Note: Descriptions are shown in the official language in which they were submitted.
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Wellbore Injection System
Field of the Invention
This invention relates to an injection device and method for the in-situ
production of
hydrocarbons from downhole wellbores.
Background
Heavy oil and bitumen reservoirs are prevalent worldwide but extraction from
such
subsurface formations is often difficult and poses a number of challenges to
efficiency and cost
effectiveness. Steam or fluid injection into horizontal wellbores is a known
method for
enhanced exploitation and recovery from oil, heavy oil or bitumen bearing
unconsolidated
reservoirs and subsurface formations. Generally, steam injected into heavy oil
and bitumen
formations assists in reducing the high viscosity of in-situ heavy oils and
bitumens thereby
increasing mobility out of the formation. Steam Assisted Gravity Drain (SAGD),
cyclic steam
stimulation (CSS) and steamflooding are common exploitation methods used as
enhanced oil
recovery techniques. However, steam injection into horizontal wellbores cannot
always be
distributed in an even, preferential manner. Some preferred distributions
include equalized
outflow distributions, specifically placed injection distributions and skewed
distributions.
Present technologies include steam injection via low open area slotted liners,
having
approximately 1% open area, and single or dual internal tubing string
conveyances. These
methods are commonly used with sand control screens or liners to add radial
resistance to
steam flow and encourage axial distribution of the steam along the horizontal
wellbore and
promote equalized distribution throughout the formation. However, one problem
with this
technology is that the injection/prodcution liner often has too large of an
open area and
therefore cannot provide sufficient radial resistance to steam flow. This
leads to non-uniform
steam distribution into the formation.
The open area of the injection/prodcution liner is generally designed to
provide a means
for controlling and preventing sand from plugging pore spaces of the reservoir
either directly or
indirectly above the injection/prodcution liner. It also acts to prevent sand
from infiltrating and
plugging the profile of the injection/prodcution liner during the production
phase of in-situ oil
recovery. Therefore the open area for sand control, which is typically 3%, but
can range from
1.5%-5%, is much larger than the required open area desired for equalized
steam distribution,
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which is typically <0.05% but can range from 0.001%-1%.
Single tubing conveyed steam injection systems tend to be positioned nearest
the heel
of the wellbore, and create a poorly distributed steam chamber which has a
large steam
chamber nearest the heel for the wellbore and very little steam distribution
at the toe.
Dual tubing conveyed steam injection system provides one tubing to convey
steam near
the heel and a second tubing to convey steam nearer the toe of the horizontal
well. This
alleviates the problem of a large steam chamber only at the heel, as seen in
single tubing
systems. However, the dual system instead forms two large steam chambers, one
nearest the
heel and the other nearest the toe of the horizontal wellbore.
There is therefore a need for a device and method to provide evenly
distributed steam
or other injection fluid along the entire length of the wellbore, in which
steam distribution can
be targeted as needed.
Summary
A device is taught for delivery and equalized distribution of steam into a
subsurface formation
from a wellbore or for producing fluids from the subsurface formation into the
wellbore, said
device comprising an outer sleeve ; an inner sliding sleeve in concentric
relationship with the
outer sleeve; one or more sets of nozzles arranged on the outer sleeve of the
device through
which steam or production fluids are transferred into or out of the subsurface
formation; and
means for actuating movement of the inner sliding sleeve within the outer
sleeve to at least
partially cover the one or more sets of nozzles on the outer sleeve, thereby
controlling steam
injection into or out of the subsurface formation, wherein actuation of the
inner sliding sleeve
within the outer sleeve serves to fully open, partially open and fully close
said one or more sets
of nozzles.
A method is further provided for delivery and equalized distribution of steam
into a subsurface
formation from a wellbore or for producing fluids from the subsurface
formation into the
wellbore, said method comprising the steps of introducing into the wellbore
one or more
devices, each device comprising an outer sleeve and an inner sliding sleeve in
concentric
relationship with the outer sleeve and one or more sets of nozzles arranged on
the outer sleeve;
actuating movement of the inner sliding sleeve within the outer sleeve of one
or more selected
devices to control steam injection into or production fluid flow out of the
subsurface formation
through any said one or more selected devices; and transferring steam or
production fluids
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through the one or more sets nozzles into and out of the subsurface formation
via the one or
more selected devices, wherein actuation of the inner sliding sleeve within
the outer sleeve
serves to fully open, partially open and fully close said one or more sets of
nozzles.
Finally, a method is provided for delivering and equally distributing steam
into a subsurface
formation from a wellbore or for producing fluids from the subsurface
formation into the
wellbore, said method comprising the steps ofintroducing into a heel location
of the wellbore a
first and second pairs of flow control hangers and polished bore receptacles,
wherein the
polished bore receptacles are connected to an intermediate casing and cemented
in place;
connecting the first pair of flow control hanger and polished bore receptacle
to an
injection/prodcution liner; connecting one or more devices to the second pair
of flow control
hanger and polished bore receptacle, said devices comprising an outer sleeve
and an inner
sliding sleeve in concentric relationship and one or more sets of nozzles
arranged on the outer
sleeve; actuating movement of the inner sliding sleeve within the outer sleeve
of one or more
selected devices to control steam injection into or production fluid flow out
of the subsurface
formation through any said one or more selected devices; and transferring
steam or production
fluids through the nozzles into or out of the subsurface formation via the
devices,wherein
actuation of the inner sliding sleeve within the outer sleeve serves to fully
open, partially open
and fully close said one or more sets of nozzles.
Brief Description of the Drawings
The present invention will now be described in greater detail, with reference
to the
following drawings, in which:
Figure 1 is a cross sectional view of one example of the present steam pup
device;
Figure 2 is a cross sectional view of one example of the present steam pup
device, installed with
one example of the present setting tool;
Figure 3 is a perspective view of one example of the present setting tool;
Figure 4 is a cross sectional view on the present steam pup device, showing
one example of an
angled nozzle in an open position;
Figure 5 is a is a cross sectional view on the present steam pup device,
showing one example of
an angled nozzle in a closed position;
Figure 6 is a flow diagram illustrating one embodiment of the method of the
present invention;
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Figure 7 is a schematic diagram illustrating a first embodiment of the present
invention as used
with flow control seals and polished bore receptacle joints; and
Figure 8 is a schematic diagram illustrating a second embodiment of the
present invention as
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used with flow control seals and polished bore receptacle joints.
Description of the Invention
The present invention relates to one or more steam pups that are removably
inserted
into horizontal wellbores for controlled injection of steam or other injection
fluids into the well,
and also for production flows from the formation into the well. Although
horizontal wellbores
are preferably mentioned throughout, the present invention is equally useful
in vertical and
slanted wellbores and it is to be understood that these applications are
encompassed by the
present invention. Although the device of the present invention is referred to
as a steam pup, it
will be well understood by a person of skill in the art that the present
device can be used for
injection of steam and any other well known injection fluids, and also for
production of fluids
from the formation into the wellbore.
More specifically, the present device serves to manage steam or other
injection fluid
flow into the well and production flows from the well. The steam pups are
designed to be set
and operated from the surface without removing the steam pups from the well.
The steam
pups preferably comprise two or more fluid flow settings. One setting closes
off the flow areas
and stops flow into or out of the wellbore. The other settings provide a range
of flow rates up to
full flow into or out of the wellbore. Further preferably, each steam pup can
be operated or set
independently, allowing the operator to either set them all to the same flow
rate, or to
selectively turn off flow from particular steam pups, thereby isolating
particular sections of the
well.
Although steam is most commonly referred to, it is to be understood that the
present
device and method provide a means of injecting any suitable injection fluid
into the subsurface
formation. Many such injection fluids are known in the art and include steam,
water, varsol,
diesels and solvents. It is therefore to be understood that the present
invention encompasses
any and all such known fluids.
The invention aids in improving the delivery and distribution of steam into
the target
formation by providing an equalized steam distribution along the wellbore,
coupled with proper
sand control. The present retrievable system can be used in conjunction with
SAGD,
steamflood, CSS or other steam exploitation processes and/or steam injection
combined with
injection of other fluids such as solvents. For the purposes of the present
invention solvents are
considered to include any chemical or biochemical that aids in reducing the in-
situ oil viscosity,
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improving steam delivery or increasing the beneficial exploitation properties
of the reservoir.
The present invention further provides a means of equalizing the steam
delivery, normalized
into the formation by relating the axial wellbore resistance to the radial
formation resistance to
injection.
In the present system, fluid properties are taken into consideration when
determining
the desired open area for fluid injection over the length of the wellbore. By
relating fluid
properties to the wellbore specifications and formation properties, the nozzle
size and number
of open nozzles, corresponding to the open area for injection, can be
specified to allow for
equalized steam distribution along the horizontal wellbore. Further
preferably, the system can
also be designed for varying fluid properties during the course of injection
and production,
which allows for use of the present system in a wide range of applications.
With reference to Figure 1 , the present steam pup 2 comprises an outer sleeve
4 and an
inner sliding sleeve 6. The outer sleeve 4 and inner sliding sleeve 6 are
preferably made of
hardened materials such as high speed steels (HSS) and other hardened steels
commonly used
in downhole tools and directional drilling tools.
The steam pup can be built in a number of sizes, from standard tubing sizes
used in the
industry up to standard and commonly known casing sizes. More particularly,
steam pup
diameters can range from 1 inch to 11 % inches. The length of the steam pup
also varies with
application and can be from a minimum length of lm to a maximum of 13.5 m.
The outer sleeve 4 consists of an upper box connection and a lower pin
connection (not
shown) to mate with a desired casing to be run in conjunction with the steam
pups 2. The outer
sleeve 4 comprises at least two rows comprising one or more nozzle holes 8.
The inside
diameter of the outer sleeve 4 preferably comprises at least one retainer ring
10 which limits
motion of the inner sliding sleeve 6 and prevents the inner sliding sleeve 6
from sliding
completely out of the outer sleeve 4. The outer sleeve 4 also comprises one or
more locking
rings 12, for positioning the inner sliding sleeve 6 in one of a number of
desired positions.
The inner sliding sleeve 6 takes the form of a mandrel which slidingly fits
into the inside
diameter of the outer sleeve 4. The inner sliding sleeve 6 comprises a series
of o-rings 14 to
minimize and prevent the flow of debris between the outer diameter of the
inner sliding sleeve
6 and the inner diameter of the outer sleeve 4. The outside diameter of the
inner sliding sleeve
6 comprises 2 or more machined grooves 16 that mate with the locking ring 12
to position the
inner sliding sleeve in a number of different positions, corresponding to a
number of different
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nozzle opening 8 settings. The inside diameter of the inner sliding sleeve 6
further contains one
or more pins 18.
A setting tool 20 is shown in a preferred arrangement with the present steam
pup 2 in
Figure 2 and on its own in more detail in Figure 3. With reference to these
figures, the setting
tool 20 comprises an upper box connection (not shown) corresponding with the
working string
connection, and a lower open hole end 22. The outside diameter of the setting
tool 20
comprises one or more grooves, or slides 24 that extend over the length of the
setting tool 20
and which correspond to pins 18 on the inner sliding sleeve 6. The outside
diameter of the
setting tool 20 is slidingly received into the inner sliding sleeve 6 only
when slides 24 are aligned
with the pins 18. When the slides 24 are not aligned with the pins 18, then
the open hole end
22 of the setting tool 20 abuts the pins 18 and push thereagainst.
Alternatively, movement of the inner sliding sleeve 6 within the outer sleeve
4 of the
steam pup 2, may be hydraulically controlled remotely from the surface, in
which case no
setting tool 20 is required.
The present nozzles 8 may be oriented perpendicular to the axis of steam pup
2, as
shown in Figures land 2, or alternatively they may be angled, as shown in
Figures 4 and 5. Any
angle is possible for the nozzles and encompassed in the present invention
With reference to Figures 4 and 5, the sets of nozzles may preferably be set
at a 600
angle to the axis of the steam pup 2. More preferably, the orientation of each
nozzle 8 in the set
is alternated or the orientation of each nozzle in the set can be randomly
varied. This promotes
an equal distribution of steam to the formation. An angled orientation also
reduces friction
losses often caused by 900 turns during steam travel. The angled orientation
is also preferred to
reduce wear around the nozzles 8 caused from the high velocity of steam or
other injection
fluids. The nozzles 8 can be machined to the outer sleeve 4 as shown in the
figures. Optionally,
the nozzles 8 may also be part of a separate unit that is attached to the
outer sleeve 4. In a
preferred embodiment nozzles 8 of steam pups 2 used in the heel of a wellbore
are preferably
specifically designed to account for steams properties at the heel location to
provide the
preferential radial flow resistance to steam along the horizontal wellbore.
The present arrangement of nozzles 8 and the preferential manner in which
nozzles 8
can be opened or closed allows steam to be equally distributed along the
horizontal wellbore.
Further preferably, nozzle geometry may be a varied and may include circular,
tapered, conical,
oval, square, rectangular or slot shapes. Varying nozzle geometry provides a
resilient but
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flexible means for adjusting to potential thermal loading and plastic
deformation of the nozzles
under high pressure and temperature situations during the steam injection
phase. The geometry
may also optionally be selected to provide control of flow resistance,
pressure and flow rate.
Turning to Figures 4 and 5, at the point of exit from the nozzle 8 of the
steam pup 2,
injection fluid follows a graduated ramp 28. A hardened blast plate 30 is
positioned above the
nozzle 8 to protect against wear of the injection/production liner (not shown)
that the steam
pup 2 resides in.
Nozzle geometry and size of the present steam pup can be designed for a number
of
different steam injection pressures or rates. For example, steam can be
injected below, at or
above a fracture pressure of the reservoir. Steam can also be injected at
subsonic/subcritical or
sonic/critical flow regimes.
Preferably the steam pup 2 is a retrievable system which is situated within
and
optionally attached, threaded or otherwise connnected to a larger
injection/production liner
which interfaces with the formation. The steam pup 2 can be a closed or open
ended system.
Further preferably a series of steam pups can be joined together by lengths of
blank casing to
form a steam pup string, to allow variation in injection and production along
the entire length of
the wellbore, and also to preferentially isolate particular lengths of the
wellbore. In this way the
system can be used in waterflooding operations, creating steam isolation zones
or in de-
watering applications.
The present steam pup 2 assembly may be kept inside the injection/production
liner
after the injection phase and used for the production phase, to produce in-
situ fluids, in the case
of a single well design. In this case, production fluids flow in a reverse
direction back into the
steam pup 2, through the nozzles 8. In production, the blast plate 30 acts to
reduce resistance
of the production fluids as they enter the steam pups 2.
Sand control screens/liners used with the present invention can be any type of
sand
screen known in the art and include, but are not limited to wire-wraps,
slotted liners, meshriteTM
or other sand control screens. The injection/production liner preferably
interfaces the entire
length of the reservoir, not simply portions thereof and there are therefore
no blank lengths of
pipe in the horizontal wellbore. This desirably allows for low pressure drops
for producing
fluids, better radial inflow, better contact with the whole reservoir, better
sand control and
better steam distribution along the horizontal wellbore.
Preferably, there is also provided a means of positioning and preferably
centralizing the
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steam pup 2 within the injection/production liner by connecting one or more
packers which are
larger than the outside diameter of the steam pup 2, but is small enough to
fit snuggly within
the inside diameter of the injection/production liner, which interfaces with
the formation. The
packers are run with the steam pups 2 and predetermined amounts of casing and
used to isolate
the series of steam pups 2.
The packers are designed to allow space for milling and retrieving if
required, as well as
some pressure control and steam distribution control. The packers can be
preferably set at the
heel location, and also one third and two thirds of the way along the length
of the horizontal
wellbore or selectively at other locations along the wellbore, inside of the
injection/prodcution
liner to maintain pressure control of the injection fluid and control of fluid
distribution by sealing
off the annular space between the formation and the injection/prodcution liner
and the steam
pups 2. Alternatively, if packers are not used, then the present inventors
estimate that the high
viscosity of the in-situ oil can also provide the necessary pressure control
and fluid distribution
control.
In operation, the setting tool 20 is run into the well, preferably using a 2
7/8" work
string, which is commonly used in such applications. The setting tool 20 is
run to a location just
above a steam pup 2, indicated by a stoppage in movement corresponding to
abutment of the
open hole end 22 of the setting tool 20 against the pins 18. In rare occasions
when the slides 24
of the setting tool 20 coincidentally align with the pins 18 on the inner
sliding sleeve 6, the
setting tool 20 may not abut against the inner sliding sleeve 6, but will
instead bypass the steam
pup 2. In such cases, the string can be raised to a position above the steam
pup 2, and rotated
to offset the slides 24 with the pins 18, and then lowered again.
To position the steam pup 2 to a desired nozzle setting, a force or weight is
applied to
the setting tool 20. Once the weight exceeds resistance from the locking ring
12, the inner
sliding sleeve 6 will slide along until the locking ring 12 receives the next
locking ring groove 16,
or until the inner sliding sleeve 6 abuts against a downstream retainer ring
10.
Alternatively, the setting tool 20 may also be pulled up to set the steam pup
2 to a
desired nozzle setting. In this case, the setting tool 20 must pass back
through the inner sliding
sleeve 6 first. The work string is rotated until the slides 24 line up with
the pins 18 and the
setting tool 20 is then lowered through the inner sliding sleeve 6. The
setting tool 20 is again
rotated to offset the slides 24 and the work string is raised until a
resistance is felt, indicating
that the setting tool 20 has abutted against the pins 18. The work string can
then be raised until
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the resistance from the locking ring 12 is overcome and until the locking ring
12 receives a new
locking ring groove 16, or until the inner sliding sleeve 6 abuts the upstream
retainer ring 10.
In an alternate embodiment, the present invention can also operate without a
injection/production liner, as for example in the case of a SAGD operation. In
such cases, no
packers are required and there is no need for a dual flow control hanger but
only a single flow
control hanger. For SAGD applications there is typically a "warm-up" phase or
"circulation"
phase, which requires that bitumen or heavy oil reserves lying between the
injector well and the
producer well be heated for mobility, steam chamber growth, production and
fluid control. This
warm up phase typically requires a significantly lower quantity and lower
pressure of steam
injection than during the full injection-production phase of a fully
functioning SAGD well pair. In
these cases, a first steam pup system can preferably be designed to provide
equalized and
optimized steam distribution for the warm-up phase, after which the first
steam pup system
may optionally either be retrieved and a second steam pup system inserted to
provide high
pressure steam for a full injection phase, or the first system may optional be
kept in place and
the inner sliding sleeve 6 adjusted to allow for full injection through the
nozzles 8, without
removing the initial steam pup system.
The steam pup 2 flow settings are preferably machined to provide an open, full
flow
setting as a top setting, herein referred to as position "A", a shut off flow
setting as a middle
setting, herein referred to as position "B", and another partially open flow
setting at a lowest
setting, herein referred to as position "C". The extent of open area for both
the upper and
lower settings, positions "A" and "C" are predetermined based on fluid
properties including
pressure, quality, temperature and loss. The complete steam pup string
including packers, can
be removed from the well and redesigned if required.
By creating an equalized distribution of steam along the horizontal wellbore
the whole
reservoir is preferentially contacted with steam providing more oil
production, lower steam-oil
ratios and more efficient transfer of energy into the formation.
In a preferred embodiment, the present invention can be designed for fluid
injection at
injections pressures that are above or below the fracture pressure of the
reservoir or the
invention can also accommodate subcritical or critical flow regimes.
In an alternate embodiment, the present steam pup 2 may not be attached to the
injection/production liner of the wellbore. In such cases it is preferable to
have pairs of flow
control hangers and polished bore receptacles (PBR). The pairs of flow control
hangers and
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polished bore receptacles are fitted together and placed one above the other
in the location of
the intermediate casing. The polished bore receptacles are connected to the
intermediate
casing and cemented in place. This system is then installed in the heel
location of the horizontal
wellbore to minimize leak rates and control pressure loss of steam injected at
the heel location,
which can be caused by high pressure steam tending to create a by-pass past a
flow control
hanger at the heel location. The first flow control hanger and polished bore
receptacle, which
are located furthest into the wellbore are connected to the
injection/prodcution liner, thereby
providing a seal against leak off and to maintain pressure and at the heel
location. The second
flow control hanger and polished bore receptacle are connected to the steam
pup and situated
above, but not necessarily connected to the first flow control hanger and
polished bore
receptacle. These also provide a similar pressure and leak off seal.
In a further preferred embodiment, the present invention can also operate
without the use of
packers for centralizing the steam pups or steam pup string. This embodiment,
illustrated in
Figures 7 and 8, utilizes one or more pairs of polished bore receptacle (PBR)
joints 26 and flow
control (FC) seals 28 to isolate the steam steam pups instead of packers. For
example, the one
or more pairs of PBR joints 26 are run down the well with one or more slotted
liners 30 run
between the PBR joints 26. The number of slotted liners 30 used will depend on
such factors as
the formation characteristics, the length of the wellbore and costing
considerations. In some
cases, slotted liners 30 may be run between each PBR joint 26 in the string to
allow an equal
spacing of isolation zones. In other cases as few as 2 to 3 slotted liners 30
may be required.
Although the term slotted liners is used herein, it would be well understood a
person of skill in
the art that any sand control screen type could be utilized for these purposes
without departing
from the scope of the present invention.
Steam liners can be connected by one or more blank casings with one or more
steam pups 2, all
located between the FC seals 28. The distance between PBR joints 26 in the
fixed slotted liner
string is set to mate with the distance between FC seals 28 on the steam liner
string. The FC
seals 28 can be fit to the PBR joints 26 with a positive memory seal. However,
it is also possible
to have a fit allowance of from 0.001" to 0.002" without causing significant
steam losses. More
preferably, increasing smaller inside diameter PBR joints 26 and FC seals 28
are installed within
the slotted liner string, from the surface to the bottom of the wellbore. This
allows clearance
for all of the PBR joints 26 and FC seals 28 to be run down the wellbore. When
bottom of the
wellbore is reached, each FC seal 28 comes in contact with its corresponding
PBR joint 26 and
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the sealing is complete. In this way, steam distribution and steam pressure
are equalized and
maintained over the length of the well bore and there is less occurrence of
steam bypass.
By not using packers, it is possible to avoid possibly sealing packers with
too much pressure or
deterioration of packers due to steam, which then requires having to mill out
and retrieve failed
packers. Furthermore, using PBR joints to isolate zones of the formation does
not lead to
undesirable wellbore diameter restrictions, as does the use of a combination
of packers and
piping for the same purposes. Restricted wellbore diameters can cause friction
losses and
impede steam distribution, increase pumping requirements and restrict the
types of tools that
can be used downhole. The preferred PBR/FC seal system will operate in a
similar manner to a
configuration with packers, in that, if there is an area of the wellbore that
needs isolating, the
steam pup between two FC seals is simply closed off so that the isolated area
will not produce
fluids and is sealed off from the rest of the wellbore.
Examples
The following examples serve merely to further illustrate embodiments of the
present invention,
without limiting the scope thereof, which is defined only by the claims.
Example 1:
A well has an intermediate casing, known as the build section, at a depth of
600m, and the total
depth of the well is 1500m. The pay zone, or horizontal section, of the
production zone is 900m
long. Three different groups of steam pups are used for steaming, together
with three packers.
The 15t packer, set at a 1200m depth, isolates 3/4 of the nozzles in the first
steam pup from 1200m
depth to 1500m depth. The 2"cl packer, set at a 900m depth, isolates 1/2 of
the nozzles in the
second steam pup from the 900m depth to the 1st packer at 1200m. The 3rd
packer is set at
600m, at the bottom of the intermediate casing and isolates% of the nozzles in
the third steam
pup between a 600m depth and the 2nd packer at 900m.
Predetermined amounts of casing are run in conjunction with the steam pups to
achieve the
required lengths between the packers. By using different nozzle settings on
the steam pups
between the isolated packers, the operator is able to deliver steam or other
injection fluids into
the formation evenly.
When a production cycle is required, the well can produce through the same
nozzles, or the
steam pups can be set to a larger open area for production. If one of the
isolated zones are
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producing an unwanted product such as water or sand, the associated steam pups
can be set to
a lower flow setting or can be closed off completely.
In the foregoing specification, the invention has been described with a
specific embodiment
thereof; however, it will be evident that various modifications and changes
may be made
thereto without departing from the scope of the invention.
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