U.S. patent application number 11/397077 was filed with the patent office on 2007-10-04 for casing transition nipple and method of casing a well to facilitate well completion, re-completion and workover.
This patent application is currently assigned to Oil States Energy Services, Inc.. Invention is credited to L. Murray Dallas.
Application Number | 20070227742 11/397077 |
Document ID | / |
Family ID | 38557155 |
Filed Date | 2007-10-04 |
United States Patent
Application |
20070227742 |
Kind Code |
A1 |
Dallas; L. Murray |
October 4, 2007 |
Casing transition nipple and method of casing a well to facilitate
well completion, re-completion and workover
Abstract
A casing transition nipple and method of casing a well
facilitates well completion, re-completion and workover while
increasing safety and reducing expense. The casing transition
nipple provides a connection between a large diameter production
casing joint suspended by a wellhead and a standard production
casing string. The large diameter production casing joint permits
long downhole tool strings to be lubricated into the well without
leaving a high lubricator profile and reduces the cost of
performing many other well completion, re-completion and workover
procedures.
Inventors: |
Dallas; L. Murray;
(Fairfield, TX) |
Correspondence
Address: |
NELSON MULLINS RILEY & SCARBOROUGH, LLP
1320 MAIN STREET, 17TH FLOOR
COLUMBIA
SC
29201
US
|
Assignee: |
Oil States Energy Services,
Inc.
|
Family ID: |
38557155 |
Appl. No.: |
11/397077 |
Filed: |
April 4, 2006 |
Current U.S.
Class: |
166/380 ;
166/242.1 |
Current CPC
Class: |
E21B 17/08 20130101 |
Class at
Publication: |
166/380 ;
166/242.1 |
International
Class: |
E21B 17/02 20060101
E21B017/02 |
Claims
1. A casing transition nipple, comprising: a tubular body having a
top end adapted for fluid tight connection to a well casing of a
fist diameter and a bottom end adapted for fluid tight connection
to a well casing of a second, smaller diameter; and a smooth
annular tool guide surface between the first and second ends.
2. The casing transition nipple as claimed in claim 1 wherein the
fluid tight connections to the top and bottom ends comprise one or
more of: threaded, welded, locking or glued connections.
3. The casing transition nipple as claimed in claim 2 wherein the
wherein the top end is box threaded and the bottom end is box
threaded.
4. The casing transition nipple as claimed in claim 2 wherein where
in the top end is box threaded and the bottom end is pin
threaded.
5. The casing transition nipple as claimed in claim 2 wherein the
top end is pin threaded and the bottom end is box threaded.
6. The casing transition nipple as clamed in claim 2 wherein the
top end is pin threaded and the bottom end is pin threaded.
7. The casing transition nipple as claimed in claim 1 wherein the
annular tool guide surface slopes downwardly at an angle of a
30.degree.-60.degree. with respect to a plain that is perpendicular
to the top and bottom ends.
8. A method of casing a wellbore, comprising: running a production
casing of a first diameter into the wellbore until a bottom end of
the production casing of the first diameter is approximately a
predetermined distance from a bottom of the wellbore; connecting a
bottom end of a casing transition nipple to a top end of the casing
of the first diameter; connecting a bottom end of a production
casing of a second, larger diameter to a top end of the casing
transition nipple, the production casing of the second diameter
having a length approximately equal to the predetermined distance;
and suspending the production casing of the second, larger diameter
from a wellhead of the well.
9. The method as claimed in claim 8 wherein suspending the
production casing of the second, larger diameter from the wellhead
comprises suspending the production casing using a casing
mandrel.
10. The method as claimed in claim 8 wherein suspending the
production casing of the second, larger diameter from the wellhead
comprises suspending the production casing using casing slips.
11. The method as claimed in claim 8 wherein the predetermined
distance is 6-60 feet.
12. The method as claimed in claim 8 wherein the diameter of the
first casing is one of 41/2, 5 and 51/2 inches.
13. The method as claimed in claim 10 wherein a diameter of the
second casing is 51/2-8 inches.
14. The method as claimed in claim 8 further comprising using at
least one casing collar to connect at least one of the casings of
the first and second diameter to the casing transition nipple.
15. A method of casing a wellbore of a predetermined depth,
comprising: running a production casing of a first diameter into
the wellbore until a bottom end of the production casing of the
first diameter is at a depth that is less than the predetermined
depth of the wellbore; connecting a bottom end of a casing
transition nipple to a top end of the production casing of the
first diameter; connecting a bottom end of a production casing of a
second, larger diameter to a top end of the casing transition
nipple; and running the production casing of the second, larger
diameter into the wellbore until the wellbore is cased.
16. The method as claimed in claim 15 further comprising suspending
the production casing of the second, larger diameter from a
wellhead that suspends a surface casing in the wellbore.
17. The method as claimed in claim 16 wherein suspending the
production casing comprises connecting a top end of the production
casing to a casing mandrel and landing the casing mandrel in a
casing bowl of the wellhead.
18. The method as claimed in claim 16 wherein suspending the
production casing comprises landing casing slips around the
production casing in a casing bowl of the wellhead, and cutting off
a top of the production casing above the casing slips.
19. The method as claimed in claim 15 wherein a difference between
the depth of the wellbore and the depth to which the production
casing of the first diameter is run into the wellbore is about 6-60
feet.
20. The method as claimed in claim 15 wherein a difference in a
diameter of the production casing of the first diameter and the
production casing of the second diameter is about 11/2''-31/2''.
Description
FIELD OF THE INVENTION
[0001] This invention generally relates to hydrocarbon well
completion, recompletion and workover and, in particular, to a
casing transition nipple and method of casing a well to facilitate
well completion, re-completion and workover.
BACKGROUND OF THE INVENTION
[0002] Most oil and gas wells require some form of stimulation to
enhance hydrocarbon flow to make or keep them economically viable.
The servicing of oil and gas wells to stimulate production requires
the pumping of fluids under high pressure. The fluids may be
caustic and are frequently abrasive because they are laden with
abrasive propants such as sharp sand, bauxite or ceramic
granules.
[0003] It is well know that advances in coil tubing technology have
generated an increased interest in using coil tubing during well
completion, re-completion and workover procedures. Techniques have
been developed over the years for pumping well fracturing fluids
through coil tubing, or pumping "down the backside" around the coil
tubing. Processes and equipment have also been developed for
perforating casing and fracturing a production zone in a single
operation, as described in Applicant's U.S. Pat. No. 6,491,098
entitled Method and Apparatus for Perforating and Stimulating Oil
Wells, which issued on Dec. 10, 2002.
[0004] Although performing two or more functions in a single run
down a cased wellbore is economical and desirable, there is a
disadvantage with using existing techniques for performing such
operations. The principal disadvantage is the height of the
equipment stack that is necessary for lubricating the required tool
string into the well.
[0005] FIG. 1 is a schematic diagram of a setup 10 for performing a
well completion in accordance with the prior art techniques in
which a long tool string (not shown), e.g. a tool string for
perforating and stimulating production zones of the well in a
single run, are lubricated into the cased well bore.
[0006] As schematically illustrated in FIG. 1, a wellhead generally
indicated by reference numeral 12 includes a casing head 14
supported by a conductor 16. The casing head 14 supports a surface
casing 18. A tubing head spool 20 is mounted to the casing head 14.
The tubing head spool 20 supports a production casing 22, which
extends downwardly through the production zone(s) of the well.
[0007] Mounted to a top of the tubing head spool 20 is a blowout
preventer (BOP) 24 for controlling the well after the production
casing 22 is perforated. Optionally mounted to a top of the BOP is
a "frac cross" 26, also referred to as a fracturing head. The
purpose of the frac cross 26 is to permit well stimulation fluids
to be pumped down the backside, i.e. down production casing 22, and
around a coil tubing 34.
[0008] Mounted to a top of the frac cross 26 is one or more
"lubricator joints" 28. In this example three lubricator joints
28a, 28b and 28c are used. The lubricator joints house the downhole
tool string (not shown), which is supported by the coil tubing
string 34, or a wire line (not shown). A coil tubing BOP 30 or a
wire line BOP (not shown) is mounted to a top of the lubricator
joints. Tubing rams of the coil tubing BOP seal around the coil
tubing string 34 while the tool string is being run into and out of
the well. Likewise, wire line rams of a wire line BOP seal around a
wire line as it is being run into or out of the well. A coil tubing
injector 32 is mounted to a top of the coil tubing BOP 30. The coil
tubing injector 32 is used to run the coil tubing string 34 into
and out of the production casing 22 in a manner well known in the
art. The coil tubing string 34 is supplied from a coil tubing spool
36, which is likewise well known in the art and may be mounted on a
trailer or a truck.
[0009] As is apparent, the setup 10 shown in FIG. 1 creates an
equipment stack that extends 20'-40' from the ground. The setup 10
is in a normally assembled on the ground and place after its is
assembled. For the sake of clarity, the stays, work platforms,
cranes and other equipment required to assemble, disassemble,
operate, and maintain the setup 10 are not shown.
[0010] As will be understood by those skilled in the art,
assembling and operating the setup 10 can be dangerous, because
maintenance work must be performed on elevated work platforms high
off the ground. As will be further understood, the setup 10 can
also be dangerous because a great deal of mechanical bending and
twisting stress is placed on the wellhead 12 and the lubricator 28
by the very high setup 10, which acts as a lever when force is
applied to a top of the set up 10 by operation of the coil tubing
injector or 32 or the wire line unit (not shown).
[0011] As will also be appreciated by those skilled in the art,
assembling the setup 10 is expensive because heavy hoisting
equipment, such as an 80-ton crane, is required to hoist the
equipment to those heights. The 80-ton crane must also be connected
to a top of the set up 10 and used to counter force applied to the
setup 10 by operation of the coil tubing injector 32 or the wire
line unit. The 80-ton crane must therefore remain on the job during
the entire well stimulation process. The rental of such hoisting
equipment for an extended period of time is very expensive.
[0012] There is therefore a need for a way of facilitating well
completion, re-completion and workover while preserving the time
and cost savings of being able to perform more than one function
during a single run into a cased wellbore.
SUMMARY OF THE INVENTION
[0013] It is therefore an object of the invention to provide a way
of facilitating and improving the safety of well completion,
re-completion and workover while preserving the time and cost
savings of being able to perform more than one function during a
single run into a cased wellbore.
[0014] The invention therefore provides a casing transition nipple,
comprising: a tubular body having a top end adapted for fluid tight
connection to a well casing of a fist diameter and a bottom end
adapted for fluid tight connection to a well casing of a second,
smaller diameter; and a smooth annular tool guide surface between
the first and second ends, the tool guide surface sloping
downwardly with respect to the top end.
[0015] The invention further provides a method of casing a
wellbore, comprising: running a production casing of a first
diameter into the wellbore until a bottom end of the production
casing of the first diameter is approximately a predetermined
distance from a bottom of the wellbore; connecting a bottom end of
a casing transition nipple to a top end of the production casing of
the first diameter; connecting a bottom end of a production casing
of a second, larger diameter to a top end of the casing transition
nipple, the production casing of the second diameter having a
length approximately equal to the predetermined distance; and
suspending the production casing of the second, larger diameter
from a wellhead of the well.
[0016] The invention yet further provides a method of casing a
wellbore of a predetermined depth, comprising: running a production
casing of a first diameter into the wellbore to a depth less than
the predetermined depth of the wellbore; connecting a bottom end of
a casing transition nipple to a top end of the production casing of
the first diameter; connecting a bottom end of a production casing
of a second, larger diameter to a top end of the casing transition
nipple; and running the production casing of the second, larger
diameter into the wellbore until the wellbore is cased.
BRIEF DESCRIPTION OF THE DRAWINGS
[0017] Having thus generally described the nature of the invention,
reference will now be made to the accompanying drawings, in
which:
[0018] FIG. 1 is a schematic diagram of a prior art setup for
running a long downhole tool string into a production casing of a
well in order to perform more than on function in a single run into
the well;
[0019] FIG. 2 is a schematic diagram of a well cased in accordance
with an embodiment of the invention;
[0020] FIG. 3 is a schematic diagram of a well cased in accordance
with another embodiment of the invention;
[0021] FIG. 4 is a schematic diagram of a well cased in accordance
with yet another embodiment of the invention;
[0022] FIG. 5 is a schematic diagram of a well cased in accordance
with yet a further embodiment of the invention;
[0023] FIG. 6 is a cross-sectional schematic diagram of the casing
transition nipple shown in FIG. 2;
[0024] FIG. 7 is a cross sectional schematic diagram of the casing
transition nipple shown in FIG. 3;
[0025] FIG. 8 is a cross-sectional schematic diagram of the casing
transition nipple shown in FIG. 4;
[0026] FIG. 9 is a cross-sectional schematic diagram of the casing
transition nipple shown in the FIG. 5;
[0027] FIG. 10 is a schematic diagram of a set up for lubricating a
long downhole tool string into a well cased in accordance with the
invention;
[0028] FIG. 11 is a schematic diagram of the set up shown in FIG.
10, illustrating the long downhole tool string in a "lubricated-in"
condition; and
[0029] FIG. 12 is a schematic diagram of a setup in accordance with
another embodiment of the invention illustrating the long downhole
tool string in a lubricated in condition, the setup being
configured to run the long downhole tool string into the well using
a wire line unit.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0030] The invention provides a casing transition nipple and a
method of casing a well in order to facilitate well competition,
re-completion and workover. In accordance with the invention, the
casing transition nipple is used to interconnect a bottom end of at
least one casing joint of a first diameter having a top end
connected to the wellhead and a top end of a production casing of a
second, smaller diameter that communicates with production zones of
the well. A well cased in accordance with the invention facilitates
many well completion, recompletion and workover procedures. For
example, the well cased in accordance with the invention
facilitates the process of lubricating long downhole tool strings
into the well and significantly reduces a distance that a coil
tubing injector or a wire line unit is above the ground after the
tool string has been lubricated into the well. This significantly
reduces expense and improves safety by lowering working height and
significantly reducing strain on the wellhead.
[0031] FIG. 2 is a schematic diagram partially in cross-section
showing a well cased in accordance with the invention. As
schematically shown in FIG. 2, the surface casing 18 is supported
by a casing mandrel or casing slips 46 landed in a casing bowl, in
a manner well known in the art. If the casing 18 is supported by
casing slips, a top of the casing is cut off after the slips are
set.
[0032] A casing transition nipple 40a connects an upper section of
production casing 42 to a lower section of production casing 44.
The upper section of production casing 42 has a larger diameter
than the lower section of production casing 44. For example, the
upper section of production casing 42 may have a diameter of 6-8
inches. The lower section of production casing 44 is of a standard
casing size, e.g. 41/2, 5 or 51/2 inches. A lower section of the
production casing extends from the casing transition nipple 40a to
the bottom of the well.
[0033] In one embodiment of the invention the upper section of
production casing 42 has a length of 6-60 feet. It may be, for
example, one joint of casing, which is typically 30 feet in length.
However, the upper section of production casing 42 may be shorter
or longer than 30 feet, depending on anticipated need.
[0034] In this embodiment, the casing transition nipple 48 is box
threaded on each end as will be explained below in more detail with
reference to FIG. 6.
[0035] FIG. 3 is a schematic diagram partially in cross-section
showing a well cased in accordance with another embodiment of the
invention. The upper section of production casing 42 and the lower
section of production casing 44 are identical to that described
above with reference to FIG. 2. In this embodiment, a casing
transition nipple 40b has a box end for connection to the upper
section of production casing 42 and a nipple end for connection to
the lower section of production casing 44. Consequently, a casing
collar 50, commonly known in the art for connecting joints of
casing, is used to connect the nipple end of the casing transition
nipple 40b to the lower section of the production casing 44. This
will be explained below in more detail with reference to FIG.
7.
[0036] FIG. 4 is a schematic diagram partially in cross-section
showing a well cased in accordance with yet a further embodiment of
the invention. The upper section of the production casing 42 and
the lower section of the production casing 44 are the same as that
described above with reference to FIG. 2. In this embodiment, the
casing transition nipple 40c is pin threaded for connection to the
upper section of the production casing 42 and box threaded for
connection to the lower section of the production casing 44.
Consequently, a casing collar 52 is used to connect the upper
section of the production casing 42 to the transition nipple 40c,
as will be explained below in more detail with reference to FIG.
8.
[0037] FIG. 5 is a schematic diagram partially in cross-section
showing a well cased in accordance with yet another embodiment of
the invention. The upper section of the production casing for 42
and the lower section of the production casing 44 are the same as
that described above with reference to FIG. 2. In this embodiment,
the casing transition nipple 40c is pin threaded for connection to
the upper section of the production casing 42 and pin threaded for
the connection of the lower section of the production casing 44.
Consequently, a casing collar 52 is used to connect the upper
section of the production casing 42 to the casing transition nipple
40d, and a casing collar 50 is used to connect the lower section of
the production casing 44 to the casing transition nipple 40d, as
will be explained below in more detail with reference to FIG.
9.
[0038] FIG. 6 is a cross-sectional schematic view of the casing
transition nipple 40a shown in FIG. 2. The casing transition nipple
40a has a top end 60a for connection to the upper section of the
production casing 42. The casing transition nipple 40a also has a
bottom end 62a for connection of the lower section of the
production casing 44. The casing transition nipple 40a further
includes a smooth, annular downwardly inclined tool guide surface
68a. As illustrated, in one embodiment the tool guide surface 68a
is downwardly inclined at an angle of about 30.degree.-60.degree.
from a plane that is perpendicular to the top end 60a and the
bottom and 62a of the casing transition nipple 40a.
[0039] The upper end 60a has a box thread 64a, which engages a pin
threaded end of the upper section of the production casing 42. The
box thread 64a is shown schematically. As is understood by those
skilled in the art, casing is available in a plurality of thread
patterns. For example, casing may be threaded using a Buttress,
Hydril, Acme, Rucker Atlas, EUE 8-round, EUE 10-round, EUE 8-V or
EUE 10-V thread pattern, and this list is not exhaustive. It should
therefore be understood that the thread pattern used to machine
threads on any of the box threaded or pin threaded ends described
above and below is purely a matter of design choice, and the
schematically illustrated threads shown in FIGS. 6-9 are intended
to be representative of any thread pattern applied to casing, as
well as any other method that may be used for connecting the casing
40, 42 to the casing transition nipple 40 a-d. The bottom end 62a
likewise includes a box thread 66a for direct connection of a pin
threaded top end of the lower section of the production casing
44.
[0040] FIG. 7 is a cross-sectional schematic diagram of the casing
transition nipple 40b shown in FIG. 3. The casing transition nipple
40b is identical to the casing transition nipple 40a described
above with reference to FIG. 6 with the exception that the bottom
end 62b is pin threaded. As explained above with reference to FIG.
3, a casing collar 50 is used to connect the lower section of
production casing 44 to the pin thread 70b of the casing transition
nipple 40b.
[0041] FIG. 8 is a schematic cross-sectional view of a casing
transition nipple 40c described above with reference to FIG. 4. The
casing transition nipple 40c is the same as the casing transition
nipple 40a described above, with the exception that the top end 60c
is pin threaded and the bottom end 62c is box threaded.
Consequently, a casing collar 52 is used to connect the production
casing 42 to the top end 60c of the casing transition nipple 40c.
As explained above, the lower section of production casing 44 is
connected directly to the box thread 66c of the casing. transition
nipple 40c.
[0042] FIG. 9 is a schematic cross-sectional view of the casing
transition nipple 40d described above with reference to FIG. 5. The
casing transition nipple 40d is the same as the casing transition
nipple 40a described above with reference to FIG. 6 with the
exception that the top end 60d is pin threaded and the bottom end
62d is also pin threaded. Consequently, as described above with
reference to FIG. 5 a casing collar 52 is used to connect the upper
section of production casing 42 to the pin thread 72d of the top
end 60d. Likewise, a casing collar 50 is used to connect the lower
section of production casing 44 to the pin thread 70d of the bottom
end 62d of the casing transition nipple 40d.
[0043] As will be understood by those skilled in the art, any of
the above the threaded connections may be made permanent using a
thread glue such as Baker Lock.RTM.. Furthermore, any of the above
connections may be welded connections, glued connections, or
connections made using any one of a number of fluid tight
quick-lock, screw-lock or other locking connectors that are known
in the art.
[0044] FIG. 10 is a schematic view partially in cross-section of a
setup 100 for running a long downhole tool string 102 into a
wellbore cased in accordance with the invention. As used in this
document, a "long downhole tool string 102" means any one or more
of a perforating gun; jetting tool; packer; plug; a selective
acidizing and/or fracturing tool; a casing or tubing cutter; a
fishing tool; a pulling tool; a grapple; etc. in any
combination.
[0045] The setup 100 is very similar to the setup 10 described
above with reference to FIG. 1, with the exception that the
lubricator 28a-c is replaced by a subsurface lubricator 104 that is
schematically illustrated. The subsurface lubricator 104 is not
described because it is not within the scope of this invention.
None of the control structure for the subsurface lubricator 104 is
illustrated for the purposes of clarity. In this example, the
subsurface lubricator 104 is mounted to a top of the frac cross 26,
which is in turn mounted to a top of a blowout preventer 24 as
described above with reference to FIG. 1. As will be understood by
those skilled in the art, prior to lubricating in the long downhole
tool string 102 blind rams 106 of the blowout preventer 24 are
closed to seal an annulus of the upper section of the production
casing 42. Due to a length of the downhole tool string 102, a
height of the set up 100 is 20'-40', similar to the set up 10 shown
in FIG. 1.
[0046] The set up 100 is assembled on the ground in a manner to
that described above with reference to FIG. 1. The set up 100 may
be hoisted into position using, for example, a coil tubing unit
crane, because as will be explained below with reference to FIG.
11, an 80-ton crane is not required to stabilize the setup 100
after it is "lubricated in".
[0047] FIG. 11 is a schematic diagram partially in cross-section of
the setup 100 after it has been lubricated into the wellbore cased
in accordance with the invention. As will be understood by those
skilled in the art, the subsurface lubricator 104 has been lowered
down through the blowout preventer protector 24 and the wellhead 14
and into the upper section of the production casing 42 to a
locked-down condition in which a well completion, recompletion or
workover procedure is ready to be performed. As can be seen, in the
locked-down position a height of a top of the coil tubing injector
32 is about 15'-18' above the ground, as opposed to about 40' above
the ground for the setup 10 shown in FIG. 1. The setup 100 reduces
cost because a crane is not required to stabilize the setup 100
after it is lubricated in. The setup 100 also significantly
improves a work safety and facilitates equipment maintenance
because of the reduced working height. As will be understood by
those skilled in the art, mechanical bending and twisting stresses
on the wellhead 14 are also significantly reduced. This is not only
due to the reduced working height of the setup 100, but also due to
the subsurface lubricator 104 which runs inside the upper section
of the production casing 42 and thereby lends significant rigidity
to the wellhead components through which it is run. Consequently,
rather than mechanically stressing the wellhead, the setup 100
actually reinforces the wellhead and substantially eliminates any
possibility that the wellhead could be damaged by the mechanical
bending and twisting forces exerted by coil tubing or wireline
units when long tool strings are lubricated into or out of the
well.
[0048] FIG. 12 is a schematic diagram partially in cross-section of
another setup 110 in accordance with the invention, showing the
long downhole tool string 102 in a lubricated in condition. The
setup 110 is configured to lower the long downhole tool string 102
into the wellbore cased in accordance with the invention using a
wireline unit 106, which is schematically illustrated. As
understood by those skilled in the art, a wireline 84 of the
wireline unit 106 runs over a wireline sheave 88 and through a
grease injector 82. The grease lines, pumps and other components of
the grease injector 82 are not shown. The wireline 84 runs through
a wireline BOP 80 and the frac cross 26. The wireline 84 is
connected to a top of the long downhole tool string 102. In this
example, the wireline sheave 88 is supported by a sheave boom 86
mounted to a side of the subsurface lubricator 104, so that a crane
is not required to support the wireline sheave 88. The setup 110
provides all of the advantages described above with reference to
the setup 100.
[0049] A wellbore cased in accordance with the invention therefore
improves work safety, enables downhole operations that were
heretofore impossible, impractical or excessively dangerous, and
reduces cost by lowering the overall working height after a long
downhole tool string has been lubricated into the cased well.
[0050] As will be understood by those skilled in the art, the
above-noted dimensions of the upper section of production casing 42
and the casing transition nipple 40a are exemplary only. The
dimensions of the upper section of the production casing 42, a
lower section of the production casing 44 and the casing transition
nipple 40a-d are, within certain limits, a matter of design choice.
It is only important that the upper section of production casing 42
has an internal diameter large enough to accept a subsurface
lubricator that provides full-bore access to the lower section of
production casing 44. A difference in the two diameters of about
11/2''-31/2'' is generally sufficient. It is also important that a
burst strength of a the upper section of production casing 42 be at
least as high as a burst strength of the lower section of
production casing 44, or at least as high as anticipated well
stimulation fluid pressures, plus a margin for safety.
[0051] The embodiments of the invention described are therefore
intended to be exemplary only, and the scope of the invention is
intended to be limited solely by the scope of the appended
claims.
* * * * *