Note: Descriptions are shown in the official language in which they were submitted.
, CA 02765812 2012-01-25
STEAM SPLITTER
BACKGROUND OF THE INVENTION
Field of the Invention
Embodiments of the present invention generally relate to artificial lift for
hydrocarbon wells. More particularly, the invention relates to a method and an
apparatus for injecting steam into a wellbore.
Description of the Related Art
Throughout the world there are major deposits of heavy oils which are not
recoverable using ordinary production techniques. These deposits are often
referred
to as "tar sand" or "heavy oil" deposits due to the high viscosity of the
hydrocarbons
which they contain. These tar sands may extend for many miles and occur in
varying
thicknesses of up to more than 300 feet. The tar sands contain a viscous
hydrocarbon material, commonly referred to as bitumen, in an amount which
ranges
from about 5 to about 20 percent by weight of hydrocarbons. Bitumen is usually
immobile at typical reservoir temperatures. Although tar sand deposits may lie
at or
near the earth's surface, generally they are located under a substantial
overburden or
a rock base which may be as great as several thousand feet thick. In Canada
and
California, vast deposits of heavy oil are found in the various reservoirs.
The oil
deposits are essentially immobile and are therefore unable to flow under
normal
natural drive or primary recovery mechanisms. Furthermore, oil saturations in
these
formations are typically large, which limits the injectivity of a fluid
(heated or cold) into
the formation.
Several in situ methods of recovering viscous oil and bitumen have been
developed over the years. One such method is called Steam Assisted Gravity
Drainage (SAGD). The SAGD operation requires placing a pair of coextensive
horizontal wells spaced one above the other at a distance of typically 5-8
meters.
The pair of wells is located close to the base of the viscous oil and bitumen.
Thereafter, the span of formation between the wells is heated to mobilize the
oil
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CA 02765812 2012-01-25
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contained within that span by circulating steam through each well at the same
time.
In this manner, the span of formation is slowly heated by thermal conductance.
After the oil in the span of the formation is sufficiently heated, the oil may
be
displaced or driven from one well to the other, establishing fluid
communication
between the wells. At this point, the steam circulation through the wells is
terminated, and steam injection at less than formation fracture pressure is
initiated
through the steam injection well while the production well is opened to
produce
draining liquid. As the steam is injected, a steam chamber is formed as the
steam
rises and contacts cold oil immediately above the upper injection well. The
steam
gives up heat and condenses; the oil absorbs heat and becomes mobile as its
viscosity is reduced, allowing the heated oil to drain downwardly under the
influence
of gravity toward the production well.
A steam generator is located at the surface of the steam injection well. The
steam generator is configured to generate and inject steam down a steam
tubular
into the steam injection well. The steam tubular includes several steam
splitters to
distribute the steam in predetermined sections in the well. Generally, the
steam
splitter is a fluid communication device that selectively injects steam into
the
surrounding wellbore. The conventional steam splitter can be opened or closed
based on the steam requirements during the SAGD operation. To close the
conventional steam splitter, an isolation insert must be inserted in the steam
splitter.
For example, if the steam tubular includes three steam splitters that need to
be
closed, then three isolation inserts must be run into the well, each on a
separate trip
into the well. In other words, three separate trips into the well are required
to close
the three steam splitters. In a similar manner, to open the steam splitters, a
separate
trip into the well is required for each conventional steam splitter to remove
the
isolation insert. As a result, multiple trips are required into the wellbore
to open and
close the conventional steam splitters. Therefore, there is a need for an
improved
steam splitter that can be operated without the need of multiple trips into
the well.
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CA 02765812 2012-01-25
SUMMARY OF THE INVENTION
The present invention generally relates to injecting steam into a wellbore. In
one aspect, a device for injecting steam into a surrounding wellbore is
provided. The
device includes a body having an opening formed in a wall of the body. The
body
further has a bore configured to communicate steam through the body. The
device
also includes a sleeve movable in the bore of the body between a first
position and a
second position, wherein the sleeve in the first position blocks steam from
exiting the
opening of the body and the sleeve in the second position allows steam to exit
the
opening of the body. The device further includes a shroud disposed on a
portion of
the body such that an annulus is formed between the shroud and the body,
wherein
the annulus is configured to direct steam from the opening in the body toward
steam
outlets.
In another aspect, a method of injecting steam into a wellbore using a steam
tubular is provided. The steam tubular includes a first steam splitter device
and a
second steam splitter device. The method includes the step of opening the
first
steam splitter device and the second steam splitter device. The method further
includes the step of pumping steam down the steam tubular and into the
wellbore
through the first steam splitter device and the second steam splitter device.
The
method also includes the step of closing the second steam splitter device.
Additionally, the method includes the step of pumping steam down the steam
tubular
and into the wellbore through the first steam splitter device.
In a further aspect, a method of injecting steam into a wellbore and
transporting wellbore fluid out the wellbore using a tubular is provided. The
tubular
includes a plurality of steam splitter devices. The method includes the step
of
opening one or more steam splitter devices. The method further includes the
step of
pumping steam down the tubular and into the wellbore through the one or more
steam splitter devices. The method also includes the step of closing the one
or more
steam splitter devices. Further, the method includes the step of opening at
least one
steam splitter device. Additionally, the method includes the step of
transporting
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wellbore fluid up through the tubular which enters through the at least one
steam
splitter.
BRIEF DESCRIPTION OF THE DRAWINGS
So that the manner in which the above recited features of the present
invention can be understood in detail, a more particular description of the
invention,
briefly summarized above, may be had by reference to embodiments, some of
which
are illustrated in the appended drawings. It is to be noted, however, that the
appended drawings illustrate only typical embodiments of this invention and
are
therefore not to be considered limiting of its scope, for the invention may
admit to
other equally effective embodiments.
Figure 1 illustrates a partial cross-sectional view of a steam splitter device
disposed in a steam injection well for use in a Steam Assisted Gravity
Drainage
(SAGD) operation.
Figure 2 illustrates a cross-sectional view of the steam injection well and a
production well of the SAGD operation.
Figure 3 illustrates a view of the steam splitter device in a closed position.
Figure 4 illustrates a view of the steam splitter device in an opened
position.
Figures 5 and 6 illustrate views of the steam splitter device being moved to
the
opened position by a shifting tool.
Figures 7 and 8 illustrate views of the steam splitter device being moved to
the
closed position by the shifting tool.
Figure 9 illustrates a partial cross-sectional view, of multiple steam
splitter
devices disposed in the steam injection well.
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DETAILED DESCRIPTION
The present invention generally relates to a steam splitter device for
injecting
steam into a wellbore. The device will be described herein in relation to a
Steam
Assisted Gravity Drainage (SAGD) having two wellbores. It is to be understood,
however, that the device may also be used in other wellbore operations, such
as in
the production wellbore as an inflow production device, without departing from
principles of the present invention. To better understand the novelty of the
device of
the present invention and the methods of use thereof, reference is hereafter
made to
the accompanying drawings.
Figure 1 illustrates a partial cross-sectional view of a steam splitter device
100
disposed in a steam injection well 110 for use in a Steam Assisted Gravity
Drainage
(SAGD) operation. In a typical SAGD operation, there are two coextensive
horizontal
wells, a production well 105 and the steam injection well 110. As shown in
Figure 1,
the steam injection well 110 includes casing 115 on the vertical portion of
the
wellbore. A steam generator 120 is located at the surface of the steam
injection well
110 to inject steam 135 down a steam tubular 125 and through the steam
splitter
device 100 of the present invention. As will be described herein, the steam
splitter
device 100 can be selectively moved between a closed position (Figure 3) and
an
opened position (Figure 4) any number of times.
The production well 105 is lined with casing 30 on the vertical portion of the
wellbore and a screen or a slotted liner (not shown) on the horizontal portion
of the
wellbore. The production well 105 includes production tubing 50 disposed
within the
vertical portion for transporting oil to the surface of the well 105. A pump
55 is
disposed close to the lower end of the production tubing 50 and is in a
substantially
horizontal position near the lowest point of the well 105. A control mechanism
10 is
disposed at the surface of the production well 105 to control the pump 55. The
control mechanism 10 typically provides a hydraulic signal to the pump 55
through
one or more control conduits (not shown), which are housed in a coil tubing
25.
Additionally, one or more pumps 65 may be attached to a fluid conduit 70 to
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CA 02765812 2012-01-25
encourage fluid flow from the toe of the production well 105 to the heel of
the
production well.
Figure 2 illustrates a cross-sectional view of the steam injection well 110
and
the production well 105 of the SAGD operation. As steam 135 is injected in the
upper injection well 110 through the steam splitter device 100, it rises and
contacts
the cold oil immediately thereabove. As the steam 135 gives up heat and
condenses, the oil absorbs the heat and becomes mobile as its viscosity is
reduced.
The condensate and heated oil thereafter drain under the influence of gravity
towards
the production well 105. From the production well 105, the oil is transported
to the
surface using the pumps 55, 65. In the SAGD operation, the condensate and
heated
liquid oil occupy an area depicted by shape 40. The top of the shape 40 is
called a
liquid level 45. Due to the steam 135, oil flows inwardly along drainage lines
into the
area 40. The vertical location of the drainage lines corresponds to the height
of the
liquid level 45. During the SAGD operation, the liquid level 45 will rise and
fall
depending on the amount and location of oil in the reservoir.
Figure 3 illustrates a view of the steam splitter device 100 in a closed
position.
The steam splitter device 100 includes a body 155 having a bore 150. As shown,
steam 135 from the steam generator 120 flows through the bore 150 of the body
155
from one end of the body 155 to the other end when the steam splitter device
100 is
the closed position. A shroud 160 is placed around a portion of the body 155.
The
shroud 160 is offset from the body 155 by a plurality of spacer members 165.
An
annulus 170 is formed between the shroud 160 and the body 155. The annulus 170
is connected to steam outlets 205, which are used for fluid communication to
the
surrounding wellbore when the steam splitter device 100 is in the opened
position. In
one embodiment, the shroud 160 is attached to the body 155 by a heat shrink
process.
A sleeve 175 is disposed inside the body 155. The sleeve 175 is selectively
movable between a first position and a second position within the body 155.
The
sleeve 175 in the first position is shown in Figure 3 and corresponds to the
steam
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CA 02765812 2012-01-25
splitter device 100 in the closed position. The sleeve 175 in the second
position is
shown in Figure 4 and corresponds to the steam splitter device 100 in the
opened
position. The sleeve 175 includes a restraining device 215 which is configured
to
maintain the sleeve 175 in the first position or the second position after the
sleeve
175 has moved to the respective position. In one embodiment, the restraining
device
215 is a double collet arrangement which interacts to restrain or provide
resistance to
the movement of the sleeve 175 when it is in the first position or the second
position.
The sleeve 175 includes a plurality of slots 180 that are configured to act as
a
fluid passageway when the steam splitter device 100 is in the opened position
(Figure 4). In the embodiment shown in the Figure 3, the slots 180 are spiral
slots,
which are constructed and arranged to prevent accidental engagement with
engagement members 85 of a shifting tool 75 (Figures 5-8) when the shifting
tool 75
moves through a bore 210 of the sleeve 175. In another embodiment, the slots
180
are longitudinal slots. In a further embodiment, a plurality of holes is
formed in the
sleeve 175 that may be used instead of the slots 180 or in addition to the
slots 180.
The sleeve 175 further includes seals 130 that straddle an opening 190 in the
body
155 when the steam splitter device 100 is in the closed position. The seals
130 are
configured to substantially prevent steam 135 from flowing out through the
opening
190 in the body 155 and into the annulus 170 when the steam splitter device
100 is in
the closed position. The sleeve 175 further includes a first shoulder profile
185 and a
second shoulder profile 195 at each end.
Figure 4 illustrates a view of the steam splitter device 100 in the opened
position. As shown, the sleeve 175 has moved from the first position to the
second
position. In the second position, the slots 180 in the sleeve 175 are aligned
with the
opening 190 in the body 155, thus creating a fluid pathway between the bore
150 and
the surrounding wellbore. The steam 135 generated by the steam generator is
pumped down the steam tubular and into the steam splitter device 100. A
portion of
the steam 135 is directed into the surrounding wellbore, and another portion
of the
steam 135 moves through the steam splitter device 100. The portion of the
steam
directed into the surrounding wellbore flows through the bore 155, the slots
180, the
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CA 02765812 2012-01-25
opening 190, the annulus 170, and subsequently out through the steam outlets
205.
As set forth herein in relation to the SAGD operation, the steam 135 rises and
contacts the cold oil immediately thereabove. As the steam 135 gives up heat
and
condenses, the oil absorbs the heat and becomes mobile as its viscosity is
reduced.
The condensate and heated oil thereafter drain under the influence of gravity
towards
the production well. From the production well, the oil is transported to the
surface
using the pumps.
Figures 5 and 6 illustrate views of the steam splitter device 100 being moved
to the opened position. The shifting tool 75 is positioned in the steam
splitter device
100 using a conveyance member 80, such as coiled tubing, slickline or tractor,
to
move the steam splitter device 100 from the closed position (Figure 5) to the
opened
position (Figure 6), The steam splitter device 100 may be opened (Figures 5
and 6)
and/or closed (Figures 7 and 8) by deploying the shifting tool 75 into the
steam
injection well in a single trip. The ability to open and/or close the steam
splitter
device 100 in a single trip is particularly advantageous when multiple steam
splitter
devices are located in the steam injection well (Figure 9). For instance, the
shifting
tool 75 is deployed into the steam injection well in a single trip to open or
close any
number of steam splitters depending on the steam requirements during the SAGD
operation. This arrangement allows for better control of the distribution of
steam 135
within the steam injection well.
The shifting tool 75 includes a plurality of engagement members 85, such as
dogs, that are configured to engage the first shoulder profile 185 of the
sleeve 175.
The engagement members 85 are movable between a retracted position and an
extended position by hydraulic pressure (or electric control). The engagement
members 85 are shown in the retracted position in the shifting tool 75
illustrated by
dashed lines in Figure 5, and the engagement members 85 are shown in the
extended position in the shifting tool 75 illustrated by solid lines in Figure
5. The
engagement members 85 of the shifting tool 75 may have a profile that is
configured
to mate with a mating profile on the first shoulder profile 185 and the second
shoulder
profile 195 at each end of the sleeve 175.
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CA 02765812 2012-01-25
The shifting tool 75 is moved through the bore 150 of the body 155 and into
the bore 210 of the sleeve 175 in the direction indicated by arrow 95 by
applying a
force on the conveyance member 80. After the shifting tool is located within
the bore
210 of the sleeve 175, the shifting tool 75 is moved through the bore 210 of
the
sleeve 175 in an opposite direction indicated by arrow 90 by applying a force
on the
conveyance member 80 until the engagement members 85 of the shifting tool 75
contact and engage the first shoulder profile 185 of the sleeve 175 as shown
in
Figure 5. Next, the sleeve 175 and the shifting tool 75 are urged through the
bore
150 of the body 155, as shown in Figure 6, until an end of the sleeve 175 is
positioned proximate a shoulder 140 in the body 155. Thereafter, the
engagement
members 85 of the shifting tool 75 may be disengaged from the first shoulder
profile
185 of the sleeve 175 by retracting the engagement members 85 into the body of
the
shifting tool 75 through hydraulic (or electric) means or by urging the
shifting tool 75
in the direction indicated by arrow 90 which causes the engagement members 85
to
move radially inward to disengage from the first shoulder profile 185 of the
sleeve
175. The shifting tool 75 may then be removed from the steam splitter device
100.
At this point, the steam splitter device 100 is in the opened position, and
thus steam
135 is directed out through the steam splitter device 100 into the surrounding
wellbore as shown in Figures 1 and 4.
Figures 7 and 8 illustrate views of the steam splitter device 100 being moved
to the closed position by the shifting tool 75. To move the steam splitter
device 100
from the opened position (Figure 7) to the closed position (Figure 8), the
shifting tool
75 is positioned in the steam splitter device 100 using the conveyance member
80.
The shifting tool 75 is moved through the bore 150 of the body 155 and into
the bore
210 of the sleeve 175 in the direction indicated by arrow 95 by applying a
force on
the conveyance member 80 until the engagement members 85 of the shifting tool
75
contact and engage the second shoulder profile 195 of the sleeve 175 as shown
in
Figure 7. Next, the sleeve 175 and the shifting tool 75 are urged through the
bore
150 of the body 155, as shown in Figure 8, until an end of the sleeve 175 is
positioned proximate a shoulder 145 in the body 155. Thereafter, the
engagement
members 85 of the shifting tool 75 may be disengaged from the second shoulder
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profile 195 of the sleeve 175 by retracting the engagement members 85 into the
body
of the shifting tool 75 through hydraulic (or electric) means or by urging the
shifting
tool 75 in the direction indicated by arrow 95 which causes the engagement
members
85 to move radially inward. The shifting tool 75 may then be removed from the
steam
splitter device 100. At this point, the steam splitter device 100 is in the
closed
position, and thus steam 135 is directed through the steam splitter device 100
as
shown in Figure 3.
Figure 9 illustrates a partial cross-sectional view of multiple steam splitter
devices 100A-D disposed in the steam injection well 110. Each steam splitter
device
100 can be selectively moved between the closed position (Figure 3) and the
opened
position (Figure 4) any number of times in a similar manner as described
herein. The
ability to open or close selective steam splitter devices 100A-D allows for
better
control of the distribution of steam 135 within the steam injection well 110.
For
example, if more steam is needed proximate the steam splitters 100A, 100C,
then
steam splitters 100A, 100C may be moved to the opened position while the steam
splitters 100B, 100D remain in the closed position as shown in Figure 9. In
another
example, if more steam is needed proximate the steam splitter 100D, then steam
splitter 100D may be moved to the opened position while the steam splitters
100A,
100B, and 100C remain in the closed position. In other words, any number of
steam
splitters 100A-D may be moved to the opened position or closed position
depending
on the steam requirements during the SAGD operation. Further, the steam
splitters
100A-D may be opened and/or closed by using the shifting tool 75 in a single
trip into
the steam injection well 110. For instance, the shifting tool 75 is deployed
into the
steam injection well one time (e.g., single trip) to open or close any number
of steam
splitters depending on the steam requirements during the SAGD operation. The
single trip arrangement saves time and is more cost efficient as compared to
multiple
trips required to operate the conventional steam splitter. As a result, the
single trip
arrangement allows for better control of the distribution of steam 135 within
the steam
injection well.
CA 02765812 2012-01-25
In another embodiment, the steam splitter device 100 may be used in a single
well (e.g., wedge well) to inject steam and produce the wellbore fluid. Rather
than
two wells as shown in Figure 1, the SAGD operation includes the single well.
In this
arrangement, the steam splitter device 100 may be used to inject steam into
the
single well during the steam injection operation, and the steam splitter
device 100
may also be used to receive wellbore fluid during the production operation. In
this
manner, the steam splitter device 100 may be used to selectively manage
control of
the steam injected into the single well and selectively manage control of the
inflow of
produced wellbore fluid.
In one embodiment, a device for injecting steam into a surrounding wellbore is
provided. The device includes a body having an opening formed in a wall of the
body. The body further having a bore configured to communicate steam through
the
body; The device also includes a sleeve movable in the bore of the body
between a
first position and a second position, wherein the sleeve in the first position
blocks
steam from exiting the opening of the body and the sleeve in the second
position
allows steam to exit the opening of the body. The device further includes a
shroud
disposed on a portion of the body such that an annulus is formed between the
shroud
and the body, wherein the annulus is configured to direct steam from the
opening in
the body toward steam outlets. In one aspect, the sleeve includes a plurality
of slots
that are configured to substantially align with the opening formed in the wall
of the
body when the sleeve is in the second position.
In another embodiment, a method of injecting steam into a wellbore using a
steam tubular is provided. The steam tubular includes a first steam splitter
device
and a second steam splitter device. The method includes the step of opening
the
first steam splitter device and the second steam splitter device. The method
further
includes the step of pumping steam down the steam tubular and into the
wellbore
through the first steam splitter device and the second steam splitter device.
The
method also includes the step of closing the second steam splitter device.
Additionally, the method includes the step of pumping steam down the steam
tubular
and into the wellbore through the first steam splitter device. In one aspect,
a shifting
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tool is run into the wellbore to open and close the first steam splitter
device and the
second steam splitter device. In a further aspect, the first steam splitter
device and
the second steam splitter device are opened by the shifting tool in a single
trip into
the wellbore. In a further aspect, the second steam splitter device is
disposed closer
to the end of the steam tubular than the first steam splitter device.
In another embodiment, a method of injecting steam into a wellbore and
transporting wellbore fluid out of the wellbore using a tubular is provided.
The tubular
includes a plurality of steam splitter devices. The method includes the step
of
opening one or more steam splitter devices. The method further includes the
step of
pumping steam down the tubular and into the wellbore through the one or more
steam splitter devices. The method also includes the step of closing the one
or more
steam splitter devices. Further, the method includes the step of opening at
least one
steam splitter device. Additionally, the method includes the step of
transporting
wellbore fluid up through the tubular which enters through the at least one
steam
splitter. In one aspect, the one or more steam splitter devices are opened by
a
shifting tool in a single trip into the wellbore. In another aspect, each
steam splitter
device includes a sleeve member that is movable between a first closed
position and
a second opened position.
While the foregoing is directed to embodiments of the present invention, other
and further embodiments of the invention may be devised without departing from
the
basic scope thereof, and the scope thereof is determined by the claims that
follow.
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