Note: Descriptions are shown in the official language in which they were submitted.
CA 02303058 2000-03-28
BLOWOUT PREVENTER PROTECTOR AND
METHOD OF USING SAME
TECHNICAL FIELD
The present invention relates to equipment for
servicing oil and gas wells and, in particular, to an
apparatus and method for protecting blowout preventers
from exposure to high pressure and abrasive or corrosive
fluids during well fracturing and stimulation procedures
while providing direct access to production tubing in the
well and permitting production tubing to be run in or out
of the well.
BACKGROUND OF THE INVENTION
Most oil and gas wells eventually 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 are
generally corrosive and abrasive because they are
frequently laden with corrosive acids and abrasive
proppants such as sharp sand.
The components which make up the wellhead such
as the valves, tubing hanger, casing hanger, casing head
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and the blowout preventer equipment are generally
selected for the characteristics of the well and not
capable of withstanding the fluid pressures required for
well fracturing and stimulation procedures. Wellhead
components are available that are able to withstand high
pressures but it is not economical to equip every well
with them.
There are many wellhead isolation tools used in
the field that conduct corrosive and abrasive high
pressure fluids and gases through the wellhead components
to prevent damage thereto.
The wellhead isolation tools in the prior art
generally insert a mandrel through the various valves and
spools of the wellhead to isolate those components from
the elevated pressures and the corrosive and abrasive
fluids used in the well treatment to stimulate
production. A top end of the mandrel is connected to one
or more high pressure valves, through which the
stimulation fluids are pumped. In some applications, a
pack-off assembly is provided at a bottom end of the
mandrel for achieving a fluid seal against an inside of
the production tubing or casing so that the wellhead is
completely isolated from the stimulation fluids. One
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such tool is desci:~i.bed in Applicant's United States
Patent No. 4,867,243, which issued September 19, 1989 and
is entitled WELLHEAD ISOLATION TOOK AND SETTING TOOL AND
METHOD OF USING SAME.,
In an ~.mproved wellhead isolation tool
configuration, the mandrel in an operative position,
requires fixed-point pack-off in the well, as described
in Applicant's United States Patent No. 5,819,851, which
issued October .L3, 1':398 and is entitled BLOWOUT PREVENTER
PROTECTOR FOR USE TURING HIGH-PRESSURE OIL/GAS WELL
STIMULATION. A furt=her improvement of that tool is
described in App7_icant's United States Parent
No. 6,247,537, whicru issued on June 19, 2001 and is
entitled HIGH PRESSURE FLUID SEAL FOR SEALING AGAINST A
BIT GUIDE IN A WELLF~F:AD AND METHOD OF USING SAME. The
mandrel described in. this patent and patent application
includes an annular :>ealing body attached to the boi~tom
end of the mandrel for sealing against a bit guide which
is mounted on the to~:> of a casing in the wellhead.
This type of isolation tool advantageously
provides full access t:o a well easing and permits use of
downhole tools durir~.g a well stimulation treatment. A
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mechanical lockdown mechanism for securing a mandrel
requiring fixed-point pack-off in the well is described
in Applicant's United States Pat=ent No. 6,289,753, which
issued on September 18, 2001 and is entitled BLOWOUT
PREVENTER PROTECTOR AND SETTING 'POOL. The mechanical
lockdown mechanism has an axial adjusting length adequate
to compensate for variations in a distance between a top
of the blowout prevezuter and the top of the casing of the
different wellheads tc~ permit the mandrel to be secured
in the operative position even if a length of a mandrel
is not precisely matched with a particular wellhead. The
mechanical lockdown rnechanism secures the mandrel against
the bit guide to rna:intain a fluid seal but does not
restrain the mandrel from downwards movement. The force
exerted on the annu:L<~r sealing be>dy between the bottom
end of the mandrel ~~nd the bit guide results from a
combination of the weight of the isolation tool and
attached valves and fittings, a force applied by the
lockdown mechanism and an upward force exerted by f7_uid
pressures acting on t:h.e mandrel.
The wellhe<~d isolation tools described in the
above patents and patent appl:Lcations work well and are
in significant demand. However', i.t is also desirable
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from a cost and safety standpoint, to be able to leave
the tubing string, or as it is sometimes called the "kill
string", in the well during a well stimulation treatment.
The above-described wellhead isolation tool is not
adapted to support a tubing string left in the well
because the weight of a long tubing string may damage the
seal between the bottom of the mandrel and the bit guide.
Some prior art wellhead isolation tools are
adapted for well stimulation treatment with a tubing
string left in the well. For example, Canadian Patent
No. 1,281,280 which is entitled ANNULAR AND CONCENTRIC
FLOW WELLHEAD ISOLATION TOOL AND METHOD OF USE THEREOF,
which issued to McLeod on March 12, 1991, describes an
apparatus for isolating the wellhead equipment from the
high pressure fluids pumped down to the production
formation during the procedures of fracturing and
acidizing oil and gas wells. The apparatus utilizes a
central mandrel inside an outer mandrel and an expandable
sealing nipple to seal the outer mandrel against the
casing. The bottom end of the central mandrel is
connected to a top of the tubing string and a sealing
nipple is provided with passageways to permit fluids to
be pumped down the tubing and/or the annulus between the
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CA 02303058 2001-12-04
tubing and the casing in an o_Ll or gas well. One
disadvantage of this apparatus is that the fluid flow
rate is restricted by the diameter of the outer mandrel
which must be smaller than the diameter of the casing of
the well and further restricted by the passageways ire the
sealing nipple between the central and outer mandrels.
The sealing nipple also blocks t:he annulus, preventing
tools from being run down the wellbore. The passageways
in the sealing nipple are also susceptible to damage by
the abrasive particle-laden fluids and are easily
washed-out during a well st=Lmulation treatment. A
further disadvantage of the isolation tool is that the
tool has to be removed and re-installed every time the
tubing string is to be moved up or down in the well.
Applicant's co-pending Canadian Patent
application entitled. BLOWOUT PREVENTER PROTECTOR AND
METHOD OF USING SAME which was fi.Led on January 28, 2000
and has been assigned Serial No. 2, 297, 600, describes an
improved isolation tool which i.s adapted for use with a
tubing string to be left in the well, or run into or out
of the well during a well stimulation treatment. The
blowout preventer protector seals against. a bit guide of
the well and provides full access to the casing of the
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well to permit downhole tools to be run in or out of the
casing. However, there are certain types of wellheads
which do not include a bit guide. Such wellheads are
generally referred to as "Larkin-type" wellheads. In
Larkin-type wellheads, the top of the casing is threaded
and the wellhead is screwed to the top of the wellhead
using a high-pressure sealing compound, or the like.
Consequently, the blowout preventer protector described
in Applicant's co-pending patent application filed
January 28, 2000 cannot be used to service such wells.
In addition, as wells age and are stressed by extended
use, the seal between the bit guide and the casing cannot
always be relied on to withstand elevated fluid
pressures.
There therefore exists a need for a blowout
preventer protector that seals off in the casing of the
well while providing access to tubing in the well or
permitting tubing to be run into or out of the well.
2 0 SLJMMP~RY OF THE INVENTION
It is an object of the invention to provide a
BOP protector which is adapted to support a tubing string
CA 02303058 2000-03-28
in a wellbore so that the tubing string is accessible
during a well treatment to stimulate production.
It is a further object of the invention to
provide a BOP protector that permits a tubing string to
be moved up and down in the wellbore without removing the
BOP protector from the wellhead.
It is another object of the present invention
to provide a BOP protector that permits a tubing string
to be run into or out of the wellbore without removing
the BOP protector from the wellhead.
In accordance with one aspect of the invention,
there is provided an apparatus for protecting a blowout
preventer from exposure to fluid pressures, abrasives and
corrosive fluids used in a well treatment to stimulate
production. The apparatus is adapted to support a tubing
string in a wellbore so that the tubing string is
accessible during the well treatment. The apparatus
includes a mandrel adapted to be inserted down through
the blowout preventer to an operative position. The
mandrel has a mandrel top end and a mandrel bottom end.
The mandrel bottom end includes a sealing assembly for
sealing engagement with a casing of the well when the
mandrel is in the operative position. A base member is
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adapted for connection to the wellhead and includes fluid
seals through which the mandrel is reciprocally moveable.
The apparatus further comprises a fracturing head, a
tubing adapter and a lock mechanism. The fracturing head
includes a central passage in fluid communication with
the mandrel and at least one radial passage in fluid
communication with the central passage. The tubing
adapter is mounted to a top end of the fracturing head
and supports the tubing string while permitting fluid
communication with the tubing string. The lock mechanism
for locking the apparatus in the operative position to
inhibit upward movement of the mandrel induced by fluid
pressures in the wellbore.
The apparatus preferably includes a mandrel
head affixed to the mandrel top end and the fracturing
head is mounted to the mandrel head. The lock mechanism
preferably includes a mechanical lockdown mechanism which
is adapted to inhibit upward movement of the mandrel head
induced by fluid pressures when the mandrel is in the
operative position.
More especially, according to an embodiment of
the invention, the base member has a central passage to
permit the insertion and removal of the mandrel. The
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CA 02303058 2000-03-28
passage is surrounded by an integral sleeve having an
elongated spiral thread for engaging a lockdown nut that
is adapted to secure the mandrel in the operative
position. A passage from the mandrel head top end to the
mandrel head bottom end is provided for fluid
communication with the mandrel and permits the tubing
string to extend therethrough.
The tubing adapter is configured to meet the
requirements of a job. It may be a flange for mounting a
BOP to the top of the apparatus so that tubing can be run
into or out of the well. Alternatively, the tubing
adapter may include a threaded connector to permit the
connection of a tubing string that is already in the
well.
A blast joint may be connected to the tubing
adapter if coil tubing is run into the well. The blast
joint protects the coil tubing from erosion when abrasive
fluids are pumped through the fracturing head.
In accordance with another aspect of the
invention, a method is described for providing access to
a tubing string while protecting a blowout preventer on a
wellhead from exposure to fluid pressure as well as to
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abrasive and corrosive fluids during a well treatment to
stimulate production. The method comprises:
a) suspending the apparatus above the
wellhead;
b) aligning the apparatus with a tubing
string supported on the wellhead and lowering the
apparatus until a top end of the tubing string extends
through the axial passage above the fracturing head;
c) connecting the top end of the tubing
string to a top end of the fracturing head, lowering the
tubing string and the apparatus until the apparatus rests
on the wellhead, and mounting the base member to the
wellhead;
d) opening the blowout preventer;
e) lowering the tubing string and the
fracturing head to stroke the mandrel bottom end down
through the wellhead into the casing of the well until
the mandrel reaches an operative position in which the
fracturing head rests on the base member and the seal
assembly is in sealing contact with an inner wall of the
casing; and
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f) locking the fracturing head to the base
member to inhibit the mandrel from upward movement
induced by fluid pressure in the well.
In accordance with a further aspect of the
invention, a method is described for running a tubing
string into or out of a well while protecting a first
blowout preventer on a wellhead of the well from exposure
to fluid pressure as well as to abrasive and corrosive
fluids during a well treatment to stimulate production.
The method related to the use of the above-described
apparatus comprises:
a) mounting the base member of the apparatus
to the wellhead;
b) closing at least one second blowout
preventer which is mounted to an adapter flange mounted
to a top the fracturing head;
c) opening the first blowout preventer;
d) lowering the fracturing head to stroke the
mandrel bottom end down through the wellhead into the
casing until the mandrel is in an operative position in
which the fracturing head rests against the base member
and the annular sealing assembly is in fluid sealing
engagement with an inner wall of the casing of the well;
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e) locking the mandrel in the operative
position to prevent the mandrel from upward movement
induced by fluid pressure in the well; and
f) running the tubing string into or out of
the well through the at least one second blowout
preventer.
A primary advantage of the invention is the
capability to support a tubing string in a wellbore
during the well stimulation treatment. This provides
direct access to both the tubing string and the well
casing so that the use of the apparatus is extended to a
wide range of well service applications.
Furthermore, the apparatus permits the tubing
string to be moved up and down, or run in or out of the
well without removing the apparatus from the wellhead.
The tubing string can even be moved up or down in the
well while well treatment fluids are being pumped into
the well. Labour and the associated costs are thus
reduced.
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BRIEF DESCRIPTION OF THE DRAWINGS
The invention will now be further described by
way of illustration only and with reference to the
accompanying drawings, in which:
FIG. 1 is a cross-sectional view of a preferred
embodiment of the BOP protector in accordance with the
invention, showing the mandrel in an exploded view;
FIG. 2 is a cross-sectional view of the
embodiment shown in FIG. 1 illustrating the BOP protector
in a condition ready to be mounted to a wellhead;
FIG. 3 is a cross-sectional view of the BOP
protector shown in FIG. 2 suspended over the wellhead
prior to installation on the wellhead;
FIG. 4 is a cross-sectional view of the BOP
protector shown in FIG. 3 illustrating a further step in
the installation procedure, in which the tubing string is
connected to a tubing adapter;
FIG. 5 is a cross-sectional view of the BOP
protector shown in FIG. 4, in which the mandrel of the
BOP protector is inserted through the wellhead and locked
in an operative position;
FIG. 6 is a partial cross-sectional view of a
BOP protector in accordance with the invention, showing a
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tubing adapter flange used for mounting a BOP to permit
tubing to be run into or out of the well without removing
the BOP protector from the wellhead; and
FIG. 7 is a cross-sectional view of a preferred
embodiment of a sealing assembly for the BOP protector
shown in FIGs. 1-6.
DETAILED DESCRIPTION OF THE PREFERRED EI~ODIMENT
FIG. 1 shows a cross-sectional view of the
apparatus for protecting the blowout preventers
(hereinafter referred to as a BOP protector) in
accordance with the invention, generally indicated by
reference numeral 10. The apparatus includes a lockdown
mechanism 12 which includes a base member 14, a mandrel
head 16 and a lockdown nut 18 that detachably
interconnects the base member 14 and the mandrel head 16.
The base member 14 includes a flange and an integral
sleeve 20 that is perpendicular to the flange of the base
member 14. A spiral thread 22 is provided on an exterior
of the integral sleeve 20. The spiral thread 22 is
engageable by a complimentary spiral thread 24 on an
interior surface of the lockdown nut 18. The flange of
the base member 14 with the integral sleeve 20 form a
- 15 -
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passage 26 that permits a mandrel 28 to pass
therethrough. The mandrel head 16 includes an annular
flange, having a central passage 30 defined by an
interior wall 32. A top flange 34 is adapted for
connection to a fracturing head 35. A lower flange 36
retains a top flange 38 of the lockdown nut 18. The
lockdown nut 18 secures the mandrel head 16 from upward
movement with respect to the base member 14 when the
lockdown nut 18 engages the spiral thread 22 on the
integral sleeve 20.
The mandrel 28 has a mandrel top end 40 and a
mandrel bottom end 42. Complimentary spiral threads 43
are provided on the exterior of the mandrel top end 40
and on a lower end of the interior wall 32 of the mandrel
head 16 so that the mandrel top end 40 may be securely
attached to the mandrel head 16. One or more O-rings
(not shown) provide a fluid-tight seal between the
mandrel head 34 and the mandrel 28. The passage 26
through the base member 14 has a recessed region at the
lower end for receiving a steel spacer 44 and packing
rings 46 preferably constructed of brass, rubber and
fabric. The steel spacer 44 and packing rings 46 define
a passage of the same diameter as the periphery of the
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mandrel 28. The packing rings 46 are removable and may
be interchanged to accommodate different sizes of
mandrel 28. The steel spacer 44 and packing rings 46 are
retained in the passage 26 by a retainer nut 48. The
combination of the steel spacer 44, packing rings 46 and
the retainer nut, provide a fluid seal to prevent passage
to the atmosphere of well fluids from an exterior of the
mandrel 28 and the interior of the BOP when the
mandrel 28 is inserted into the BOP, as will be described
below with reference to FIGS. 3-5.
An internal threaded connector 50 on the
mandrel bottom end 42 is adapted for the connection of
mandrel extension sections of the same diameter. The
extension sections permit the mandrel 28 to be
lengthened, as required by different wellhead
configurations. An optional mandrel extension 52, has a
threaded connector 54 at a top end 56 adapted to be
threadedly connected to the mandrel bottom end 42. An
extension bottom end 58, includes a threaded connector 60
that is used to connect a sealing assembly 62, which will
be described below with reference to FIG. 7. High
pressure 0-ring seals 64, well known in the art, provide
a high pressure fluid seal in the threaded connectors
- 17 -
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between the mandrel 28, the optional mandrel
extensions) 52 and the sealing assembly 62.
The mandrel 28, the mandrel extension 52 and the
sealing assembly 62 are preferably each made from 4140
steel, a high-strength steel that is commercially
available. 4140 steel has a high tensile strength and a
Burnell hardness of about 300. Consequently, the
assembled mandrel 28 is adequately robust to contain
extremely high fluid pressures of up to 15,000 psi, which
approaches the burst pressure of the well casing.
The fracturing head 35 includes a sidewall 74
surrounding a central passage 76 that has a diameter not
smaller than the internal diameter of the mandrel 28. A
bottom flange 78 is provided for connection in a fluid
tight seal to the mandrel head 16. Two or more radial
passages 80, 82 with threaded connectors 84, 86 are
provided to permit well stimulation fluids to be pumped
through the wellhead.
The radial passages 80, 82 are preferably
oriented at an acute upward angle with respect to the
sidewall 74. At the top end 88 of the sidewall 74, a
threaded connector 90 removably engages a threaded
connector 92 of one embodiment of a tubing adaptor 94, in
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CA 02303058 2001-12-04
accordance with the invention. The tubing adapter 94
includes a flange 96, the threaded connector 92 a:nd a
sleeve 98. The tubing adapter 94 also includes a central
passage 100 with the threads 102 for detachably
connecting a tubing joint of a tubing string. A spiral
thread 104 is provided on the exterior of the sleeve 98
and adapted for connecting other equipment, for example,
a high pressure valve 136 (FIG. 4).
The mandrel head 16 with its upper and lower
flanges 34, 36, and the lockdown nut 18 with its top
flange 38 are illustrated in FIG. 1 respectively as an
integral unit assembled, for example, by welding or the
like. However, persons skilled in the art will
understand that any one of the mandrel head 16 or the
lockdown nut 18 may be constructed to permit the mandrel
head 16 or the loc:kdown nut 18 to be independently
replaced.
FIG. 2 illustrates the BOP protector 10 shown
in FIG. 1, prior to being mounted to a BOP for a well
stimulation treatment. 'The mandrel head 16 is connected
to the top end of the mandrel 28, which includes any
required extension section (s) 52 and the pack:-off
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assembly 62 to provide a total length of the mandrel 16
required for a particular wellhead.
FIGS. 3 through 5 illustrate the installation
procedure of the BOP protector 10 to a wellhead 120 with
a tubing string 122 supported, for example, by slips 124
or some other supporting device, at the top of the
wellhead 120. Several components may be included in a
wellhead. For purposes of illustration, the wellhead 120
is simplified and includes only a BOP 126 and a tubing
head spool 128. The BOP 126 is a piece of wellhead
equipment that is well known in the art and its
construction and function do not form a part of this
invention. The BOP 126, the tubing head spool 128 and
the slips 124 are, therefore, not described. The tubing
string 122 is usually supported by a tubing hanger, not
shown, in the tubing head spool 128. The tubing
string 122 is therefore pulled out of the well to an
extent that a length of the tubing string 122 extending
above the wellhead 120 is greater than a length of the
BOP protector 10. The tubing string 122 is then
supported at the top of the BOP 126 using slips, for
example, before the installation procedure begins. Two
high pressure valves 130 and 132 are mounted to the
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threaded connectors 84, 86, preferably before the BOP
protector 10 is installed.
As illustrated in FIG. 3, the BOP protector 10
is suspended over t:he wellhead 122 by a crane or other
lift equipment (not. shown). The BOP protector 10 is
aligned with the tubing string 122 and lowered over the
tubing until the to~> end 134 of the tubing string 122
extends above the top end 88 of the sidewall 74.
FIG. 4 illustrates the next step of the
installation procedure. A tubing adapter 94 is first
connected to the top end 134 of the tubing string 122.
The tubing adapter 94 is then connected to the top of the
fracturing head. A high pressure valve 136 is mounted to
the tubing adapter 94 via the thread 104 on the
L5 sleeve 98. The tubing string 122 and the BOP
protector 10 are then lifted using a rig, for example, so
that the slips 124 can be removed. The rig lowers the
tubing string 122 anti the BOP protector 10 onto the top
of the BOP so that the base member 14 rests on the
BOP 126. The mandrel 28 is inserted from the top into to
the BOP 126 but remains above the BOP rams (not shown).
Persons skilled in the art will understand that in a high
pressure wellbore, the tubing string 122 is plugged and
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the rams of the BOP are closed around the tubing
string 122 before the installation procedure begins, so
that the fluids under pressure in the wellbore are not
permitted to escape from the tubing string or the annulus
between the tubing string and the wellhead 120.
To open the rams of the BOP 126 and further
insert the mandrel 28 down through the wellhead, the high
pressure valves 130, 132 and 136 must be closed and the
base member 14 mounted to the top of the BOP 126. The
packing rings 46 and all other seals between interfaces
of the connected parts, seal the central passage of the
BOP protector 10 against pressure leaks. The BOP rams
are now opened after the pressure is balanced across the
BOP rams. This procedure is well known in the art and is
not described. After the BOP rams are opened, the rig
further lowers the BOP protector 10 to move the mandrel
bottom end down through the BOP. The BOP protector 10 is
in an operative position where the sealing assembly 62 is
inserted into the casing 142. As noted above, the
extension sections) is optional and of variable length
so that the assembled mandrel 28, including the sealing
assembly 62, has adequate length to ensure that the
sealing assembly 62 is inserted into the casing 142. The
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lockdown nut 18 shown in FIG. 5, secures the mandrel 28
in the operative position against an upward fluid
pressure.
The BOP protector 10, in accordance with the
above-described embodiments of the invention, has
extensive applications in well treatments to stimulate
production. After the BOP protector 10 is installed to
the wellhead as illustrated in FIG. 5, a pressure test is
usually done by opening the tubing head spool side valve
to ensure that the BOP and the wellhead are properly
sealed. The high pressure lines (not shown) can be
hooked up to high pressure valves 130, 132 and 136 to
begin a wellhead stimulation treatment. A high pressure
well stimulation fluids can be pumped down through any
one or more of the three valves into the well. The
tubing string can also be used to pump a different fluid
or gas down into the well while other materials are
pumped down the casing annulus so that the fluids only
commingle downhole at the perforations area and are only
mixed in the well.
In the event of a "screen-out", the high
pressure valve 136 which controls the tubing string, may
be opened and hooked to the pit (not shown). This
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permits the tubing string 122 to be used as a well
evacuation string, so that the fluids can be pumped down
the annulus of the casing and up the tubing string to
clean and circulate proppants out of the wellbore. In
other applications for well stimulation treatment, the
tubing string 122 can be used as a dead string to measure
downhole pressure during a well fracturing process.
The tubing also can be used to spot acid in the
well. To prepare for a spot acid treatment, a lower
limit of the area to be acidized is blocked off with a
plug set in the well below a lower end of the tubing
string, if required. A predetermined quantity of acid is
then pumped down the tubing string to treat a portion of
the wellbore above the plug. The area to be acidized may
be further confined by a second plug set in the well
above the first plug. Acid may then be pumped under
pressure through the tubing string into the area between
the two plugs.
As will be understood by those skilled in the
art, coil tubing can be used for any of the stimulation
treatments described above. If coil tubing is used, it
is preferably run through a blast joint so that the coil
tubing is protected from abrasive proppants.
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FIG. 6 illustrates a configuration of the BOP
protector 10 in accordance with the invention that is
adapted to permit tubing to be run into or out of the
well. Coil tubing, which is well known in the art, is
particularly well adapted for this purpose. Coil tubing
is a jointless, flexible tubing available in variable
lengths. If tubing is to be run into or out of the well,
pressure containment is required. Accordingly, the
tubing adapter 394, in this embodiment, is different from
the tubing adapter 94 shown in FIGS. 1-5. The tubing
adapter 394 has a flange 396 with a threaded connector
392 for engaging the thread 90 on the top of the
fracturing head 35. The flange 396 is adapted to permit
a second BOP 326 to be mounted to a top of the fracturing
head 35. A blast joint 300, having a threaded top
end 301 engages a thread 302 so that the blast joint 300
is suspended from the tubing adapter 394. The blast
joint has a inner diameter large enough to permit the
coil tubing 322 to be run up and down therethrough. The
blast joint 300 protects the coil tubing 322 from erosion
when abrasive fluids are pumped through the radial
passages 80, 82 in the fracturing head 35. The coil
tubing 322 is supported, for example, by slips 324 or
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CA 02303058 2000-03-28
other supporting mechanisms to the top of the BOP 326.
As is understood by those skilled in the art, a
"stripper" for removing hydrocarbons from coil tubing
pulled out of the well may also be associated with the
second BOP 326.
If tubing is to be run in and out of the well
during a stimulation treatment, a third BOP, not shown,
may be required, as is also well known in the art. As is
well understood, the BOPS are operated in sequence
whenever the tubing is pulled from or inserted into the
well.
The method of installing the BOP protector 10
shown in FIG. 6, to permit tubing to be run into or out
of a well while protecting the BOP 126 on the wellhead
during a well stimulation treatment is described below.
The base member 14 is first mounted to the top of the BOP
126 while the bottom end of the mandrel is inserted from
the top into the BOP 126. The BOP 326 is closed and the
BOP 126 is opened after the pressure across the BOP 126
is equalized. The fracturing head 35 and attached BOP
326 are lowered to stroke the mandrel bottom end down
through the BOP 126. The lockdown nut 18 is screwed down
- 26 -
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when the mandrel 28 is in the operative position and the
sealing mechanism 62 is sealed inside the casing 142.
The apparatus in accordance with the invention
does not significantly restrict fluid flow along the
annulus of the casing or include components susceptible
to wash-out. More advantageously, the apparatus in
accordance with the invention enables an operator to move
the tubing string up and down or run tubing into and out
of a well without removing the apparatus from the
wellhead. A tubing string can also be moved up or down
in the well while stimulation fluids are being pumped
into the well, as will be understood by those skilled in
the art. The apparatus is especially well adapted for
use with coil tubing which provides a safer operation in
which there are no joints, no leaking connections and no
snubbing unit needed if it is run in under pressure.
Running coil tubing is also a faster operation that can
be used easier and less expensively in remote areas, such
as off-shore.
FIG. 7 schematically illustrates a sealing
assembly 62 in accordance with a preferred embodiment of
the invention inserted into the casing 142 of a
hydrocarbon well. The sealing assembly 62 includes a cup
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CA 02303058 2000-03-28
tool 402 which threadedly connects to the bottom end of
the mandrel 28 or a mandrel extension 52 (FIG. 1). The
cup tool 402 has a top end 404 with a diameter equal to a
diameter of the mandrel 28 and a bottom end 406 of a
smaller outer diameter. Located between the top end 404
and the bottom end 406 is a radial shoulder 408. A
cup 410 includes a resilient depending skirt 412, which
is typically formed with a rubber compound well known in
the art. The skirt 412 is bonded to a steel ring 414
that is axially slidable over the bottom end 406 of the
cup tool 402. A pair of 0-rings 416 provide a fluid seal
between the steel ring 414 and the bottom end 406 of the
cup tool 402. Located above the cup 410 is a resilient
compressible sealing element 420 and a gauge ring 422.
The cup 410, sealing element 420 and gauge ring 422 are
retained on the bottom end 406 of the cup tool 402 by a
bullnose 424 which threadedly engages threads 426 on the
bottom end 406 of the cup tool 402. The bullnose 426
guides the sealing assembly through the wellhead and
helps protect the resilient skirt 412 of the cup 410 from
damage when the tool is inserted through the wellhead
into the casing.
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CA 02303058 2000-03-28
When the sealing assembly 62 is inserted into
the casing 142 of a wellbore and exposed to fluid
pressures in the wellbore, the resilient skirt 412 of the
cup 410 is forced outwardly against the casing 142 and
the cup is forced upwardly against the resilient sealing
element 420. The resilient sealing element is compressed
against the gauge ring 422 and deforms radially against
the cup tool 402 and the casing 142 to provide a high
pressure fluid seal in the annulus between the sealing
assembly 62 and the casing 142.
Modifications and improvements to the
above-described embodiments of the invention, may become
apparent to those skilled in the art. For example,
although the mandrel head and the fracturing head are
shown and described as separate units, they may be
constructed as an integral unit. Many other
modifications may also be made.
The foregoing description is intended to
exemplary rather than limiting. The scope of the
invention is therefore intended to be limited solely by
the scope of the appended claims.
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