Note: Descriptions are shown in the official language in which they were submitted.
Gravity Drainage of Hydrocarbons by Steam and Solvent
Injections with Reduced Energy Usage
TECHNICAL FIELD
[0001] The disclosure relates generally to hydrocarbon recovery from
underground
reservoirs. More specifically, the disclosure relates to gravity drainage
processes utilizing
both steam and hydrocarbon solvents to recover viscous hydrocarbons.
BACKGROUND
[0002] Bitumen and heavy oil reserves (collectively referred to herein as
"viscous oil" or
"viscous hydrocarbons" as further defined below) exist at various depths
beneath the
earth's surface. Where viscous oil is found at depth, it is commonly produced
to surface
using in situ processes. Most commonly, in situ processes comprise injecting a
mobilizing
agent such as steam or solvent into the underground reservoir through a well
to mobilize
the oil and then a combination of gravity drainage and pressure cause the oil
to flow to a
production well. The viscous oil is pumped to the surface from the production
well.
[0003] One example of an in situ process is steam-assisted gravity drainage
(SAGD). In
SAGD, directional drilling is employed to place two horizontal wells in the
reservoir; a lower
horizontal well near the base of the reservoir which is used for production
with a second
horizontal well above the first well which is used for injection. Steam is
injected into the
upper well to heat the bitumen and lower its viscosity. The condensed steam,
viscous oil
and other reservoir fluids will then drain downward through the reservoir
under the action
of gravity drainage and flow into the lower production well, whereby these
liquids are
pumped to surface. On the surface, the viscous oil is separated from the other
fluids so
that it can be transported to an oil refinery and converted into a variety of
products of
value. An example of SAGD is described in U.S. Patent No. 4,344,485 (Butler).
[0004] Another example of an in situ process is a process known as "Vapor
Extraction"
(Vapex) where a similar well configuration to SAGD is employed but instead of
steam, a
solvent vapor such as a light hydrocarbon (e.g. propane, butane or other
alkanes) is
injected as the mobilizing agent. An example of Vapex is described in U.S.
Patent No
5,899,274 (Frauenfeld).
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[0005] In situ processes can also combine heat and solvent as the mobilizing
agents. An
example is Heated Vapex (H-Vapex) where heated solvent is injected into the
reservoir.
An example of H-Vapex is described in U.S. Patent 6,883,607 (Nenniger).
[0006] In situ processes can also combine steam and solvent injection as the
mobilizing
agents along with their associated heat. Examples include Solvent-Assisted
Steam-
Assisted Gravity Drainage (SA-SAGD) as described in Canadian Patent No.
2,323,029
(Nasr), and the Steam and Vapor Extraction Process (SAVEX) as described in
U.S. Patent
No. 6,662,872 (Gutek) and Canadian Patent No. 2,553,297 (Gates).
[0007] Azeotropic Vapex (AzeoVapex) is an improvement on H-Vapex where steam
and
solvent are co-injected, thereby significantly reducing the volumes of solvent
required
while maintaining the benefits of a lower operating temperature as described
in Canadian
Patent No. 2,915,571 (Boone).
[0008] It is desirable to provide an improved or alternative gravity drainage
process for
recovering viscous oil from an underground reservoir. In particular, it is
desirable to
develop improved processes that reduce or minimize the heat required to
produce the
recoverable oil and thereby minimize the associated greenhouse gas (GHG)
emissions as
well as reducing the large volumes of solvent that must be processed with the
H-Vapex
and AzeoVapex processes.
SUMMARY
[0009] The process described herein provides a gravity drainage process for
producing
viscous oil using steam injection followed by solvent injection. Mixing
solvent in the steam
chamber of the reservoir at an appropriate point in time provides the effect
of lowering the
temperature of the steam chamber and vaporizing water in the steam chamber
which then
transfers heat stored in the steam chamber to the steam chamber boundary. The
process
greatly reduces heat requirements for producing the remaining viscous oil
while making
efficient use of heat injected by steam and limiting the volume of solvent
that is injected.
[0010] Accordingly, in one embodiment, a gravity drainage process for
production of
viscous oil from one or more well pairs in an underground reservoir is
provided which
includes the steps of: (a) providing an injection of steam into an upper well
of the well pair
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to form a steam chamber which mobilizes and produces the viscous oil via a
lower well of
the well pair until the steam chamber occupies between 25% to 80% of the
reservoir
volume; (b) stopping the injection of steam after step (a) and starting the
injection of a
predominantly vaporized, condensable non-aqueous solvent as a vapor into the
upper
well, the non-aqueous solvent mixing with the steam in the steam chamber,
thereby
lowering the temperature of the steam chamber and transferring heat to the
steam
chamber boundary, thereby reducing heat requirements for producing the viscous
oil; and
c) continuing the production of the viscous oil.
[0011] According to another embodiment, a gravity drainage process for
production of
viscous oil from one or more well pairs in an underground reservoir is
provided, which
includes the steps of: (a) providing an injection of steam into an upper well
of the well pair
to form a steam chamber which mobilizes and produces the viscous oil via a
lower well of
the well pair until at least 15% of the original oil-in-place (00IP) has been
produced; (b)
stopping the injection of steam after step (a) and starting the injection of a
predominantly
vaporized condensable non-aqueous solvent as a vapor into the upper well, the
non-
aqueous solvent mixing with the steam in the steam chamber, thereby lowering
the
temperature of the steam chamber and transferring heat to the steam chamber
boundary,
thereby reducing heat requirements for producing the viscous oil; and c)
continuing the
production of the viscous oil.
[0012] The solvent may be selected to produce a steam-solvent mixture having
an
azeotrope temperature at least 20 C lower than the temperature of the steam
in the
reservoir. In some embodiments, the solvent is a C3 to C7 hydrocarbon.
[0013] The step of injecting the solvent may be performed at a time point
selected to
minimize total heat requirements for producing the viscous oil to the
estimated ultimate
recovery.
[0014] The step of injecting the solvent may be performed at a time point
selected to
minimize the total volume of the solvent injected for producing the viscous
oil to the
estimated ultimate recovery.
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[0015] In some embodiments, the solvent is commercially available diluent or a
fractionated portion of commercially available diluent.
[0016] In some embodiments, the reservoir pressure is maintained approximately
constant following step (b). In other embodiments, the reservoir pressure is
permitted to
decline following step (b).
[0017] In some embodiments, the solvent is in a composition including steam
and the
composition is injected with a molar solvent concentration greater than its
azeotropic
solvent molar fraction at the reservoir operating pressure. In other
embodiments, the
solvent is in a composition including steam and the composition is injected
with a molar
solvent concentration greater than 70% of its azeotropic solvent molar
fraction at the
reservoir operating pressure.
[0018] In some embodiments, up to about 30% by mass of the injected solvent or
the
composition is in a liquid state during injection.
[0019] In some embodiments, the operating pressure of the reservoir is about
0.5 MPa to
about 5 MPa.
[0020] In some embodiments, operating temperature of the reservoir during
steps (b) and
(c) is about 30 C to about 250 C.
[0021] In some embodiments, after a selected period of solvent injection, a
second
solvent is injected, the second solvent selected to further reduce the
azeotrope
temperature of the steam-solvent mixture.
[0022] In some embodiments, the process further includes the step of stopping
the
injection of the solvent and permitting production of the viscous oil to
continue.
[0023] In some embodiments, after the injection of the solvent is stopped, a
gas which
does not condense in the reservoir is injected. The gas may be natural gas,
methane or
nitrogen.
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[0024] In some embodiments, in step (a), up to 20% by volume of a separate non-
aqueous
solvent is injected with the steam for at least a fraction of the time that
step (a) is
performed.
[0025] In some embodiments, the process further includes providing one or more
infill
wells between the well pairs and injecting steam or solvent into the infill
wells in step (a)
or step (b), or in both step (a) and step (b). Additionally, viscous oil may
also be produced
from the infill wells.
[0026] In some embodiments, the process further includes providing one or more
infill
wells between the well pairs and producing the viscous oil from the infill
wells.
BRIEF DESCRIPTION OF THE DRAWINGS
[0027] Various objects, features and advantages of the technology will be
apparent from
the following description of particular embodiments, as illustrated in the
accompanying
drawings. Instead, emphasis is placed upon illustrating the principles of
various
embodiments.
Figure 1 is a diagram of a typical SAGD well configuration in an underground
reservoir.
Figure 2 is a plot of steam-solvent dew point temperatures for various
solvents at
a pressure of 2.5 MPa.
Figure 3 illustrates the evolution of the temperature within the steam-solvent
chamber after starting solvent injection.
Figure 4A is a drawing showing typical temperature regions in the reservoir
during
steam or steam solvent injection.
Figure 4B is a drawing showing how the temperature in the reservoir evolves
over
time during SAGD operations followed by steam injection.
Figure 5 is a plot showing the evolution of average mole fraction of solvent
and
average temperature in the steam-solvent chamber from simulations of steam
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injection (SAGD) followed by (i) azeotropic steam-pentane injection and (ii)
100%
pentane injection.
Figure 6 is a plot showing the evolution of average mole fraction of solvent
and
average temperature in the steam-solvent chamber from simulations of steam
injection (SAGD) followed by (i) azeotropic steam-butane injection and (ii)
100%
butane injection.
Figure 7 is a plot comparing the total heat requirement (in equivalent m3 of
steam)
to achieve ultimate recovery for simulated cases of SAGD, azeotropic pentane
and
butane injection and cases of SAGD followed by solvent injection.
Figure 8 is a plot comparing the total steam and solvent volumes required to
achieve ultimate recovery for simulated cases of SAGD, azeotropic pentane and
butane injection and cases of SAGD followed by solvent injection.
Figure 9 is a process flow diagram indicating main steps of a process
according
to one example embodiment.
Figure 10 is a process flow diagram indicating main steps of a process
according
to another example embodiment.
DETAILED DESCRIPTION
Introduction and Rationale
[0028] Existing in situ recovery processes that rely on gravity drainage have
significant
limitations. SAGD exploits the characteristic that water is a very effective
working fluid for
heat transfer. However, in order to mobilize the viscous oil the reservoir
must be heated
to high temperatures, typically 200 C or greater. This results in significant
fuel costs for
heating water to steam and significant greenhouse gas (GHG) emissions. In
recent years
GHG emissions have become a significant concern to society and operators incur
associated costs such as carbon taxes. It is expected that future costs
associated with
GHG emissions from SAGD operations will increase significantly, potentially
making it
uneconomic to continue with the SAGD operations.
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[0029] VAPEX has not proven to be practically viable when operating at typical
reservoir
temperatures due to very low production rates of the viscous oil. H-VAPEX is
more
practically viable but suffers from the limitation that hydrocarbon solvents
such as alkanes
are not effective working fluids for heating the reservoir. As a result, there
is a requirement
to inject and process much larger volumes of solvent than is necessary with
steam to
mobilize the viscous oil. This results in excessively high injected solvent to
produced oil
ratios and higher associated costs.
[0030] SAVEX is a process where initially steam is injected and then after a
short period
of steam injection, prior to the steam chamber reaching the top of the
reservoir, solvent
injection begins. SAVEX suffers the same limitation as H-VAPEX that it relies
on
hydrocarbon solvents as a working fluid for heat transfer and there is a
requirement to
inject and process much larger volumes of solvent than is necessary with steam
to
mobilize the viscous oil.
[0031] The process described by Gates in Canadian Patent 2,553,297 is one
where
steam, hydrocarbon solvent gases and non-condensable gases are co-injected,
and the
volumes are progressively adjusted so that the hydrocarbon solvent and non-
condensable
gases become predominant. This process also requires much larger volumes of
hydrocarbon solvent than is necessary with steam to mobilize the viscous oil.
[0032] AzeoVAPEX partially addresses the problem of H-VAPEX by injecting a
fraction of
steam with the solvent for the purposes utilizing steam as a working fluid to
augment the
heat transfer. It also has the advantage of reducing both the injection
temperature and
the average temperature of the reservoir, so that less heat is required to
recover the
viscous oil. Nonetheless, the AzeoVAPEX process still requires very high
volumes of
solvent to be cycled through the reservoir.
[0033] Embodiments of the process described herein exploit the benefits of
steam as an
effective working fluid while capturing most of the benefit of the full life-
cycle lower heat
utilization of AzeoVAPEX at the ultimate economic recovery of the viscous oil.
An
additional benefit is that it can be effectively integrated with existing SAGD
operations
which rely on steam generators to generate the heat required to produce
viscous oil. As
such, the process can be efficiently used by most existing SAGD operations to
both
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increase oil production rates, reduce energy requirements and reduce
associated GHG
emissions.
[0034] Selection of the timing for solvent injection is one aspect of this
technology. During
the steam injection phase, the steam chamber is at or near steam temperatures
and, in
effect, excess heat is being stored in the reservoir. After solvent injection
commences,
the excess heat is progressively redistributed from the depleted reservoir to
the
boundaries of the steam-solvent chamber as it further expands. The process
benefits
from maximizing the excessive heat stored during the steam injection phase
because
steam is an effective working fluid for heat transfer. On the other hand, it
is desirable to
minimize the total heat usage. Therefore, it is preferable not to inject steam
beyond what
is required to supply the heat needed to efficiently produce the remaining oil
during the
solvent injection phase.
[0035] Heat losses to the overburden and underburden are also important
considerations
in selecting the timing for solvent injection. The processes of SAVEX and
Gates (Canadian
Patent No. 2,553,297) initiate solvent injection early in the operational
life, or at low
recovery levels, of a SAGD well pair. In the case of SAVEX, solvent injection
is initiated
prior to the steam chamber reaching the overburden. By contrast, this process
relies upon
utilizing steam as the working fluid to provide much of the required heat to
the overburden
and underburden. Therefore solvent injection does not commence until the steam
chamber has spread across much of the top of the reservoir.
[0036] In the idealized case illustrated in Figure 1, the steam chamber 103
has expanded
to the point where it occupies about 25% of the reservoir volume and has
spread across
about 50% of the reservoir overburden. When the steam chamber has expanded to
occupy about 50% of the reservoir volume, as indicated by areas 103 and 104 in
Figure
1, it will have spread across the entire reservoir overburden.
[0037] It is recognized that in a real-world case, the shape of the steam
chamber is much
more complex and it is not practical to accurately map or image the extent of
a steam
chamber on a continuous basis. A useful physical factor to consider in the
process, is the
volume of the steam chamber rather than its specific shape because the process
exploits
the excess heat stored in the materials, primarily in the sand grains,
contained within the
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volume of reservoir occupied by the steam chamber. Additionally, the volume of
the steam
chamber is also directly related to the volume of the oil produced. Therefore,
the oil
recovery factor, such as for example, a percentage of the original oil-in-
place (00IP) can
be used as a practical measure of the extent and volume of the steam chamber.
[0038] In order to select the optimal time for the start of solvent injection
a variety of
methods can be used to assess the benefits including field performance of
existing wells,
analytical models and simulation models.
[0039] It is recognized that all operations have specific characteristics that
may impact
the selection of the optimal timing of solvent injection including factors
such as depletion
state of the operating well pairs, steam generation capacity, produced water
handling
capacity, and produced oil handling capacity.
[0040] While the process can be optimally timed to minimize total heat
injection, to limit
solvent requirements or a combination thereof, many existing SAGD well pairs
will already
have exceeded this time or recovery level. Nonetheless, there will still be
very significant
benefits from implementing the process. For example, if one starts solvent
injection at a
the time when 60% of the original-oil-in-place (00IP) has been recovered and
the
estimated ultimate recovery is 75% of 00IP a heat savings of up to 20%
relative to total
heat requirements for SAGD operations can be achieved.
[0041] Selection of the solvent is one aspect of the process which relates to
the azeotrope
temperature or minimum dew point temperature for the steam-solvent system.
Ultimately,
the objective of minimizing heat requirements for the process relies upon
reducing the
temperature in the steam-solvent chamber to as close to the azeotrope
temperature as
practical to maximize the abovementioned process of progressively
redistributing heat
from the depleted reservoir to the boundaries of the steam-solvent chamber. As
such,
solvents with lower azeotrope temperatures generally allow for greater
reductions in heat
requirements.
[0042] Another important advantage of process is that it can be operated at
constant or
near constant pressure. For practical purposes, it is often preferable to
operate gravity
processes at or near constant pressure. For example constant pressure will
prevent fluids
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from being lost or will prevent fluids from flowing in from or out to an
underlying aquifer
(water) zone or overlying gas zone.
[0043] The processes permit selection of specific solvents for injection and
permit
selection of timing of the solvent injection. These selections may be made
based on the
characteristics of individual reservoirs. During the initial phase of steam
injection by SAGD
a large volume of the reservoir is heated to steam temperatures and
significant amounts
of heat are lost to the underburden and overburden. Through appropriate
selection of the
solvent and timing of solvent injection, most of the heat required for
recovering the
remaining viscous oil may be provided from within the reservoir itself while
significantly
reducing the total heat requirement.
Terms and Definitions
[0044] For ease of reference, certain terms used in this application and their
meaning, as
used in this context, are set forth below. If a term used herein is not
defined below, it
should be given the broadest definition persons in the pertinent art have
given that term
as reflected in at least one printed publication or issued patent. Further,
the present
processes are not limited by the usage of the terms shown below, as all
equivalents,
synonyms, new developments and terms or processes that serve the same or a
similar
purpose are considered to be within the scope of the present disclosure.
[0045] A "hydrocarbon" is an organic compound that primarily includes the
elements of
hydrogen and carbon, although nitrogen, sulfur, oxygen, metals, or any number
of other
elements may be present in small amounts. Hydrocarbons generally refer to
components
found in heavy oil or in oil sands. Hydrocarbon compounds may be aliphatic or
aromatic,
and may be straight chained, branched, or partially or fully cyclic.
[0046] "Bitumen" is a naturally occurring heavy oil material. Generally, it is
the
hydrocarbon component found in oil sands. Bitumen can vary in composition
depending
upon the degree of loss of more volatile components. It can vary from a very
viscous, tar-
like, semi-solid material to solid forms. The hydrocarbon types found in
bitumen can
include aliphatics, aromatics, resins, and asphaltenes. A typical bitumen
might be
composed of: 19 weight (wt.) percent (%) aliphatics (which can range from 5
wt. % - 30
wt.%, or higher); 19 wt. % asphaltenes (which can range from 5 wt. % - 30 wt.
%, or
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higher); 30 wt. % aromatics (which can range from 15 wt. % -50 wt. %, or
higher); 32 wt.
% resins (which can range from 15 wt. % -50 wt. %, or higher); and some amount
of sulfur
(which can range from 2 to 7 wt. %, or higher%). In addition, bitumen can
contain some
water and nitrogen compounds ranging from less than 0.4 wt %. to in excess of
0.7 wt. %.
The percentage of the hydrocarbon found in bitumen can vary. The term "heavy
oil"
includes bitumen as well as lighter materials that may be found in a sand or
carbonate
reservoir.
[0047] "Heavy oil" includes oils which are classified by the American
Petroleum Institute
("API"), as heavy oils, extra heavy oils, or bitumens. The term "heavy oil"
includes bitumen.
Heavy oil may have a viscosity of about 1,000 centipoise (cP) or more, 10,000
cP or more,
100,000 cP or more, or 1,000,000 cP or more. In general, a heavy oil has an
API gravity
between 22.3 API (density of 920 kilograms per meter cubed (kg/m3) or 0.920
grams per
centimeter cubed (g/cm3)) and 10.0 API (density of 1,000 kg/m3 or 1 g/cm3).
An extra
heavy oil, in general, has an API gravity of less than 10.0 API (density
greater than 1,000
kg/m3 or 1 g/cm3). For example, a source of heavy oil includes oil sand or
bituminous sand,
which is a combination of clay, sand, water and bitumen.
[0048] The term "viscous oil" as used herein means a hydrocarbon, or mixture
of
hydrocarbons, which occurs naturally and that has a viscosity of at least 10
cP (centipoise)
at initial reservoir conditions. Viscous oil includes oils generally defined
as "heavy oil" or
"bitumen." Bitumen is classified as an extra heavy oil, with an API gravity of
about 10 or
less, referring to its gravity as measured in degrees on the American
Petroleum Institute
(API) Scale. Heavy oil has an API gravity in the range of about 22.3 to about
10 . The
terms viscous oil, heavy oil, and bitumen are used interchangeably herein
since they may
be extracted using similar processes.
[0049] "In situ' is a Latin phrase for "in the place" and, in the context of
hydrocarbon
recovery, refers generally to a subsurface hydrocarbon-bearing reservoir. For
example, in
situ temperature means the temperature within the reservoir. In another usage,
an in situ
oil recovery technique is one that recovers oil from a reservoir below the
earth's surface.
[0050] The terms "formation" and "subterranean formation" refer to the
material existing
below the earth's surface. The subterranean formation may comprise a range of
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components, e.g. minerals such as quartz, siliceous materials such as sand and
clays, as
well as the oil and/or gas that is extracted. The subterranean formation may
be a
subterranean body of rock or sand that is distinct and continuous. The terms
"reservoir"
and "formation" may be used interchangeably.
[0051] The term "reservoir" may be used to refer to a regional volume
subterranean
formation that encompasses multiple SAGD well pairs or the volume of the
subterranean
formation that is local to a single SAGD well pair where that SAGD well pair
can drain the
oil.
[0052] "Pressure" is the force exerted per unit area by the gas on the walls
of the volume.
Pressure may be shown in this disclosure as pounds per square inch (psi),
kilopascals
(kPa) or megapascals (MPa). "Atmospheric pressure" refers to the local
pressure of the
air. "Absolute pressure" (psia) refers to the sum of the atmospheric pressure
(14.7 psia at
standard conditions) plus the gauge pressure. "Gauge pressure" (psig) refers
to the
pressure measured by a gauge, which indicates only the pressure exceeding the
local
atmospheric pressure (i.e., a gauge pressure of 0 psig corresponds to an
absolute
pressure of 14.7 psia). The term "vapor pressure" has the usual thermodynamic
meaning.
[0053] For a pure component in an enclosed system at a given pressure, the
component
vapor pressure is essentially equal to the total pressure in the system.
Unless otherwise
specified, the pressures in the present disclosure are absolute pressures.
[0054] The term "steam chamber" refers to the region of the reservoir where a
portion of
the reservoir's porosity is occupied by gas, including water vapor, and the
temperature is
near the steam temperature for the specific pressure in the reservoir. The
term "steam
chamber" may also be used for cases where there is both steam and solvent in
the vapor
phase. In the case of steam and solvent, the temperature in the steam chamber
will be
near the dew point temperature corresponding to the local molar fractions of
steam and
solvent.
[0055] "Azeotrope" means the thermodynamic azeotrope composition of a mixture
of
liquids whose proportions cannot be altered by distillation. As more
specifically used
herein, the azeotrope is characterized by a specific molar concentration of
solvent relative
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to steam. The related term "azeotrope temperature" refers to the temperature
of the
steam-solvent chamber at a defined pressure when the azeotrope composition is
reached.
The azeotrope temperature also represents the minimum dew point temperature
for a
steam-solvent system. At the azeotrope temperature the two fluids condense
together in
the same molar concentration as they exist in the gas. Figure 3 illustrates
the azeotrope
temperature for a steam-pentane system at a pressure of 2.5 MPa.
[0056] The term "Original Oil in Place" ("00IP") is a production term commonly
used in
the oil and gas industry. It is the best estimate of the volume of oil
initially contained within
a reservoir.
[0057] "Recovery Factor" is a production term commonly used in the oil and gas
industry.
It is a measure of the total production to date from a reservoir or well and
is commonly
measured as a fraction or percent of the 00IP.
[0058] The term "infill well" refers to a single horizontal well, drilled
between two adjacent
SAGD well pairs. Conventionally, an infill well will be constructed to produce
unproduced
oil between the two adjacent SAGD well pairs. In the process described herein,
an infill
well may be provided as an additional point of injection for steam or solvent
as well as an
additional point for production.
[0059] Estimated Ultimate Recovery ("EUR") is a production term commonly used
in the
oil and gas industry. Estimated Ultimate Recovery is an approximation of or
the current
best engineering estimate of the quantity of oil or gas that is potentially
recoverable from
a well or a SAGD well pair. Another term used in industry which is synonymous
with the
EUR is "Proved + Probable Reserves" which can be characterized as the volume
of oil
that has at least a 50% chance of being produced. Reserves are commonly
determined
by the operator and reported to regulators. Methods for estimating reserves
are described
in detail in Canadian Oil and Gas Evaluation Handbook (COGEH) published by the
Calgary Chapter of the Society of Petroleum Evaluation Engineers (SPEE) which
is an
industry standard for the evaluation of oil and gas properties. It is
recognized that there is
always uncertainty in this estimate prior to the final cessation of
production. Operators will
modify and update the EUR as the production of oil progresses. For SAGD
operations,
the EUR is commonly between 50 and 80% of the initial oil-in-place above the
production
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well. Reserves or the EUR is commonly reported for a group or pad of SAGD
wells. In
such a case, the EUR for a single SAGD well pair can be determined as the
total reserves
divided by the number of SAGD well pairs. The EUR may vary somewhat when
processes
such as SA-SAGD, VAPEX or AzeoVapex are applied but the same overall range is
generally applicable.
Description of Embodiments
[0060] Figure 1 shows a simplified cross-section of a SAGD well pair. Most
commonly in
commercial operations, there are multiple pairs of adjacent SAGD well pairs
where the
dimension W shown in Figure 1 is the spacing between SAGD well pairs..
[0061] Figure 2 shows dew point temperatures for different steam-solvent
systems as a
function of solvent mole fraction at equilibrium. When selecting a solvent, it
is desirable to
select a solvent with the lowest minimum dew point for the desired pressure.
The minimum
dew point temperature is also known as the azeotrope temperature.
[0062] The greater the difference between the steam temperature (solvent mole
fraction
= 0) and the minimum dew point temperature, the greater the available heat
that can be
scavenged and redistributed from the reservoir contacted during SAGD
operations.
[0063] As can be seen from Figure 2, lighter hydrocarbons have lower minimum
dew
points which is desirable. However, lighter hydrocarbons are also generally
less soluble
in bitumen so they may be less effective in reducing the viscosity of the
viscous oil resulting
in lower oil production rates.
[0064] An additional consideration is availability of the solvent. Many SAGD
operations
rely on mixing diluent with bitumen to ship the viscous oil to market from the
production
facility. Diluent commonly has high fractions of pentane but only small
fractions of butane
or propane. So pentane or a mix of alkanes with an average molecular weight
comparable
to pentane may be readily available.
[0065] As noted above, Figure 1 is a cross-section of a SAGD well pair. The
SAGD
injection well (101) and production well (102) are cross sections of wells
extending into
the plane of the page with a defined length (L ¨ not illustrated in Figure 1).
The reservoir
- 14 -
Date Recue/Date Received 2022-04-19
volume that is assigned to the well pair is commonly taken as the width (W)
times the
height (H) times the length (L). The 00IP for the well pair is the volume of
oil contained
within the volume WxHx L.
[0066] A common simplification used in industry is to characterize the steam
chamber as
having a triangular shape as shown in Figure 1. Reference numerals 103, 104
and 105
indicate the extent of the steam chamber at different points in time as steam
is injected,
as described in more detail below. The steam chamber is assumed to be uniform
along
the length of the well. Area 103 illustrates a point in time at which the
steam chamber
encompasses about 25% of the reservoir volume. Areas 103 and 104 added
together
illustrate the stage where the steam chamber encompasses about 50% of the
reservoir
volume at a later point in time as steam is injected. It is usually not
economical to operate
the SAGD wells until the steam chamber encompasses the entire reservoir
volume. Areas
103, 104 and 105 added together are illustrative of the steam chamber at the
end of SAGD
operations where the steam chamber encompasses about 87.5% of the reservoir
volume.
In this case, the recoverable oil within areas 103, 104 and 105 added together
is the EUR.
[0067] When determining the recovery factor at a given time, one must consider
the
reservoir porosity, (I), initial saturation of oil in the reservoir, Soi, and
the saturation after
depletion or the residual oil saturation, So,. In the common simplified model,
the volume of
oil recovered can be estimated as the reservoir volume occupied by the steam
chamber
times the porosity (d)) times the change in oil saturation (S0i-S01).
[0068] For the process to be advantageous, a significant volume of the
reservoir must be
encompassed by the steam chamber prior to solvent injection and it is also
beneficial if
the steam chamber has spread across a significant fraction of the reservoir.
Area 103 in
Figure 1 illustrates a point in time where these criteria are first reached as
the steam
chamber encompasses about 25% of the reservoir volume. At this time, the
recovery
factor will commonly be between about 15% and about 20% of the 00IP.
[0069] The process exploits the transfer of heat from the volume of the
reservoir that is
occupied by the steam chamber at the start of solvent injection to the
progressively
growing steam-solvent chamber after the start of solvent injection. The steam
chamber
volume can be determined, for example, by 3D seismic imaging or simulation
models.
- 15 -
Date Recue/Date Received 2022-04-19
However, such images or models may not exist for all SAGD well pairs. Recovery
factor
is an alternative measure that can be determined for all SAGD well pairs and
is an
alternative measure that directly relates to the volume of the steam chamber.
[0070] If pentane is selected as the solvent to inject, the average
temperature in the
steam-solvent chamber will progress as shown in Figure 3 for a case where the
steam-
solvent chamber has a constant pressure of 2.5 MPa. For example, initially
100% steam
may be injected until approximately 50% of the reservoir volume is occupied by
the steam
chamber as is illustrated by areas 103 and 104 in Figure 1. At this stage, all
of the steam
chamber illustrated by areas 103 and 104 will be at the steam temperature
(solvent mole
fraction = 0) in Figure 3. If at this stage an injection of either 100%
pentane gas or a
mixture of pentane and steam is started, the average solvent mole fraction in
the steam-
solvent chamber will increase and average temperature will decrease. By
appropriately
selecting the timing of the start of pentane injection, the temperature in the
entire steam-
solvent chamber (i.e. areas 103, 104 and 105 in Figure 1) will be at or near
the minimum
dew point temperature at the time of ultimate oil recovery or (EUR) is
reached.
[0071] Effectively, excess heat from the reservoir materials, primarily the
sand grains,
represented by areas 103 and 104 in Figure 1 at the end of steam-only
injection will be
redistributed to reservoir represented by area 105 as the viscous oil recovery
progresses
to the EUR. The primary physical mechanism by which this heat transfer will
occur is
evaporation of water in the existing steam-solvent chamber and subsequent
condensation
of the steam at the boundary of the steam-solvent chamber.
[0072] For this heat transfer to occur, there must be sufficient water in the
reservoir to
evaporate and sufficiently cool the region that had been heated to steam
temperatures.
Fortunately, all SAGD reservoirs have significant initial water saturations
and SAGD
operations may further increase the water saturations. Additionally, a water
cycle will
develop in the reservoir where the water is repeatedly vaporized and condensed
without
being produced.
[0073] Heat losses to the overburden and the underburden are also an important
consideration. Edmunds et al. have developed a simple model that calculates
the steam
to oil ratio required to produce viscous oil using SAGD (A Unified Model for
Prediction of
- 16 -
Date Recue/Date Received 2022-04-19
CSOR in Steam-Based Bitumen Recovery, N. Edmunds; J. Peterson, Paper presented
at
the Canadian International Petroleum Conference, Calgary, Alberta, June 2007.,
Paper
Number: PETSOC-2007-027). The model has two key terms. One term relates to the
heat
required to heat the reservoir sand, water and oil. The second term relates to
the heat loss
to the overburden and underburden. The Edmunds model and most reservoir
simulators
model the heat loss to the over and underburden using 1D analytical models.
Using these
same models, it can be shown that if the overburden or underburden boundary is
maintained at steam temperatures for a period of time and then subsequently
the
temperature at the boundary is reduced to a significantly lower temperature,
such as the
azeotrope temperature, there may be little or no additional heat loss to the
boundary as
the process continues. This, in effect, significantly reduces or eliminates
the second term
in the Edmunds model. From a practical perspective, when employing this
technology, the
steam injected during SAGD operations is used to provide most or all of the
heat required
to heat the overburden and underburden to achieve the ultimate recovery.
[0074] Another useful feature of the steam-solvent chamber is that at the
boundary of the
chamber where steam and solvent are condensing, the temperature is at or near
the
azeotrope temperature even when the average temperature of the steam-solvent
chamber
is much higher. This feature is readily observed in Figures 14, 15 and 16 of
Khaledi et al.,
2018 (Azeotropic Heated Vapour Extraction- A New Thermal-Solvent Assisted
Gravity
Drainage Recovery Process, Rahman Khaledi; Hamed Reza Motahhari; Thomas J.
Boone; Chen Fang; Adam S. Coutee, Paper presented at the SPE Canada Heavy Oil
Technical Conference, March 13-14, 2018, SPE-189755-MS) and is illustrated in
Figure
4A. If after a period of steam-only operations, solvent vapor is injected into
the steam
chamber, the temperatures will evolve as shown in Figure 4B. Most importantly
the
temperature at the boundary of the steam-solvent chamber rapidly reduces to at
or near
the azeotrope temperature after the initiation of solvent injection which aids
in reducing or
eliminating additional heat loss to the underburden and overburden after the
start of
solvent injection.
[0075] The simulated examples show significant benefits for both butane and
pentane
injection. Other alkanes may also be effective depending on the reservoir
pressures,
temperatures, and the availability of solvents. Heavier solvents such as
hexane tend to
- 17 -
Date Recue/Date Received 2022-04-19
have higher azeotropic temperatures making them less effective. Lighter
solvents such as
propane are less soluble in bitumen and may be less effective at reducing the
bitumen-
solvent mixture viscosities.
[0076] Mixtures of various hydrocarbons, such as what is commonly termed
"diluent" in
the industry, can be effectively used in the place of pentane or butane alone.
Specific
fractions of commercially available diluent can be employed. Solvents can be
extracted
from the produced hydrocarbons and reused in the reservoir.
[0077] Solvents or solvent steam mixtures are preferably injected
predominantly in the
vapor phase. Heat in the reservoir may vaporize some liquid solvent when
injected but
there is also a risk that liquid solvent will drain directly to the production
well and not aid
in producing viscous oil.
[0078] An alternative mechanism for reducing the reservoir temperature over
time is to
reduce the reservoir pressure which in turn reduces the steam temperature.
Where
practical, reducing the reservoir pressure can be employed prior to or in
conjunction with
solvent injection.
[0079] The benefits of the process can also be realized by injecting a first
solvent such as
pentane and then subsequently converting to injection of a second solvent such
as butane
with a lower minimum steam-solvent dew point than the first solvent.
[0080] In order to minimize the volume of solvent injected it is desirable to
delay solvent
injection until the steam chamber occupies at least about 25% to about 80% of
the
reservoir volume or the recovery factor reaches at least about 15% to about
70% of 00IP
However, if it is found that more oil can be viably recovered than estimated
and the
average steam-solvent chamber has declined to the azeotrope temperature, then
oil
production can be continued with H-Vapex or AzeoVapex.
[0081] Eventually, after a period of solvent injection, oil production rates
will decline and
it will become uneconomic to continue solvent injection into the SAGD well
pair. Various
methods may be employed after the end of solvent injection to recovery
additional viscous
oil and solvent that may remain in the reservoir. These methods may include
continued
- 18 -
Date Recue/Date Received 2022-04-19
production without any injection, with injection of non-condensable gases such
as natural
gas, methane or nitrogen or low-pressure steam injection.
[0082] Another benefit of initiating with steam injection then converting SAGD
well pairs
to solvent injection is that solvent is much more expensive than steam and it
is
advantageous to have developed a stable, well controlled steam chamber prior
to the
introduction of solvent so that there is a lower likelihood of losing or
displacing solvent in
a manner such that it cannot be recovered.
[0083] As an alternative embodiment to initially injecting steam-only, the SA-
SAGD
process may be employed where a relatively small fraction of solvent,
typically less than
20% by volume, is injected with the steam.
[0084] It is common practice now to drill one or more "infill wells" between
SAGD well
pairs at a point in time after initiation of SAGD operations. See, for
example, US Patent
No. 7,556,099B2 (Arthur). In an alternative embodiment of the process
described herein,
the process may include provision of one or more infill wells. In some
embodiments,
steam, solvent or both fluids may be injected into the infill well
intermittently or for the
entire period that the process performed. In some alternative embodiments,
production
may also occur from the infill wells.
[0085] Figure 9 is a process flow diagram illustrating one general embodiment.
Upon
characterization of a reservoir containing viscous hydrocarbons, the reservoir
volume will
be determined and a solvent or a composition of solvents will be selected in
accordance
with the characteristics of the viscous hydrocarbons. Steam is injected at an
appropriate
rate until the steam chamber encompasses about 25% to about 80% of the
reservoir's
volume. During this process, a steam chamber is formed with a concurrent
temperature
increase. At this point, steam injection is stopped and injection of a solvent
or a
composition of solvents will be started to generate a gradually increasing
average solvent
mole fraction in the steam-solvent chamber with a concurrent gradually
decreasing
average temperature in the steam-solvent chamber, occurring as a result of
evaporation
of water to steam in the steam-solvent chamber (see Figure 4B). This
temperature
decrease induces scavenging and redistribution of heat from the reservoir
occupied by the
steam chamber into the growing steam-solvent chamber, which, in turn, reduces
heat
- 19 -
Date Recue/Date Received 2022-04-19
requirements for continued production. An advantageous feature of the steam-
solvent
system is that at the boundary of the steam-solvent chamber the temperature
rapidly
approaches the azeotrope temperature after the start of solvent injection.
This greatly
reduces heat losses to the overburden and underburden after the start of
solvent injection.
The production continues with continuous solvent injection until 100% of the
EUR is
produced. It is to be understood that a specific time point for stopping
injection of steam
and starting injection of solvent may be selected based on a projection of the
EUR for a
specific solvent or solvent composition, in view of other production
parameters, such that
the entire input of energy is minimized. Alternatively, if solvent injection
does not begin at
that specific time point but instead begins earlier or later, it is to be
understood that, while
the process will not be exactly optimized for maximal energy savings,
significant energy
savings will still be obtained as a result of scavenging heat from the
formation as outlined
above. Therefore the process does not require detailed optimization to derive
a significant
economic benefit. It is also possible to adjust the time of solvent injection
to minimize the
total volume of solvent projected to be used by the process. An economic
benefit will also
be derived from the process if employed in this manner, by reducing the total
cost
associated with the solvent. Also shown in Figure 9 is an optional step of
separating
solvent from hydrocarbons produced from the reservoir followed by recycling
the solvent
back to the solvent injection step. Implementation of this step will reduce
total solvent input
into the process.
[0086] Figure 10 illustrates the steps of another embodiment of the process
which is
generally similar to the embodiment shown in Figure 9 with the exception that
the original-
oil-in-place (00IP) for the reservoir is determined and the solvent injection
begins at a
time point when at least 15% of the 00IP has been produced (as an alternative
to
estimating the percentage volume of the reservoir occupied by the steam
chamber). This
also represents a time point where sufficient heat provided by steam has been
provided
to the reservoir such that the steam chamber is sufficiently developed to
begin scavenging
and redistributing heat within the steam chamber for continued production of
viscous oil
without additional steam, thereby reducing the energy requirements for
continued
production.
Examples
-20 -
Date Recue/Date Received 2022-04-19
Example 1: Simulation Model for Embodiments of Hydrocarbon Recovery Using
Steam
and Solvent Injections
[0087] A fit-for-purpose simulation model was developed to model the process
and aid in
determining optimal implementation. Key features of the model are that it
accounts for the
phase behavior illustrated in Figures 2 and 3, it balances all heat and mass
flows, it models
progressive development of the steam-solvent chamber, it accounts for heat
losses to the
overburden and underburden using the Edmunds model and it accounts for cooling
and
water vaporization in the steam chamber. Consistent with analytical models and
field
observations a constant oil production rate is used to determine the rate of
growth for the
steam chamber. Parameters used in the simulation model are listed in Table 1.
Table 1: Process Model Simulation Parameters
Well and Reservoir Properties (Units) Value
Reservoir Height (m) 20
Well Spacing (m) 100
Well Length (m) 1000
Porosity 0.32
Initial Temperature ( C) 12.0
Initial Water Saturation 0.2
Initial Oil Saturation 0.8
Residual Oil Saturation 0.15
Initial Reservoir Heat capacity (kJ/m3/ C) 2231
Depleted Reservoir Heat capacity (kJ/m3/ C) 1815
Oil Production Rate (m3/day) 100
Fluid Properties
Reservoir Pressure (MPa) 2.5
Steam Temperature ( C) 224.5
Steam-Pentane Azeotrope Temperature ( C) 157.7
Steam-Pentane Azeotrope Mole Fraction Pentane 0.8
Steam-Butane Azeotrope Temperature ( C) 125
Steam-Butane Azeotrope Mole Fraction Pentane 0.92
Edmunds Steam-Oil-Ratio Parameters
Reservoir Heat Capacity (kJ/m3/ C 2231
Overburden Heat Capacity (kJ/m3/ C) 2231
- 21 -
Date Recue/Date Received 2022-04-19
Overburden Heat Conduction (MJ/m K year) 85
[0088] Figure 5 shows results of the simulations for cases where (i) SAGD is
operated
with steam-only injection until a recovery level of 52% of 00IP is reached and
then 100%
pentane vapor is injected until the recovery level reaches the EUR of 71% of
00IP and
(ii) SAGD is operated with steam-only injection until a recovery level of 47%
of 00IP is
reached then azeotropic pentane-steam vapor is injected until the EUR is
reached. The
timing of the start of pentane injection was selected in both cases to result
in a final
average temperature in the steam-solvent chamber close to the azeotropic
temperature
for pentane-steam mixtures.
[0089] The benefits of azeotropic steam-solvent injection are described in
Khaledi et al.,
2018. In Figure 5, it can be seen to allow for earlier implementation of
conversion to solvent
injection.
[0090] Figure 6 shows results of the simulations for cases where (i) SAGD is
operated
with steam-only injection until a recovery level of 41% of 00IP then 100%
butane vapor
is injected until the EUR of 71% of the oil-in-place is reached and (ii) SAGD
is operated
with steam-only injection until a 37% recovery of 00IP then azeotropic butane-
steam
vapor is injected until the EUR is reached. The timing of the start of butane
injection was
selected in both cases to result in a final average temperature in the steam-
solvent
chamber close to the azeotropic temperature for butane-steam mixtures.
[0091] When comparing the plots in Figures 5 and 6, one can see that the final
temperatures in the cases of butane injection are significantly lower than
with pentane
injection. As result the process of solvent injection can be started earlier
with butane than
with pentane.
[0092] The benefit of a greatly reduced heat requirement is illustrated in
Figure 7. The
heat requirement to achieve the same ultimate recovery is compared between
SAGD,
AzeoVapex, and the simulated cases as measured in terms of equivalent cold
water
equivalent steam volumes as is customarily used in the industry. Compared to
SAGD,
AzeoVapex with pentane injection requires approximately 69% of the heat to
achieve the
-22 -
Date Recue/Date Received 2022-04-19
same EUR. The process of described herein with steam-only injection followed
by pentane
only and azeotropic pentane-steam require approximately 78% and 77%,
respectively, of
the heat of SAGD. Similarly, compared to SAGD, AzeoVapex utilizing butane
injection
requires approximately 54% of the heat to achieve ultimate recovery. The
process
described herein with steam-only injection followed by butane only and
azeotropic butane-
steam requires approximately 63% and 62%, respectively, of the heat of SAGD.
The
process described herein captures most of the benefit of the AzeoVAPEX as
measured
by heat reduction and is much superior to operating SAGD for the full recovery
period.
[0093] Figure 8 compares the volumes of both steam and solvent for all the
cases. The
processes described herein use measurably less steam and, most critically, an
order of
magnitude less solvent to achieve the same EUR. The latter is of great
practical
significance.
Equivalents and Scope
[0094] Other than described herein, or unless otherwise expressly specified,
all of the
numerical ranges, amounts, values and percentages, such as those for amounts
of
materials, elemental contents, times and current rate, ratios of amounts, and
others, in the
following portion of the specification and attached claims may be read as if
prefaced by
the word "about" even though the term "about" may not expressly appear with
the value,
amount, or range. Accordingly, unless indicated to the contrary, the numerical
parameters
set forth in the following specification and attached claims are
approximations that may
vary depending upon the desired properties sought to be obtained. At the very
least, each
numerical parameter should at least be construed in light of the number of
reported
significant digits and by applying ordinary rounding techniques.
[0095] The terms "approximately," "about," "substantially," and similar terms
are intended
to have a broad meaning in harmony with the common and accepted usage by those
of
ordinary skill in the art to which the subject matter of this disclosure
pertains. It should be
understood by those of skill in the art that these terms are intended to allow
a description
of certain features described and claimed without restricting the scope of
these features
to the precise numeral ranges provided. Accordingly, these terms should be
interpreted
as indicating that insubstantial or inconsequential modifications or
alterations of the
subject matter described and are considered to be within the scope of the
disclosure.
-23 -
Date Recue/Date Received 2022-04-19
[0096] The articles "the", "a" and "an" are not necessarily limited to mean
only one, but
rather are inclusive and open ended so as to include, optionally, multiple
such elements.
[0097] "At least one," in reference to a list of one or more entities should
be understood
to mean at least one entity selected from any one or more of the entities in
the list of
entities, but not necessarily including at least one of each and every entity
specifically
listed within the list of entities and not excluding any combinations of
entities in the list of
entities. This definition also allows that entities may optionally be present
other than the
entities specifically identified within the list of entities to which the
phrase "at least one"
refers, whether related or unrelated to those entities specifically
identified. Thus, as a non-
limiting example, "at least one of A and B" (or, equivalently, "at least one
of A or B," or,
equivalently "at least one of A and/or B") may refer, to at least one,
optionally including
more than one, A, with no B present (and optionally including entities other
than B); to at
least one, optionally including more than one, B, with no A present (and
optionally
including entities other than A); to at least one, optionally including more
than one, A, and
at least one, optionally including more than one, B (and optionally including
other entities).
In other words, the phrases "at least one," "one or more," and "and/or" are
open-ended
expressions that are both conjunctive and disjunctive in operation. For
example, each of
the expressions "at least one of A, B and C," "at least one of A, B, or C,"
"one or more of
A, B, and C," "one or more of A, B, or C" and "A, B, and/or C" may mean A
alone, B alone,
C alone, A and B together, A and C together, B and C together, A, B and C
together, and
optionally any of the above in combination with at least one other entity.
[0098] Where two or more ranges are used, such as but not limited to 1 to 5 or
2 to 4, any
number between or inclusive of these ranges is implied.
[0099] As used herein, the phrase, "for example," the phrase, "as an example,"
and/or
simply the term "example," when used with reference to one or more components,
features, details, structures, and/or methods according to the present
disclosure, are
intended to convey that the described component, feature, detail, structure,
and/or method
is an illustrative, non-exclusive example of components, features, details,
structures,
and/or methods according to the present disclosure. Thus, the described
component,
feature, detail, structure, and/or method is not intended to be limiting,
required, or
exclusive/exhaustive; and other components, features, details, structures,
and/or
-24 -
Date Recue/Date Received 2022-04-19
methods, including structurally and/or functionally similar and/or equivalent
components,
features, details, structures, and/or methods, are also within the scope of
the present
disclosure.
[00100] The
term "comprising" is intended to be open and permits but does not
require the inclusion of additional elements or steps. When the term
"comprising" is used
herein, the term "consisting of' is thus also encompassed and disclosed. Where
ranges
are given, endpoints are included. Furthermore, it is to be understood that
unless
otherwise indicated or otherwise evident from the context and understanding of
one of
ordinary skill in the art, values that are expressed as ranges can assume any
specific
value or subrange within the stated ranges in different embodiments, to the
tenth of the
unit of the lower limit of the range, unless the context clearly dictates
otherwise. Where
the term "about" is used, it is understood to reflect +/- 10% of the recited
value. In addition,
it is to be understood that any particular embodiment that falls within the
prior art may be
explicitly excluded from any one or more of the claims. Since such embodiments
are
deemed to be known to one of ordinary skill in the art, they may be excluded
even if the
exclusion is not set forth explicitly herein.
-25 -
Date Recue/Date Received 2022-04-19
