U.S. patent application number 12/322730 was filed with the patent office on 2010-08-12 for apparatus and method for treating zones in a wellbore.
Invention is credited to Gary Maier, Troy Palidwar.
Application Number | 20100200218 12/322730 |
Document ID | / |
Family ID | 42539431 |
Filed Date | 2010-08-12 |
United States Patent
Application |
20100200218 |
Kind Code |
A1 |
Palidwar; Troy ; et
al. |
August 12, 2010 |
Apparatus and method for treating zones in a wellbore
Abstract
Apparatus and method for treating zones in a wellbore. The
apparatus includes an expandable packer assembly and a sealing
element positioned in the treatment assembly above the packer
assembly. A communication port is positioned between the sealing
element and the packer assembly. A plurality of slips will
grippingly engage the well above the port through which treatment
fluid is communicated to resist upward force caused by treatment
pressure in the well acting on the sealing element. The sealing
element may be a cup packer.
Inventors: |
Palidwar; Troy; (Langdon,
CA) ; Maier; Gary; (Calgary, CA) |
Correspondence
Address: |
JOHN W. WUSTENBERG
P.O. BOX 1431
DUNCAN
OK
73536
US
|
Family ID: |
42539431 |
Appl. No.: |
12/322730 |
Filed: |
February 6, 2009 |
Current U.S.
Class: |
166/126 ;
166/185; 166/305.1; 166/382 |
Current CPC
Class: |
E21B 33/1265 20130101;
E21B 33/124 20130101; E21B 43/26 20130101 |
Class at
Publication: |
166/126 ;
166/185; 166/305.1; 166/382 |
International
Class: |
E21B 23/00 20060101
E21B023/00; E21B 43/16 20060101 E21B043/16 |
Claims
1. A treatment assembly for treating formations intersected by a
well comprising: an expandable packer element mounted on a packer
mandrel and movable between a set position in which the packer
element seals against the well and an unset position in which the
packer element is spaced from the well; at least one cup packer
connected in the treatment assembly above the expandable packer
element for engaging the well; a ported sub connected in the
treatment assembly between the at least one cup packer and the
expandable packer element, the treatment assembly defining a flow
passage for communicating fluid to the ported sub; and radially
extendable slips for grippingly engaging a casing in the well
connected in the treatment assembly above the at least one cup
packer.
2. The treatment assembly of claim 1, the at least one cup packer
comprising two cup packers connected in the treatment assembly
above the ported sub.
3. The treatment assembly of claim 1, the slips comprising
hydraulically actuated slips.
4. The treatment assembly of claim 3, further comprising a
hold-down head comprising: a top sub adapted to be threadedly
connected to a tubing; a hold-down body connected to the top sub,
the hydraulically actuated slips being mounted in the hold-down
body; and a bottom sub connected to the hold-down body.
5. The treatment assembly of claim 4, the hold-down body having an
upper end and a lower end, and having a longitudinally extending
communication port extending from the upper end of the hold-down
body in a wall thereof for communicating hydraulic pressure to the
radially extendable hold-down slips in the hold-down body.
6. The treatment assembly of claim 5, the top sub having upper and
lower ends, wherein the lower end of the top sub and the upper end
of the hold-down body define a passage therebetween, hydraulic
pressure being communicated into the longitudinally extending
communication port through the passage.
7. The treatment assembly of claim 6, further comprising a debris
barrier positioned in the passage.
8. A method of treating a zone intersected by a well comprising the
steps of: lowering a treatment assembly into the well, the
treatment assembly comprising an expandable packer, a downwardly
facing cup packer positioned above the expandable packer, and a
ported sub positioned between the cup packer and the expandable
packer; expanding the expandable packer in the well to engage the
well; pumping a treating fluid into a selected zone in the well
through the ported sub; applying a radially outwardly directed
force to the casing in the well with the treatment assembly to
resist movement of the treatment assembly upwardly in the well as
the treating fluid is being pumped through the ported sub into the
zone.
9. The method of claim 8, wherein the radially outwardly directed
force is a result of increasing pressure in the treatment
assembly.
10. The method of claim 8, the treatment assembly further
comprising a hydraulic hold-down head, the applying step comprising
radially extending hold-down slips in the hold-down head to engage
the casing in the well.
11. The method of claim 8, the applying step comprising radially
expanding a hold-down tool positioned in the treatment assembly
above the cup packer to engage the well.
12. The method of claim 10, comprising increasing pressure in the
treatment assembly to radially expand the hold-down tool to engage
the well.
13. The method of claim 8, wherein the radially outwardly directed
force is applied above the cup packer.
14. A method of treating multiple zones in a well comprising:
lowering a treatment assembly into the well to a first position in
the well to treat an initial selected zone; sealingly engaging the
well with a sealing element during the lowering steps; expanding an
expandable packer element to engage the well after the treatment
assembly has reached the first position in the well; engaging the
well with a plurality of downwardly facing slips below the packer
element; injecting a treating fluid through the treatment assembly
between the sealing element and the expandable packer element into
the initial selected zone; grippingly engaging the well with the
treatment assembly to resist an upward force applied to the sealing
element during the injection step; and moving the treatment
assembly in the well after the initial selected zone has been
treated to at least one additional position to treat at least one
additional selected zone.
15. The method of claim 14, wherein the initial, and the at least
one additional selected zone are in a horizontal portion of the
wellbore.
16. The method of claim 14, further comprising: releasing the
gripping engagement; and retracting the expandable packer element
prior to the moving step.
17. The method of claim 14, further comprising repeating the
expanding, injecting, and grippingly engaging steps at the at least
one additional selected zone.
18. The method of claim 14, wherein the sealing element comprises a
downward facing cup-type packer.
19. The method of claim 14, the grippingly engaging step comprising
radially expanding a portion of the treatment assembly to
grippingly engage the well.
20. The method of claim 19, the radially expanding step comprising
communicating fluid pressure from a central passage in the
treatment assembly to a passageway defined in a wall of the
treatment assembly, wherein the fluid pressure urges a portion of
the treatment assembly radially outwardly into engagement with the
well.
21. The method of claim 14, the treatment assembly further
comprising a hold-down head, wherein the grippingly engaging step
comprises radially extending hold-down slips in the hold-down head
to engage the well.
22. The method of claim 14, the grippingly engaging step comprising
radially extending upwardly facing slips to engage the well above
the sealing element.
23. A tool for treating multiple zones in a wellbore comprising: at
least one cup packer mounted on a mandrel connected in the tool
slips; an expandable packer assembly connected in the tool below
the cup packer, the tool including an injection port positioned
between the at least one cup packer and the expandable packer
assembly for communicating a treating fluid from the tool into a
zone to be treated; and upwardly facing radially extendable slips
positioned above the at least one cup packer for engaging the well
and resisting the upward force resulting from the treatment
pressure acting on the cup packer.
24. The tool of claim 23, the at least one cup packer comprising a
first downward facing cup packer and a second downward facing cup
packer, the injection port being positioned between the second
downward facing cup packer and the expandable packer assembly.
25. The tool of claim 23, wherein the radially extendable slips
comprise a portion of a hydraulic hold-down assembly.
26. The tool of claim 25, the hydraulic hold-down assembly
comprising: an upper sub; and a hold-down body connected to the
upper sub, the hold-down body having an axial passage therein
communicated with a central flow passage defined through the
hold-down body, wherein hydraulic pressure communicated through the
axial passage will urge the radially extendable slips outwardly
into engagement with the well.
27. The tool of claim 26, the upper sub and the hold-down body
defining a space therebetween, wherein fluid pressure is
communicated from the central flow passage in the hold-down body
through the space and into the axial passage.
28. The tool of claim 23, the upwardly facing radially extendable
slips being positioned in the tool above the at least one cup
packer.
29. A method of anchoring a treatment tool in a well comprising:
lowering the treatment tool into the well, the treatment tool
defining a longitudinal central flow passage and at least one
treatment port for communicating treatment fluid into a zone to be
treated; radially expanding a packer element to contact the well
below the treatment port; radially extending downward facing slips
to resist downward movement of the tool; communicating treatment
fluid through the treatment port into the zone to be treated; and
grippingly engaging the well with upwardly facing slips to resist
upward movement of the tool during the communicating step.
30. The method of claim 29, the grippingly engaging step comprising
radially extending a plurality of slips to engage the well above
the treatment port.
31. The method of claim 30, further comprising applying hydraulic
pressure to the slips to radially extend the slips.
32. The method of claim 29, further comprising: retracting the
packer element from contact with the well; releasing the gripping
engagement; and moving the tool to at least one additional zone in
the well to be treated.
33. The method of claim 29, further comprising sealingly engaging
the well above the treatment port as the tool is lowered in the
well.
34. The method of claim 33, the sealingly engaging step comprising
engaging the well with at least one cup packer.
35. The method of claim 34, the grippingly engaging step comprising
radially extending the upward facing slips to engage the well above
the at least one cup packer.
36. The method of claim 29, wherein the tool includes a cup packer
positioned above the treatment port and a hydraulic hold-down
assembly positioned above the cup packer, and wherein the
grippingly engaging step comprises increasing pressure to extend
the upwardly facing extendable slips in the hold-down assembly to
engage the well.
Description
BACKGROUND
[0001] This disclosure relates to an assembly and method for
treating a subterranean well formation, or zone, and more
particularly to an apparatus and method for fracturing.
[0002] A number of techniques have been developed for treating
formations to stimulate hydrocarbon production from formations
intersected by a subterranean well. One such technique involves the
hydraulic fracturing of a zone by isolating a zone and pumping a
stimulation fluid into the isolated zone. The zone to be treated
may be isolated with packers installed on a tubing lowered into the
well, and the fracturing fluid may be pumped through the tubing so
that it will exit one or more ports between the packers and move
into the zone to be treated. Such arrangements work well, but in
cases where cup-type packers are used, the pressure developed
during pumping will try to lift the tubing in the well, which can
damage the tubing.
[0003] In situations where large diameter casing is in use, for
example, 51/2 or 7 inch, or where the treatment occurs in a
horizontal well, the pressure may be such that the packers used to
isolate the well, along with the weight of the tubing in the well,
is not sufficient to keep the tool in place during fracturing. As
such, there is a continuing need for fracturing assemblies in high
pressure and/or large diameter casing applications that will resist
upward movement due to the pressure applied by the fracturing fluid
on the upper packer.
SUMMARY OF THE INVENTION
[0004] The current disclosure is directed to a treatment assembly
for treating formations or zones intersected by the well. The
treatment assembly has an expandable packer element mounted on a
packer mandrel. The expandable packer element is movable between
set positions in which the packer element seals against the well
and an unset position in which the space is defined between the
packer element and the well. The well may be cased or uncased. At
least one cup packer is connected in the treatment assembly above
the expandable packer element and will engage the well as the
treatment assembly is lowered into the well to the zone to be
treated. A ported sub is connected in the treatment assembly
between the at least one cup packer and the expandable packer
element. Treatment fluid is communicated through the treatment
assembly and through the ported sub into the zone to be
treated.
[0005] The treatment assembly includes radially extendable slips
for grippingly engaging the casing in the well to resist upward
force that occurs when treatment pressure is increased in the well.
The slips may be positioned above the ported sub and preferably
above the at least one cup packer. The radially extendable slips
may comprise a portion of a hold-down head which includes a top sub
adapted to be connected to the tubing that lowers the treatment
assembly in the well. The hold-down head may further include a
hold-down body connected to the top sub and a bottom sub connected
to the hold-down body. A plurality of radially extendable slips are
mounted in the hold-down body that upon the application of
hydraulic pressure will radially extend to grippingly engage the
casing. The hydraulic pressure is generated by the treating fluid
that is pumped through the treatment assembly and into the zone
being treated. A radially directed force between the treatment
assembly and the casing will resist the upward force that results
from the pressure acting on the cup packer. Thus, additional
holding or resisting force is applied by the treatment
assembly.
[0006] When treatment of a particular zone is complete, the pumping
will cease and the hydraulic pressure will be relieved so that the
extendable slips will retract. The packer element may likewise be
released and moved to the unset position and the treatment system
moved in the well to a second or more additional zones for
treatment in the manner described herein.
BRIEF DESCRIPTION OF THE DRAWINGS
[0007] FIG. 1 schematically shows a treatment assembly in a
well.
[0008] FIG. 1A schematically shows the treatment assembly in a
horizontal well.
[0009] FIG. 2 is a partial cross section of the lower portion of
the treatment assembly in a run-in position.
[0010] FIG. 3 is a partial cross section of the lower portion of
the treatment assembly in a set position.
[0011] FIG. 4 is a partial cross section of the lower portion of
the treatment assembly in a retrievable position.
[0012] FIG. 5 is a cross-section view from line 5-5 of FIG. 6.
[0013] FIG. 6 is an end view of the hold-down assembly.
[0014] FIG. 7 is a cross-section view from line 7-7.
[0015] FIG. 8 shows the position of the lug in the J-slot.
[0016] FIGS. 9 and 10 are side and bottom views of a debris
barrier.
DETAILED DESCRIPTION OF AN EMBODIMENT
[0017] While the making and using of various embodiments of the
present invention are discussed in detail below, it should be
appreciated that the present invention provides many applicable
inventive concepts which can be embodied in a wide variety of
specific contexts. The specific embodiments discussed herein are
merely illustrative of specific ways to make and use the invention,
and do not limit the scope of the present invention.
[0018] The present invention provides improved methods and tools
for treating hydrocarbon zones in a single well. The methods can be
performed in either vertical or horizontal wellbores. The term
"vertical wellbore" is used herein to mean the portion of a
wellbore in a producing zone to be completed which is substantially
vertical, inclined or deviated. The term "horizontal wellbore" is
used herein to mean the portion of a wellbore in a subterranean
producing zone, which is substantially horizontal. Since the
present invention is applicable in vertical, horizontal and
inclined wellbores, the terms "upper and lower" and "top and
bottom" as used herein are relative terms and are intended to apply
to the respective positions within a particular wellbore while the
term "levels" or "intervals" is meant to refer to respective spaced
positions along the wellbore. The term "zone" is used herein to
refer to separate parts of the well designated for treatment and
includes an entire hydrocarbon formation or even separate portions
of the same formation and horizontally and vertically spaced
portions of the same formation. As used herein, "down," "downward"
or "downhole" refer to the direction in or along the wellbore from
the wellhead toward the producing zone regardless of whether the
wellbore's orientation is horizontal, toward the surface or away
from the surface. Accordingly, the upper zone would be the first
zone encountered by the wellbore and the lower zone would be
located further along the wellbore. Tubing, tubular, casing, pipe
liner and conduit are interchangeable terms used herein to refer to
walled fluid conductors.
[0019] Referring now to the drawings and more particularly to FIG.
1, a well 10 comprising a wellbore 15 and casing 20 cemented
therein is shown. A treatment assembly 25 which may be referred to
as a fracturing assembly 25 is shown lowered into well 10 on a
tubing 32. Tubing 32 may be coiled or jointed tubing. An annulus 30
is defined by and between well 10, and more particularly between
casing 20 and treatment assembly 25. Well 10 intersects an upper
selected zone 34 and a lower selected zone 36 and may intersect any
number of selected zones that may be treated as described herein.
While zone 34 may be referred to as the first zone, since it is the
first zone encountered during drilling, the treatment of zones will
occur from the bottom of well 10 upwardly, so that the first zone
encountered will be the last zone treated.
[0020] Treatment assembly 25 is shown disposed in a vertical
wellbore or a vertical portion of a wellbore 15 in FIG. 1, but it
is understood that treatment assembly 25 may be utilized in a
horizontal or horizontal portion of a wellbore as shown in FIG. 1A.
Numerical designations used in FIG. A include the subscript .sub.a
for the well, wellbore, casing, annulus and first and second zones.
Treatment assembly 25 may include a hold-down head or hold-down
assembly 38 connected at its upper end 40 to tubing 32. It is
understood that the hold-down head 38 and other components
described herein may be connected together with fittings or
adapters of types known in the art so that the hold-down head may
be connected at its upper end 40 to tubing 32.
[0021] Treatment assembly 25 includes at least one and preferably a
plurality of cup packers 44 that may be referred to as an upper cup
packer 46 and a lower cup packer 48 both of which are downwardly
faced cup packers. Cup packers 46 and 48 may be mounted on mandrels
and connected in treatment assembly 25 with couplings or other
adapters 50 known in the art. Cup packers 46 and 48 comprise
sealing elements that will be in engagement with well 10, and in
the embodiment shown with casing 20, as treatment assembly 25 is
lowered into position adjacent selected zones to be treated.
[0022] A centralizer 52 is connected in treatment assembly 25 below
cup packers 46 and 48 and may be connected at a lower end thereof
to a blast or spacer joint 54. Treatment assembly 25 can include as
many lengths of blast joint 54 as desired. A ported sub 56 is
connected to spacer joint 54 and to an equalizing valve assembly
58. Treatment assembly 25 may further include a packer assembly 60
that includes expandable packer elements 62 connected to equalizing
valve assembly 58. A slip assembly 64 and drag block assembly 66
are attached in treatment assembly 25 below expandable packer
elements 62.
[0023] Referring now to FIG. 2, a portion of treatment assembly 25
is shown in partial cross section in run-in mode. Ported sub 56 has
an upper end 70, a lower end 72 and has at least one and preferably
a plurality of injection ports 74 defined therethrough. Injection
ports 74, which may be referred to as treatment ports 74, are
communicated with longitudinal central passage 76 which will
receive a treating fluid therethrough. Equalizing valve assembly 58
includes a valve housing 78 having upper end 80 and lower end 82.
In the run-in mode, upper end 80 will abut lower end 72 of ported
sub 56. A plurality of slots 84 are defined through valve housing
78. A valve extension 86 having an upward facing shoulder 85
thereon, and having an upper threaded portion 88 is threadedly
connected to ported sub 56 at the lower end 72 thereof. A seal
retainer 87 having a seal 89 disposed thereabout is connected to a
lower end of valve extension 86.
[0024] Upper end 90 of valve extension 86 may comprise a ball seat
92. A closing or plugging ball 94 is positioned between seat 92 and
a plug portion 96 of ported sub 56. Longitudinal ports 98
communicate longitudinal central passageway 76 with a cage 100
defined by plug portion 96 and seat 92. Closing ball 94 is trapped
in cage 100. Valve housing 78 is connected and preferably
threadedly connected to a mandrel 102 which comprises a portion of
packer assembly 60. Valve extension 86 extends into mandrel 102, so
that seal 89 sealingly engages mandrel 102.
[0025] Packer mandrel 102 has upper end 104, lower end 106 and has
a J-slot 108 defined therein. Expandable packer elements 110 are
mounted on mandrel 102 and are movable between set and unset
positions as will be explained in more detail herein.
[0026] Packer elements 110 have an upper end 112 which abuts lower
end 82 of valve housing 78, and a lower end 114. A slip wedge 116
is mounted on mandrel 102 and abuts lower end 114 of packer
elements 110. Slip assembly 64 may comprise a plurality of slips
118 mounted on mandrel 102. Drag block assembly 66 includes drag
block housing 120 mounted on mandrel 102, a plurality of drag
blocks 122 and a drag block retainer 124 mounted to mandrel 102. A
plurality of drag block springs 126 will urge drag blocks 122
outwardly as is known in the art.
[0027] A lug rotator 128 which includes radially inwardly extending
lug 130 is positioned in a lug rotator slot 132 defined by a
shoulder 134 on drag block retainer 124 and an upper end 136 of a
lug retainer 138 that is threadedly connected to drag block
retainer 124. Lug rotator 128 will rotate in lug rotator slot 132
so that lug 130 will move in J-slot 108 as the treatment assembly
25 is moved between the run-in, set and retrieve modes.
[0028] Referring now to FIGS. 5-7, hydraulic hold-down assembly 38
comprises an upper or top sub 150 threadedly connected to a
hold-down body 152 that is in turn threadedly connected to a bottom
sub 154 which is adapted to be connected in treatment assembly 25
to cup packers 46 and 48 with connectors known in the art.
Likewise, upper sub 150 is internally threaded so that it may be
connected to tubing 32. A central passage 156 is defined through
hydraulic hold-down assembly 38. Hydraulic slips 158 having teeth,
or buttons 160 thereon are positioned in a bore 162 defined in
hold-down body 152. Hydraulic slip 158 may comprise a cylindrical
member 166 having an elongated slot 168 extending through a portion
thereof, a plurality of recesses 170 therein, along with teeth 160.
A plurality of hold-down straps 172 are attached to hold-down body
152. A plurality of slip retraction springs 174 bias the plurality
of slips 158 in a retracted position within hold-down body 152.
[0029] Referring now to FIGS. 7 and 8, upper, or top sub 150 has a
lower end 180. Hold-down body 152 has first inner diameter 182 and
second inner diameter 184. A shoulder which is preferably an upward
facing shoulder 186 is defined by and between first and second
inner diameters 182 and 184. A space, or passage 188 is defined
between lower end 180 of top sub 150 and shoulder 186. Space 188
allows communication of fluid and thus fluid pressure to a
longitudinal port 190 defined in wall 191 of hold-down body 152.
Longitudinal port 190 may be filled with grease in certain
circumstances but in any case will allow fluid pressure to urge
hydraulic slips 158 outwardly into engagement with the well 10.
Fluid pressure from longitudinal port 190 acts upon cylindrical
member 166 to urge hydraulic slip 158 outwardly. A sand barrier 192
may be positioned in space 188. Sand barrier 192 will act as an
additional protective device to prevent blockage of longitudinal
ports 190, and to prevent sand or other debris from inhibiting the
proper operation and movement of slips 158. The sand barrier may be
grooved as shown in FIGS. 9 and 10, to allow pressure to be
communicated into ports 190. Sand barrier 192 may have radial inlet
grooves 194 and 196, and a circular groove 198, to communicate
pressure to longitudinal ports 190.
[0030] In operation, treatment assembly 25 is lowered into well 10.
As it is lowered therein, cup packers 46 and 48 will engage casing
20. Treatment assembly 25 is lowered until the lower selected zone
36 to be treated is reached. The initial zone treated will in most
cases be the lowermost zone. Lug 130 will be in region A as
depicted in FIG. 8. Once this occurs, an upward pull is applied and
then released. The upward pull will cause rotation of lug rotator
128. When the upward pull is released, downward motion will cause
the lug rotator to continue to rotate so that lug 130 moves into
region B as shown in FIG. 8 and allows the treatment assembly 25 to
move to the set position shown in FIG. 3 in which the mandrel 102
along with the slip wedge 116 and valve housing 78 move downwardly
to urge slips 118 outwardly into engagement with casing 20. When
this occurs, continued compression will cause expandable packer
elements 110 to expand outwardly to sealingly engage casing 20. The
treatment fluid, such as fracturing fluid, may then be pumped
through port 74 and into the zone to be treated. Hydraulic pressure
inside treatment assembly 25 caused by fluid passing therethrough
which passes through central passage 156 will urge hydraulic slips
158 outwardly. Hydraulic pressure is applied through port 190 and
space 188. Engagement of the hydraulic slips 158 will help to hold
treatment assembly 25 in well 10 and to prevent the assembly 25
from lifting upwardly, opening valve assembly 58 and potentially
releasing packer elements 110 damaging the tubing 32.
[0031] Slips 118, positioned below packer elements 110 are
downwardly facing slips designed to resist downward forces, but
will not effectively resist the upward force caused by the pressure
in the well acting on the downward facing cup packers 44. In the
absence of slips 158, the primary force resisting the upward force
is simply the weight of the tubing in the well. In some cases, a
coiled tubing injector will apply an additional force to hold the
tool in the well, but in many cases will not keep the treatment
assembly 25 from lifting in the well. Hydraulic slips 158 will
apply a radially outward directed force to casing 20, and will grip
casing 20. Hydraulic hold-down assembly 38 will permit such a
method to be utilized with higher pressure treatment and allow
larger diameter tools such as 51/2 and 7 inch cup-type packers, for
which treatment assembly 25 with hold-down head 38, and the
associated method of use has previously been unavailable.
[0032] Once lower zone 36 has been treated, it may be desired to
treat additional zones in the well. When the pumping ceases,
pressure will be equalized and the hydraulic slips 158 will retract
from engagement with well 10. After a period of time, the pressure
will equalize and an upward pull may be applied. Upward pull will
cause seal retainer 87 to move upwardly so that seal 89 moves
upwardly past the slots 84 in equalizer valve housing 78 so the
pressure above and below packer elements 110 will equalize.
Continued upward pull will cause shoulder 85 on valve extension 86
to engage equalizer valve housing 78 and pull equalizer valve
housing 78 upwardly so that the compressive force applied to packer
elements 110 will be relieved. Packer elements 110 will retract
radially inwardly, and treatment assembly 25 can be moved in well
10 upwardly or downwardly as desired. If it is desired to treat
another zone, the tool will be moved upwardly and the operation can
be repeated as described herein, for example, in zone 34, or other
selected zones.
[0033] While the embodiment herein discloses use of hydraulic slips
158, mechanical slips or other means to grippingly engage casing 20
may be used to prevent cup packer assemblies 44, including the
cup-packer mandrel, from being moved upwardly, and pulling the
entire treatment assembly 25 upwardly during the treatment
procedure. Slips 158, or other slips, are preferably upward facing
slips, to effectively resist upward movement as a result of
pressure applied to the downward facing cup packers. Any type of
slip used must be sufficient to apply an outwardly directed force
to the casing so that the upward force resulting from treatment
pressure is resisted. The gripping engagement of slips 158 with
casing 20 will allow for greater treatment pressure, since it
creates a holding force in addition to that resulting from the
weight of the tubing in the well, and the force applied by slip
assembly 64 and packer assembly 60. The embodiment described herein
positions slips 158 above cup packers 44, but other arrangements
are possible.
[0034] Thus, it is seen that the apparatus and methods of the
present invention readily achieve the ends and advantages mentioned
as well as those inherent therein. While certain preferred
embodiments of the invention have been illustrated and described
for purposes of the present disclosure, numerous changes in the
arrangement and construction of parts and steps may be made by
those skilled in the art, which changes are encompassed within the
scope and spirit of the present invention as defined by the
appended claims.
* * * * *