Note: Descriptions are shown in the official language in which they were submitted.
CA 2968392 2017-05-24
VARIABLE PRESSURE SAGD (VP-SAGD) FOR HEAVY OIL RECOVERY
FIELD OF THE INVENTION
[0001] The invention is in the field of hydrocarbon reservoir
engineering, particularly
thermal recovery processes such as steam-assisted gravity drainage (SAGD)
systems
in heavy oil reservoirs.
BACKGROUND OF THE INVENTION
[0002] Crude heavy oil and bitumen are characterized with high
viscosities (i.e.,
higher than 100 mPa.s for heavy oil and 10,000 mPa.s for bitumen) and low API
(American Petroleum Institute) gravities (i.e., lower than 20.0 API for heavy
oil and
10.0 API for bitumen) [Speight, 1991]. These conditions make them immobile
under
reservoir conditions. Open-pit mining and in situ methods are the two main
techniques
used for recovering heavy oil and bitumen. Open-pit is feasible for bitumen
deposits less
than 100 m deep and has a limited future capacity since 80 percent of the oil
sand
resources lie too deep underground to mine. In situ production primarily
relies on two
commercial thermal recovery methods: cyclic steam stimulation (CSS) and steam-
assisted gravity drainage (SAGD). Both of these processes employ steam to heat
and
dilute bitumen to make it mobile enough to recover.
'
[0003] Cyclic steam stimulation (CSS) is commonly known as "huff and puff'
and
was the first commercially applied process to recover heavy oil/bitumen. In
this process,
a vertical/horizontal well is used cyclically as a steam injector and an oil
producer. In a
typical cycle of conventional CSS, steam is first injected into a formation at
a
temperature of 300-400 C and a pressure up to 2,000 psi for a period of time
("injection"). Then the well is shut in for several days to weeks to let steam
condense
and release the latent heat into a formation ("soaking"). Finally, the well is
re-opened to
produce heated oil and steam condensate that are pumped to the surface until
the
production rate declines to an economic limit ("production"). Throughout this
process an
expanding "steam chamber" is gradually developed due to the depletion of heavy
oil/bitumen.
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[0004] In conventional SAGD, parallel horizontal wells are applied with one
right
above the other by about 5 meters. Initially, steam is circulated through both
wells to
warm up the areas around the wells, and the heated oil nearby is produced
until the two
wells are communicated. The production of heavy oil/bitumen leads to the
development
of a steam chamber around the steam injector. The saturated steam is injected
into the
steam chamber at a constant temperature of 150-300 C and below a fracture
pressure.
Steam condenses at the steam chamber boundary and releases its latent heat to
crude
oil. The heavy oil/bitumen is diluted, becomes mobile, and drains along the
steam
chamber boundary to the production well at the bottom of a reservoir, where it
is
pumped out to the surface by a natural lift, a gas lift, or a submersible
pump.
[0005] Atypical SAGD process is disclosed in Canadian Patent No.
1,130,201
issued on 24 August 1982, in which two wells are drilled into a deposit, one
for injection
of steam and the other for production of oil and water. Steam is injected via
the injection
well to heat the formation. It condenses and gives its latent heat to
reservoir rock and
the inside fluids. The viscous hydrocarbons are thereby mobilized, and drained
with an
aqueous condensate by gravity toward the production well. In this way, the
injected
steam initially mobilizes the in-place hydrocarbon to create a "steam chamber"
in the
reservoir around and above the horizontal injection well. The term "steam
chamber"
accordingly refers to the volume of the reservoir which is generally saturated
with
injected steam in the presence of residual oil and water, and from which
mobilized oil
has at least partially drained. Mobilized viscous hydrocarbons are recovered
continuously through the production well. The conditions of steam injection
and of
hydrocarbon production may be modulated to control the growth of the steam
chamber
to ensure that the steam chamber remains above the production well, with the
production well in an appropriate position to collect mobilized hydrocarbons.
[0006] Variants of the SAGD and CSS processes have been described. For
example, US. Pat. No. 4,344,485, 1982 discloses steam-assisted gravity
drainage
(SAGD) processes wherein steam is injected via an upper horizontal well
section to
transfer heat to the normally immobile heavy oil so that it will melt and will
drain by
gravity to a lower horizontal well section where the oil is recovered. Butler
(1999)
describes a steam and gas push (SAGP) process in which steam is co-injected
with a
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non-condensable gas such as natural gas. Gas accumulates in the chamber above
an
injector and lowers the average temperature in the reservoir by reducing heat
loss to the
overburden. Rising gas fingers increase the pressure towards the top of the
reservoir
and displace oil downwards even though the temperature is below that of
saturated
steam, and they also penetrate into the cooler oil because of their higher
mobility. The
gas in the chamber comes from the combination of added gas, solution gas, and
gas
generated by chemical reactions, minus gas produced with the oil and the net
gas
driven to or coming from outside the depleted region by pressure difference.
Ba ci, S.,
& GOrnrah, F. (1992) Journal of Petroleum Science and Engineering, 8(1), 59-
72,
described cyclic and continuous steam-injection processes using horizontal
wells to
produce heavy oils ¨ specifically a horizontal injector and a horizontal
producer. For
each cycle, first the steam is injected (injection period), and then the
injection well and
production well are closed for some time. After the soaking period, the well
was opened
for production. International Patent Publication WO 2013181750 Al ¨2013
describes a
method for a production well in a SAGD process to increase hydrocarbon
recovery from
a hydrocarbon reservoir, wherein the SAGD process occurs at a site including
an
injection well, a production well and a steam chamber. The method includes
shutting the
production well and maintaining or increasing steam injection through the
injection well
until pressure in the steam chamber increases. Then, while continuing steam
injection,
production is resumed at rates for normal SAGD or greater until reservoir
pressure
reaches normal operating pressure.
[0007] In the context of the present application, various terms are used
in
accordance with what is understood to be the ordinary meaning of those terms.
For
example, "petroleum" is a naturally occurring mixture consisting predominantly
of
hydrocarbons in the gaseous, liquid or solid phase. In the context of the
present
application, the words "petroleum" and "hydrocarbon" are used to refer to
mixtures of
widely varying composition. The production of petroleum from a reservoir
necessarily
involves the production of hydrocarbons, but is not limited to hydrocarbon
production.
Similarly, processes that produce hydrocarbons from a well will generally also
produce
petroleum fluids that are not hydrocarbons. In accordance with this usage, a
process for
producing petroleum or hydrocarbons is not necessarily a process that produces
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exclusively petroleum or hydrocarbons, respectively. "Fluids", such as
petroleum fluids,
include both liquids and gases. Natural gas is the portion of petroleum that
exists either
in the gaseous phase or is in solution in crude oil in natural underground
reservoirs, and
which is gaseous at atmospheric conditions of pressure and temperature.
Natural gas
may include amounts of non-hydrocarbons. The abbreviation POIP stands for
"producible oil in place" and in the context of the methods disclosed herein
is generally
defined as the exploitable or producible oil structurally located above the
production well
elevation.
[0008] It is a common practice to segregate petroleum substances of high
viscosity
and density into two categories, "heavy oil" and "bitumen". For example, some
sources
define "heavy oil" as a petroleum that has a mass density of greater than
about 900
kg/m3. Bitumen is sometimes described as that portion of petroleum that exists
in the
semi-solid or solid phase in natural deposits, with a mass density greater
than about
1,000 kg/m3 and a viscosity greater than 10,000 centipoise or 10 Pa.s measured
at
original temperature in the deposit and atmospheric pressure, on a gas-free
basis.
Although these terms are in common use, references to heavy oil and bitumen
represent categories of convenience, and there is a continuum of properties
between
heavy oil and bitumen. Accordingly, references to heavy oil and/or bitumen
herein
include the continuum of such substances, and do not imply the existence of
some fixed
and universally recognized boundary between the two substances. In particular,
the
term "heavy oil" includes within its scope all "bitumen" including
hydrocarbons that are
present in semi-solid or solid form.
[0009] A reservoir is a subsurface (or subterranean) formation
containing one or
more natural accumulations (or deposits) of moveable petroleum, which are
generally
confined by relatively impermeable rock. An "oil sand" (or formerly "tar
sand") reservoir
is generally comprised of strata of sand or sandstone containing petroleum. A
"zone" in
a reservoir is merely an arbitrarily defined volume of the reservoir,
typically
characterised by some distinctive property. Zones may exist in a reservoir
within or
across strata, and may extend into adjoining strata. In some cases, reservoirs
containing zones having a preponderance of heavy oil are associated with zones
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containing a preponderance of natural gas. This "associated gas" is gas that
is in
pressure communication with the heavy oil within the reservoir, either
directly or
indirectly, for example, through a connecting water zone.
[0010] A "chamber" within a reservoir or formation is a region that is
in fluid
communication with a particular well or wells, such as an injection or
production well.
For example, in a SAGD process, a steam chamber is the region of the reservoir
in fluid
communication with a steam injection well, which is also the region that is
subject to
depletion, primarily by gravity drainage, into a production well.
SUMMARY
[0011] Variable Pressure-SAGD (VP-SAGD) is a process that mingles the
operation
scheme of SAGD and CSS. Over a life of a conventional SAGD process, the SAGD
operating scheme is first practiced. After a steam chamber is initially
developed, at a
certain stage (better at an early or an intermediate stage) the steam injector
is shut in
while the producer is kept open and the production constraints are adjusted to
let the
pressure in the steam chamber drop quickly. Once the pressure in the steam
chamber
(monitored at the injector) declines to a specific level the steam injection
is resumed at a
higher rate than that before the injector was shut in in order to restore the
production
constraints to their previous levels. If required this pressure drawdown
process may be
repeated at a later stage of a SAGD process.
BRIEF DESCRIPTION OF THE DRAWINGS
[0012] Figure 1 is a perspective illustration in a cross section of a
modeled reservoir,
showing the reservoir model for a simulation base case.
[0013] Figure 2 is a line graph illustrating crude heavy oil viscosity
vs. temperature
at 101.325 kPa.
[0014] Figure 3 includes three plots, showing (a) oil and water relative
permeability,
(b) gas and oil relative permeability, and (c) three-phase relative
permeability.
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[0015] Figure 4 illustrates the simulation results of enhanced SAGD: (a) a
recovery
factor and an oil production rate and (b) cumulative and instantaneous
steam¨oil ratios
(Note: "VP-SAGD" denotes "enhanced SAGD").
[0016] Figure 5 illustrates the steam chamber development of SAGD and VP-
SAGD.
[0017] Figure 6 includes two plots that illustrate (a) temperature and
pressure
profiles and (b) a pressure versus temperature profile during the pressure
drawdown
and buildup of VP-SAGD.
[0018] Figure 7 includes two plots that illustrate the effect of a steam
release rate
during pressure drawdown on VP-SAGD: (a) pressure and (b) recovery factor
(RF).
[0019] Figure 8 includes two plots that illustrate the effect of turning
pressure or Pmin
on the (a) pressure and (b) RF of VP-SAGD.
[0020] Figure 9 includes two plots that illustrate the effect of a steam
injection rate
on the (a) pressure and (b) RF of VP-SAGD.
[0021] Figure 10 includes two plots that illustrate the effect of
starting time on VP-
SAGD performance: (a) RF and (b) cSOR.
[0022] Figure 11 includes two plots that illustrate the effect of
starting time and
turning pressure on final (a) RF and (b) SOR of VP-SAGD (t = 1/1/2029).
[0023] Figure 12 includes three plots that illustrate the effects of
different SAGD
stabilized pressures on the VP-SAGD performance: (a) p = 2550 kPa and T = 225
C,
(b) p = 4000 kPa and T= 250 C, and (c) p = 5080 kPa and T = 265 C.
[0024] Figure 13 includes two plots that illustrate the effects of
absolute permeability
on (a) RF and (b) RF ratio of VP-SAGD and SAGD.
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[0025] Figure 14 includes three plots that illustrate the effect of
heterogeneity of (a)
permeability and (b) porosity on (c) RF and cSOR of VP-SAGD.
[0026] Figure 15 includes three plots illustrating (a) the effect of
starting time on final
cRF (t = 1/1/2029) for Swc = 13%, (b) optimum turning pressure at different
starting time
for Swc = 13%, and (c) optimum turning pressure at different starting time for
Swc = 13%.
[0027] Figure 16 includes three plots illustrating (a) the effect of
starting time on final
RF (t = 1/1/2029) for Swc = 23%, (b) optimum turning pressure at different
starting time
for Swc = 23%, and (c) optimum turning pressure at different starting time for
Swc = 23%.
[0028] Figure 17. The effect of payzone thickness (H = 20 or 30 m) on
the (a) RF
and (b) cSOR of VP-SAGD.
[0029] Figure 18. (a) Impermeable interlayer distribution and (b) RF of
SAGD and
VP-SAGD with the impermeable interlayers.
[0030] Figure 19 is a graph illustrating RF and cSOR of multiple cycle
VP-SAGD vs.
SAGD.
[0031] Figure 20 is a graph illustrating SAGD and VP-SAGD performance in a
real
field case.
[0032] Figure 21 includes two plots illustrating the effect of gas
injection pressure on
the (a) RF profiles and (b) final RF of VP-SAGD.
[0033] Figure 22 includes two plots illustrating the effect of gas
injection duration on
the RF profiles and final RFs of VP-SAGD.
DETAILED DESCRIPTION OF THE INVENTION
[0034] In accordance with various aspects of the invention, detailed
computational
simulations of reservoir behaviour have been carried out to describe and
analyze the
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new process, named VP-SAGD. The fluid and reservoir properties and the basic
operating conditions are listed in Tables 1 and 2. The simulation model, crude
heavy oil
viscosity vs. temperature and multi-phase permeability profiles used in this
study are
shown in Figs. 1-3, respectively.
Table 1. Properties and parameters of a simulation base case.
Reservoir
Dimension (m x m x m) 50 x 100
x 30
Number of grid blocks 50 x 1 x
30
Permeability (Darcy) 1
Porosity (vol.%) 30
Fluid
Crude heavy oil content 8.23
mol.% oil, 91.77 mol. /0
Heavy oil gravity 0.975
Heavy oil viscosity Fig. 2
Relative permeability Figs. 3
Initial conditions
Pressure (kPa) 3000
Temperature ( C) 16
Operation
Injector depth (m) 525
Producer depth (m) 530
Steam injection temperature 250
Steam injection pressure 4000
Steam quality (unity) 0.8
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Table 2. Operation constraints for each cycle of VP-SAGD.
SAGD process
Inector BHP bottom hole pressure MAX, kPa 4000
j
STW surface water rate MAX, m3/day 40
BHP bottom hole pressure MIN, kPa 3000
Producer STL surface liquid rate MAX, m3/day 30
STEAM steam rate MAX, m3/day 0.1
Pressure drawdown process
Injector Shut in
Shut in for 0-7 days and then
Producer STL surface liquid rate MAX, m3/day 30
STEAM steam rate MAX, m3/day 5.0
[0035] Fig. 4 provides the simulation results of a conventional SAGD and
a typical
VP-SAGD. Compared to SAGD, the final RF of VP-SAGD is higher by 8.1% and its
cSOR is lower by 0.4 clearly demonstrating the greater potential of VP-SAGD.
[0036] Without being limited to the theory, in some embodiments, the
process may
be adapted to implement specific mechanisms, particularly specific mechanisms
of heat
transfer. Heat transfer from the steam to the bitumen and the gravity drainage
of diluted
bitumen are two of the most important recovery mechanisms of SAGD. During the
heat
transfer from the steam to the bitumen the steam chamber pressure is
maintained
constant throughout the SAGD process. The convection velocity or pressure
gradient
across a heat transition zone is very limited so the heat transfer is
dominated by
conduction rather than by convection. In VP--SAGD, the steam chamber pressure
is first
drawn down and then built up, which may be implemented so as to cause a
significant
pressure difference across the heat transition zone and thus enlarge the
convection
effect. This is evident by the thinner transition-zone thickness of VP-SAGD
(Figs. 5c-d).
[0037] In addition, during the pressure drawdown period, pressure may be
adjusted
so as to drop sharply while temperature declines slowly, as shown in Fig. 6a.
More
specifically, it can be seen that the pressure versus temperature profile
falls along the
vapour line above 2,800 kPa. Afterwards, the profile drops almost vertically.
This may,
for example, be carried out so that the decreased pressure makes the steam
over-
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saturated and easy to condense accelerating the pressure drop. During the
pressure
restoration process, in some embodiments, the pressure versus temperature
profile first
rises quickly and then follows the vapour line since the injected fluid is
pure steam (Fig.
6b).
[0038] The gravity drainage of heated bitumen is generally largely
determined by a
slip angle. In most bitumen reservoirs, permeability in the horizontal
direction is greater
than in the vertical direction due to the geological deposition. In SAGD, the
contrast
between horizontal and vertical permeability may result in a slimmer and
slimmer slip
angle over time. This may be especially true near the reservoir bottom where
it can
seriously reduce the oil drainage rate. In the present process, the pressure
drawdown
and buildup process may accordingly be adapted to provide time for the heated
bitumen
to slip down from a chamber side and accumulate at the chamber bottom,
augmenting
the interface slope (Figs. 5c-d) and benefiting the oil drainage rate during
the
subsequent gravity drainage process.
[0039] A variety of operating conditions may be imposed at various
stages of the
process of the invention, and these may vary from one embodiment to another.
Selected embodiments of particular operating conditions are described below.
Pressure drawdown rate
[0040] During the pressure drawdown process the producer may, for
example, be
shut in, for example, for a few days, to allow the heat to soak into the heavy
oil. Then
the same producer may be opened and the steam rate at the surface increased.
The
production of steam, water and oil may be adjusted to quickly bring down the
steam
chamber pressure. In Fig. 7 a comparison between the effect of a steam rate
and the
decline rate of the injector BHP (bottom-hole pressure) is outlined. For
subsequent oil
production the steam chamber pressure may, for example, be brought down as
quickly
as possible. In other words, the steam rate may be set as high as possible
during the
pressure drawdown process.
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Turning pressure
[0041] A turning pressure (Pmin) is defined as the terminal and minimum
pressure of
the pressure drawdown period. It is also the starting pressure for the
following gravity
drainage process. Fig. 8 shows the effect of the turning pressure on the oil
recovery
factor profiles. It is found that for the base case (the starting point is RF
= 25%), higher
Pmin leads to a quicker production response but with a lower final recovery.
In some
embodiments, Pmin = 250-500 kPa may be the optimum turning pressure range.
Pressure buildup rate
[0042] Once the BHP reaches Pmin, steam injection may be resumed.
Consequently,
the steam chamber pressure is gradually restored, for example, to the previous
SAGD
operation pressure, and then it may be maintained at that level. Fig. 9
analyzes the
steam injection rate or pressure buildup rate on the VP-SAGD performance. It
is found
that the pressure buildup rate is significantly related to the oil production
response but
only slightly impacts the eventual oil recovery. Accordingly, in some
embodiments, the
steam injection rate for the second or subsequent SAGD processes may be set as
high
as possible in the short run, and may, for example, be varied in the long run.
Timing
[0043] Fig. 10 analyzes the effect of the starting time of the pressure
drawdown on
the VP-SAGD performance. It is found with the given reservoir properties
(porosity,
permeability, and initial water saturation), a starting point of approximately
RF = 20%
may give the highest recovery factor and lowest cSOR at a later particular
time point.
Fig. 11 shows the effect of the starting time and turning pressure on the
final (a) RF and
(b) SOR of VP-SAGD. In the selected embodiments, the starting time at RF = 15-
30%
may, for example, achieve an optimal recovery enhancement and SOR reduction.
SAGD pressure/temperature
[0044] Fig. 12 shows the effects of three different SAGD pressures on
the VP-SAGD
performance: p = 2550 kPa and T= 225 C, p = 4000 kPa and T= 250 C, and p =
5080
kPa and T= 265 C. The relative RF enhancement at the same time for the three
cases
are 20.3%, 14.3%, and -0.1%, respectively. This illustrates that applying the
VP-SAGD
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scheme to lower-pressure SAGD operations can in some implementations achieve a
significant production improvement.
Reservoir Properties
Permeability
[0045] Fig. 13 shows the RF and SOR of SAGD and VP-SAGD for three cases with
different permeabilities (K = 1, 3, and 5 Darcy). It has been determined that
in the
illustrated embodiment VP-SAGD has a higher RF and lower SOR than SAGD in all
cases. The greater the permeability the quicker the production response while
smaller
permeability saves more time. For instance, for a final RF of 60%, the VP-SAGD
of K =
5 Darcy saves 2.67 yrs from SAGD, the K = 3 Darcy case saves 2.88 yrs, and the
K = 1
Darcy case saves 6.68 yrs. For heterogeneous permeability and porosity, the
advantages of VP-SAGD over SAGD are more or less the same as shown in Fig. 14.
Initial water saturation
[0046] Initial water saturation may have a great effect on the VP-SAGD
performance.
For Swc = 13%, Fig. 15 shows the final recovery factor (t =1/1/2029) for
different turning
pressures (Pmin = 1500, 1000, 500, 250, and 150 kPa) along a SAGD life
(starting RF =
5, 10, 15, 20, 25, 30, 35, 40, 45, and 50%). It is found that in the selected
embodiments
optimum pressures for different starting times are distinct. In some cases, in
the early
and middle stages, a lower turning pressure may lead to more oil production,
whereas
at the late stages, the best turning pressure may gradually increase from 150
kPa to
950 kPa. Fig. 15c illustrates the general trend of the optimum turning
pressure.
[0047] For Sc = 23%, in the exemplified embodiment, the situation is
different
although the general trend remains the same. Lower turning pressures work well
only in
the early stages. Higher turning pressures perform better than lower ones at a
late
stage. As shown in Fig. 16, in the selected cases, a turning pressure of
approximately
1100 kPa may provide the best performance after RF = 25%.
Payzone thickness
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[0048] Fig. 17 shows the effect of payzone thickness (H = 20 and 30 m) on
the RF
and cSOR of VP-SAGD. In the exemplified embodiment, the RF enhancement and
cSOR reduction of VP-SAGD in a thinner reservoir are more or less the same as
those
in a thicker one.
-- Impermeable interlayer
[0049] An impermeable interlayer may greatly affect the VP-SAGD
performance
depending on the distribution and location of the impermeable interlayer, as
shown in
Fig. 18.
-- Multiple cycles
[0050] Fig. 19 shows a multi-cycle VP-SAGD. The first cycle starts at RF
= 15%,
while the second cycle starts randomly at RF = 42%. The final RF at t =
1/1/2029 of VP-
SAGD with two cycles is 66.2%, which is slightly higher than the final RFs of
VP-SAGD
with one cycle (65.8%) and significantly higher than that of conventional SAGD
(RF =
-- 58.5%). Therefore, in alternative embodiments, multiple cycles can be
applied to VP-
SAGD, dependent on the reservoir properties and operation parameters.
Real field case
[0051] Fig. 20 shows VP-SAGD performance with real reservoir and fluid
properties
-- and operating conditions. For a real field case, the RF at t = 1/1/2019,
which is 15 years
after the pressure fluctuation, is improved by 8.2% and cSOR increased by
0.45.
Further Improvement by Adding Non-Condensable Gas
[0052] In some embodiments, injection of a slug of non-condensable gas
(such as
-- 002, N2, CH4, 002, etc.), for example, at a pressure higher than the SAGD
operation
pressure, before pressure drawdown, can be adapted to result in a larger final
RF. The
high-pressure non-condensable gas may, for example, be injected so as to
induce a
greater pressure difference later on to provide stronger stimulation of the
heated heavy
oil at a steam chamber boundary. This may be adapted to result in a larger
slip angle
-- and higher VP-SAGD performance. In some embodiments, the non-condensable
gas
may, for example, accumulate at the top part of a steam chamber, for example,
so as to
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help reduce the heat losses to the overburden formation in the subsequent VP-
SAGD
process. The following section analyzes the injection of a slug of non-
condensable gas
on the RF and SOR of VP-SAGD.
[0053] Fig. 21 shows that the gas injection pressure exerts a big
difference on the
recovery profiles. In the selected embodiments, the optimum gas injection
pressure in
terms of the highest RF may, for example, be around p = 4,300-4,500 kPa, which
is
300-500 kPa higher than the normal SAGD operating pressure (p = 4,000 kPa).
[0054] A gas injection pressure of p = 4,500 kPa is selected to
investigate the effect
of gas injection duration on the final RF at t = 1/1/2029. Fig. 22 shows that
the gas
injection duration has an invisible effect on the RF profiles. Nevertheless,
it is found that
one week's injection is the best injection length as long as the steam chamber
pressure
reaches the pre-specified value, i.e., p = 4,500 kPa.
[0055] As discussed above, various aspects of the invention involve the
drilling of
one or more wells that are situated and operated so as to form a hydrocarbon
extraction
chamber within a reservoir. This may, for example, include SAGD well pairs
within a
reservoir, with each injection well paired with a corresponding production
well. Each well
may have a completion on the surface, for example, with a generally vertical
segment
leading to the heel of the well, which then extends along a generally
horizontal segment
to the toe of the well. In very general terms, to provide a general
illustration of the scale
in the selected embodiments, these well pairs may, for example, be drilled in
keeping
with the following parameters. There may be approximately 5 m depth separation
between the injection well and production well. The SAGD well pair may, for
example,
average approximately 800 m in length, although a wide range of alternatives
are
possible, for example, from about 200 m to about 1,600 m. The lower production
well
profile may generally be targeted so that it is approximately 1 to 2 m above
the reservoir
base.
[0056] It will be appreciated that the VP-SAGD recovery techniques can be
practiced
in combination with other hydrocarbon recovery processes. A very wide variety
of
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alternative techniques may be combined with VP-SAGD, including conventional
SAGD,
for example, consecutively or in alteration.
[0057] In alternative embodiments, using steam additives such as
solvents or other
chemical additives may enhance VP-SAGD. Solvents or other chemical additives
may,
for example, include xylene, toluene, diesel, propane, butane, pentane,
hexane, diluent,
condensate, C7-C10 hydrocarbons, surfactants, other polar compounds, or
combinations thereof.
Conclusion
[0058] Although various embodiments of the invention are disclosed herein,
many
adaptations and modifications may be made within the scope of the invention in
accordance with the common general knowledge of those skilled in this art. For
example, any one or more of the injection or production wells may be adapted
from well
segments that have served or serve a different purpose so that the well
segment may
be re-purposed to carry out aspects of the invention, including, for example,
the use of
multilateral wells as injection or production wells. Such modifications
include the
substitution of known equivalents for any aspect of the invention in order to
achieve the
same result in substantially the same way. Numeric ranges are inclusive of the
numbers
defining the range. The word "comprising" is used herein as an open-ended
term,
substantially equivalent to the phrase "including but not limited to", and the
word
"comprises" has a corresponding meaning. As used herein, the singular forms
"a", "an"
and "the" include plural referents unless the context clearly dictates
otherwise. Thus, for
example, reference to "a thing" includes more than one such thing. Citation of
references herein is not an admission that such references are prior art to
the present
invention. Any priority document(s) and all publications, including but not
limited to
patents and patent applications, cited in this specification are incorporated
herein by
reference as if each individual publication were specifically and individually
indicated to
be incorporated by reference herein and as though fully set forth herein. The
invention
includes all embodiments and variations substantially as hereinbefore
described and
with reference to the examples and drawings.
