Note: Descriptions are shown in the official language in which they were submitted.
CA 02297600 2000-O1-28
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 or downhole tools
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 too=L is described in Applicant's United States
Patent No. 4,867,243, which issued September 19, 1989 and
is entitled WELLHEAD ISOLATION TOOL AND SET'rING TOOL AND
METHOD OF USING SAME. The length of the mandrel need not
be precise because the location of the pack-off assembly
in the production tubing or casing is immaterial, so long
as the park-off assembly is sealed against the inner wall
of the production tubing or casing. Consequently,
variations in the length of the wellhead of different oil
or gas we=Lls are of no consequence.
In an improved 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 Ocv~ober 13, 1998 and is entitled BLOWOUT PREVENTER
PROTECTOR FOR USE DURING HIGH-PRESSURE OIL/GAS WELL
STIMULATION. A further improvement of that tool is
described in App:licant's United States Patent
No. 6,247,.537 which issued on June 19, 2001 and is
entitled HIGH PRESStJRE FLUID SEAL FOR SEALING AGAINST A
BIT GUIDE IN A WELLHEAD AND METHOD OF USING SAME. The
mandrel described in this patent and pateni~ application
includes an annular sealing body attached to the bottom
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end of the mandrel for sealing against a bit guide which
is mounted on the top of a casing in the well_head.
This type of isolation tool advantageously
provides full access to a well casing and permits use of
downhole tools during a well stimulation treatment. A
mechanica:L lockdown mechanism for securing a mandrel
requiring fixed-point pack-off in the well is described
in Applicant's United States Patent No. 6,289,993 which
issued on September 18, 2001 and is entitled BLOWOUT
PREVENTER PROTECTOR AND SETTING TOOL. The mechanical
lockdown mechanism has an axial adjusting length adequate
to compensate for variations in a distance between a top
of the blowout preventer and iehe top of the casing of the
different wellheads to permit the mandrel t=o be secured
in the operative position even if a length of a mandrel
is not precisely matched with a particular wellhead. The
mechanical lockdown mechanism secures the mandrel against
the bit guide to maintain a fluid seal but does not
restrain the mandrel from downwards movement. The force
exerted cn the annular sealing body between the bottom
end of the mandrel and the bit. guide results from a
combination of the weight of
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the isolation tool and attached valves and fittings, a
force applied by the lockdown mechanism and an upward
force exerted by fluid pressures acting on the mandrel.
The wellhead isolation tools described in the
above patents and patent applications work well and are
in significant demand. However, it is also desirable
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
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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
tubing and the casing in an oil 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 in the
sealing nipple between the central and outer mandrels.
The sealing nipple also blocks the 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 stimulation 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.
Therefore, there exists a need for an improved
isolation tool which is adapted for use with a tubing
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string to be left in the well, or run into or out of the
well during a well stimulation treatment.
SUMMARY OF THE INVENTION
It is an object of the invention to provide a
BOP protector which is adapted to support a tubing string
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
CA 02297600 2000-O1-28
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 an annular sealing body
for sealing engagement with a bit guide at a top of a
casing of the well when the mandrel is in the operative
position. A base member is 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
a fixed position to inhibit upward movement of the
mandrel induced by fluid pressures in the wellbore and
downward movement of the mandrel induced by a weight of
the tubing string supported by the tubing adapter.
The apparatus preferably includes a mandrel
head affixed to the mandrel top end and the fracturing
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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 and a load transferring mechanism for
transferring a substantial part of the weight of the
tubing string from the mandrel head to the wellhead to
protect the sealing body from the entire weight of the
tubing string when the tubing string is supported by the
tubing adapter.
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
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 mandrel head includes
a spiral thread for operatively engaging a load transfer
nut that is adapted to be rotated down so that a head of
the load transfer nut rests against a top of the lockdown
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nut to transfer the weight of the tubing string from the
mandrel head to the base member.
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
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
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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 blowout preventer, and adjusting a lock
mechanism until the mandrel is in an operative position
in which the annular sealing body is in fluid sealing
engagement with a bit guide mounted to a top of the
casing of the well;
f) adjusting the lock mechanism to lock the
mandrel in the operative position and to transfer weight
of the tubing string and the apparatus to the wellhead so
that the sealing body is not compressed against the bit
guide by a full weight of the tubing string.
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
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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 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 blowout preventer,
and adjusting a lock mechanism until the mandrel is in an
operative position in which the annular sealing body is
in fluid sealing engagement with a bit guide mounted to a
top of the casing of the well;
e) adjusting the lock mechanism to lock the
mandrel in the operative position and to transfer weight
of the tubing string and the apparatus to the wellhead so
that the sealing body will not be compressed against the
bit guide by a full weight of the tubing string; and
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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.
A further advantage of the invention is to
permit a maximum flow rate into the well during a
stimulation treatment because the mandrel has a diameter
at least as large as that of the casing of the well.
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 illustrating a further step in
the installation procedure, in which the mandrel of the
BOP protector is inserted through the wellhead and locked
in an operative position;
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FIG. 6 is a cross-sectional view of the BOP
protector shown in FIG. 5 illustrating a final step in
the installation procedure, in which a load transfer nut
is tightened to complete the installation;
FIG. 7 shows an alternate embodiment of the
lockdown mechanism for the BOP protector shown in FIG. 1;
FIG. 8 shows another alternate embodiment of
the lockdown mechanism for the BOP protector shown in
FIG. 1;
FIG. 9 is a partial cross-sectional view of a
first embodiment of an annular sealing body fused to the
bottom end of the mandrel of the BOP protector (shown in
FIG. 1) for sealing against a bit guide in a wellhead;
FIG. 10 is a partial cross-sectional view of an
alternate embodiment of an annular sealing body for
sealing against a bit guide in a wellhead; and
FIG. 11 is a partial cross-sectional view of a
BOP protector in accordance with the invention, showing a
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.
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DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT
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 base member 14. A
spiral thread 22 is provided on an exterior of the
integral sleeve 20. The spiral thread 22 is engageable
with 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 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
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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
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
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mandrel 28 is inserted into the BOP, as will be described
below with reference to FIGS. 5 and 6.
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 mandrel pack-off assembly 62,
which will be described below in more detail. High
pressure 0-ring seals 64, well known in the art, provide
a high pressure fluid seal in the threaded connectors
between the mandrel 28, the optional mandrel
extensions) 52 and the mandrel pack-off assembly 62.
The mandrel 28, the mandrel extension 52 and
the mandrel pack-off assembly 62 are preferably each made
from 4140 steel, a high-strength steel which is
commercially available. 4140 steel has a high tensile
strength and a Burnell hardness of about 300.
Consequently, the assembled mandrel 28 is adequately
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robust to contain extremely high fluid pressures of up to
15,000 psi, which approaches the burst pressure of the
well casing. In order to support an annular sealing
body 66, however, the walls of the mandrel pack-off
assembly 62 are preferably about 1.75" (4.45cm) thick.
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 the threaded
connector 92 of one embodiment of a tubing adaptor 94, in
accordance with the invention. The tubing adapter 94
includes a flange 96, a threaded connector 92 and a
sleeve 98. The tubing adapter 94 also includes a central
passage 100 with the threads 102 thereon for detachably
connecting a tubing joint of a tubing string. A spiral
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thread 104 is provided on the exterior of the sleeve 98
and adapted for connecting other equipment, for example,
a high pressure valve.
A spiral thread 106 is provided on the
periphery of the top flange 34 of the mandrel head 16.
The spiral thread 106 engages a complimentary spiral
thread 108 of a load transfer nut 110. The load transfer
nut 110 includes a bottom flange 112 that rests on the
top flange 38 of the lockdown nut 18 to transfer a weight
of a tubing string from the fracturing head 35 to the
base member 14 when the load transfer nut 110 is rotated
downwardly. Rotating the load transfer nut 110 upwards,
releases the lockdown nut 18 to permit free rotation of
the lockdown nut 18. A plurality of handles 114, only
two of which are shown, are preferably attached to a
periphery of the load transfer nut 110. The handles 114
facilitate rotation of the load transfer nut 110.
The mandrel head 16 with its upper and lower
flanges 34, 36, the lockdown nut 18 with its top
flange 38 and the load transfer nut 110 with its bottom
flange 112 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
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understand that any one of the mandrel head 16, the
lockdown nut 18 or the load transfer nut 110 may be
constructed to permit the mandrel head 16, the lockdown
nut 18 or the load transfer nut 110 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 sections) 52 and the pack-off
assembly 62 to provide a total length of the mandrel 16
required for a particular wellhead. The load transfer
nut 110 is rotated upwardly and the lockdown nut is
disengaged from the integral sleeve 20 of the base
member 14 because the mandrel 28 is to be inserted into
the wellhead while the base member is mounted to the top
end of the BOP.
FIGS. 3 through 6, 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
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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
threaded connectors 84, 86, preferably before the BOP
protector 10 is installed.
As illustrated in FIG. 3, the BOP protector 10
is suspended over the 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 top end 134 of the tubing string 122
extends above the top end 88 of the sidewall 74.
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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 134 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 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 and 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
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
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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. When the BOP
protector 10 is in an operative position in which the
bottom end of the pack-off assembly 62 is in sealing
contact with a bit guide 140 attached to a top of a
casing 142 (FIG. 5). The bit guide 140 caps the
casing 142 to protect the top end of the casing 142 and
provides a seal between the casing 142 and the tubing
head spool 128, in a manner well-known in the art. As
noted above, the extension sections) is optional and of
variable length so that the assembled mandrel 28,
including the pack-off assembly 62, has adequate length
to ensure that the top end of the mandrel 28 extends
above the top of the BOP 74, just enough to enable the
mandrel to be secured by the lockdown assembly 12,
described above, when the pack-off assembly 62 is seated
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against the bit guide 142. However, the distance from
the top of the bit guide 140 to the top of the BOP 126,
may vary to some extent in different wellheads.
In accordance with the invention, the
mechanical lockdown mechanism 12 is configured to provide
a broad range of adjustment to compensate for variations
in the distance from the top of the BOP 126 to the top
end 40 of the mandrel 28, which is described with
reference to FIGS. 7 and 8. The complimentary spiral
threads 22, 24 on the respective integral sleeve 20 and
lockdown nut 18, have a length adequate to provide the
required compensation. Preferably, the respective
threads 22, 24 are at least about 9" (22.86cm) in axial
length. A minimum engagement for safely containing the
elevated fluid pressures acting on the BOP protector 10
during a well treatment to stimulate production is
represented by a section labelled "A". Sections "B"
represent the adjustment available to compensate for
variations in the distance from the top of the BOP 126 to
the top end 40 of the mandrel 28. A spiral thread with
about 9" of axial length provides about 5" of adjustment
while ensuring that a minimum engagement of the lockdown
nut 18 is maintained.
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The lockdown nut 18 shown in FIC~. 5, secures
the mandr~=_1 28 in the operative ~>osit:ion only against an
upward fluid pressure and, therefore, does not stop the
mandrel from moving downwardly under a downward force,
such as the weight of the tubing string 122 which is
transferred to the mandrel 28 through the fracturing head
35 and the mandrel head 16 when the tubing string is
unhooked from the rig. As illustrated in FIG. 6, the
load transfer nut 110 is rotated down until the bottom
flange 11.2 firmly rests on the top flange 38 of the
lockdown nut 18. Therefore, the tubing adapter 94,
fracturing head 35, the mandrel head 16 and the base
member 14,. cooperate to support the weight of the 1=ubing
string 122 and transfer the load to the wel lhead 12 0, so
that the mandrel 28, the pack-off assembly 6'? and the bit
guide 140 do not bear the weight of the tubing
string 122. The installation procedure of the BOP
protector 10 is thereby completed and the installed
apparatus,, as shown in FIG. 6, is ready for various types
of well treatment to stimulate production. As described
in Applicant's United States Patent No. 6,289,993, the
base member 14 includes ~t least
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two connection points 150 for attaching an insertion tool
used when a rig is not required to mount the BOP
protector 10 to a wellhead.
As noted above, FIGs. 7 and 8 illustrate two
alternate embodiments of the mechanical lockdown
mechanism 12 in accordance with the invention. In
FIG. 7, the spiral thread 24 on the lockdown 18 has an
axial extent "A" to ensure the minimum engagement
required for safety and the thread 22 on the integral
sleeve 20 of the base member 14 has a full length spiral
thread which includes the "A" section for the minimum
engagement and the "B" for adjustment. The mechanical
lockdown mechanism 12, illustrated in FIG. 8, provides a
similar adjustable lockdown with length "A" for minimum
safe threaded engagement on the integral sleeve 20 and
length "B" for adjustment on the lockdown nut 18.
A second mechanical locking mechanism may be
added to advantageously improve the range of adjustment
of the lockdown mechanism, so that the length of a
mandrel may be less precisely matched to the distance
from the top of the well to the fixed-point pack-off
position in the well. The embodiment with the second
mechanical lock-down mechanism is described in
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Applican't's co-pending United States Patent No. 6, 179, 053
which is entitled M:EC:HANISM FOR WELL TOOLS REQUZRTNG
FIXED-POINT PACKOFF and issued on January 30, 2001.
FIGS. 9 and 10 illustrate the pack-off
assembly 62 in accordance with alternate embodiments of
the invention. The pack-off assembly 62, illustrated in
FIGS . 9 arzd 10, may be used for the BOP protector 10 to
improve performance, a.s descri.bed in Applic:ant's United
States Patent: No. 6,247,537. In FIG. 9, a high pressure
~.0 seal 198 is z~n elastom~~ric material, preferably a plastic
matErial such as polyFahylene or a rubber compound such
as nitryl rubber. 'I he elastomeric rlaterial preferably
has a hardness of about 80 to about 100 durometer. The
high pressures fluid seal 198 is bonded directly to 'the
1:~ bottom end of the pack-off assembly 62. The bottom end
of the pack-off assembly 62 includes at least one
downwardly protrudincx annular ridge 200, which provides
an area of increased compression of the high pressure
fluid seal 1!~B in an area preferably adjacent to an outer
20 wall 202 of
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CA 02297600 2000-O1-28
the pack-off assembly 62. The annular ridge 200 not only
provides an area of increased compression, it also
inhibits extrusion of the high pressure fluid seal 198
from a space between the pack-off assembly 62 and the bit
guide 142 when the mandrel 28 is exposed to extreme fluid
pressures. The annular ridge 200 likewise helps to
ensure that the high pressure fluid seal 198 securely
seats against the bit guide 142 even if the bit guide 142
is worn due to impact and abrasion resulting from the
movement of the production tubing or well tools into or
out of the casing 140. A pair of O-rings 204 are
preferably provided as backup seals to further ensure
wellhead components are isolated from pressurized
stimulation fluids.
The pack-off assembly 62, illustrated in
FIG. 10, has an inner wall 206 which extends downwardly
past the bit guide 142 and a top edge of the casing 140
into an annulus of the casing 140. High pressure fluid
seal 208 is particularly designed for use in wellheads
where the bit guide 142 does not closely conform to the
top edge of the casing 140, leaving a gap 210 in at least
one area of a circumference of a joint between the casing
140 and the bit guide 142. The gap makes the top edge of
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the casing 140 susceptible to erosion called "wash-out"
if large volumes of abrasives are injected into the well
during a well stimulation process. The pack-off
assembly 62, in accordance with this embodiment of the
invention, covers any gaps at the top of the casing 140
to prevent wash-out. The length of the inner wall 206 is
a matter of design choice.
As noted above, the high pressure fluid
seal 208 is bonded directly to the end 212 of the
pack-off assembly 62, using techniques well-known in the
art. The high pressure fluid seal 208 covers an outer
wall portion 220 of the inner wall 206. It also covers a
portion of an outer wall 222 located above the end 212.
A bottom end of the outer wall 222 of the pack-off
assembly 62 protrudes downwardly in an annular ridge 224,
as described above, to provide extra compression of the
high pressure fluid seal 208 to ensure that the high
pressure fluid seal 208 is not extruded from a space
between the pack-off assembly 62 and the bit guide 142
when the high pressure fluid seal 208 is securely seated
against the top surface of the bit guide 142.
The BOP protector 10, in accordance with the
above-described embodiments of the invention, has
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extensive applications in well treatments to stimulate
production. After the BOP protector 10 is installed to
the wellhead as illustrated in FIG. 6, 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 value 136 which controls the tubing string, may
be opened and hooked to the pit. This 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
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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.
FIG. 11 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
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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. 1-6. 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
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.
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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. 11, 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
until the mandrel 28 is in the operative position and the
annular sealing body is sealed against the bit guide (not
shown). The load transfer nut 110 is then rotated down
to firmly rest on the lockdown nut 18 so that the weight
of the coil tubing is run into the well.
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The apparatus in accordance with the invention
does not 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 coil 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.
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.
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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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