CA 02654447 2009-05-11
WELL BORE ISOLATION USING TOOL WITH SLIDING SLEEVE
This invention is in the field of horizontal wells for hydrocarbons and in
particular
fracturing such wells to increase production in the wells.
BACKGROUND
Conventionally, wells for oil and gas recovery are substantially vertical. A
well bore is
drilled from the surface to a position below a desired hydrocarbon containing
fon:nation,
and then a casing, basically a steel pipe with a diameter just slightly
smaller than the well
bore, is placed inside the walls of the well bore and cemented into place. The
walls of the
casing that are located within the desired formation are perforated, and then
the formation
is fractured by pumping sand or a like proppant into the cased hole at high
pressure. The
pressurized proppant enters the formation through the perforations in the
casing and
breaks the formation with a series of fractures that expand as additional sand
is pumped.
After the formation is fractured, the resultant fractures act as permeable
pathways
allowing oil or gas to flow from the formation into the wellbore.
In contrast in a horizontal well, the well bore is drilled downward to the
formation, and
then turns to extend more or less horizontally through the formation. When
drilling
horizontal wells, coiled tubing is used where has the tubing as one continuous
string
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coiled around a drum that reels pipe in or out to reach the desired depth,
unlike
conventional tubing where nine meter long lengths of pipe are screwed together
as
needed to position the tool at the bottom of the string at the desired
location.
Conventional tubing has the ability to rotate, such as to rotate a drill bit
at the bottom of
the tubing string, whereas coiled tubing cannot rotate, as it is anchored to
the reel. The
coiled tubing can bend to the required horizontal orientation to drill
horizontally
however, and typically the drilling bit is driven by a separate motor at the
bottom end of
the tubing driven by electric or hydraulic power. In a horizontal well, only
the vertical
portion of the well has a casing installed, and the horizontal well bore is
left bare,
comprising simply an open hole through the formation. Thus casing perforations
are not
required
Since rock formations, including hydrocarbon formations, are typically laid
down in
more or less horizontal layers, conventional vertical wells were fractured at
one location
only, where they passed through the formation. Horizontal wells have the
signiScant
advantage of extending for long distances through the formation. Thus
production can
generaliy spealdng be increased by fischuing the formation at as many
locations as
possible along the length of the well bore that is located in the formation.
To attain additional fractures after the initial fracture, the initial
fracture must be isolated
to prevent the pressurized proppant from simply entering and enlarging the
initial
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fracture. Thus the initial fracture is made at the farthest or deepest end of
the horizontal
well bore, and then that initial fractare is isolated by various mechanicaJ,
fluid, hydraulic,
or cement baniers sueh that pre,ssurized proppant can be pumped into the well
bore to
create a new fracture on the upper side of the initial fracture. This proeess
is repeated
along the horizontal ]ength of the well bore until a number fractures have
been made
along the horizontal length of the well bore from the initial fiadure at the
deepest ends to
a final fractnre at the shallow end of the horizontal well bore.
The present systems for isolating prior fxactures typically incxease cost,
putnping time,
and complexity, and as well only a limited number of fractures can be placed.
In one system, used by Packers Plus of Calgary, Canada, a liner is placed in
the
horizontal well bore. The liner includes a series of 10-12 balI seats that
progressively
incxease in size fiom the deepest to the shatlowest end of the [iner. Covered
ports are
defined in the walls of the liner at intervals between the ball seats, and the
covers are
designed to rupteme at a progressively increasing pressums from the deepest to
the
shailowest end of the liner. Packers are positioned on the outside of the
liner adjaoent to
each baii seat to seal offthe iiner to the open well bore to isolate each
zone.
Thus in the Packers Plus system, the initial fracfiue is made by pushing a
small diameter
ball down the liner to seat in the farthest ball seat and seal the end of the
liner. Proppant
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is then pumped into the liner and the pressure is increased until the covers
of the ports
between the farthest ball seat and the next adjacent ball seat rupture,
allowing the
proppant to form a fracture in the formation through the farthest ports. For
example this
initial rupture pressure nzight be 1000 pounds per square inch (psi), and the
fracture made
at these ports is limited to the fracture that can be made with a pressure of
1000 psi, since
increasing the pressure above this may caase the next adjacent ports to
rupture.
Once the initial fracture has been made, a slightly larger balS is pushed down
the liner to
seat in the next adjacent ball seat, sealing off and isolating the first
fracture. Pressure is
increased to that sufficient to rupture the covers on the next adjacent ports,
for example
1200 psi, and the second fracture is made creating whatever fracture can be
made with
this slightly increased pressure of 1200 psi. This process is repeated until
all the
available ports have been ruptured and fractures made through them. When all
fractures
have been made, the inteimediate baIIs are typically pushed up to the surface
by the
production flowing from the fractures, with the farthest ball remaining in
place sealing
the end of the liner. The liner with the ball seats is left in the well which
complicates
future well repair and re-worldng. This system is currently popular as it is
effective at
preventing communication between fractures.
A system used by Baker Hughes of Houston Texas utilizes a pernianent liner and
ball
seats similar to Packers Plus except it has siiding sleeves or trap doors that
are opened
CA 02654447 2009-02-17
when a fractare is required and then sealed and isolated with progressively
larger balls.
This system currently is capable of about 14 separate fractures. When the
fracturing is
complete the liner is again left in the hole.
5 Other systems are lmown that utilize a coiled tubing assembiy. Once an
initial frachure is
completed, a gel (viscous silicone) plug is pumped down the we1l bore and
allowed to
harden to isolate the first fracture from later ones. After fracriuing is
completed, the gel
plugs are drilled out leaving the wellbore open to future repairs and enhanced
recovery.
TEuis system was initially popular but has been found to allow communication
between
fractures since the gel plugs do not seal well enough to resist the high
pressures, often
3000 psi or more, of a fracturing operation.
It is also Irnown to pump in cement to form the plugs instead of gel. The
cement is
allowed to harden, then a fracture is made, then a new plug, then fracturing,
and so on.
This system's main drawback is the time required for the cement to harden
sufficiently.
With a conventional fracturing operation costing thousands of dollars an hour,
this is not
economically feasible on any but the most productive wells.
It is also commonly required to isolate portions of a well bore for other well
stimulation
methods such as acidizing, swabbing, sandjetting, brazingõ and ths like. A
system for
isolating a portion of a well bore between upper and lower packers and
providing fluid to
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the isolated portion is disclosed in United States Patent Number 6,782,954 to
Serafin et
al. In the system a sliding sleeve is provided by a mandrel and housing
between the
upper and lower packers, and a bypass is provided through the sleeve from the
well bore
below the lower packer to the well bore above the upper packer. The upper and
lower
packers are acxivated and sest by a first Qressure and then a second increased
pressure
opens ports in the sliding sleeve in the isolated zone between the packers.
The system
includes spnngs, catches, fingers, and other moving parts which react to
changes in
pressure to move the housing reiative to the mandrel to open and close the
ports in the
sliding sleeve.
SUMMARY OF THE INVENTION
It is an object of the present invention to provide a system and method for
fracturing
fonuations in hydrocarbon wells that overcames problems in the prior art.
In a first embodiment the present invention provides an apparatus for
isolating a portion
of an open horizontal well bore and for providing pressurized fluid to the
isolated well
portion. The apparatus comprises an upper packer adapted for attachment to a
bottom
end of a tubing string A sliding sleeve oomprises an upper sleeve
telescopically engaged
with a lower sleeve, where the upper sleeve is connected at a top end thereof
to the upper
packer and to the bottom end of an attached tubing string, and the lower
sleeve is
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connected at a lower portion thereof to a lower packer such that a bottom end
of the
lower sleeve below the lower packer is open. A ball seat is defined at the
bottom end of
the lower sleeve, and a ball is configured to pass down through an attached
tubing string
and through the upper and lower aleeves to seal the bottom end of the lower
sleeve. The
upper and lower sleeves define sleeve ports that are in alignment to provide a
flow path
through the upper and lower sleeves when the sliding sleeve is in an open
position, and
wherein the sleeve ports are out of alignment to prevent flow through the
upper and lower
sleeves when the sliding sleeve is in a closed position. A bias element is
operative to
exert a bias force on the upper and lower sleeves urging the sliding sleeve
toward the
closed position. The upper and lower packers are configured such that same can
be
coliapsed to allow same to be moved along the well bore by an attached tubing
string ,
and such that the lower packer can be set to seal the wett bore when the lower
packer is at
a desired location. After the lower packer is set, an opening force can be
exerted through
the tubing string on the sliding sleeve to move the sliding sleeve to the open
position
against the bias force. The upper and lower packers are configured such that,
after the
lower packer is set and the sliding sleeve is in the open position, the upper
packer can be
set to seal the well bore and isolate a portion of the well bore between the
upper and
lower packers with the sliding sleeve in the open position.
In a seoond embod'unent the present invention provides an apparatus for
isolating a
portion of an open horizontal well bore and for providing preLmmzed fluid to
the isolated
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well portion. The apparatus comprises an upper packer attached to a bottom end
of a
coiled tubing string. A sliding sleeve comprises an upper sleeve
telescopically engaged
with a lower sleeve, and the upper sleeve is connected at a top end thereof to
the upper
packer and to the bottom end of the coiled tubing string, and the lower sleeve
is
connected at a lower pottion theroof to a lower packer such that a bottom end
of the
lower sleeve below the lower packer is open. A ball seat is defined at the
bottom end of
the lower s5eeve, and a ball is configured to pass down through the coiled
tubing string
and through the upper and tower sleeves to seal the bottom end of the lower
sleeve. The
upper and lower sleeves, define sleeve ports that are in aligmnent to provide
a flow path
through the upper and lower sleeves when the sliding sleeve is in an open
position, and
wherein the sleeve ports are out of aiignment to prevent flow through the
upper and iower
sleeves when the sliding sleeve is in a closed position. A bias element is
operative to
exert a bias force on the upper and lower sleeves urging the siiding sleeve
toward the
elosvd position. The upper and lower packers are eonfigured such that same cen
be
13 collapsed to allow same to be moved along the well bore by the coiled
tubing string , and
sach that the lower packer can be set to seal the well bore when the lower
packer is at a
desired location. After the lower packer is set, an opening force can be
exerted tbrough
the coiled tubing string on the sliding sle4we to move the sliding sleeve to
the open
position against the bias force. The upper and lower packers are configured
such that,
atkr the lower packer is set and the sliding sleeve is in the open position,
the upper
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packer can be set to seal the well bore and isolate a portion of the well bore
between the
upper and lower packers with the sliding sleeve in the open position.
In a ihird embodiment the present invention provides a method of isolating a
portion of
an open horizontal weI[ bore and for providing preasurized fluid to the
isolated well
portion. The method comprises attaching an upper packer to a bottom end of a
tubing
string; providing a sliding sleeve comprising an upper sleeve telescopically
engaged with
a lower sleeve, and eonnecting a top end of the upper sleeve to the upper
packer and to
the bottom end of the tubing string, and connecting a lower portion of the
lower sleeve to
a lower packer such that a bottom end of the lower sleeve below the lower
packer is
open; providing a ball seat at the bottom end of the lower sleeve, and a balI
configured to
pass down through the tubing string and through the upper and lower sleeves to
seal the
ball seat; wherein the upper and lower sleeves define sleeve ports that are in
alignment to
provide a flow path through the upper and lower sleeves when the sliding
sleeve is in an
open position, and wherein the sleeve ports am out of alignment to prevent
flow through
the upper and lower sleeves when the sliding sleeve is in a closed position;
providing a
bias element operative to exert a bias force on the upper and lower sleeves
urging the
sliding sleeve toward the closed position; collapsing the upper and lower
packers and
circalating fluid through the tubing stcing and open bottom end of the lower
sleeve and
moving the packers along the well bore with the tubing string to locate the
lower packer
at a desired location; after the lower packer is at the desired location,
pushing the ball
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tbrough the tubing string and upper and lower sleeves to the ball seat to seal
the bottom
end of the lower sleeve; after the lower packer is at the desired location,
setting the lower
packer to seal the well bore at the desired location; after the lower packer
is set,
manipulating the tubing string to exert an opening force on the sliding sleeve
to move the
5 sliding sleeve to the open position against the bias force; after the lower
packer is set and
the sliding sleeve is in the open position, setting the upper packer to seal
the well bore
and isolate a portion of the weii bore between the upper and lower packers;
and pumping
pressurized fluid through the tubing string and aligned sleeve ports to the
isolated well
portion.
The apparatus and method of the present invention allow placement of the
isolated
portion of the well bore virtually anywhere along the well bore while
preventing
communicatiion between the cutrent isolated portion and prior isolated
portions of the
well bore. The upper and lower packers are set in the open horizontal welI
bore with an
open communication path from the tubing string to the desired formation
location
through the open sliding sleeve. The sliding sleeve is simple, with the only
moving parts
being a sliding relative movement between the upper and lower sleeves.
The invention allows quick placement of location with minimal time between
each stage,
and allows an unlimited nnmber of locations, rather than being limited by
liners as in the
prior art. Circulation and well control through the tubing string are
available if required,
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and in the event of being stuck in the hole by sand or the like, there are
multiple ways to
circulate the throngh the appara.tus, washing the sand away, preventing it
from becoming
stuck and possibly anchored permanently down hole
Operations require less time, and no costly sleeves or like equipment is
pennanently left
in hole. When the process is complete, only an open hole remains, enabling
future
workovers using new technologies as they may become available, unlike prior
art
systtms where fiiture work is obstructed by liners and the like left in the
well bore.
DESCRIPTION OF THE DRAWINGS
While the invention is claimed in the concluding portions hereof, preferred
embodiments
are provided in the accompanying detailed description which may be best
understood in
aonjunction with the aocompanying diagrams where like parts in each of the
several
diagrams are labeled with like numbers, and where:
Fig. I is a schematic sectional side view showing an embodiment of an
apparatus of
the present invention in a typical well such as would be drilled to recover
hydriocarbons;
Fig. 2 is a schematic side view of the apparatus of Fig. 1;
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Fig. 3 is a schematic sectional side view of the sliding sleeve of the
apparatus of Fig. 2
shown in the closed position;
Fig. 4 is a schematic sectional side view of the sliding sleeve of the
apparatus of Fig. 2
shown in the open position;
Fig. 5 is a schematic sectional side view showing the apparatus of Fig. I in a
typical
well in a first location to isolate a first portion of the well bore, and in a
second
location shown in phantom lines to isolate a second portion of the well bore;
Figs. 6 and 7 schematically illustrate embodiments of the invention that
include valve
mechanisms operative to close off the lower packer to substantiially prevent
fluid
communication between the sliding sleeve and the lower packer when the sliding
sleeve is in the open position.
DETAILED DESCRIPTION OF THE ILLUSTRATED EMBODIMENTS
Figs. 1 and 2 schematicalty illustrate a side view of an embodiment of an
apparatus 1 of
the present invention for isolating a portion of an open horizontal well bore
and for
providing pressnrized fluid to the isolated well portion. 'Ihe apparatus I is
illustrated in
_ , ,
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Fig. 1 attached to the bottom end of a coiled tubing string 2 in a typical
horizontal we113
such as is commonly dtilled for recovering hydrocarbons such as oil and gas
from
underground formations. The well 3 comprises a generally vertical section of
well bore 5
that is typically lined with a casing 7. The well 3 curves from vertical to
horizontal when
the desired fonnation is reached, and a section of borizontal well bore 9
extends through
the formation. The horizontal well bore 9 is not cased, but rather is what is
commonly
referred to as an open hole or open well bore. Thus the bare formation is
exposed along
the length of the horizontal well bore 9.
TypicalIy once the well 3 has been drilled and the vertical portion cased, the
well will be
completed by carrying out a well completion process such as fracturing the
formation to
allow hydrocarbons to more easily pass from the formation into the well. In
horizontal
wells the well bore is generally in the fornaaxion along its entire length, or
most of its
length, and so fracturing the formation at relativeLy close intervals is
desirable. The
present invention allows pressurized fluid for fracturing or like well
completion or other
processes, to be carried out at very close intervals, and unlike the systems
of the prior art,
with virtually no limit on the number of well portions that can be isolated
and treated by
fracturing or the like.
The apparatus I comprises an upper packer 11 attached to a bottom end of the
coiled
tubing string 2. Although the apparatus I is oriented horizontally when in use
in the
CA 02654447 2009-02-17
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horizontal well bore 9, in this description terms such as "uppe ', 'lower",
"up", and
"down" are used relative to the surface of the ground 13 at the top of the
vertical well
bore 5.
A sliding sleeve 15 comprises an upper sleeve 17 telescopically engaged with a
lower
sleeve y9. The upper sleeve 17 is oonnecteb at a top end thereof to the upper
packer 11
and to the bottom end of the coiled tubing string 2, and the 3ower sleeve 19
is connected
at a lower portion thereof to a lower packer 21 such that a bottom end 23 of
the lower
sleeve 19 is below the lower packer 21, and is opon, such that 8uid can
c'ucilate through
the coiled tubing string 2 and sliding sleeve 15 and then out the open bottom
end 23 of
tbe lower sleeve 19. As illust<ated in Figs. 3 and 4, the upper and'lower
sleeves 17, 19
are shown extending tlunugh the corresponding upper and lower packers 11, 21.
The
actual construction may be otherwise, so long as fluid can freely conununicate
from the
tubing string 2 out the open bottom end of the apparatus, shown as the bottom
end 23 of
the lower sleeve 19.
A seat provided by ball seat 25 is defined at the bottom end 23 of the lower
sSeeve 19,
and a seaiing element, provided by ball 27 is configured to be able to pass
down through
the coiled tubing string 2 and through the upper and lower sleeves 17, 19 to
seal the
bottom end 23 of the lower sleeve 19. Alternatively as is known in the art the
sealing
element can be provided by an elongate dart shaped body that will move down
the tubing
CA 02654447 2009-02-17
string without tumbling, and which has a tapered or rounded bottom end that is
configured to provide a seal when in contact with the seat. Such a sealing
element or ball
27 is also commonly configured to collapse at pressures above those
contemplated to be
used in a particular operation so that, should the need arise, pressura in the
tubing string
5 can be increased to blow the sealing element out the end of the lower sleeve
in order to
allow circulation through the open bottom end of the tubing string at the open
bottom end
23 of the lower sleeve 19 the sealing element.
The upper and lower sleeves 17, 19 define sleeve ports 29 that are in
alignment to
10 provide a flow path through the upper and lower sleeves 17, 19 when the
sliding sleeve
15 is in an open position as illustratod in Fig. 4 where the sleeve port 29A
in the upper
sleeve 17 is aligned with the sleeve port 29B in the lower sleeve 19. The
sleeve ports
29A, 29B are out of alignment to prevent flow through the upper and lower
sleeves 17,
19 whcn the sliding sleeve 15 is in the closed position illustrated in Fi,g.
3.
A bias element, illustmtett as a spft 31, is opemtive to exert a bias force BF
on the
upper and lower sleeves 17, 19 urging the sliding sleeve 15 toward the closed
position.
In the illustrated embodiment of Figs. 3 and 4, the bias force BF is exerted
upward, or
toward the surface, to urge the upper sleeve 17 upward relative to the lower
sleeve 19.
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The upper and lower packers 11, 21 are configured such that same can be
collapsed to
allow same to be moved along the well bore 9 by the coilea tubing string 2,
and such that
the lower packer 21 can be set to seal the well bore 9 when the lower packer
11 is at a
desired location. Convenientiy the iower pacicer 21 is provided by a hydraulic
packer of
the type that is operative to expand and set in response to pressurized fluid
directed
through the coiled tubing string 2 and into the lower sleeve 19 after the ball
27 is in the
ball seat 27 to prevent the fluid from simply passing out the open end 23 of
the lower
sleeve 19.
After the lower packer 21 is set, the lower packer is fixed in the well bore 9
so that an
opening force OP can be exerted through the coiled tubing string 2 on the
sliding sleeve,
such as by releasing some of the weight of the vertical portion of the tubing
string 2 such
that the tubing string moves down exerting an opening force OP that is greater
than the
bias force BF and so is sufficient to move the sliding sleeve 15 to the open
position of
Fig. 4 against the bias force BF provided by the spring 31.
After tlte lower packer 21 is set and fixed in the well bore 9, and the
sliding sleeve 15 is
in the open position, the upper packer i l can be set to seal the well bore 9
and isolate that
portion of the well bore 9 that is between the upper and lower packers 11, 21.
Conveniently the upper packer 11 is provided by a compression packer that is
set by
releasing a further weight of the tubing string 2 sufficient to exert a
downward setting
CA 02654447 2009-02-17
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force on the compression packer. The compression packer is set by the weight
of the
tubing forcing the top of the packer downward while the bottom of the packer
is fixed in
place by the set lower packer 21 and the fully collapsed sliding sleeve 15.
The setting force required to set the upper compression type packer l 1 is
greater than the
opening force OP that is required to overcome the bias force to open the
sliding sleeve
15. Thus the sliding sleeve 15 will move to the open position before the upper
packer 11
sets. When using the compression type upper packer 11, the sliding sleeve 15
must be in
the open position before the upper packer 11 is set, since once the upper
packer 1 l is set,
no movement of the sliding sleeve to the open position is possible.
Once the upper and lower packers are set, the portion of the well bore 9 that
is between
the upper and lower packers 11, 21 is isolated from the rest of the well bore
9 and
pressurized fluid for well stimulation by fracturing or acidizing the
fonmation at the
isolated location, or for other purposea, can be provided down th,e tubing
string 2 and
through the aligned sleeve ports 29.
Thus a method of the present invention for isolating a portion of an open
horizontal well
bore and for providing pressurized fluid to the isolated well portion
comprises attaching
an upper packer l 1 to a bottom end of a tubing string 2; providing a sliding
sleeve 15
oomprising an upper sleeve 17 telesoopicaliy engaged with a lower sleeve 19,
and
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connecting a top end of the upper sleeve 17 to the upper paeker I! and to Hhe
bottont end
of the tubing stfing 2, and eonnectiag a lower portion of the lower sleeve 19
to a lower
packer 21 such that a bottom end 23 of the lower sleeve9 is below the lower
packer 21 is
open; providing a bail seat 25 at the bottom end 23 of the iower sleeve 19,
and a bail 27
configured to pass down through the tubing string 2 and through the upper and
lower
sleeves 17, 19 to seal the ball seat 25. The upper and lower sleeves 17, 19
define sleeve
ports 29 that are in aiigament to provide a flow path through the upper and
lower sleeves
17, 19 when the sliding sleeve 15 is in an open position such as illustrated
in Fig. 4, and
wherein the sleeve ports 29 are out of alignment to prevent flow through the
upper and
lower sleeves 17, 19 when the sliding sleeve 15 is in the closed position
shown in Fig. 3.
A b'tas element such as a spring 31 is operative to exert a bias f+at+co BF
cxe the upper and
lower sleeves 17, 19 urging the sliding sleeve 15 toward the closed position.
The method then includes collapsing the upper and lower packers 11, 21 and
circulating
fluid through the tubing string 2 and open bottom end 23 of the lower sleeve
19 and
moving the packers 11, 21 along the well bore 9 with the tubing string 2 to
locate the
lower packer 21 at a desired location, and after the lower packer 21 is at the
desired
location, pushing the bal127 through the tubing string 2 and upper and lower
sleeves 17,
19 eo the ball seat 25 to seal the bottom end 23 of the lower sleeve 19, and
a$er the lower
packer 21 is at the desired location, setting the lower packer 21 to seal the
well bore 9 at
the desired location.
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The hydraulic lower packer 21 is set by pressurized fluid pumped into the
tubing string 2
and through the sliding sleeve 15 which is in the closed position and into the
hydraulic
lower packer 21, since the ball seat at the bottom end 23 of the lower sleeve
19 is sealed
by the ball 27. Typically the fluid enters the bydraulic packer tbrough a one
way valve
and the hydraulic packer which expands in response to the pressure.
The method thcn includes, after the lower packer 21 is set, manipulating the
tubing string
2 to exert an opening force OP on the sliding sleeve 15 to move the sliding
sleeve 15 to
the open position of Fig. 4 against the bias force BF, and after the lower
packer 21 is set,
setting the upper packer i 1 to seal the well bore 9 and isolate a portion of
the weli bore 9
between the upper and lower packers 11, 21. Pressurized fluid is then pumped
through
the tubing strmg 2 and out through the aligned sleeve ports 29 to the isolated
well
portion. Using the hydraulically activated Iower pack 21 as described above,
requires
that the ball 27 be pushed through the tubing string 2 and upper and lower
sleeves 17, 19
to the ball seat 25 prior to setting the lower packer 21 so that pressurized
fluid pumped
down the tubing string 2 can exert pressure on the lower packer 21 to set the
packer
rather than escaping out the open bottom end 23 of the lower sleeve 19.
When using the illustrated apparatus 1, the opening force OP is exerted in a
downward
direction by releasing a weight of the tubing string 2 sufficient to overcome
the bias foroe
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BF to move the sliding sleeve 15 downward to the open position. As the tubing
string 2
moves down the sliding sleeve 15 opens, allowing some circulation through the
aligned
sleeve ports 29 and the surface through the annulus between the walls of the
well bore 9
on the outside of the tubing string 2. This allows water to be pumped into the
well bore 9,
5 conditioning the hole, and, for example in a fracturing operation, allowing
the proppant to
be circulated down the tubing string to arrive at the desired working location
when
needed. Once the sliding sleeve is open, and any desired circulation through
the annutus
is complete, further weight from the tubing string 2 can be allowed to exert a
downward
setting force, greater than the opening force UP, on the compression packer
that is
10 required to set the upper compression type packer 21.
As schematically illustrated in Fig. 5, ance the desired operation, such as
maSring
fractures 33 in the formation, has been completed at a first isolated portion
WA of the
well bore 9, the upper and lower packen 11, 21 are eoilapsed and the tubing
string 2 is
15 moved to locate the lower packer 21 at a second desired location in the
well bore 9.
Generally in practice the operations will be performed first at the deepest
end of the well
bore 9 moving toward the top end of the well bore 9 so that the coiled tubing
string 2 can
pull the apparatus I back out of the hole and leave the operated portions of
the well bore
9 behind. Thus generally tbe second desired location will be neares to the
surface of the
20 well 3 tban the first isolated portion WA.
, , ,
CA 02654447 2009-02-17
21
The compression type upper packer 11 is collapsed by exerting an upward force
on the
coiled tubing string 2. Once the upper packer 11 is collapsed, the upper
packer l l will
begin moving upward in response to continued upward force and the sliding
sleeve 15
will move to the closed position as the upper sleeve moves upward with the
upper packer
11. When the sliding sleeve 15 is fully extended, the upward force of the
tubing striag 2
will then be transfecred to the lower hydraulic packer 21 and will open the
one way valve
to release the pressurized fluid trapped therein, and collapse the hydraulic
lower packer
21. By statting operations at the deepest desired location, fiatber upward
force on the
tubing string 2 then pulls the apparatus I to the next desired location.
When the lower packer 21 is at the seeond desired location, shown in, phantom
lines, the
lower packer 21 is again set to seal the well bore 9 at the second desired
location, and the
tubing string 2 is lowered to open the sliding sleeve 15 and set the upper
packer 1 I to seal
the well bore and isolate a second portion WB of the weli bore 9 between the
upper and
lower packers 17, 19, and pressurized fluid is pumped through the tubing
string 2 and
aligned sleeve ports 29 to the second isolated well portion WB to make further
fractures
33.
In most operations the bal127 can be left in the seat 25 when moving the
apparatus 1
from a one location to the next, however should the apparatus 1 and packers
11, 21
become stuck in the well bore 9, the ball 27 can be circulated out of the seat
25 by
_ , _,
CA 02654447 2009-02-17
22
drawing fluid upward tbrough the tubing string 2, moving the ba1127 out of the
tubing
string 2, and then circulating fluid through the open bottom end 23 of the
lower sleeve 19
to clear ehe well bore 9, ot if necessary by increasing the pressure to
collapse the ball 27
and blow same out the end 23 of the lower sleeve 19 to allow circulation.
Figs. 6 and 7 schematieally illustrate embodiments of the invention that
include a valve
mechanism operative to close off the lower packer 21 to substantially prevent
fluid
communication between tiie sliding sjeeve i5 and the lower packer 21 when the
sliding
sleeve 15 is in the open position. Such a valve mechanism prevents the lower
packer 21
from being subjected to abrasive fluids and the high pressures during a
fracturing
operation.
In the embodiment of Fig. 6, the valve mechanism comprises a first valve
sealing portion
43 moureted to the upper sleeva 17 and a second valve sealing porfiion 45
mounted to the
lower sleeve 19 such that when the sliding sleeve 15 moves to the open
position where
the sleeve ports 29 are alignad, the first and second valve sealing portions
43, 45 mate to
seal off the lower packer 21 from fluid and pressure in the sliding sleeve 15.
Similacly in the embodiment of Fig. 7 the valve mechanism camprises a valve
flap 47
biased to an open position and then pushed tlo a closed position as the upper
sleeve 17
CA 02654447 2009-02-17
23
moves down into the lower sleeve 19 and the sliding sleeve 15 moves to the
open
position where the sleeve ports 29 are aligned.
In both embodiments as the sliding sleeve 15 moves to the closed position, the
val;ve
mechanism opens to allow fluid cammunicatios. It is contemplated that nnmerous
other
valve mechanisms kaown in the art would serve the purpose as well.
The apparatus and method of the present invention allows placement of the
isolated
portion of the well bore virtually anywhere along the well bore while
preventing
communication 6etween the cun=t isolated portion and prior isolated portions
of the
well bore. = The invention allows quick placement of location with minimal
time between
each stage, and allows an unlitnited number of locations, rather than being
limit.ed by
liners as in the prior art.
Beneficially the ball and seat arrangement allows circailation/well control
through the
tubing string should the fbrmation begin flowing uneontrolled, and allows well
control
during a fiachning process. hi the event of `sanding off or being stuck in
sand, there are
multiple ways to circulate the thcough the apparatus, washing the sand away,
preventing
it fmm becoming stuck and possibly anchored permanently down hole Circulation
of
varying amounts is possible in the apparatus, as well as out the bottom of the
apparatus,
CA 02654447 2009-02-17
24
Operations require less time, and no costly sleeves or Iflce equipment is
permanently left
in hole. When the prooess is complete, only an open hole remains, enabling
future
workovers using new teohnoiogies as they may become available, unldce prior
art
systems whete future work is obstcucted by liners and the like left in the
well bore.
The present invention may be used for well stimulation methods such as
fracturing,
acidizin,g, and the liice.
The foregping is considered as illustnative only of the principles of the
invention.
Further, since numerous changes and modifications will readily occur to those
slolled in
the ait, it is not desired to limit the invention to the exact constsuction
and operation
shown and described, and accordingly, all such suitable changes or
modifications in
structure or operation which may be resortcd to are intended to fall within
the scope of
the claimed invention.
