Note: Descriptions are shown in the official language in which they were submitted.
2 0 2 9 5 2 9
CASING VALVE
Background Of The Invention
1. Field Of The Invention
The present invention relates generally to casing valves for
use in wells, and more particularly, but not by way of limita-
tion, to a casing valve adapted for use in substantially non-
vertical deviated portions of wells.
2. Brief Description Of The Prior Art
It is known that sliding sleeve type casing valves can be
placed in the casing of a well to provide selective communication
between the casing bore and subsurface formations adjacent the
casing valve. One such casing valve is shown in ~. S. Patent No.
3,768,562 to Baker, assigned to the assignee of the present
invention. The Baker '562 patent also discloses a positioning
tool for actuating the sliding sleeve of the casing valve.
U.S. Patent 4,880,059 to Brandell/ and
also assigned to the assignee of the present invention, discloses
the use of sliding sleeve casing valves in a deviated portion of
a well. One embodiment of the Brandell device utilizes an alumi-
num plug in the housing of the casing valve which can be removed
by acid washing.
Summary Of The Invention
The present invention provides further improvements in casing
valves and particularly in casing valves for use in substantially
deviated wells.
The casing valve includes an outer housing having a longitu-
dinal passageway defined therethrough and having a side wall with
a communication port defined through the side wall. A sliding
B
.. . . .. . ~ . . . ... . ~ --. . ...
2 0 2 9 5 2 9
--2--
sleeve is disposed in the longitudinal passageway and is selec-
tively movable relative to the housing between a first position
blocking the communication port and a second position wherein the
communication port is communicated with the longitudinal passa-
geway.
First and second longitudinally spaced seals are disposed
between the sliding sleeve and the housing and define a sealed
annulus between the sliding sleeve and the housing.
The casing valve includes a position latching means for
releasably latching the sliding sleeve in its first and second
positions. The latching means is disposed in the sealed annulus
of the casing valve where it is protected from debris in the
well.
A third seal is disposed between the sleeve and the housing
and isolates the housing ports from the sleeve ports when the
sleeve is in its first longitudinal position relative to the
housing.
The sliding sleeve has a plurality of sleeve ports defined
therein. When the sleeve is moved to its second position rela-
tive to the housing, the sleeve ports are in registry with the
housing ports. The sleeve ports and housing ports are both ini-
tially blocked by disintegratable plugs. When the sleeve is
moved to its second position where the ports are in registry, the
disintegratable plugs can be removed by hydraulic jetting.
The sealed annulus of the casing valve is substantially iso-
lated from both the housing ports and the sleeve ports.
An alignment means is disposed in th~ sealed annulus for
2 0 2 9 5 2 9
--3--
maintaining the sleeve ports in registry with the housing ports
when the sleeve is moved to its second position.
Numerous objects, features and advantages of the present
invention will be readily apparent to those skilled in the art
upon a reading of the following disclosure when taken in conjunc-
tion with the accompanying drawings.
Brief Description Of The Drawings
FIG. 1 is a schematic elevation sectioned view of a well
having a substantially deviated well portion. A work string is
being run into the well including a positioner means, a jetting
tool assembly, and a wash tool. The deviated portion of the well
has multiple casing valves placed in the casing string.
FIGS. 2A-2D comprise an elevation sectioned view of the
casing valve. The sleeve is in a closed position and the sleeve
ports and housing ports are plugged.
FIGS. 3A-3E comprise an elevation sectioned view of the posi-
tioner tool, the jetting tool, and the wash tool.
FIGS. 4A-4E comprise an elevation sectioned view of the tool
string of FIGS. 3A-3E in place within the casing valve of FIGS.
2A-2D. The sleeve has been moved to an open position and the
plugs have been jetted out of the sleeve ports and housing
ports.
FIG. 5 is a laid out view of a J-slot and lug means located
in the positioner tool.
FIG. 6 is a view similar to FIG. 1, after the well has been
fractured adjacent each of the casing valves. A stimulation tool
string is shown in place in the well.
2 0 2 9 5 2 9
--4--
FIG. 7 is a view similar to FIG. 1 with a production tubing
string in place producing formation fluids through a lowermost
one of the casing valves.
FIGS. 8 and 9 are side and front elevation views of a
modified engagement block.
FIG. 10 is an elevation section view of the engagement block
of FIGS. 8 and 9 in place in the positioning tool.
Detailed Description Of The Preferred Embodiments
Referring now to the drawings, and particularly to FIG. 1, a
well is shown and generally designated by the numeral 10. The
well 10 is constructed by placing a casing string 12 in a bore-
hole 14 and cementing the same in place with cement as indicated
at 16. The casing string may be in the form of a liner instead
of the full casing string 12 illustrated. Casing string 12 has a
casing bore 13.
The well 10 has a substantially vertical portion 18, a
radiused portion 20, and a substantially non-vertical deviated
portion 22 which is illustrated as being a substantially horizon-
tal well portion 22. Although the tools described herein are
designed to be especially useful in the deviated portion of the
well, they can of course also be used in the vertical portion of
the well.
Spaced along the deviated well portion 22 of casing 12 are a
plurality of casing valves 24, 26, and 28. The casing valve 24,
which is identical to casing valves 26 and 28, is shown in detail
in FIGS. 2A-2D. Each of the casing valves is located adjacent a
subsurface zone or formation of interest such as zones 30, 32,
2 0 2 9 5 2 9
--5--
and 34, respectively.
In FIG. 1, a tubing string 36 having a plurality of tools
connected to the lower end thereof is being lowered into the well
casing 12. A well annulus 38 is defined between tubing string 36
and casing string 12. A blowout preventer 40 located at the sur-
face is provided to close the well annulus 40. A pump 42 is con-
nected to tubing string 36 for pumping fluid down the tubing
string 36.
The tubing string 36 shown in FIG. 1 has a positioner tool
apparatus 44, a jetting tool apparatus 46, and a wash tool
apparatus 48 connected thereto. This tool string is shown in
detail in FIGS. 3A-3E.
The Casing Valve
The casing valve 24, which may also generally be referred to
as a sliding sleeve casing tool apparatus 24, is shown in detail
in FIGS. 2A-2D. Casing valve 24 includes an outer housing 50
having a longitudinal passageway 52 defined therethrough and
having a s,ide wall 54 with a plurality of housing communication
ports 56 defined through the side wall 54.
The outer housing 50 is made up of an upper housing portion
58, a seal housing portion 60, a ported housing section 62, and a
lower housing section 64. Upper and lower handling subs 65 and
67 are attached to the ends of housing 50 to facilitate handling
and makeup of the sliding sleeve casing tool 24 into the casing
string 12. Subs 65 and 67 are threaded at 69 and 71, respec-
tively, for connection to casing string 12.
The casing valve 24 also includes a sliding sleeve 66 sli-
20 295 2g
dably disposed in the longitudinal passageway 52 of housing 50.Sleeve 66 is selectively movable relative to the housing 50 bet-
ween a first position as shown in FIGS. 2A-2D blocking or
covering the housing communication ports 56 and a second position
illustrated in FIGS. 4A-4E wherein the housing communication
ports 56 are uncovered and are communicated with the longitudinal
passageway 52.
The casing valve 24 also includes first and second longitudi-
nally spaced seals 68 and 70 disposed between the sliding sleeve
66 and the housing 50 and defining a sealed annulus 72 between
the sliding sleeve 66 and the housing 50. The first and second
seals 68 and 70 are preferably chevron type packings. This style
of packing will provide a long life seal that is less susceptible
to cutting and/or wear by entrapped abrasive materials such as
frac sand and formation fines than are many other types of seals.
A position latching means 74 is provided for releasably
latching the sliding sleeve 66 in its first and second positions.
The position latching means 74 is disposed in the sealed annulus
72.
The position latching means 74 includes a spring collet 76
which may also be referred to as a spring biased latch means 76
attached to the sliding sleeve 66 for longitudinal movement
therewith.
The position latching means 74 also includes first and second
radially inward facing longitudinally spaced grooves 78 and 80
defined in the housing 50 and corresponding to the first and
second positions, respectively, of the sliding sleeve 66.
2 0 2 9 5 2 ~
--7--
By placing the spring collet 76 in the sealed annulus 72 the
collet is protected in that cement, sand and the like are pre-
vented from packing around the collet and impeding its successful
operation.
It is noted that the position latching means 74 could also be
constructed by providing a spring latch attached to the housing
and providing first and second grooves in the sliding sleeve 66
rather than vice versa as they have been illustrated.
The first chevron packing type seal 68 is held in place bet-
ween a lower end 82 of upper housing portion 58 and an upward
facing annular shoulder 84 of seal housing portion 60.
The second chevron type seal 70 is held in place between an
upper end 86 of ported housing section 62 and a downward facing
annular shoulder 88 of seal housing section 60.
The sliding sleeve 66 has a longitudinal sleeve bore 90
defined therethrough and has a sleeve wall 92 with a plurality of
sleeve communication ports 94 defined through the sleeve wall 92.
All of the housing communication ports 56 and sleeve com-
munication ports 94 have disintegratable plugs 96 and 98, respec-
tively, initially blocking the housing communication ports 56 and
the sleeve communication ports 94.
The disintegratable plugs 96 and 98 are preferably
constructed from threaded hollow aluminum or steel insert rings
120 and 122, respectively, filled with a material such as Cal
Seal, available from U. S. Gypsum, which can be removed by
hydraulic jetting as is further described below.
, ,, , _ .. . , . ~
20 295 29
--8--
By initially providing the communication ports 56 and 94 with
the disintegratable plugs 96 and 98, cement and other particulate
material is prevented from entering the ports and getting between
the sliding sleeve 66 and housing 50.
In the first position of sleeve 66 relative to housing 50 as
shown in FIGS. 2A-2D, the housing communication ports 56 and the
sleeve communication ports 94 are out of registry with each
other, and a third chevron type seal packing 100 between sleeve
66 and housing 50 isolates the sleeve communication ports 94 from
the housing communication ports 56.
The sleeve 66 is selectively movable relative to the housing
50 between the first position of FIGS. 2A-2D to the second posi-
tion shown in FIGS. 4A-4E wherein the housing communication ports
56 are in registry with respective ones of the sleeve com-
munication ports 94.
An alignment means 102 is operably associated with the
housing 50 and sliding sleeve 66 for maintaining the sleeve com-
munication ports 94 is registry with the housing communication
ports 56 when the sleeve 66 is in its said second position with
spring collet 76 engaging groove 80. The alignment means 102
includes a plurality of longitudinal guide grooves such as 104
and 106 disposed in the housing 50, and a plurality of
corresponding lugs ]08 and 110 defined on the sliding sleeve 66
and received in their respective grooves 104 and 106.
The alignment means 102 is located in the sealed annulus 72
defined between first and second seals 68 and 70.
The lugs 108 and 110 preferably have weep holes 112 and 114
2 0 2 9 5 2 9
defined therethrough communicating the sleeve bore 90 with the
sealed annulus 72 so as to pressure balance the first and second
seals 68 and 70. The lugs 108 and 110 are preferably cylindrical
pins which are threadedly engaged with radial bores 116 and 118
defined through the sleeve wall 92.
It is noted that the casing valve 24 could also be
constructed so as to have lugs or pins attached to housing 50 and
received in longitudinal grooves defined in sliding sleeve 66 in
order to provide alignment between the housing communication
ports 56 and the sleeve communication ports 96.
The sliding sleeve 66 of casing valve 24 has a comparatively
short sleeve travel as compared to sliding sleeve type casing
valves of the prior art. In one embodiment of the casing valve
24, a sleeve travel of only 10.75 inches was required.
The sliding sleeve 66 has an enlarged internal bore 124
defined between an upper downward facing shoulder 126 and a lower
upward facing shoulder 128. As further defined below, the posi-
tioning tool 44 will engage the upper shoulder 126 to pull the
sleeve 66 upward, and it will engage the lower shoulder 128 to
pull the sleeve downward.
The Positioning Tool
Turning now to FIGS. 3A-3E, a tool string is thereshown made
up of the positioning tool 44, the jetting tool 46, and the wash
tool 48. These same components are shown in place within the
casing valve 24 in the casing string 12 in FIGS. 4A-4E.
The positioning tool apparatus 44 may be generally described
as a positioning tool apparatus for positioning a sliding member
20 295 2g
--10--
of a well tool, such as the sliding sleeve 66 of casing valve 24.
The primary components of the positioning tool apparatus 44
are a drag assembly 130, an inner positioning mandrel 132, and an
operating means 134.
The drag assembly 130 includes a lug housing section 136 con-
nected to a drag block housing section 138 at threaded connection
140. A plurality of radially outwardly biased drag blocks 142
and 144 are carried by the drag block housing section. The drag
assembly 130 has a longitudinal passageway 146 defined through
the lug housing section 136 and drag block housing section 138.
The positioning mandrel 132 is disposed through the longitu-
dinal passageway 146 of drag assembly 130 and is longitudinally
movable relative to the drag assembly 130, that is the posi-
tioning mandrel 132 can slide up and down within the longitudinal
passageway 146. The positioning mandrel 132 has a star guide or
centralizer 133 attached thereto for centralizing the positioning
tool 44 within the casing valve 24 or the casing string 12.
The operating means 134 provides a means for selectively
operably engaging the sliding sleeve 66 of casing valve 24 in
response to longitudinally reciprocating motion of the posi-
tioning mandrel 132 relative to the drag assembly 130.
More particularly, the operating means 134 includes an enga-
gement means 148 connected to the drag assembly 130 for operably
engaging the sliding sleeve 66 of casing valve 24. Operating
means 134 also includes an actuating means 150 connected to the
positioning mandrel 132 for actuating the engagement means 148 so
that the engagement means 148 can operably engage the sliding
20 295 29
--11--
sleeve 66 of casing valve 24. The operating means 134 also
includes a position control means 152 operably associated with
the drag assembly 130 and positioning mandrel 132 for permitting
the positioning mandrel 132 to reciprocate longitudinally rela-
tive to the drag assembly 130 and selectively actuate and unacu-
tate the engagement means 148 with the actuating means 150.
The engagement means 148 includes a first plurality of enga-
gement blocks 154 circumferentially spaced about a longitudinal
axis 156 of drag assembly 130, with each of the engagement blocks
154 having a tapered camming surface 160 defined on one end
thereof, and each of the blocks 154 also having an engagement
shoulder 162 defined thereon and facing away from the end having
the tapered camming surface 160. It will be understood that the
engagement blocks 154 are segmented blocks which are placed in an
annular pattern about the positioning mandrel 132. A first
biasing means comprised of a plurality of leaf type springs 164
connect the first plurality of blocks 154 to the upper end of lug
housing section 136 of drag means 130 for resiliently biasing the
first plurality of blocks 154 radially inward toward the longitu-
dinal axis 156 of the drag assembly 130.
The engagement means 148 further includes a second plurality
of engagement blocks 166 similarly located adjacent the lower end
of drag block housing section 138. Each of the second blocks 166
has a tapered camming surface 168 defined on one end thereof
facing away from the first plurality of blocks 154. Each of the
blocks 166 has an engagement shoulder 170 defined thereon and
facing toward the first plurality of engagement blocks 154.
2 0 2 9 5 2 9
-12-
Engagement means 148 also includes a second biasing means 172
made up of a plurality of leaf springs each of which connects one
of the second plurality of blocks 166 to the drag block housing
section 138 so that the second plurality of blocks 166 is resi-
liently biased radially inward toward the longitudinal axis 156
of the drag assembly 130.
Generally speaking the engagement means 148 can be said to
include separate first and second engagement means, namely the
first and second pluralities of engagement blocks 154 and 166,
respectively.
The actuating means 150 includes upper and lower annular
wedges 174 and 176, respectively.
First annular wedge 174 includes a tapered annular wedging
surface 178 complementary to the tapered camming surfaces 160 of
the first plurality of engagement blocks 154. The annular wedge
174 is positioned on the positioning mandrel 132 so that when the
positioning mandrel 132 is moved downward from the position
illustrated in FIGS. 3A-3E to a first longitudinal position rela-
tive to the drag assembly 130, the annular wedging surface 178
will wedge against the tapered camming surfaces 160 and bias the
blocks 154 radially outward.
The second annular wedge 176 similarly has a tapered annular
wedging surface 180 complementary to the tapered camming surfaces
168 of the second plurality of blocks 166.
The tapered annular wedging surfaces 178 and 180 of the first
and second annular wedges 174 and 176 face toward each other with
the first and second pluralities of engagement blocks 154 and 166
2 0 2 9 5 2 9
-13-
being located therebetween.
The position control means 152 includes a J-slot 182 defined
in the positioning mandrel 132, and a plurality of lugs 184 and
186 connected to the drag assembly 130, with the lugs 184 and 186
being received in the J-slot 182. Generally speaking the J-slot
can be said to be defined in one of the positioning mandrel 132
and the drag assembly 130, with the lug being connected to the
other of the positioning mandrel 132 and the drag assembly 130.
The J-slot 182 could be defined in the drag assembly 130, with
the lugs 184 being connected to the positioning mandrel 132.
The J-slot 182 is best seen in the laid out view of FIG. 5.
J-slot 182 is an endless J-slot.
Referring back to FIG. 3B, the lugs 184 and 186 are mounted
in a rotatable ring 188 sandwiched between the lug housing sec-
tion 136 and drag block housing section 138 with bearings 190 and
192 being located at the upper and lower ends of rotatable ring
188. This permits the lugs 184 and 186 to rotate relative to the
J-slot 182 as the positioning mandrel 132 is reciprocated or
moves longitudinally relative to the drag assembly 130 so that
the lugs 184 and 186 may traverse the endless J-slot 182.
The J-slot 182 and lugs 184 and 186 of position control means
152 interconnect the positioning mandrel 132 and the drag means
130 and define at least in part a repetitive pattern of longitu-
dinal positions of positioning mandrel 132 relative to the drag
assembly 130 achievable upon longitudinal reciprocation of the
positioning mandrel 132 relative to the drag assembly 130. That
repetitive pattern of positions is best illustrated with
2 0 2 9 5 2 9
-14-
reference to FIG. 5 in which the various positions of lug 184 are
shown in phantom lines.
Beginning with one of the positions designated as 184A, that
position corresponds to a position in which the upper annular
wedge 174 would have its wedging surface 178 engaged with the
first plurality of blocks 154 to cam them outwards so that their
shoulders 162 could engage shoulder 128 of sliding sleeve 66 so
as to pull the sliding sleeve 66 downward within casing valve
housing 50 to move the sliding sleeve 66 to a closed position as
illustrated in FIGS. 2A-2D. Thus blocks 154 can be referred to
as closing blocks. As is apparent in FIG. 5, in this first posi-
tion 184A the position is not defined by positive engagement of
the lug 184 with an extremity of the groove 182, but rather the
position is defined by the engagement of the upper wedge 174 with
the upper blocks 154.
By then pulling the tubing string 36 and positioner mandrel
132 upward, with the drag assembly 130 being held in place by the
frictional engagement of drag blocks 142 and 144 with the casing
string 12 or casing valve 24, the J-slot 182 will be moved upward
so that the lug 184 traverses downward and over to the position
184B seen in FIG. 5. In position 184B, which can be referred to
as an intermediate position, the lug 184 is positively engaged
with an extremity of J-slot 182 and allows the drag means 130 to
be moved upwardly in common with the positioner mandrel 132 with
both sets of engagement blocks 154 and 156 in an unengaged posi-
tion as seen in FIGS. 3B-3C so that the positioning tool 44 can
be pulled upwardly out of the casing valve 24 without operatively
-
20 295 29
-15-
engaging its sliding sleeve 66.
The next downward stroke of positioning mandrel 132 relative
to drag means 130 moves the lug to position 184C which is another
intermediate position in which lug 184 is positively engaged with
another extremity of groove 182 so that the positioning mandrel
132 and drag means 130 can be moved downwardly together through
casing string 12 and casing valve 24 without actuating either the
upper blocks 154 or lower blocks 166.
On the next upward stroke of positioning mandrel 132 relative
to drag means 130, the lug 184 moves to the position 184D which
is in fact defined by engagement of the lower annular wedge 176
with the lower set of engagement blocks 166 so that they are
cammed outward to operably engage shoulder 126 of sliding sleeve
66 of casing valve 24 as is illustrated in FIG. 4C. On this
upward stroke the sleeve valve 66 can be pulled up to an open
position. Thus blocks 166 can be referred to as opening blocks.
The next downward movement of positioning mandrel 132 rela-
tive to drag means 130 moves the lug to position 184E which is in
fact a repeat of position 184C insofar as the longitudinal posi-
tion of mandrel 132 relative to drag means 130 is concerned. The
next upward motion of positioning mandrel 132 moves the lug to
position 184F which is a repeat of the position 184B insofar as
longitudinal position of positioning mandrel 132 relative to drag
means 130 is concerned.
Then, the next downward motion of positioning mandrel 132
relative to positioning me~ns 130 moves the lug back to position
184A in which the upper wedge 178 will engage the upper blocks
2 0 2 9 5 2 g
-16-
154 to cam them outwards to that the sliding sleeve 66 may be
engaged and moved downward within the casing valve 124.
The positioning tool 44 further includes an emergency release
means 194 operatively associated with each of the first and
second actuating means 174 and 176 for releasing the first and
second engagement means 154 and 166 from operative engagement
with the sliding sleeve 66 without moving the positioning mandrel
132 to one of the intermediate positions such as 184B, 184C, 184E
or 184F. This emergency release means 194 includes first and
second sets of shear pins 196 and 198 connecting the first and
second actuating wedges 174 and 176, respectively, to the posi-
tioning mandrel 132. For example, if the positioning tool 44 is
in position corresponding to lug position 184D as shown in FIGS.
4A-4E, with the lower engagement blocks 166 cammed outward and in
operative engagement with the sliding sleeve 66, and the position
control means 152 becomes disabled as for example by jamming of
the lug and J-slot, then a sufficient upward pull on the tubing
string 36 will shear the shear pins 198 thus allowing the lower
annular wedge 176 to slide downward along an outer surface 199 of
positioning mandrel 132 so that the wedge 176 is pulled away from
the lower engagement blocks 166 allowing them to bias inwardly
out of engagement with the sliding sleeve 66.
FIGS. 8, 9 and 10 show an alternative embodiment for the
engagement blocks such as upper engagement block 154. FIG. 8 is
a side elevation view of a modified engagement block 154A. FIG.
9 is a front elevation view of the modified engagement block
154A. FIG. 10 is an elevation sectioned view of the modified
2 0 2 9 5 2 g
-17-
block 154A as assembled with the surrounding portions of the
positioning tool 44.
In FIGS. 8 and 9, it is seen that the engagement block 154A
includes an inverted T-shaped lower portion having a stem 155 and
a cross bar 157. A safety retainer lip 159 extends down from the
rear edge of the cross bar 157.
The inverted T-shaped portion 155, 157 is received in an
inverted T-shaped slot 161 defined in lug housing section 136 as
best shown in phantom lines in FIG. 9.
As best seen in FIG. 10, the lug housing section 136 has an
internal undercut 163 therein just below the slots such as 161,
which is dimensioned so as to abut the retaining lip 159 in the
radially outermost position of block 154A.
The retaining lip 159 and associated structure of lug housing
section 136 function together as a safety retainer means for
maintaining a connection between the engagement block 154A and
the lug housing section 136 of the drag assembly 130 in the event
the leaf spring 164 breaks. Thus, if the leaf spring 164 breaks,
the engagement block 154A can not fall out of assembly with the
remainder of the drag assembly 44. Instead, due to the
interlocking effect of the T-shaped portion 155, 157 in T-shaped
slot 161 along with the retainer lip 159, the engagement block
154A will remain in place.
Due to the retaining lip 159, the engagement block 154A must
be assembled with the lug housing section 136 by sliding the
engagement block 154A into the T-shaped slot 161 from the inside
of the lug housing section 136.
20 2 95 29
-18-
The Jetting Tool
The jetting tool 46 can be generally described as an appara-
tus for hydraulically jetting a well tool such as casing valve 24
disposed in the well 10.
The construction of the jetting tool 46 is very much asso-
ciated with that of the positioning tool 44. When the posi-
tioning tool 44 engages the sliding sleeve 66 of casing valve 24
and moves it to an open position, the dimensions of the posi-
tioning tool 44 and the jetting tool 46 will cause the jetting
tool 46 to be appropriately aligned for hydraulically jetting the
disintegratable plugs found in the casing valve.
The jetting tool 46 can be generally described as a jetting
means 46, connected at a rotatable connection defined by a swivel
201 to the positioning tool 44 so that the jetting means 46 is
rotatable relative to the positioning tool 44 and the casing
valve 24. Thus, the jetting tool 46 can hydraulically jet the
disintegratable plugs from the casing valve 24 as the jetting
tool 46 is rotated relative to the positioning tool 44 and the
casing valve 24.
The jetting tool 46 includes a jetting sub 200 having a
chamber 202 defined therein with open upper and lower ends 204
and 206, respectively. The sub 200 has a peripheral wall 208
with a plurality of jetting orifices 210 defined therethrough and
communicated with chamber 202. Each of the jetting orifices 210
is defined in a threaded insert 212 set in a recessed portion 214
of a cylindrical outer surface 216 of the jetting sub 200.
A check valve means 218 is disposed in the lower end of
2 0 2 9 5 2 9
--19--
chamber 202 for freely permitting upward fluid flow through
chamber 202 and for preventing downward fluid flow out the lower
end 206 of chamber 202 so that a downward fluid flow through the
chamber 202 is diverted through the jetting orifices 210.
The check valve means 218 includes a seat 220 defined in the
open lower end 206 of chamber 202 and a ball valve member 222
dimensioned to sealingly engage the seat 220. The ball valve
member 222 is free to move up into the chamber 202.
The jetting sub 200 further includes a ball retainer 224 in
the open upper end 204 of sub 200 to prevent the ball valve
member 222 from being carried out of the chamber 202 by upwardly
flowing fluid.
The check valve permits the tubing string 36 to fill while
running into the well 10, as well as permitting reverse cir-
culation through the wash tool 48. Additionally, the ball 222 is
self centered to facilitate easy seating thereof when the jetting
tool 46 is in a horizontal position such as in the deviated por-
tion 22 of,the well 10.
The wash tool 48 located below jetting tool 46 is also opera-
tionally associated with the jetting tool 46 as is further
described below. The wash tool 48 can be generally described as
a wash means 48 located below the positioning tool 44 and the
jetting tool 46 for washing the bore of casing string 12 while
reverse circulating down the well annulus 38 and up through the
wash tool 48 and the jetting tool 46.
The swivel 201 best seen in FIG. 3A can be described as a
swivel means 201 for providing the mentioned rotatable connection
2 0 2 9 5 2 9
-20-
between the positioning tool 44 and the jetting tool 46, and for
connecting the positioning tool 44 and jetting tool 46 for common
longitudinal movement relative to the well 10.
The jetting tool 46 further includes a rotatable jetting
mandrel 224 fixedly attached to the jetting sub 200 through a
connector 226. The connector 226 is threadedly connected to
jetting mandrel 224 at thread 228 with set screws 230 maintaining
the fixed connection. The connector 226 is fixedly connected to
jetting sub 200 at threaded connection 232 with the connection
being maintained by set screws 234. An 0-ring seal 236 is pro-
vided between jetting mandrel 224 and connector 226, and an 0-
ring seal 238 is provided between connector 226 and jetting sub
200.
Thus, the jetting mandrel 224 is fixedly attached to the
jetting sub 200 by connector 226, so that the jetting mandrel 224
and jetting sub 200 rotate together relative to the positioning
tool 44.
The jetting mandrel 224 has a jetting mandrel bore 240
defined therethrough which is communicated with the chamber 202
of jetting sub 200.
The jetting mandrel 224 is concentrically and rotatably
received through a bore 242 of the positioning mandrel 132 of
positioning tool 44.
The jetting mandrel 224 extends upward all the way through
the positioning tool 44 to the swivel 201.
The swivel 201 includes a swivel housing 244 which is con-
nected to an upper end of the positioning mandrel 132 at threaded
2 0 2 9 5 2 9
-21-
connection 246 with set screws 248 maintaining the connection.
An 0-ring seal 250 is provided between swivel housing 244 and the
positioning mandrel 132. The swivel housing 244 is made up of a
lower housing section 252 and an upper housing section 254 con-
nected at threaded connection 256.
The lower and upper housing sections 252 and 254 define an
inner annular recess 258 of the swivel housing 244.
The jetting mandrel 224 includes an upper jetting mandrel
extension 260 connected to the lower jetting mandrel portion at
thread 262. The upper jetting mandrel extension has an outer
annular shoulder 264 defined thereon, which is received in the
annular recess 258 of swivel housing 244.
Upper and lower thrust bearings 266 and 268 are disposed in
the annular recess 258 above and below the annular shoulder 264.
The upper thrust bearing 266 has an outer race 270 fixed to the
swivel housing 244 and an inner race 272 fixed to the jetting
mandrel extension 260. The lower thrust bearing 268 includes an
outer race 274 fixed to the swivel housing 244, and an inner race
276 fixed to the jetting mandrel 224.
An upper end portion 278 of jetting mandrel extension 260
extends through the upper end of upper swivel housing section 254
with an O-ring seal 280 being provided therebetween.
An upper adapter 282 is connected at thread 284 to the upper
end portion 278 of jetting mandrel extension 260, with an O-ring
seal 286 being provided therebetween. The upper adapter 282
includes threads 288 for connection to the tubing string 36 of
FIG. 1 so that the tubing string 36 is in fluid communication
with the bore 240 of the jetting mandrel 224.
20 2 95 29
-22-
The Disintegratable Inserts
As mentioned above, the preferred design for the disin-
tegratable plugs 96 and 98 is to have a hollow externally
threaded insert ring 120 or 122 filled with a disintegratable
material, which preferably is Cal Seal available from U. S.
Gypsum Company. Cal Seal is a calcium sulfate cement which has a
bearing strength, i.e., yield strength, of approximately 2500
psi. This material can be readily disintegrated by a hydraulic
jet of clear water at pressures of 4,000 psi or greater, which
can be readily supplied with conventional tubing strings. The
hydraulic jetting of plugs constructed from Cal Seal is pre-
ferably done at hydraulic pressures in a range of from about
4,000 psi to about 5,000 psi.
Typical conventional tubing strings 36 can convey hydraulic
pressures up to about 12,000 psi. Thus, in order to utilize a
conventional tubing string with the tools of the present inven-
tion, it is desirable that the disintegratable plugs be
constructed of a material having a bearing strength sufficiently
low that said material can be readily disintegrated by a
hydraulic jet of water at a pressure of no greater than about
12,000 psi. Such materials can then be disintegrated by the
tools of the present invention, utilizing a tubing string of con-
ventional strenath, without the need for use of any abrasive
materials or of acids or other volatile substances.
It will be appreciated that the clear fluids preferably uti-
lized to jet the plugs out of the communication port are "clear"
only in a relative sense. It is only meant that they do not con-
2 0 2 9 5 2 9
-23-
tain any substantial amount of abrasive materials for the purpose
of abrading the plugs, nor do they need to contain acids or the
like. Thus, the preferred plug material is defined as material
which as a bearing strength such that it can be readily disin-
tegrated by a hydraulic jet of water at a pressure of no greater
than about 12,000 psi. Such plugs can, of course, also be disin-
tegrated with hydraulic jets which do contain abrasive materials
or substances such as acid.
Most materials when subjected to a hydraulic jet of plain
water will exhibit a "threshold pressure" which is the hydraulic
pressure required to readily disintegrate or cut the material
with the hydraulic jet. At pressures below this threshold there
is little disintegration. At pressures significantly above the
threshold the material readily disintegrates. There is no signi-
ficant advantage of further raising the pressure to values
greatly above this threshold.
The value of this "threshold pressure" for a given material
depends somewhat upon the nature of the material. In any event,
however, the threshold pressure is always greater than the
bearing strength of the material.
For example, for a calcium sulfate cement such as Cal Seal,
having a bearing strength of 2500 psi, the material will readily
disintegrate under a hydraulic jet of water at a hydraulic
pressure of about 4,000 psi. At such pressures a Cal Seal plug
will disintegrate in a matter of a few minutes.
In view of the maximum pressure typically available through a
conventional tubing string, i.e., a hydraulic pressure of no more
20 295 29
-24-
than about 12,000 psi, materials should be used for the disin-
tegratable plugs having a bearing strength of less than about
5,000 psi. These materials can generally be cut by jets at a
hydraulic pressure of 12,000 psi or less. If cement type
materials are used, those materials will generally have a bearing
strength of less than about 3500 psi.
A number of materials other than the Cal Seal brand calcium
sulfate cement are believed to be good candidates for use for
construction of the disintegratable plugs in some situations.
Properly formulated Portland cement which has bearing strength in
the range from 1,000 to 3,500 psi, depending upon its for-
mulation, age, etc., will be usable in some instances. Some
plastic materials could be utilized. Also, composites such as
powdered iron or other metal in an epoxy carrier are possible
candidates.
The Wash Tool
The wash tool 48 can be generally described as an apparatus
to be run on the tubing string 36 to clean out the casing bore
13. Wash tool 48 includes a wash tool housing 290 having a
thread 292 at its upper end which may be generally described as a
connector means 292 for connecting the housing 290 to the tubing
string 36 by way of the other tools located therebetween.
Wash tool 48 includes an upper packer means 294 connected to
the housing 290 for sealing between the housing 290 and the
casing bore 13.
The upper packer means 294 is shown in FIG. 4E in place
within the casing 12. It is there seen that the upper packer
-~ 2029529
-25-
means 294 defines an upper portion 38A of well annulus 38 above
the upper packer means 294.
The wash tool 48 further includes a lower packer means 296
connected to the housing 290 below the upper packer means 294 for
sealing between the housing 290 and the casing bore 13 and for
defining an intermediate portion 38B of well annulus 38 between
the upper and lower packer means 294 and 296, and for defining a
lower portion 38C of well annulus 38 below the lower packer means
296.
The housing 290 has an upper fluid bypass means 298 defined
therein for communicating the upper portion 38A and the inter-
mediate portion 38B of the well annulus so that fluid pumped down
the well annulus 38 is bypassed around the upper packer means 294
and directed into the intermediate portion 38B of well annulus 38
to wash the casing bore 13 in the intermediate portion 38B of the
well annulus.
The housing 290 also has a lower fluid bypass means 300
defined therein for communicating the intermediate portion 38B
and the lower portion 38C of the well annulus 38 so that fluid is
bypassed from the intermediate portion 38B of the well annulus
around the lower packer means 296 and directed into the lower
portion 38C of the well annulus to wash the casing bore 13 below
the lower packer means 296.
The housing 290 also has a longitudinal housing bore 302
defined therethrough having an open lower end 304 so that fluid
in the lower portion 38C of the well annulus may return up
through the wash tool housing bore 302 and the tubing string 36
-- 20 295 29
-26-
to carry debris such as cement particles and the like out of the
casing bore 13.
The upper packer means 294 is an upwardly facing packer cup
294, and the lower packer means 296 is a downwardly facing packer
cup 296.
The wash tool housing 290 includes an inner mandrel housing
section 306 having the longitudinal bore 302 defined
therethrough.
Housing 290 also includes a packer mandrel assembly 308 con-
centrically disposed about the inner mandrel housing section 306
and defining a tool annulus 310 therebetween. A seal means 312
is provided between the inner mandrel housing section 290 and the
packer mandrel assembly 308 for dividing the tool annulus 310
into an upper tool annulus portion 314 and a lower tool annulus
portion 316 which are part of the upper and lower bypass means
298 and 300, respectively.
The packer mandrel assembly 308 includes an upper packer
mandrel 318, an intermediate packer mandrel 320 and a lower
packer mandrel 322.
The inner mandrel housing section 306 includes an upward
facing annular support shoulder 324 near its lower end on which
the lower packer mandrel 322 is supported. The upper packer
mandrel 318 is received in a recessed annular groove 326 of an
upper nipple 328 of wash tool housing 290.
The nipple 328 and the inner mandrel housing section 306 are
threadedly connected at 330 and the packer mandrel assembly 308
and upper and lower packer cups 294 and 296 are held tightly in
.. , , , ., , ~ . ....
20 295 29
-27-
place therebetween.
The upper packer cup 294 has an anchor ring portion 332
disposed about a reduced diameter outer surface 334 of upper
packer mandrel 318 and sandwiched between the upper packer
mandrel 318 and the intermediate packer mandrel 320.
The lower packer cup 296 has an anchor ring portion 336
disposed about a reduced diameter outer surface 338 of lower
packer mandrel 322 and sandwiched between intermediate packer
mandrel 320 and lower packer mandrel 322.
An 0-ring seal 340 is provided between upper packer mandrel
318 and intermediate packer mandrel 320, and an 0-ring seal 342
is provided between intermediate packer mandrel 320 and lower
packer mandrel 322.
The upper fluid bypass passage means 298 of housing 290
includes a plurality of supply ports 344 disposed through the
upper packer mandrel to communicate the upper well annulus por-
tion 38A with the upper tool annulus portion 314. Upper fluid
bypass passage means 298 further includes a plurality of jet
ports 346, which may also be referred to as upper wash ports 346,
disposed through the intermediate packer mandrel 320 to com-
municate the upper tool annulus portion 314 with the intermediate
portion 38B of the well annulus. The jet ports 346 are down-
wardly directed at an acute angle 348 to the longitudinal axis
156 of the inner mandrel housing section 306.
The lower fluid bypass passage means 300 includes a plurality
of return ports 350 disposed through the intermediate packer
mandrel 320 below the jet ports 346 to communicate the inter-
.
2 0 2 9 5 2 9
-28-
mediate well annulus 38B with the lower tool annulus portion 316.
Lower fluid bypass passage means 300 further includes a plurality
of lower wash ports 352 disposed through the lower packer mandrel
322 to communicate the lower tool annulus portion 316 with the
lower portion 38C of the well annulus.
The jet ports 346 provide a means for directing jets of fluid
against the casing bore 13 in the intermediate portion 38B of the
well annulus. The jet ports are downwardly directed at the acute
angle 348 so that debris washed from the casing bore 13 in inter-
mediate well annulus portion 38B is washed downwardly toward the
return ports 350.
The inner mandrel housing section 306 of wash tool housing
290 includes a plurality of teeth 354 defined on a lower end
thereof so that upon rotation of the housing 290, the teeth 254
will break up debris, such as residual cement, in the casing bore
13.
The wash tool 48 is used in the following manner. As the
tool is lowered through casing string 12 it is rotated by
rotating the tubing string 36. Simultaneously, fluid is pumped
down the well annulus 38.
The rotating teeth 354 break debris loose in a portion of the
casing bore. Well fluid circulated down through the casing annu-
lus 38 bypasses the upper and lower packer cups 294 and 296
through the bypass passage means 298 and 300, respectively, and
exits the lower wash ports 352 to wash away the debris created by
the rotating teeth 354 and to reverse circulate that debris with
the well fluid up through the longitudinal housing bore 302 and
~ r~ ~ ~f ~
-29-
the tubing string 36.
After that portion of the bore initially engaged by the teeth
354 is washed by the lower wash ports 352, the lower packer cup
296 wipes that portion of the casing bore 13 as the wash tool 48
is advanced downwardly through the casing string 12.
That portion of the casing bore 13 which has been wiped by
the lower packer cup 296 is then jet washed by fluid exiting the
jet ports or upper wash ports 346.
The method just described is a continuous method wherein
debris is being broken loose and reverse circulated up the well
from one portion of the casing bore, while another portion of the
casing bore is being wiped, and yet another portion of the casing
bore is being jet washed. These steps are performed simulta-
neously on different portions of the casing bore, and in the
order mentioned on each respective portion of the casing bore.
Further, it is noted that the well fluid which jet washes one
portion of the casing bore as it exits the jetting ports 346 is
used subsequently in time to reverse circulate debris out of a
lower portion of the casing bore which is adjacent the lower wash
ports 352.
Methods Of Operation
The use of the casing valve 24 in highly deviated well bore
portions 22 along with the tool string shown in FIGS. 3A-3E pro-
vides a system for the completion of highly deviated wells which
will substantially reduce completion costs in such wells by eli-
minating perforating operations, and by eliminating the need for
establishing zonal isolation through the use of packers and
2 ~ 2 ~
-30-
bridge plugs. In general, this system will provide substantial
savings in rig time incurred during completion of the well.
Completion of the well 10 utilizing this system begins with
the cementing of the production casing string 12 into the well
bore 14 with cement as indicated at 16. Particularly, the well
is cemented across the zones of interest in which casing valves
such as 24, 26 and 28 have been located prior to running the
casing string 12 into the well. With this system, a casing valve
such as 24 is located at each point at which the well 10 is to be
stimulated adjacent some subsurface formation of interest such as
the subsurface formations 30, 32 and 34. These points of
interest have been previously determined based upon logs of the
well and other reservoir analysis data. The casing string or
liner string 12 containing the appropriate number of casing
valves such as 24 is centralized and cemented in place within the
well bore 14 utilizing acceptable practices for cementing in
horizontal hole applications.
After cementing, a bit and stabilizer trip should be made to
clean and remove as much as possible of the residual cement
laying on the bottom of the casing 12 in the horizontal section
22. The bit size utilized should be the largest diameter bit
that can be passed safely through the casing string 12. After
cleaning out to total depth of the well by drilling out residual
cement, the fluid in the casing string 12 should be changed over
to a filtered clear completion fluid suitable for use in
completing the well if this has not already been done when
displacing the final cement plug during the cementing process.
~ i - 2 ~
_ ~ ~ ~ wJ
-31-
The next trip into the well is with the tool string of FIGS.
3A-3E including positioning tool 44, jetting tool 46 and wash
tool 48, as is schematically illustrated in FIG. 1. In FIG. 1,
this tool assembly is shown as it is being initially lowered into
the vertical portion 18 of well 10. The tool assembly will pass
through the radiused portion 20 and into the horizontal portion
22 of the well 10. The tool assembly should first be run to just
below the lowermost casing valve 28.
Then, hydraulic jetting begins utilizing a filtered clear
completion fluid. The hydraulic jetting is performed with the
jetting tool 46 by pumping fluid down the tubing string 36 and
out the jetting orifices 210 so that high pressure jets of fluid
impinge upon the casing bore 13. The tubing string 36 will be
rotated while the jetting tool 46 is moved upward through the
casing valve 28 to remove any remaining residual cement from all
of the recesses in the internal diameter of the casing valve 28.
This is particularly important when casing valve 28 is located in
a deviated well portion because significant amounts of cement
will be present along the lower inside surfaces of the casing
valve 28. This cement must be removed to insure proper engage-
ment of positioning tool 44 with sleeve 66. During this jetting
operation, the positioning tool 44 should be indexed to one of
its intermediate positions such as represented by lug position
104B or 104F so that the positioning tool 44 can move upward
through casing valve 28 without engaging the sliding sleeve 66 of
casing valve 28.
It is noted that when the terms "upward" or "downward" are
. . .
- 2ij2~;~2~
-32-
used in the context of a direction of movement in the well, those
terms are used to mean movement along the axis of the well either
uphole or downhole, respectively, which in many cases will not be
exactly vertical and can in fact be horizontal in a horizontally
oriented portion of the well.
After hydraulically jetting the internal bore of the casing
valve 28, the positioning tool 44 is lowered back through the
casing valve 28 and indexed to the position represented by lug
position 184D. The positioning tool 44 is pulled upward so that
the lower wedge 176 engages the lower engagement blocks 166 to
cam them radially outward so their upward facing shoulders 170
engage shoulder 126 of sliding sleeve 66. The tubing string 36
is pulled upward to apply an upward force of approximately 10,000
pounds to the sliding sleeve 66 of casing valve 28. The internal
collet 76 which is initially in engagement with the first groove
78 of valve housing 50 will compress due to the 10,000 pound
upward pull and release the first groove 78. As the internal
collet 76 compresses and releases a decrease in upward force will
be noted at the surface to evidence the beginning of the opening
sequence. The sliding sleeve 66 will continue to be pulled to
its full extent of travel which will be confirmed by a sudden
rise in weight indicator reading at the surface as the top of the
sliding sleeve 66 abuts the bottom end 63 of the upper handling
sub 65 as shown in FIG. 4B. At this point the collet 76 will
engage second latch groove 80.
At this time, upward pull on the tubing string is reduced to
maintain approximately 5,000 to 8,000 pounds upward force on the
~?~3~
.
opening blocks 166. While maintaining that upward pull, and thus
maintaining opening blocks 166 in operative engagement with
shoulder 126 of sliding sleeve 66, rotation of the work string 36
begins maintaining the slowest rotary speed possible. As the
tubing string 36 rotates, so does the jetting tool 46 which is
connected to the tubing string 36 by the jetting mandrel 224.
While slowly rotating the work string 36 and the jetting tool 46,
high pressure fluid is pumped down the tubing string 36 and
directed out the jetting ports 210.
When the sliding sleeve 66 slides upward to its open position
as just described, each of the sleeve communication ports 94 is
placed in registry with a respective one of the housing com-
munication ports 56 as seen in FIG. 4D. Also, the jet orifices
210 of jetting tool 46 are aligned with a plurality of longitudi-
nally spaced planes 354, 356, 358 and 360 (see FIG. 4D) in which
the sleeve ports 56 and housing ports 94 lie. The planes 354
through 360 shown in FIG. 4D are shown on edge and extend perpen-
dicularly out of the plane of the paper on which FIG. 4D is
drawn.
The jetting tool 46 is rotated while maintaining the jetting
orifices 210 in alignment with the planes 354-360 so that the
disintegratable plugs 96 and 98 initially located in the housing
communication ports 56 and sleeve communication ports 94 are
repeatedly contacted by the high velocity fluid streams from the
jet orifices 210 to disintegrate the plugs.
After hydraulically jetting the plugs for sufficient time to
remove the port plugging material, the blowout preventers 40 (see
.
2 ~7 ~ ~ e~ 2 ~
-34-
FIG. 1) may be closed and the well 10 may be pressurized to pump
fluid into the formation 34 adjacent casing valve 28 to confirm
plug removal if desired and feasible based upon anticipated for-
mation breakdown pressures and pressure limitations of the
blowout preventers 40 and casing string 12.
Once the jetting of the plugs has been completed and the
pressure testing has been completed, the positioning tool 44 is
indexed to a position represented by lug position 184A wherein
the positioning mandrel 132 slides downward relative to drag
means 130 until the upper wedge 174 engages the closing blocks
154. As the positioning tool 44 moves downward through casing
valve 28, the closing blocks 154 will be cammed outward and their
downward facing shoulders 162 will engage shoulder 128 of sliding
sleeve 66. Then approximately 10,000 pounds downward force is
applied to the sliding sleeve 66 to cause the collet 76 to
collapse and move out of the engagement with upper groove 80.
The sleeve 66 will then slide downward until collet 76 engages
the lower groove 78 and the valve is once again in the position
as shown in FIGS. 2A-2E, except that the plugs have now been
disintegrated and removed from the sleeve ports 94 and housing
ports 56.
If desired, the blowout preventers 40 can again be closed and
the casing can be pressure tested to confirm that the casing
valve 28 is in fact closed.
Then, the tool string is moved upward to the next lowest
casing valve such as casing valve 26 and the sequence is
repeated. After casing valve 26 has been treated in the manner
.. . . .
~ ~ 2~ ~ 2 ~
-35-
just described, the tool string is again moved upward to the next
lower casing valve until finally all of the casing valves have
been hydraulically jetted to remove residual cement, and have
then been opened and had the plugs jetted therefrom, and then the
valves have been reclosed.
Once all of the casing valves have been jetted out and
reclosed, the work string should be pulled up to the top of the
liner, or to the top of the deviated section 22 of the casing 12
and backwashed. Backwashing is accomplished by reverse cir-
culation down the well annulus 38 through the bypass passages 298
and 300 of wash tool 48 and back up the bore 302 of wash tool 48
and up through the tubing string 36. The casing is backwashed in
a downward direction while moving the tool string down through
the well until the casing has been backwashed down to its total
depth to remove all debris residual from the hydraulic jetting
operation, in preparation for primary stimulation. Once back-
washing is complete, the work string will be withdrawn from the
well to change over to the required tool assembly for a stimula-
tion operation, e.g., a fracturing operation.
FIG. 6 illustrates a stimulation tool string, which in this
case is a fracturing tool string in place within the well 10.
The work string for fracturing operations includes the wash tool
48 attached to the bottom of the positioning tool 44 which is
located below a packer 362 all of which is suspended from the
tubing string 36. Other auxiliary equipment such as safety
valves or the like may also be located in the work string.
The work string illustrated in FIG. 6 is run to the bottom of
.. .. _ . ~
~ Ji 2 9 ~ 2 ~f
the casing string 12 and the lowermost casing valve 28 is engaged
with a positioning tool 44 to move the sliding sleeve 66 of
casing valve 28 to an open position wherein its sleeve com-
munication ports 94 are in registry with its housing com-
munication ports 56. The ports have already had their plugs
jetted out, so when the sleeve 66 is moved to this open position,
the interior of casing string 12 is communicated through the open
ports 94 and 56 with the surrounding formation 34.
Then, the positioning tool 44 is disengaged from the sliding
sleeve 66 and the work string is raised to a desired point above
the sleeve valve 28, at which the packer 362 is set. Then, the
zone 34 is stimulated as desired. With the fracturing string, a
fracturing fluid will be pumped through the ports of casing valve
28 into the surrounding formation to form fractures 364. It will
be appreciated that many other types of stimulation operations
can be performed on the formation 34 through the casing valve 28,
such as acidizing procedures and the like.
After stimulation, the zone 34 may be cleaned up and tested
as desired producing back up through the tubing string 36. After
testing, the zone 34 is killed to maintain well control, and the
packer 362 is unset. Then, the casing bore 12 and the interior
of casing valve 28 are again backwashed through the wash tool 48
to remove fracturing sand and formation fines from the interior
of casing 12 and from the interior of the casing valve 28. The
casing valve 28 is then again engaged with the positioning tool
44 and the sliding sleeve 66 thereof is moved to a closed posi-
tion.
-
~ 2~29~29
Afterwards, the work string is moved up to the next lowest
casing valve 26 and the process is repeated to fracture the for-
mation 32, then backwash the casing valve 26 and then reclose the
casing valve 26. Then the work string is moved up to the next
casing valve 24 and the operation is again repeated.
After completing all of the subsurface formations 30, 32 and
34, the casing valves 24, 26 and 28 may be reopened, selectively
if desired, in preparation for running a production packer or
whatever production string hookup is to be used, and the frac
string shown in FIG. 6 is then withdrawn from the well.
FIG. 7 schematically illustrates a selective completion of
only the lower zone 34 of well 10. Prior to removing the work
string shown in FIG. 6, the sliding sleeve 66 of the lowermost
casing valve 28 has been moved to an open position. Then, after
removal of the work string shown in FIG. 6, a production tubing
string 366 and production packer 368 are run into place and set
above the lower casing valve 28. Production of well fluids from
subsurface formation 34 is then performed through the casing
valve 28 and up through the production string 366.
Thus it is seen that the present invention readily achieves
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 may be made by those skilled in the
art, which changes are encompassed within the scope and spirit of
the appended claims.
