the
production well. Representative pressure responses to adjustment of injection
rates
over different periods are summarized in Table III.
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Table III. Pressure Response to Adjustment of Injection Rates
Time Solvent Injection Steam Injection BHP
Rate (T/d) Rate (lid) (kPa)
Feb 8 ¨ increased by 5 unchanged increased by 50 kPa
May 30 T/d on Feb. 8 (from 3150 kPa to
3200 kPa)
March 11- unchanged Decreased by decreased by 30
April 4 0.55 lid (from kPa (from 3200 kPa
1.38 T/d to 1.13 to 3170 kPa)
lid) on March
11
May 23- unchanged Decreased by decreased by 12
May 27 0.07 lid (from kPa (from 3215kPa
1.22 lid to 1.15 to 3203 kPa)
T/d) on May 23
[00296] EXAMPLE IV
[00297] In this Example, the effects on injection pressure and enthalpy
adjustment
by changing solvent injection rates and corresponding change in the steam
injection
rate were tested and studied. For this test, the injection rates were adjusted
with the
constraint of maintaining a substantially constant bottom-hole pressure (BHP).
The
solvent used was propane.
[00298] FIG. 19 shows representative results obtained during the test.
[00299] Initially (starting from D1), steam was injected at a rate of about
0.7 t/hr,
and propane was injected at a rate of about 1 t/hr for about 4 days. The BHP
was
stable at about 3200 Kpa. Some minor fluctuation in both injection rates and
BHP
was observed. The initial injection mixture of steam and propane had a
temperature
of about 190 C.
[00300] On Day 5 both steam and propane injection rates were reduced to zero
(i.e.
the injection was shut-in) for about 7 hours, which resulted in subsequent
decrease of
the BHP from about 3200 kPa to about 3185 kPa.
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[00301] Steam injection was then resumed, but at a higher steam injection rate
of
1.3 t/hr. The injection stream had a temperature of about 240 C. The BHP
responded
and started to increase immediately after the resumption of steam injection.
[00302] Propane injection was resumed at the injection rate of 1 t/hr about 5
hours
after the re-commencement of steam injection. The injection mixture at this
point had
a temperature of about 215 C. After resumption of propane injection, the BHP
again
reached the previous level of about 3200 kPa.
[00303] It was observed that the BHP overall declined only slightly, from 3205
kPa
to about 3200 kPa, over the time period of about a week, from Day 1 to Day 7,
while
the steam and solvent injection rates were adjusted during some portions of
this
period.
[00304] It can be seen that, the same or similar BHP may be obtained with
different
steam and solvent injection rate combinations, and hence different enthalpy
input. At
least at some practical levels, the steam injection rate may be increased or
reduced
without substantially affecting the BHP when the solvent injection rate is at
the same
level.
[00305] These test results seem to support the following expectations.
[00306] With residual solvent in the reservoir, relatively small increases in
the
steam injection rate could be sufficient to provide the desired pressure in
the
reservoir. In comparison, in a SAGD process, a relatively larger increase in
steam
injection rate would be required to raise the reservoir pressure or BHP by the
same
amount. The relative reduction in the required steam injection rate to achieve
the
same BHP when there is residual solvent in the reservoir, as compared to a
SAGD
process, will depend on a number of factors including the time and amount of
prior
solvent injection, the amount of residual solvent in the reservoir, and the
desired
temperature and pressure in the reservoir. As an example, when both propane
and
steam are co-injected as described in this Example, the steam injection rate
may be
only 1/10 of the corresponding steam injection rate required in a
corresponding
CA 3052491 2019-08-19
SAGD process for achieving the same BHP. When propane injection is suspended
after about a week of co-injection, the required steam inection rate to
achieve the
same BHP may be about 1/3 of corresponding SAGD rate. For instance, it may be
expected that if the required SAGD steam injection rate is 300 ton/day, the
steam
injection rate during co-injection of steam and propane may be reduced to 30
ton/day,
and then increased to only 90 ton/day for maintaining the same BHP.
[00307] The solvent (propane) requirement could be reduced with a
correspondingly smaller increase in the steam injection rate.
[00308] The small amount of increased steam injection could be sufficient to
heat
and increase the temperature of previously injected solvent in-situ, to cause
a
possible phase change in the solvent so as to increase the overall BHP.
CONCLUDING REMARKS
[00309] 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.
[00310] 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. Further, unless otherwise specified or the content dictates
otherwise, a
value or range disclosed herein as an example is not intended to limit the
possible
values or ranges for the relevant parameter or metric.
[00311] 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.
[00312] It will be further understood that the term "comprise", including any
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variation thereof, is intended to be open-ended and means "include, but not
limited to,"
unless otherwise specifically indicated to the contrary.
[00313] 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.
[00314] 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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