Note: Descriptions are shown in the official language in which they were submitted.
CA 02743748 2011-06-17
THERMAL ASSISTED GRAVITY DRAINAGE (TAG
D1
FIELD
The present disclosure relates generally to recovery of hydrocarbons. More
particularly, the present disclosure relates to thermal recovery of bitumen or
heavy oil.
BACKGROUND
The publications listed below are examples of hydrocarbon recovery processes.
U.S. Patent No. 7,673,681 issued on Mar. 9, 2010 to Vinegar et al.
U.S. Publication No. 2011/0048717 published on Mar. 3, 2011 to Diehl et al.
PCT Publication No. WO 2010/107726 published on Sept. 23, 2010 to Al-Buraik.
Canadian Patent No. 2120851 issued on Aug. 22, 1995 to Yu et al.
It is, therefore, desirable to provide systems and methods of thermal recovery
of
bitumen or heavy oil.
SUMMARY
It is an object of the present disclosure to obviate or mitigate at least one
disadvantage of previous hydrocarbon recovery processes.
In a first aspect, the present disclosure provides a method of producing
bitumen or
heavy oil from a reservoir including:
providing a heater well in a first portion of the reservoir;
providing a producer well in a second portion of the reservoir, the second
portion
being at a greater depth than the first portion;
providing a reservoir heater in the heater well;
operating the reservoir heater to conductively heat the reservoir and reduce
the
viscosity of the bitumen or heavy oil; and
producing bitumen or heavy oil through the producer well.
In an embodiment, the method further includes providing a reservoir producer
heater
in the producer well and operating the reservoir producer heater to
conductively heat the
reservoir and reduce the viscosity of the bitumen or heavy oil.
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In an embodiment, the method further includes providing a flow assurance
heater in
the producer well and operating the flow assurance heater to facilitate flow
of bitumen or
heavy oil in the producer well.
In an embodiment, the reservoir is heated to an average temperature of less
than 300
C.
In an embodiment, the reservoir is heated to an average temperature of less
than 250
C.
In an embodiment, the reservoir is heated to an average temperature of less
than 200
C
In an embodiment, the reservoir is heated to an average temperature of less
than the
thermal cracking temperature of the bitumen or heavy oil in the reservoir at
reservoir
conditions.
In an embodiment, the reservoir is heated to a temperature less than the
saturated
steam temperature at reservoir conditions.
In an embodiment, the reservoir is heated to an average temperature of between
about 120 C and about 160 C.
In an embodiment, the reservoir is heated to an average temperature of between
about 135 C and about 145 C.
In an embodiment, the reservoir is a clastic reservoir.
In an embodiment, the reservoir is a carbonate reservoir.
In an embodiment, the reservoir is a dolomite carbonate reservoir.
In an embodiment, the reservoir is a limestone carbonate reservoir.
In an embodiment, the reservoir is a karsted carbonate reservoir.
In an embodiment, the reservoir is a vuggy carbonate reservoir.
In an embodiment, the reservoir is a moldic carbonate reservoir.
In an embodiment, the reservoir is a fractured carbonate reservoir.
In a further aspect, the present disclosure provides a method of producing
bitumen or
heavy oil from a reservoir including:
providing a heater well in a first portion of the reservoir;
providing a producer well in a second portion of the reservoir, the second
portion
being at a greater depth than the first portion;
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heating the heater well to conductively heat the reservoir and reduce the
viscosity of
the bitumen or heavy oil; and
producing bitumen or heavy oil through the producer well.
In an embodiment, the method further includes heating the producer well to
conductively heat the reservoir and reduce the viscosity of the bitumen or
heavy oil.
In an embodiment, the method further includes heating the producer well to
facilitate
flow of bitumen or heavy oil in the producer well.
In an embodiment, the method further includes selecting a target average
temperature and reducing heating of the heater well once the average
temperature of the
reservoir is substantially equal to the target average temperature to maintain
the average
temperature of the reservoir at the target average temperature without
increasing the
average temperature of the reservoir.
In an embodiment, the method further includes selecting a target average
temperature and reducing heating of the heater well once the average
temperature of the
reservoir is substantially equal to the target average temperature to maintain
the average
temperature of the reservoir at the target average temperature without
increasing the
average temperature of the reservoir, and the target average temperature is
between about
120 C and about 160 C.
In an embodiment, the method further includes selecting a target average
temperature and reducing heating of the heater well once the average
temperature of the
reservoir is substantially equal to the target average temperature to maintain
the average
temperature of the reservoir at the target average temperature without
increasing the
average temperature of the reservoir, andthe target average temperature is
between about
135 C and about 145 C.
In an embodiment, the method further includes controlling pressure during
production
to prevent an increase in pressure.
In an embodiment, the method further includes controlling pressure during
production
to prevent an increase in pressure by drawing down pressure from the
reservoir.
In a further aspect, the present disclosure provides a system for producing
bitumen or
heavy oil from a reservoir comprising:
a heater well in a first portion of the reservoir;
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a producer well in a second portion of the reservoir, the second portion being
at a
depth greater than the first portion; and
a heater in the heater wellbore for heating the reservoir.
In an embodiment, the system further includes a second heater in the producer
wellbore for heating the reservoir.
In an embodiment, the system further includes a second heater in the producer
wellbore for heating bitumen or heavy oil produced from the reservoir to
maintain a selected
viscosity of the bitumen or heavy oil in the producer well.
In an embodiment, the heater is an electric resistance heater.
In an embodiment, the heater is an electric resistance heater cable heater.
In an embodiment, the heater is a fluid exchange heater.
In a further aspect, the present disclosure provides a method of producing
bitumen or
heavy oil from a reservoir including conductively electrically heating the
reservoir to lower the
viscosity of bitumen or heavy oil in the reservoir, forming a mobilized column
of bitumen or
heavy oil; and producing the bitumen or heavy oil below the mobilized column
of bitumen or
heavy oil.
In an embodiment, the method further includes heating an upper portion of the
reservoir, the upper portion of the reservoir laterally offset from the
mobilized column.
Other aspects and features of the present disclosure will become apparent to
those
ordinarily skilled in the art upon review of the following description of
specific embodiments in
conjunction with the accompanying figures.
BRIEF DESCRIPTION OF THE DRAWINGS
Embodiments of the present disclosure will now be described, by way of example
only, with reference to the attached Figures.
Fig. 1 is a schematic of a heater well and a producer well arranged in a TAGD
pattern;
Fig. 2 is a plot of viscosity as a function of temperature for Leduc bitumen;
Fig. 3 is a cross-section of a first pattern with a 60m thick pay zone;
Fig. 4 is a cross-section of a second pattern with a 40m thick pay zone;
Fig. 5 is a cross-section of a third pattern with an 80m thick pay zone;
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Fig. 6 is a plot of the bitumen production rate from a simulation of the
pattern of Fig. 3
versus time with a portion of a ramp-up stage indicated at about 3 years;
Fig. 7 is a plot of temperature in the pattern of Fig. 3 at 3 years;
Fig. 8 is a plot of viscosity in the pattern of Fig. 3 at 3 years ;
Fig. 9 is a plot of gas saturation in the pattern of Fig. 3 at 3 years;
Fig. 10 is a plot of the bitumen production rate versus time with a portion of
a peak
production stage indicated at about 7 years;
Fig. 11 is a plot of temperature in the pattern of Fig. 3 at 7 years;
Fig. 12 is a plot of viscosity in the pattern of Fig. 3 at 7 years;
Fig. 13 is a plot of gas saturation in the pattern of Fig. 3 at 7 years;
Fig. 14 is a plot of the bitumen production rate versus time with a portion of
a
production decline stage indicated at about 10 years;
Fig. 15 is a plot of temperature in the pattern of Fig. 3 at 10 years;
Fig. 16 is a plot of viscosity in the pattern of Fig. 3 at 10 years;
Fig. 17 is a plot of gas saturation in the pattern of Fig. 3 of at 10 years;
Fig. 18 is a plot of bitumen production rate and cumulative bitumen production
versus
time for the pattern of Fig. 3;
Fig. 19 is a plot of net pattern power and cumulative energy requirements
versus time
for the pattern of Fig. 3; and
Fig. 20 is a plot of the bitumen recovery factor and cumulative energy ratio
versus
time for the pattern of Fig. 3.
DETAILED DESCRIPTION
Generally, the present disclosure provides a process, method, and system for
recovering hydrocarbons from a reservoir.
[0001] Thermal Assisted Gravity Drainage (TAGD)
Thermal Assisted Gravity Drainage (TAGD) is an in situ recovery process for
production of viscous hydrocarbons such as bitumen or heavy oil. Less viscous
hydrocarbons may be produced with the bitumen or heavy oil. TAGD is applicable
to
production of bitumen or heavy oil from either clastic or carbonate
reservoirs. Carbonate
reservoirs include limestone or dolomite, and may be any combination of vuggy,
moldic,
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karsted, or fractured. More generally, TAGD is applicable to any formation
wherein it is
advantageous to transfer thermal energy to the formation.
Fig. 1 is a schematic of a heater well 10 and a producer well 20 (collectively
"wells")
arranged in a TAGD pattern in a bitumen or heavy oil reservoir 30. As used
herein, the
reservoir 30 refers to that portion of a bitumen or heavy oil reservoir within
a pattern as
defined below (for example the first pattern 200, second pattern 260, or third
pattern 270 of
Figs. 3 to 5, respectively).
The producer well 20 is located below the heater well 10 and may be located
near the
base of the reservoir 30. The heater well 10 may be between about 5 m and
about 15 m
above the producer well 20. An instrument string 40 may be present within each
of the wells.
The instrument string 40 may include a pressure sensor, a temperature sensor,
both, or
other instruments.
The heater well 10 includes a substantially horizontal heater well section 50
and a
substantially vertical heater well section 60 joined by a heater well heel 65.
The substantially
vertical heater well section 60 joins the substantially horizontal heater well
section 50 with a
wellhead (not shown). The substantially horizontal heater well section 50
includes a heating
zone 70. The heating zone 70 may have a length substantially equal to the
length of the
substantially horizontal heater well section 50. In one illustrative example,
the heating zone
70 is about 1600 m in length. The heater well 10 is cased and hydraulically
isolated from the
reservoir 30.
A reservoir heater 80 is located in the heater well 10. The reservoir heater
80
includes a heating section 90 for transferring thermal energy to the reservoir
30. The heating
section 90 defines the heating zone 70. In one illustrative example, the
heating section 90 is
about 1600 m in length.
The producer well 20 includes a substantially horizontal producer well section
110
and a vertical producer well section 120 joined by a producer well heel 125.
The vertical
producer well section 120 joins the substantially horizontal producer well
section 110 with a
wellhead (not shown). The substantially horizontal producer well section 110
includes a
production zone 130. The producer well 20 is cased and hydraulically isolated
from the
reservoir 30 except at the production zone 130. The producer well 20 is
completed in the
production zone 130 with, for example, perforations, screens, a slotted liner
140 or other fluid
inlet in the production zone 130. An artificial lift system, for example a
pump 150, such as a
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rod pump, progressing cavity pump, or electric submersible pump, is provided
in the
producer well 20 to carry bitumen or heavy oil to the surface.
A reservoir producer heater 160 may be present in the producer well 20. A
producer
well 20 including a reservoir producer heater 160 functions as both a producer
well 20 and a
heater well 10, and is referred to below as a heater producer well 170. The
reservoir
producer heater 160 performs the same functions as the reservoir heater 80,
providing
thermal energy to the reservoir 30 along a producer heater heating section 95.
The producer
heater heating section 95 defines a producer heating zone 100. The producer
heating zone
100 and the production zone 130 may be co-extensive. The producer heating zone
100 may
have a length substantially equal to the length of the substantially
horizontal producer well
section 110. In one illustrative example, the producer heating zone 100 is
about 1600 m in
length.
A flow assurance heater 190 may be present in the vertical producer well
section 120.
The flow assurance heater 190 facilitates flow of bitumen or heavy oil within
the producer
well 20 by maintaining the temperature (and thus limiting the viscosity) of
the bitumen or
heavy oil. Thermal energy output of the flow assurance heater 190 may be
uniform per unit
length from the producer well heel 125 to the wellhead. The heater producer
well 170 may
include both the reservoir producer heater 160 and the flow assurance heater
190. A
producer well 20 including the flow assurance heater 190 but lacking the
reservoir producer
heater 160 is not a heater producer well 170.
Each of the reservoir heater 80, the reservoir producer heater 160, and the
flow
assurance heater 190 (collectively "heaters") may be of any type adapted for
use in a well.
Any of the heaters may be elongate to facilitate placement in the wells. Any
of the heaters
may be an electric resistance heater, for example a mineral insulated three-
phase heater, for
example a rod heater or cable heater. The electric resistance heater may be
capable of
accommodating medium voltage levels, for example from 600 V to 4160 V phase to
phase.
Any of the heaters may be a heat exchanger that transfers thermal energy to
the
reservoir 30 by circulation of heat transfer fluid such as hot water, steam,
oil (including
synthetic oil), molten salts, or molten metals.
[0002] Heating
Thermal energy is transferred from the reservoir heater 80 or reservoir
producer
heater 160 to the reservoir 30 by conductive heating. The reservoir 30 is
heated to an
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average temperature at which the viscosity of heavy oil or bitumen is low
enough for the
heavy oil or bitumen to flow by gravity to the producer well 20 or heater
producer well 170.
The viscosity of bitumen or heavy oil may be lowered, for example, to between
about 50 cP
and about 200 cP.
Fig. 2 is a plot of the viscosity of Leduc bitumen versus temperature. The
data in Fig.
2 was applied to a simulation prepared with a commercially-available reservoir
simulator
(Computer Modeling Group (CMG)-STARS). A significant decrease in viscosity of
Leduc
bitumen occurs when the temperature of the bitumen is increased from 11 C to
between
about 120 C and about 160 C. Dead oil viscosity is reduced from about 14
million cP at an
initial reservoir temperature of 11 C to about 80 cP at 140 C. At 140 C,
the bitumen or
heavy oil is sufficiently mobile to drain downward to the producer well 20 or
heater producer
well 170 by gravity.
The reservoir heater 80 and the reservoir producer heater 160 are operated to
transfer sufficient thermal energy to the reservoir 30 to increase the average
temperature of
the reservoir 30 to a target average temperature of between about 120 C and
about 160 C.
While the reservoir 30 as a whole may average between about 120 C and about
160 C,
there may be near heater zones 180 (See for example Fig. 7) of the heater
wells 10 and
heater producer wells 170 with an average temperature of up to about 250 C.
The near
heater zones 180 are modeled as one meter blocks extending along the length of
the heating
zone 70, and for a heater producer well 170, at least a portion of the
production zone 130.
TAGD may be applied to raise the average temperature of the reservoir 30 to
between about 120 C and about 160 C. An average temperature of about 140 C
provided
favourable economics. At significantly lower average temperatures, for example
about 100
C, production rates are too low to be economical. At significantly higher
average
temperatures, for example about 180 C, the resulting increase in the
production rate does
not justify the required increase in energy input required to raise the
reservoir 30 to the
higher average temperature. In addition, heating the reservoir 30 to between
about 120 C
and about 160 C avoids other potentially undesirable effects associated with
higher average
temperatures, such as increased H2S or CO2 production, and in some cases,
thermal
cracking of bitumen or heavy oil.
During heating, the reservoir pressure may be monitored and controlled.
Pressure
may be controlled to remain below a selected value by reducing transfer of
thermal energy to
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the reservoir 30 or by producing bitumen, heavy oil, water, vapours, or other
fluids from the
reservoir 30.
[0003] Well Spacing
The spacing of the heater wells 10 and producer wells 20 is set to realize the
economical production of hydrocarbons. Substantially horizontal substantially
horizontal
heater well sections 50 may be spaced as close as between about 5 m and about
40 m apart
from each other and from substantially horizontal producer well section 110.
The following
performance metrics are relevant to optimization of the spacing of the heater
wells 10 and
producer wells 20: oil production profile (oil production rate versus time),
overall recovery
factor (fraction of original oil in place (OOIP) produced), energy ratio
(ratio of energy supplied
to the reservoir 30 to the heating value of the produced bitumen or heavy
oil), and capital
cost.
Figs. 3 to 5 are cross-sections of patterns. Each pattern has a pay thickness
230 and
a pattern width 220, and is defined by a no-flow boundary 210 at each end of
the pattern
width 220. The number of heater wells 10 and their respective locations
relative to each other
and to the heater producer well 170 may be varied to account for features of
the reservoir 30
including pay thickness 230, vertical and horizontal permeabilities, well
length, heater power
output and temperature, and cost of wells and surface facilities.
Fig. 3 is a cross section of a first pattern 200. The pattern width 220 is 50
m and the
pay zone 230 is 60 m thick. Six heater wells 10 and one heater producer well
170 are
arranged in five rows in the first pattern 200. The heater wells 10 include
aligned heater wells
240 above and substantially laterally aligned with the heater producer well
170. The heater
wells 10 also include first offset heater wells 245 above and laterally offset
from the heater
producer well 170. The heater wells 10 also include second offset heater wells
250 above
and laterally offset from the heater producer well 170 (with one half of a
second offset heater
well 250 at each no-flow boundary 210). The second offset heater wells 250 are
laterally
offset from the heater producer well 170 to a greater extent than the first
offset heater wells
245.
The number of wells, the locations of the wells in the first pattern 200, and
the heating
output of the heaters were adjusted to obtain a high net present value. The
simulation was
based on the reservoir 30 and well properties indicated in Table 1.
Table 1
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Property Quantity Unit
Vertical Permeability 2200 mDarcy
Horizontal Permeability 1100 mDarcy
Porosity 15 %
Pay thickness 60 m
Pressure at top of reservoir (absolute) 473 kPa
Initial reservoir temperature 11 C
Bitumen saturation 88 %
Water Saturation 12 %
Irreducible Water Saturation 10 %
Viscosity at 11 C 14 x 10 cP
Viscosity at 140 C 80 cP
Reservoir Heater Power output 650 W/m
Reservoir Producer Heater Power output 150 W/m
Rock Heat capacity at 11 C 2.41 x 106 J/(m = C)
Rock Heat capacity at 140 C 2.88 x 10 J/(m = C)
Rock Thermal conductivity at 11 C 4.6 W/(m=K)
Rock Thermal conductivity at 140 C 3.7 W/(m=K)
Bottomhole pressure (absolute) 500 kPa
For a reservoir 30 with the pay zone 230 being thinner or thicker than the 60
m of Fig.
3, rows of wells may be respectively added or removed. Similarly, the lateral
offset of first
offset heater wells 245 or second offset heater wells 250 (or third offset
heater wells 255 -
Fig. 5, or any offset heater wells generally) may be adjusted to account for a
reservoir 30
with the thickness 220 being greater or less than the 50 m of Fig. 3.
Fig. 4 is a cross section of a second pattern 260. The pattern width 220 is 40
m and
the pay zone 230 is 40 m thick. Five heater wells 10 and one heater producer
well 170 are
arranged in four rows. The heater wells 10 include aligned heater wells 240,
first offset
heater wells 245 and second offset heater wells 250 (with one half of a second
offset heater
well 250 at each no-flow boundary 210).
Fig. 5 is a cross section of a third pattern 270. The pattern width 220 is 50
m and the
pay zone 230 is 80 m thick. Eight heater wells 10 and one heater producer well
170 are
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arranged in six rows. The heater wells 10 include aligned heater wells 240,
first offset heater
wells 245 and second offset heater wells 250. The heaters wells further
include third offset
heater wells 255 (with one half of a third offset heater well 255 at each no-
flow boundary
210). The third offset heater wells 255 are laterally offset from the heater
producer well 170
to a greater extent than the second offset heater wells 250.
[0004] Conductive Heating
Conductive heating provides for more uniform temperature distribution in the
reservoir
30 relative to convective heating processes such as those dependent on steam
injection. The
greater uniformity provides greater predictability of the temperature
distribution. As a result, a
TAGD pattern may be more easily optimized for a particular set of reservoir
conditions than a
pattern for a recovery process based on convective heating, for example steam
assisted
gravity drainage (SAGD) or cyclic steam stimulation (CSS). The number of wells
and spacing
between wells may be adjusted to account for differences between individual
reservoirs with
respect to the thicknesses, permeabilities, pressures, temperatures, and other
properties of
the reservoirs, but the presence of obstacles does not introduce as much
uncertainty as in
processes based on convective heating.
In reservoirs having impermeable or semi-impermeable barriers, such as shale
extending across portions of the reservoir, the vertical growth of a SAGD or
CSS steam
chamber may be impeded by the barriers. However, thermal energy transfer by
conductive
heating as in the present disclosure may pass through or around the barriers,
mitigating the
impact of the barriers on production, recovery, or both.
[0005] Production
Production may be described as occurring in three general stages: a ramp-up
stage,
a peak production stage, and a production decline stage. Figs. 6 to 17 are
plots of simulation
data for the first pattern 200 of Fig. 3 at each of the stages wherein the
heating zones 70 and
the producer heating zones 100 each extend along a substantially horizontal
well length of
1600 m. In an embodiment, the bitumen or heavy oil produced from the reservoir
30 is
produced substantially as a liquid via the pump 150. In an embodiment, there
is no
appreciable vapourization of bitumen or heavy oil in the reservoir 30 or the
near heater zone
180, or both.
[0006] Ramp-Up Stage
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Fig. 6 is a plot of the bitumen production rate versus time for the simulation
with a
portion of the ramp-up stage indicated at about 3 years. Figs. 7 to 9 are
respectively plots of
temperature, viscosity, and gas saturation distributions in the reservoir 30
with the first
pattern 200 at 3 years into the simulation.
The temperature distribution ranges from about 12 C in the majority of the
reservoir
30 to about 250 C at the near heater zones 180. During the ramp-up stage
(from start-up to
about two years of heating), significant increases in temperature that result
in a portion of the
reservoir 30 reaching the target average temperature of between about 120 C
and about
160 C primarily occur in the vicinity of the near heater zones 180. The
viscosity in the
reservoir 30 ranges from 1000 cP or greater in the majority of the reservoir
30 to about 10 cP
in the near heater zones 180. Initial bitumen production is from a relatively
small volume of
heated bitumen in the vicinity of the heater producer well 170. The gas
saturation ranges
from 0 in the majority of the reservoir 30 to about 0.4 at the lowermost
aligned heater well
240 and in a gassy-bitumen zone 290. A mobilized column 280 of connected
mobile bitumen
that connects the aligned heater wells 240, the first offset heater wells 245,
and the producer
well 20 has yet to form (Fig. 12).
As time passes and the reservoir 30 is heated further, the average temperature
of the
reservoir 30 increases, the viscosity of bitumen in the reservoir 30
decreases, and a gas
chamber 300 (Fig. 13) forms and expands generally upwards.
[0007] Peak Production Stage
Fig. 10 is a plot of the bitumen production rate for the first pattern 200
with a portion
of the peak production stage indicated at about 7 years. Figs. 11 to 13 are
plots of
temperature, viscosity, and gas saturation distributions in the reservoir 30
at 7 years into the
simulation.
The average temperature in the reservoir 30 has increased relative to the ramp-
up
stage. A significant volume of bitumen is at the target average temperature of
between about
120 C and about 160 C. As a result, a mobilized column 280 of bitumen has
formed in the
reservoir 30 above the heater producer well 170 wherein the viscosity of the
bitumen is
below 1000 cP and is about 100 cP in much of the mobilized column 280. The
aligned heater
wells 240, the first offset heater wells 245, and the heater producer well 170
are within the
mobilized column 280. A gas chamber 300 comprising evolved solution gas and
water
vapour has also formed and moves upward as bitumen drains down to the heater
producer
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well 170. The gas chamber 300 provides internal drive and voidage replacement
(see
below).
Continued heating increases the height and width of the mobilized column 280
with a
concurrent increase in bitumen production rate. Peak production occurs due to
a favourable
combination of pressures and viscosity when the mobilized column 280 has
reached a
maximum height. The gas chamber 300 has reached a significant size and the
aligned
heater wells 240 and the first offset heater wells 245 are within the gas
chamber 300. During
the peak production stage, thermal energy output from the heater wells 10 or
the heater
producer well 170, or both, may be reduced to maintain the target average
temperature of
between about 120 C and about 160 C in the reservoir 30 without additional
increase in
temperature to maximize efficiency of energy use.
[0008] Production Decline Stage
Fig. 14 is a plot of the bitumen production rate for the first pattern 200
with a portion
of the production decline stage indicated at about 10 years. Figs. 15 to 17
are plots of
temperature, viscosity, and gas saturation distributions at 10 years into the
simulation.
During the production decline stage, the majority of the reservoir 30 is at
the target
average temperature of between about 120 C and about 160 C and the majority
of the
bitumen has a sufficiently low viscosity to be substantially mobile. The gas
chamber 300 has
merged with the gassy-bitumen zone 290 to form a secondary gas cap 310. The
secondary
gas cap 310 includes evolved solution gas and water vapour. An angle 320 at
which
mobilized bitumen drains to the heater producer well 170 becomes increasingly
acute to the
horizontal. During the production decline stage, the reservoir heaters 80 may
be turned down
to deliver less thermal energy than during previous stages (Fig. 19), and may
even be turned
off (not shown). As a result, while the near heater zones 180 remain, the
difference in
temperature between the near heater zones 180 and the majority of the
reservoir 30 is less
pronounced. At abandonment, the remaining oil-in-place is contained at near
residual
saturations within the gas chamber 300, and near the base of the reservoir 30
at an angle
320 that is unfavourably acute to the horizontal with respect to the heater
producer well 170.
[0009] Summary of Value Indicators Over Time
Fig. 18 is a plot of the bitumen production rate and the cumulative recovered
bitumen
of the simulation versus time. The peak production rate of 145 m3/day and
overall recovery
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after 20 years is about 69% of OOIP. The peak production rate and overall
recovery are
comparable to that observed for an average SAGD well pair.
Fig. 19 is a plot of the net pattern power and the cumulative energy of the
simulation
versus time with 650 W/m of power output to the six heater wells 10 and 150
W/m of power
output to the heater producer well 170. Each of the heater wells 10 has a 1600
m long
heating zone 70 and the heater producer well 170 has a 1600 m long producer
heating zone
100. The net pattern power drops and levels off when thermal energy output
from the heater
wells 10 and the heater producer well 170 is reduced from the above levels.
Reduction in
thermal energy output allows the target average temperature of between about
120 C and
about 160 C to be maintained (but not further increased) while using less
power.
Fig. 20 is a plot of the bitumen recovery factor and the cumulative energy
ratio of the
simulation versus time.
[0010] Voidage Replacement
To effectively drain hot mobilized bitumen or heavy oil, produced volumes must
be
replaced to prevent establishment of low reservoir pressures. Low reservoir
pressures may
prevent economical production. Without wishing to be bound by any theory, the
simulation
indicates that voidage replacement may occur by a one or more of at least
three
mechanisms.
First, evolution of solution gas from the bitumen or heavy oil. Solubility of
gas in
bitumen or heavy oil decreases significantly with increasing temperature. As
the bitumen or
heavy oil is heated, solution gas evolves from the bitumen or heavy oil. The
specific volume
of the dissolved gas component is significantly greater in the gas phase than
in the solution
phase, thus replacing some of the voidage created by production. For example,
at 140 C
and 500 kPa (absolute), the specific volume of the solution gas component is
about 200
times greater in the gas phase than as a dissolved component in the liquid
bitumen or heavy
oil phase.
Second, vapourization of connate water in low-pressure reservoirs (for example
shallow reservoirs). The specific volume of steam is significantly greater
than that of liquid
water. At 140 C, the specific volume of saturated steam is about 500 times
greater than that
of saturated liquid water. A portion of the reservoir 30 will exceed the
saturation temperature
thus leading to the vapourization of some of the connate water initially in
place and thus
contributing to voidage replacement. The target average temperature of the
reservoir 30 is
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between about 120 C and about 160 C, so water may boil where the average
temperature
of the reservoir 30 is on the upper end of this range and water will boil in
the near heater
zones 180.
Third, expansion of in-place volumes. Although less significant that the
solution gas
evolution and vapourization of connate water processes noted above, some
voidage
replacement will be realized by thermal expansion of in-place hydrocarbons,
connate water
and free gas. For example, an expansion of about 10% is estimated at 140 C
and 500 kPa
(absolute).
[0011] Gas Injection
Gas injection into a gassy-bitumen zone 290, a gas cap (not shown), or a gas-
bitumen transition zone (not shown) overlying the reservoir 30 at or near the
beginning of the
ramp-up stage may allow the ramp-up stage to be completed in a shorter time
frame. In the
simulation, the peak production stage began about two years sooner with gas
injection (i.e.
at about 5 years instead of about 7 years). Gas injection provides further
drive to the gravity
drainage process. Gas injection may be stopped once the injected gas begins to
break-
through to the producer well 20. A variety of non-condensable gases may be
used, including
natural gas, nitrogen, carbon dioxide, or flue gas.
[0012] Advantages of TAGD
The TAGD recovery process has several important advantages over other thermal
processes used to recover bitumen or heavy oil (e.g. SAGD, CSS, and hybrid
steam injection
with solvent).
TAGD allows more uniform and predictable heating of a reservoir relative to
steam
injection processes. In steam injection processes, transfer of thermal energy
is accomplished
through convection in which thermal energy is carried throughout the reservoir
by fluid flow.
Transfer of thermal energy by convection is governed by pressure differential
and the
effective permeability of the reservoir. The effective permeability may vary
by orders of
magnitude within a carbonate reservoir. Low permeability layers may block or
retard the flow
of steam. Steam may also flow preferentially in natural fractures thus
bypassing the majority
of the reservoir and resulting in poor steam conformance. Poor steam
conformance results in
poor recovery and high steam-oil ratios, and therefore in unfavourable
economics.
Heat conduction is governed largely by a temperature difference and the
effective
thermal conductivity of a reservoir. The effective thermal conductivity of the
reservoir is a
CA 02743748 2011-06-17
function of rock mineralogy, reservoir porosity, and the saturations and
thermal conductivities
of the fluids in the reservoir, including bitumen or heavy oil, water and gas.
In general, unlike
reservoir permeability, the variation of thermal conductivity throughout the
reservoir is
relatively minor and is expected to be less than about plus or minus 25%. The
result will be a
much more uniform temperature distribution within the reservoir.
TAGD allows more efficient use of input energy. In the SAGD recovery process,
the
temperature of a reservoir contacted by steam is determined by the reservoir
pressure and is
generally in excess of 200 C, such as about 260 C. Even higher temperatures
are reached
during the higher pressure CSS processes, such as about 330 C. By contrast,
the target
average temperature in TAGD is about 120 C to about 160 C, thus requiring
significantly
less input energy, for comparable oil recovery (e.g. production rate or
recovery factor, or
both), than the processes based on steam injection.
TAGD does not require steam injection and therefore does not require water for
steam generation. This may be an important advantage in field locations where
a source of
available water is absent or is costly to develop. The simulation indicates
that produced
water-oil ratios may be less than 0.5 m3/m3 after year 3 of production. In
contrast, steam-
based processes produce at water-oil ratios on the order of 3.0 m3/m3 (or
3:1). The initial
water-oil ratio in TAGD is a function of the mobility of water present in the
reservoir prior to
heating, and may vary from reservoir to reservoir. In addition to lowered
water use, this
advantage also provides the benefit of allowing processing facilities for
produced bitumen to
be smaller, simpler in design, and less expensive to build.
At the target average reservoir temperature of between about 120 C and about
160
C, little or no generation of H2S or CO2 is expected. Thus, less H2S and less
CO2 is
produced per unit of produced bitumen or heavy oil than for a typical SAGD
project.
TAGD may be used to supplement existing SAGD operations or may be used as a
retrofit existing SAGD well bores.
In the preceding description, for purposes of explanation, numerous details
are set
forth in order to provide a thorough understanding of the embodiments.
However, it will be
apparent to one skilled in the art that these specific details are not
required. The above-
described embodiments are intended to be examples only. Alterations,
modifications and
variations can be effected to the particular embodiments by those of skill in
the art without
departing from the scope, which is defined solely by the claims appended
hereto.
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