Note: Descriptions are shown in the official language in which they were submitted.
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HYDROCARBON RECOVERY START-UP PROCESS
Technical Field
[0001] The present invention relates to the production of hydrocarbons
such as
heavy oils and bitumen from an underground reservoir by heating the reservoir
to
mobilize the hydrocarbons.
Background
[0002] Extensive deposits of viscous hydrocarbons exist around the world,
including large deposits in the Northern Alberta oil sands that are not
susceptible to
standard oil well production technologies. One problem associated with
producing
hydrocarbons from such deposits is that the hydrocarbons are too viscous to
flow at
commercially relevant rates at the temperatures and pressures present in the
reservoir.
For such reservoirs, thermal techniques may be used to heat the reservoir to
mobilize
the hydrocarbons and produce the heated, mobilized hydrocarbons from wells.
One
such technique for utilizing a horizontal well for injecting heated fluids and
producing
hydrocarbons is described in U.S. Patent No. 4,116,275, which also describes
some of
the problems associated with the production of mobilized viscous hydrocarbons
from
horizontal wells.
[0003] One thermal method of recovering viscous hydrocarbons using spaced
horizontal wells is known as steam-assisted gravity drainage (SAGD). SAGD
utilizes
gravity in a process that relies on density difference of the mobile fluids to
achieve a
desirable vertical segregation within the reservoir. Various embodiments of
the SAGD
process are described in Canadian Patent No. 1,304,287 and corresponding U.S.
Patent No. 4,344,485. In the SAGD process, pressurized steam is delivered
through an
upper, horizontal, injection well into a viscous hydrocarbon reservoir while
hydrocarbons
are produced from a lower, parallel, horizontal, production well that is
vertically spaced
and near the injection well. The injection and production wells are generally
situated in
the lower portion of the reservoir, with the producer or production well
located close to
the base of the hydrocarbon deposit to collect the hydrocarbons that flow
toward the
bottom.
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[0004] The SAGD process is believed to work as follows. The injected
steam
initially mobilizes the hydrocarbons to create a steam chamber in the
reservoir around
and above the horizontal injection well. The term steam chamber is utilized to
refer to
the volume of the reservoir that is saturated with injected steam and from
which
mobilized oil has at least partially drained. As the steam chamber expands,
viscous
hydrocarbons in the reservoir are heated and mobilized and move with aqueous
condensate, under the effect of gravity, toward the bottom of the steam
chamber, where
the viscous hydrocarbons and aqueous condensate accumulate such that the
liquid /
vapour interface is located below the steam injector and above the production
well. The
heated hydrocarbons and aqueous condensate are collected and produced from the
production well.
[0005] To begin the production of hydrocarbons, the reservoir is
preheated in a
start-up operation by the circulation of steam and water at high pressure in
the injection
well or the production well or both the injection and the production well.
High pressure
ensures that the condensed steam overcomes gravity and is returned to the
surface.
The high pressure injection of steam, however, leads to inefficient heat
exchange, for
example, as a result of localized heating. Steam is generally more mobile than
the
viscous hydrocarbons and other fluids. Steam and water develop flow paths and
these
flow paths are favored by the steam injected and the condensed water, reducing
the
effectiveness of the steam in heating other regions in the reservoir.
Consequently, the
steam chamber grows irregularly.
[0006] In addition mobile fluid zones that have relatively low bitumen
saturation
may exist near the reservoir. For example, the mobile fluid zones may have
significant
saturations of gas, water, or both. In such deposits, these mobile fluid zones
can act as
"thief zones" and have undesirable effects on recovery methods. For example,
oil
sands deposits may have a mobile fluid zone above the bitumen or heavy oils.
In such
deposits, the mobile fluid zone can have a significant saturation of water or
gas which
acts as the "thief zone" and when injecting steam, steam at a pressure that is
higher
than the pressure in the water or gas zone may cause the flow of steam into
the thief
zone, resulting in steam loss. As the steam chamber approaches a gas zone, and
if the
steam pressure is kept higher than the gas zone pressure, steam and possibly
some of
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the oil may be pushed into the gas zone. When the steam chamber contacts and
is in
communication with a "thief zone", significant heat loss to the "thief zone"
may also
occur. For a water zone, steam and heat loss to the water zone, also referred
to as a
lean zone, may also occur.
[0007] Improvements in startup of hydrocarbon recovery are desirable.
Summary
[0008] According to an aspect of an embodiment, a process is provided for
startup of hydrocarbon recovery utilizing a well including a generally
vertical section and
a generally horizontal section extending into a hydrocarbon-bearing formation.
The
process includes injecting a fluid through a tube that extends through the
generally
vertical section and the generally horizontal section of the well, the fluid
exiting the tube
in the generally horizontal section of the well, lifting the fluid utilizing
artificial lift, after
transferring heat to the hydrocarbon-bearing formation, to a head of the well
to thereby
circulate the fluid prior to production, discontinuing circulating the fluid,
and beginning
production of hydrocarbons from the hydrocarbon-bearing formation.
[0009] Artificially lifting the condensed steam to the wellhead
facilitates circulation
at lower pressures than the pressure that is otherwise utilized to ensure that
the
condensed steam is returned to the surface.
Brief Description of the Drawings
[0010] Embodiments of the present invention will be described, by way of
example, with reference to the drawings and to the following description, in
which:
[0011] FIG. 1 is a sectional view through a reservoir, illustrating a
SAGD well
pair;
[0012] FIG. 2 is a sectional side view illustrating an injection and a
production
well pair;
[0013] FIG. 3A is a sectional side view illustrating a production well
according to
an embodiment;
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[0014] FIG. 3B is a sectional side view illustrating a production well
according to
another embodiment;
[0015] FIG. 4 is a flowchart illustrating a process of start-up of
hydrocarbon
recovery from a hydrocarbon-bearing formation;
[0016] FIG. 5 is a sectional view through a reservoir and through a
generally
horizontal segment of a SAGD well pair according to another embodiment;
[0017] FIG. 6 is a sectional view through a reservoir and through a
generally
horizontal segment of a SAGD well pair according to another embodiment.
Detailed Description
[0018] For simplicity and clarity of illustration, reference numerals may
be
repeated among the figures to indicate corresponding or analogous elements.
Numerous details are set forth to provide an understanding of the examples
described
herein. The examples may be practiced without these details. In other
instances, well-
known methods, procedures, and components are not described in detail to avoid
obscuring the examples described. The description is not to be considered as
limited to
the scope of the examples described herein.
[0019] The disclosure generally relates to a process for startup of
hydrocarbon
recovery utilizing a well including a generally vertical section and a
generally horizontal
section extending into a hydrocarbon-bearing formation. The process includes
injecting
a fluid through a tube that extends through the generally vertical section and
the
generally horizontal section of the well, the fluid exiting the tube in the
generally
horizontal section of the well, lifting the fluid utilizing artificial lift,
after transferring heat
to the hydrocarbon-bearing formation, to a head of the well to thereby
circulate the fluid
prior to production, discontinuing circulating the fluid, and beginning
production of
hydrocarbons from the hydrocarbon-bearing formation.
[0020] Throughout the description, reference is made to an injection well
and a
production well. The injection well and the production well may be physically
separate
wells. Alternatively, the production well and the injection well may be
housed, at least
partially, in a single physical wellbore, for example, a multilateral well.
The production
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well and the injection well may be functionally independent components that
are
hydraulically isolated from each other, and housed within a single physical
wellbore.
[0021] As described above, a steam assisted gravity drainage (SAGD)
process
may be utilized for mobilizing viscous hydrocarbons. In the SAGD process, a
well pair,
including a hydrocarbon production well and a steam injection well are
utilized. One
example of a well pair is illustrated in FIG. 1 and an example of a
hydrocarbon
production well 100 and an injection well 108 is illustrated in FIG. 2. The
hydrocarbon
production well 100 includes a generally horizontal segment 102 that extends
near the
base or bottom 104 of the hydrocarbon reservoir 106. The injection well 108
also
includes a generally horizontal segment 110 that is disposed generally
parallel to and is
spaced vertically above the horizontal segment 102 of the hydrocarbon
production well
100.
[0022] As referred to above, at startup of a SAGD well pair or at startup
of a
single well that is disposed intermediate well pairs, also referred to as an
infill well or a
well drilled using Wedge WeIITM technology, high pressure steam directed into
a well for
pre-heating may cause non-uniform heating, or heat or steam loss to a "thief
zone", or a
combination of such problems.
[0023] Canadian Patent 2,162,741, issued December 20, 2005 to Nzekwu et
al.
discloses a hydrocarbon production method in which a downhole production pump
is
utilized to pump heated oil and steam condensate during the production of
hydrocarbons. Steam injection and hydrocarbon production are simultaneous and
continuous throughout the life of the well, however, and Improvements in
startup of
hydrocarbon recovery are desirable.
[0024] A sectional side view of an example of a production well 300 is
shown in
FIG. 3A. As shown in FIG. 3A, the production well 300 includes the generally
horizontal
segment 302. A tubing 304, which may be, for example, a non-insulated tubing,
an
insulated tubing or insulated coil tubing, such as a vacuum insulated tubing,
is utilized to
deliver heated fluid, including steam, to the hydrocarbon production well. The
tubing
304 extends from the wellhead 306, through a heel portion 308 of the
production well
300, and along the generally horizontal segment 302. Use of insulated tubing
reduces
the amount of heat loss during travel of the fluid from the wellhead 306 to
the generally
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horizontal segment 302. During steam circulation, the steam transfers heat to
the
formation, condenses, and is returned to the surface as water. The use of the
insulated
tubing reduces the wasted energy caused by heat transfer to the condensed
water and
heat transfer between steam entering the well and condensed water returning
from the
well as the water collects in the well and is returned to the wellhead.
[0025] The tubing 304 generally follows the contour of the production
well 300
and may include perforations or flow control devices or both perforations and
flow
control devices along a generally horizontal portion 312 of the tubing 304 to
facilitate
distribution of the steam along the generally horizontal segment 302 of the
production
well 300.
[0026] The tubing is described herein as insulated tubing 304.
Alternatively, the
tubing may be a non-insulated tubing. The use of non-insulated tubing reduces
capital
expenditure and has a smaller thickness of pipe wall. Thus, non-insulated
tubing with
the same outside diameter as insulated tubing, has a larger inside diameter,
and
therefore larger cross sectional area available for flow, facilitating
circulation of larger
volumes of steam and reducing frictional pressure losses as a result of fluid
flow along
the pipe.
[0027] An electric submersible pump (ESP) 314 is utilized to pump fluids,
including the condensed water as well any hydrocarbons that may be produced
during
startup of the well, to the wellhead. The ESP 314 may be a slim-hole ESP that
is
coupled to a tubing string 316, such as tubing or a coil tubing string of 2
3/8" (6.03 cm)
internal diameter. The ESP 314 is disposed at or near the heel of the
production well
300 and the tubing string 316 is coupled to the ESP 314 and extends to the
wellhead
306 for the passage of fluids pumped from the ESP 314. Rather than an ESP, any
other suitable artificial lift may be utilized.
[0028] Optionally, a distributed temperature sensing system (DTS) or
array
temperature sensing system (ATS) 318, such as a downhole fiber optic
temperature
sensor, is disposed in the well and extends along the length of the generally
horizontal
segment 302. The DTS or ATS is utilized to sense the temperature along the
length of
the generally horizontal segment 302 to obtain a real-time temperature profile
across
the generally horizontal segment 302 of the production well 300. The DTS may
also be
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utilized in the generally vertical segment of the production well 300. The DTS
may also
be utilized to detect pressure.
[0029] As indicated above, any suitable artificial lift may be utilized.
According to
one embodiment, gas lift or jet pumps may be utilized. Gas lift may be
advantageous
because an ESP may be susceptible to gas locking. A sectional side view of
another
example of a production well 320 is shown in FIG. 313. As shown in FIG. 3B,
the
production well 320 includes the generally horizontal segment 302. As
described with
reference to FIG. 3A, a tubing 304 or insulated coil tubing, such as a vacuum
insulated
tubing, is utilized to deliver heated fluid, including steam, to the
hydrocarbon production
well. The tubing 304 extends from the wellhead 306, through a heel portion 308
of the
production well 320, and along the generally horizontal segment 302. Use of
insulated
tubing reduces the amount of heat loss during travel of the fluid from the
wellhead 306
to the generally horizontal segment 302. During steam circulation, the steam
transfers
heat to the formation, condenses, and is returned to the surface as water. The
use of
the insulated tubing reduces the wasted energy caused by heat transfer to the
condensed water and heat transfer between steam entering the well and
condensed
water returning from the well as the water collects in the well and is
returned to the
wellhead.
[0030] The tubing 304 generally follows the contour of the production
well 320
and may include perforations or flow control devices or both perforations and
flow
control devices along a generally horizontal portion 312 of the tubing 304 to
facilitate
distribution of the steam along the generally horizontal segment 302 of the
production
well 320.
[0031] Gas lift is utilized to pump fluids, including the condensed water
as well
any hydrocarbons that may be produced during startup of the well, to the
wellhead. A
tubing string 322, which may be tubing or a coil tubing string of 2 3/8" (6.03
cm) internal
diameter, is utilized for gas lift. The tubing 322 includes ports 324 at a
lower end
thereof, at or near the heel of the production well 320 and gas is injected
into the
annular space between the tubing strings 304 and 322 to artificially lift the
fluids as the
fluids pass through the ports 324 and are lifted from the production well 320.
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[0032] Optionally, a distributed temperature sensing system (DTS) or
array
temperature sensing system (ATS) 318 may also be included.
[0033] A flowchart illustrating a process for startup of hydrocarbon
recovery from
a hydrocarbon-bearing formation is shown in FIG. 4. The process is carried out
to
startup hydrocarbon recovery from a viscous hydrocarbon reservoir, such as the
reservoir 106. For the purpose of the present explanation, the process is
described with
continued reference to the examples of FIG. 3A and FIG. 3B. The process may
contain
additional or fewer processes than shown or described, and may be performed in
a
different order.
[0034] Heating fluid, such as heated water or steam, is injected into the
well at
402, through the tubing 304. The heating fluid is injected at a pressure
sufficient to
reach a downhole pressure that is within about 500 kPa of the pressure in the
reservoir.
For example, for a reservoir pressure of about 1200 kPa, the heating fluid is
injected at
a pressure to reach a downhole pressure of from about 700 kPa to about 1700
kPa.
Such a pressure of plus or minus 500 kPa of the reservoir pressure is suitable
for
circulation of the heating fluid within the wellbore.
[0035] Thus, the heating fluid is injected at low pressure compared to
prior
startup processes. The use of insulated tubing as the tubing 304 reduces the
amount of
heat loss during travel of the fluid from the wellhead 306 to the generally
horizontal
segment 302 compared to a non-insulated tubing string.
[0036] A surface heater or steam-production facilities may be utilized to
produce
the heating fluid that is injected down the well. Alternatively, a subsurface
heater can
be located in an upper part of the tubing 304, or the insulated coil tubing,
in the
generally vertical segment of the well. Water can be injected into the well,
through the
tubing 304, which may be insulated tubing, such that the water flashes to
steam as the
water travels past the heater, toward the generally horizontal segment 302.
[0037] As described above, the generally horizontal portion 312 of the
tubing 304
may include perforations such that heating fluid is delivered to several
locations along
the length of the generally horizontal segment 302. Alternatively, or in
addition, heating
fluid travels along the length of the tubing 304 and is delivered to the toe
of the
production well 300.
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[0038] As the heating fluid is injected into the well, the region of the
reservoir
around the generally horizontal segment 302 rises because the heating fluid is
at a
temperature that is above the ambient temperature in the reservoir. When steam
is
injected, the steam condenses and the condensed water accumulates in the
generally
horizontal segment 302. In addition to the water, some mobilized hydrocarbons
may be
collected in the generally horizontal segment 302. Because the fluid is
injected at a
relatively low pressure, for example, compared to prior art SAGD processes,
the
accumulated fluid does not naturally flow toward the wellhead. Thus,
artificial lift, such
as the ESP 314, is utilized to lift the accumulated fluids to the wellhead 306
at 404. A
slim-hole ESP 314 may be utilized such that the tubing 304, and the ESP 314
and
tubing string 316 fit in a single well. Thus, water, which may be in the form
of steam, is
circulated through the well to heat the reservoir.
[0039] The injection of heating fluid 402 may be continuous during
artificial lift of
accumulated fluid to the wellhead at 404. Alternatively, the injection of
heating fluid 402
may be discontinuous such that injection is periodically stopped while
artificially lifting
the accumulated fluid to the wellhead at 404 continues. Injection of heating
fluid 402
may begin again while artificially lifting accumulated fluid to the wellhead.
In another
alternative, the injection of heating fluid 402 may be continuous and
artificial lift of
accumulated fluid 404 may be discontinuous.
[0040] The reservoir is monitored at 406 by monitoring well conditions,
such as
temperature. For example, the reservoir may be monitored utilizing the DTS 318
that
extends through the hydrocarbon production well to obtain a real-time
temperature
profile across the generally horizontal segment of the hydrocarbon production
well.
When the temperature is not raised sufficiently to meet a threshold at 408,
the
circulation of fluid at 402 and 404 continues. When the well conditions meet a
threshold
at 408, the method continues at 410. For example, based on a lowest-measured
temperature along the length of the generally horizontal segment 302, as
measured by
the DTS, a temperature at a location of about 2.5 to 3 meters away in the
reservoir may
be calculated based on known temperature calculations. When the temperature at
this
location of about 2.5 to 3 meters away in the reservoir is raised such that
the
temperature meets a threshold temperature, the method continues at 410.
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Alternatively, a highest measured temperature, an average measured
temperature, or a
measured temperature a specific location may be utilized to calculate a
temperature at
a location in the reservoir and the calculated temperature is compared to the
threshold
to determine when the method continues at 410. The circulation of heating
fluid by
injection of heating fluid at 402 and artificial lift of fluids at 404 may
continue, for
example, for about 3 months to about 6 months.
[0041]
Heating fluid injection is discontinued at 410. Artificial lift, such as the
use
of the ESP 314, may continue to lift accumulated fluids from the production
well to
continue to lift fluids that accumulate after heating fluid injection stops.
The tubing 304
may be removed from the well and, after lifting the fluids from the well, the
ESP 314 and
the tubing string 316 may be removed from the well. The tubing 304, the ESP
314 and
the tubing string 316 may be utilized for startup of another well. Optionally,
the
insulated tubing may stay in the well, for example, for several months after
startup
without adversely affecting production. For example, for a production well in
a SAGD
pair, the tubing 304, the ESP 314, and the tubing string 316 may all remain in
the
production well for up to one year after installation such that the production
well is
utilized during SAGD prior to removal of the tubing 304, the ESP 314, and the
tubing
string 316. Thus, the tubing 304 may be removed prior to starting hydrocarbon
production or during hydrocarbon production. Heating fluid is not circulated
during
hydrocarbon production.
[0042]
Hydrocarbon production is started at 412. During SAGD, steam is injected
into an injection well to mobilize the hydrocarbons and grow the steam chamber
in the
reservoir, around and above the generally horizontal segment 302. In addition
to steam
injection into the steam injection well, light hydrocarbons, such as the C3
through C10
alkanes, either individually or in combination, may optionally be injected
with the steam
such that the light hydrocarbons function as solvents in aiding the
mobilization of the
hydrocarbons. The volume of light hydrocarbons that are injected is relatively
small
compared to the volume of steam injected. The addition of light hydrocarbons
is
referred to as a solvent- aided process (SAP). Alternatively, or in addition
to the light
hydrocarbons, various non-condensing gases, such as methane or carbon dioxide,
may
be injected. Viscous hydrocarbons in the reservoir are heated and mobilized
and the
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mobilized hydrocarbons drain under the effect of gravity. Fluids, including
the mobilized
hydrocarbons along with aqueous condensate, are collected in the generally
horizontal
segment 302. The fluids may also include gases such as steam and production
gases
from the SAGD process. Optionally, a second, larger ESP may be utilized to
lift the
hydrocarbons to the surface of the production well.
[0043] Thus, heating fluid is circulated through a well at relatively low
pressure
utilizing insulated tubing . The heating fluid is circulated prior to
production of
hydrocarbons from the well. Circulation is discontinued and production begins
from the
same well through which heating fluid was circulated.
[0044] A sectional view through a reservoir and through a generally
horizontal
segment of a SAGD well pair is illustrated in FIG. 5. In the present example,
a mobile
fluid zone 502 is disposed above the reservoir 504. The process for startup of
hydrocarbon recovery, as shown in FIG. 4 and described above, is performed by
injecting fluid at 402 through an insulated tubing in the production well. The
accumulated fluid is lifted to the wellhead at 404 and the well conditions are
monitored
at 406. In response to a temperature, such as the lowest measured temperature
along
the generally horizontal segment 506 of the production well meeting a
threshold
temperature at 408, heating fluid injection is discontinued at 410 and
hydrocarbon
production begins 412.
[0045] The generally horizontal segment 506 of the production well is
below the
generally horizontal segment 508 of the injection well and is further from the
top mobile
fluid zone 502. Thus, the steam chamber 510 that forms begins at the
production well,
which is father from the mobile fluid zone 502, advantageously delaying the
communication of the steam chamber 510 with the mobile fluid zone 502, thereby
reducing the loss of heat and steam to the mobile fluid zone.
[0046] The process illustrated in FIG. 4 is described above with
reference to FIG.
3A, FIG. 3B, and to FIG. 5 in which the process is carried out in a production
well of a
SAGD well pair. The process is not limited to a production well, however. For
example,
the process shown in FIG. 4 may be carried out in an injection well of a SAGD
well pair,
or may be carried out in a single well that is disposed intermediate well
pairs or adjacent
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to a well pair, also referred to as an infill well or a well drilled using
Wedge WeIITM
technology.
[0047] To reduce the chance of early fluid communication between the
steam
chamber and a mobile fluid zone, the production well is circulated to achieve
heating
along the production well and into the injection well as described. A
relatively short
steam cycle of about 1 month, for example, in the injection well may be
utilized after
about 3 months to about 6 months of circulation in the production well to heat
across the
injection well.
[0048] A sectional view through a reservoir and through a generally
horizontal
segment of a SAGD well pair is illustrated in FIG. 6. In this example, a
mobile fluid zone
602 is disposed below the reservoir 604. The process for startup of
hydrocarbon
recovery, as shown in FIG. 4 and described above, is performed by injecting
fluid at 402
through an insulated tubing in the injection well. The accumulated fluid is
artificially lifted
through the tubing string in the injection well to the wellhead at 404 and the
well
conditions are monitored at 406. In response to a temperature, such as the
lowest
measured temperature along the generally horizontal segment 606 of the
injection well
or production well, meeting a threshold temperature at 408, heating fluid
injection is
discontinued at 410 and hydrocarbon production begins 412 by injecting steam
through
the injection well and producing fluids through the production well.
[0049] The generally horizontal segment 606 of the injection well is
above the
generally horizontal segment 608 of the production well and is further from
the bottom
mobile fluid zone 602. Thus, the steam chamber 610 that forms begins at the
injection
well, which is farther from the mobile fluid zone 602, advantageously delaying
the
communication of the steam chamber 610 with the mobile fluid zone 602, thereby
reducing the loss of heat and steam to the mobile fluid zone.
[0050] According to another example, the process is carried out in a
single well
that is disposed intermediate well pairs. Such a well may be drilled, for
example, about
years after production is started in the neighboring well pairs. By carrying
out the
process of FIG. 4 in a single well, communication between a steam chamber that
forms
around the single well and the region of the reservoir that is heated from the
injection of
steam at neighboring well pairs is effectuated.
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[0051] Advantageously, relatively low pressure fluid is circulated to heat
the
reservoir around the well. The low pressure reduces localized heating,
increasing the
effectiveness of the steam in heating the reservoir and improving conformance
by
comparison to the circulation of high pressure fluid. The reduced localized
heating also
reduces the chance of fracturing rock around the reservoir, which causes a
loss of
steam or hotspot development. Insulated tubing that may be utilized for the
injection of
the heating fluid also improves efficiency because less heat is lost during
transport of
the heating fluid and less heat is exchanged with the fluids that accumulate
in the well
and are returned to the surface. The process is carried out prior to recovery
of
hydrocarbons utilizing the well and facilitates production by improving
conformance.
[0052] The described embodiments are to be considered in all respects only
as
illustrative and not restrictive. The scope of the claims should not be
limited by the
preferred embodiments set forth in the examples, but should be given the
broadest
interpretation consistent with the description as a whole. All changes that
come with
meaning and range of equivalency of the claims are to be embraced within their
scope.
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