Note: Descriptions are shown in the official language in which they were submitted.
'r
CA 02211835 1997-07-29
1 SOP2CA
METHODS OF AND APPARATUS FOR INSERTING
PIPES AND TOOLS INTO WELLS
The present invention relates to methods and apparatus for inserting pipes
and/or tools into
live well bore while maintaining pressure in the well bores and, also, to
snubbing jack
assemblies for use therein.
All snubbing or live well operations require blowout preventors (BOPs) or
other sealing
devices to maintain the well pressure while operations take place. A standard
blowout
preventor configuration includes, from the bottom up, a double-gate BOP
complete with
blind rams that shut the flow of the well off in the event that there is no
pipe or tools in the
well bore; a set of pipe rams directly above the blind rams, within an double-
gate BOP, that
seals off the flow of the well in the event that there is pipe in it; a single
gate stripping ram
preventor, which is used when pipe is in the well and which is necessary to
install tools into
the well bore and/or land the tubing hanger into the well head; an equalizing
spool complete
with two ports and valuing off each port for equalizing and bleeding off the
pressure from
with in the BOP configuration; and an annular BOP installed on the top of the
equalizing
spool. The annular blowout preventor is for sealing around the pipe while the
pipe being
inserted into the well, as well as sealing around non-standard shapes of
tools, etc.
Such tools may, for example, comprise bottom hole assemblies comprising
combinations of
different tools, which are site-specific, e.g. for setting-up wells and,
performing remedial
maintenance prior to actual production for assisting in the production of
hydro-carbons from
CA 02211835 1997-07-29
-2-
the wells. Plugs, packers, nipples, sleeves and blast joints are just some of
the many tools
that may be required in a typical bottom hole assembly. A single zone well may
require
nothing more than a profiled nipple with a plug in place to seal the flow of
the fluid or gas
from flowing up the tubing while it is being installed into the well while
maintaining the well
pressure at surface. When the tubing has been positioned to the desirable
depth in the well
and landed into the well head, the plug is recovered from the nipple, allowing
flow up the
tubing. The nipple may later be used to suspend pressure recorders (tools) in
the well to
monitor pressures of the zone while in a static and or flowing position. A
dual-zoned well
typically requires a nipple and plug to stop the flow during insertion of
production tubing as
well as a packer, a sliding sleeve and possibly a blast joint. The packer
serves as a sealing
device to segregate the two zones, so the top zone can be produced up the
casing or annulus
(the space between the tubing and casing) and the lower zone produced up the
tubing
simultaneously. The sliding sleeve functions as a device to be able to
equalize differential
pressures between the zones to assist in pulling or retrieving tools (plugs,
pressure recorders
etc.) from the profiled nipple as well as establishing communication between
the tubing and
casing to flow back or displace fluid, gas and or other materials from the top
zone (above the
packer) up the tubing. Because of the smaller inside diameter and ultimately
the volume
required to fill the tubing, a more desirable flow rate and pressure can
typically be
maintained while the flow back is taking place. Many zones have high static
(shut in)
pressures, but don't necessarily produce the volume required to fill larger
areas such as the
annulus fast enough to establish desirable a rate of flow. Many formations can
be severely
and irreversibly damaged when the pressure from the producing zone is flowed
back at a rate
faster then that of which the hydro-carbons can pass through the zone (rock,
sand, clay etc.)
drawing in water or oil from below the zone and restricting flow. The blast
joint may serve
as a tool to protect the tubing from the erosive effects the flow of fluid
and/or particles of
sand etc. in to the annulus.
The conventional method of lubricating or stripping-in, i.e insertion into a
live well through
the well head, is achieved by closing the stripping rams around the pipe, then
bleeding off
the pressure above. The annular BOP is then opened and the pipe and the tool
assembly are
CA 02211835 2000-11-02
-3-
lowered (i.e. the pipe is stripped through the stripping rams) into a space
provided between
the stripping rams and the annular BOP. When the tool assembly is in position,
the annular
BOP is closed and the pressure is equalized between the stripping rams and the
annular BOP.
T'he stripping rams are then opened. Normal operations then continue until the
job has been
completed.
In the event that the tools required to be lubricated or stripped into the
well are longer than
the space available in a conventional BOP configuration, an extended
lubricating spool is
installed to facilitate them.
Summary of the Invention
It is an object of the present invention to provide a novel and advantageous
method and
apparatus which eliminate the need for a stripping BOP in the equipment
described above,
as well as any need for an extended lubricating spool, in most basic live well
applications.
According to one aspect of the present invention, a chamber is provided
between upper and
lower blowout preventors or other sealing devices which is telescopically
extendible and a
pressure equalizing duct is provided for interconnecting the chamber and a
well bore.
The telescopic chamber may of any suitable length, depending on the
application. Tools to
be lubricated or stripped into the well may be anywhere along the string of
the pipe,
depending on the application. Generally, tools are connected at the bottom of
a first joint of
tubing, before it is inserted into the well bore, or on the top of the tubing
string to suspend
the pipe at a well head.
According to another aspect of the present invention, there is provided a
method of inserting
a pipe into a live well bore through upper and lower sealing devices at upper
and lower ends
of a vertically telescopically extensible and retractable housing, the method
comprising the
steps of maintaining pressure in the well bore by closure of the lower sealing
device; feeding
CA 02211835 2000-11-02
-4-
the pipe downwardly towards the well bore; telescopically extending the
housing vertically
along the pipe and raising the upper sealing device along the pipe; closing
the upper sealing
device into sealing engagement with the pipe; equalizing pressure in the
housing with the
pressure in the well bore; opening the lower sealing device; and vertically
contracting the
housing and lowering the pipe past the lower sealing device.
Preferably tools are firstly positioned just above the upper sealing device,
e.g. an annular
BOP. Safety pipe or the blind rams in the lower sealing device, e.g. a double
gate BOP, are
closed and pressure is bled off above (depending on whether or not there is
pipe in the well).
With the annular BOP open, the telescopic chamber, is then extended, creating
lubricating
space to house or accommodate a portion of the pipe and/or tools. The annular
BOP actually
moves in an upward direction to a position above the tools, thus lubricating
(housing) the
tools inside the telescopic chamber. If the tools being run in the well are
attached to the end
of the pipe (vs. a point in the string other than the end), the chamber would
be fully extended
and the tools lowered into the chamber. The annular BOP is then closed into
sealing
engagement with the pipe above the tools. The pressure is equalized on both
sides of rams
in the double-gate BOP, the rams are opened, and the tools are then lowered
into the well.
Once the tools are clear of the BOPs, the telescopic spool is contracted back
to its original
position.
The benefits to this method according to the present invention, as compared to
conventional
prior art methods, is that the pipe never moves inside the BOPS while rams are
closed,
eliminating any need for a stripping BOP or for an extended lubricating spool.
This
significantly reduces the working height of the overall operation. When an
extended
lubricating spool is required for conventional lubricating applications for
long tool
assemblies, it is normally left in position until the completion of the job
because of the extra
time and money associated with its removal. The present telescopic cylinder
provides this
extended lubricating space without the extra height required to install the
conventional
extended lubricating spool.
CA 02211835 2000-11-02
-$-
In a preferred embodiment of the present apparatus, a hydraulic snubbing jack
is provided
above the telescopic chamber for snubbing the pipe through the apparatus, and
the telescopic
chamber is hydraulically extensible and contractible.
For example, the telescopic chamber may be in the form of a hydraulically
extendible
telescopic cylinder with a outside diameter of 12 -16 inches and an internal
inside diameter
of appropriate size (normally 7 1/16 inches through-bore in most operations).
The outside
diameter is determined by the size of the internal piston required and the
hydraulic operating
pressures at which the telescopic cylinder will operate, which are all
relative to the lift and
push forces for which the telescopic cylinder is designed. The overall length
of the cylinder
when contracted is desirably five to eight feet, for practical reasons.
Extended, the telescopic
cylinder would measure approximately nine to fifteen feet in length.
This equipment preferably stands approximately seven to eight feet tall, when
contracted,
using a five foot cylinder and is mounted directly on top of a standard double-
gate BOP in
the lower sealing device and which, in turn, is attached to the wellhead. This
relatively small
height is one of the advantages provided by the present invention in contrast
to the shortest
conventional snubbing unit in use at the present time, which are twelve and a
half to sixteen
feet in length, measured from the bottom of the equalizing spool of the top
set of slips.
The telescoping action of the cylinder, in conjunction with upper and lower
slips, functions
to firstly grip the pipe with the lower slips. Then, after extending the
telescopic cylinder
upwardly and gripping the pipe with the upper slips, the lower slips are
released and the
cylinder is contracted, which lowers or forces the pipe into the well.
When a tool on the pipe is required to be inserted into the well, it is
located just above an
annular BOP, forming the upper sealing device, with the latter closed, safety
rams in the
double-gate BOP are closed and the pressure is bled off between them and the
annular BOP.
CA 02211835 2000-11-02
-6-
The annular BOP is opened, the telescopic cylinder is extended over top of the
tool. The
annular BOP is closed, the pressure is equalized and the tool is lowered into
the well.
The present method and apparatus make it possible to perform all operations
from reasonable
working heights with less rig-up time. The complete apparatus will fit through
a standard
opening in a service rig work floor or substructure on a drilling rig. Under
normal
conditions, the present apparatus will allow rig crews to take their places on
the rig floor
when inserting pipe into wells. Because of the inherent danger of working high
in the air,
as well as standing directly over top of a pressured well, oil companies and
rig contractors
generally rely on specially trained personnel to perform these tasks. The
present invention
eliminates any need for an extra man (a specialized snubbing assistant),
better utilizes
existing rig personnel, and is much safer because of the reduced working
heights and because
the operator stands away from the well bore and can operate the equipment
remotely . In
case of equipment failures, no persons are in the direct line of fire from
escaping high-
pressure gas, fluid and/or pipe.
Brief Description of the Drawings
The present invention will more readily understood by those skilled in the art
from the
following description thereof taken in conjunction with the accompanying
diagrammatic
drawings, in which:-
Figures 1 through 7 show successive steps in the insertion of a tool assembly
into a live well
through a conventional prior art snubbing configuration;
Figures 8 through 13 show successive steps in the insertion of a tool assembly
into a live well
through a snubbing configuration according to a first embodiment of the
present invention;
CA 02211835 1997-07-29
_7-
Figures 14 and 15 show diagrammatic views taken in longitudinal section
through a
snubbing configuration, according to the present invention, in a retracted
condition and an
extended condition, respectively;
Figure 16 shows a view in longitudinal cross-section through a snubbing slip
assembly
forming part of the configuration of Figures 14 and 15; and
Figures 17 through 27 show successive stages in the insertion of a tool
assembly into a live
well through the snubbing configuration of Figures 14 and 15.
In the accompanying drawings, Figure 1 illustrates a conventional snubbing
configuration,
indicated generally by reference numeral 10, with a work floor 11 that would
normally be
provided on top of a conventional hydraulic snubbing unit (jack) indicated
generally by
reference numeral 18. Elevators 14 are used to hold a pipe 16 while raising or
lowering the
pipe 16. The hydraulic snubbing jack 18 includes two sets of inverted (upside-
down) slips
and 22 that grip the pipe.
20 During snubbing operations, the jack 18 operates with a hand-over-hand
motion. The lower
slips 22 are closed to grip the pipe in a stationary positions. The upper
slips 20 are the
opened and the jack 18 is extended upward to the top of stroke of its cylinder
24. The upper
slips 20 are then closed, and the jack 18 is hydraulically forced downward,
which forces the
pipe 16 into a well bore 26. The lower slips 22 are opened when the upper
slips 20 have
control of the pipe 16. This action is continued until the pipe 16 reaches a
heavy position in
the well bore 26, i.e. a point where the weight of the pipe overcomes the
hydraulic effect of
the well pressure on the cross-sectional area of the pipe. The lower end of
the pipe 16 is
always plugged-off.
CA 02211835 1997-07-29
_g_
An upper BOP in the form of an annular BOP (blowout preventor) or stripping
head
indicated generally by reference numeral 28 comprises a steel-bodied assembly
with a rubber
sealing element 30, which is hydraulically actuated and which seals around the
outside of the
pipe 16 to maintain well pressure below the sealing element 30. Some stripping
heads are
designed to be hydraulically activated by the force of the well pressure
across the area of the
element. In that case, the greater the well pressure, the greater the
resultant force and, thus,
the better the seal around the pipe 16.
An equalizing spool indicated generally by reference numeral 32 is flanged on
each end to
connect to other wellhead or blowout preventor components. Various connecting
systems
are available for these components, e.g so-called Greylock Hubs. The spool 32
has two ports
(not shown-one on each side) with valves 34, 36 on these ports. Valve 34 is
used to equalize
the pressure between two BOPS; the other valve 36 is used to bleed off the
pressure between
the two BOPS as described below. In Fig. l, a bleed-off line 38 is shown
leading from the
valve 36 to a tank 40 located away from the well bore 26 at a location where
gas could be
safely dispersed. The valves 34 and 36 are either manually or hydraulically
actuated.
A single-gate stripping BOP, which is indicated generally by reference numeral
42, is
hydraulically actuated. The BOP 42 has opposing sealing rams 44 with inserts
(not shown),
for which Nylon or Garlock is the typical material used. The rams 44 are
specifically sized
to conform to the nominal size of the of the pipe 16 being installed in the
well bore 26.
When the rams 44 are closed on the pipe 16, the pressure is sealed below and
the pipe can
be moved up or down between couplings (not shown), i.e. locations at which one
pipe
section or tube connects to another.
An hydraulically actuated lower blowout preventor in the form of a double-gate
BOP,
indicated generally by reference numeral 46, has two sets of sealing rams 48
and 50. The top
set of sealing rams 48 are the safety pipe rams, and are specifically sized to
fit the pipe size,
but are not intended for moving the pipe 16 through them on a regular basis.
The purpose
of these rams 48 is to seal off the well pressure below and to secure the well
bore 26 when
CA 02211835 1997-07-29
-9-
there is pipe in it. In case of any equipment failure above these rams 48 ,
they are the only
safety mechanism to maintain control of the well pressure. Therefore, the rams
48 are
commonly referred to as safety rams. The lower set of rams 50 are blind rams
used to close
in and maintain control of the well bore 26 when there is no pipe in it.
A standard wellhead in the form of a casing bowl 52 is attached to a
production casing 54
which runs the total depth of the well bore 26. The casing bowl 52 has two
ports with two
valves 56 and 58, one attached to each port. The valves 56 and 58 are intended
to provide
access to the well bore 26 for production and/or remedial purposes. In this
application, the
valve 56 is used to attach a line 60 extending from the casing bowl 52 to the
equalizing spool
32.
Fig. 2 shows the snubbing configuration 10 with the work floor 11 omitted for
simplicity.
The jack 18 is in the raised position with both sets of slips 20 and 22
closed. The pipe 16
and a tool assembly 61 have been lowered mechanically to the top of the blind
rams 50. The
blind rams 50 are closed and there is well pressure below. The annular BOP 28
is closed and
the BOPS are ready to be equalized.
In Fig. 3, an extended lubricating spool 62 has been installed between the
annular BOP 28
and the equalizing spool 32. This spool 62 provides adequate space between the
stripping
rams 44 and the annular BOP 28 for the tool assembly 61 as shown in Fig. 4 to
be run into
the well bore 26. The pressure is seen below the blind rams 50.
In Fig. 4, the pressure has been equalized through the valves 56 and 34 from
the bottom of
the blind rams 50 around to the top of the blind rams 50 and is maintained
internally by the
annular BOP 28. With equal pressure on both sides of the blind rams 50, they
can be opened
with a static condition throughout the BOP stack. The pipe 16 has been snubbed
into the
well bore 26 to a point where the tool assembly 61 in the string of pipe is
shown above the
jack 18 and just below the elevators 14 .
CA 02211835 1997-07-29
- 10-
In Fig. 5, the stripping rams have been closed and the pressure bled off above
into the tank
40. The annular BOP 28 is then opened and the tool assembly 61 is lowered into
the BOP
stack. The pipe 16 is lowered mechanically or snubbed into the well bore 26
depending on
where the tool assembly 61 is located in the tubing string forming the pipe
16. In this case,
we will assume that it is lowered conventionally as it will make no difference
to the
lubricating procedure.
In Fig. 6, the annular BOP 28 is closed and the pressure is equalized between
the stripping
rams 44 and the annular BOP 28. The stripping rams 44 are then opened and the
pipe 16 and
tools 61 can now be lowered into the well.
In Fig. 7, the pipe 16 is stripped through the annular BOP 28 to whatever
depth in the well
bore 26 is desired. A similar lubricating procedure would be used to land the
tubing in the
well head.
Fig. 8 shows a diagrammatic view of a modification, indicated generally by
reference
numeral l0a according to the present invention, of the conventional snubbing
configuration
10. For convenience, parts of the snubbing configuration l0a which correspond
to those
shown in Figs. 1 through 7 have been indicated by the same reference numerals.
According
to the present invention, the modified snubbing configuration l0a includes a
telescopic
chamber in the form of a hydraulically telescopically extensible spool, which
is indicated
generally by reference numeral 70 and which replaces the solid extended
lubricating spool
62 and the single gate stripping BOP 42 shown in Figs. 2 to 7.
Fig. 9 shows a view corresponding to Fig. 4, with the telescopic spool 70 in a
contracted
position and with the tools 61 positioned just above the annular BOP 28.
CA 02211835 1997-07-29
-11-
In Fig. 10, the safety pipe rams 48 are closed into sealing engagement with
the pipe, and the
pressure has been bled off between the rams 48 and the annular BOP 28, which
has then been
opened. The spool 70 is extended upwardly so that the annular BOP 28 is
located over top
of the tools 61, thus accommodating them inside a lubricating cavity or
chamber 72. The
S tools 61 in this case do not have to be lowered or moved into position while
the safety rams
48 closed on the pipe 16 are controlling the pressure.
The annular BOP 28 is then closed, as shown in Fig. 11, and the pressure is
equalized
through the valves 56 and 34 from below the safety rams 48 to the space
extending from
above the safety rams 48 and below the annular BOP 28. With this pressure
equalized, the
safety pipe rams 48 are opened (Fig. 12) and the pipe 16 and tools 61 are
ready to be lowered
into the well bore.
In Fig. 13, the string has been lowered below the surface and the telescopic
hydraulic spool
70 is fully lowered or contracted, thus lowering the overall working height to
a more
desirable level.
Fig. 14 shows a second embodiment of the present invention, which comprises a
telescopic
hydraulic snubbing jack assembly which is indicated generally by reference
numeral 71 and
which comprises, from its top down:-
a) An upper sealing device in the form of an annular BOP or stripping head
28a;
b) A flanged or Greylock Hub connection 74;
c) An upper snubbing slip assembly indicated generally by reference numeral
76. The connection 74 connects the annular BOP 28 to the slip assembly 76,
which has a through-bore consistent with that of the blowout preventors.
CA 02211835 1997-07-29
-12-
d) A telescopically extendible chamber in the form of a hydraulic cylinder or
jack 70a, which has a nominal through-bore 80 extending its entire length.
A standard 7 1/16 bore is considered normal for most well applications, but
the bore 80 may range from 4 1/16 to whatever size is warranted for a
specific application. The outside diameter is site specific to the piston size
needed to power the cylinder. The piston size determines the lift and push
forces needed to handle the application which the equipment is intended. The
operating hydraulic fluid pressures are also a factor in determining the lift
and
push capacities of the cylinder.
e) A lower slip assembly indicated generally by reference numeral 85 at the
lower end of the cylinder 70. The cylinder 70 has flanged or Greylock
connecting systems 82 and 84 at opposite ends to connect the slip assembly
76 and the slip assembly 85.
fJ An equalizer and bleed-off spool indicated generally by reference numeral
32a, provided with flanged or Greylock connecting systems 86 and 88 at
opposite ends. The spool 32a has ports at opposite sides provided with
valves 90 and 92 corresponding to the valves 34 and 36 of Fig. 1.
This configuration should be considered as preferred, although any suitable
combination or
arrangements of blowout preventors and slips may be used in different
embodiment of the
present invention.
As shown in Fig. 15, the cylinder 70a is connected by hydraulic pressure and
return lines 99
and a manifold 96 to an hydraulic pump 98 connected to a tank 95 for
containing a supply
of hydraulic fluid, the manifold 96 being provided with valves 83 controlling
the flow of
hydraulic fluid under pressure to and from the cylinder 70a and, thus, for
extending and
retracting the cylinder 70a. For convenience, the hydraulic lines 99, the
manifold 96, the
CA 02211835 1997-07-29
-13-
pump 98, the tank 95 and the valves have been omitted from Figs. 17 through
26. A similar
hydraulic system (not shown) is provided in the embodiments of Figs. 8 through
13.
The cylinder 70a, as will be apparent from the following description, serves
both to form an
extendible housing, like the cylinder 70 of Figs. 8 through 13, for receiving
a tool assembly
61, and also as an hydraulic jack which serves to raise and lower the annular
BOP 28a and,
thus, which replaces the jacking assembly 18 shown in Figs. 1 through 13.
Fig. 15 shows the cylinder 70a extended, with pipe 16a running through the
through-bore for
the length of the entire assembly.
The snubbing slip assembly 76, as shown in Fig. 16, comprises a cylindrical
main body 63,
much the same as a spool with opposing flanged ends 65 to connect and
integrate the slip
assembly into the jack assembly 71. The main body 63 has opposed cylindrical
projection
67 incorporated into the sides of the main body of the slips that each serve
as a chamber to
house a piston 69 with rod 69a. Any suitable number of these projections 67
may be
provided and, in a standard configuration, four projections 67 are provided.
However, to
facilitate the illustration of the present embodiment of the invention, Fig.
16 shows only two
opposed chambers 67. On the inside end of the rod 69a a manufactured block or
slip body
73 is mechanically attached and designed to receive a slip die. The blocks 73
and dies are
replaceable to facilitate different sizes of pipe. The slip dies are
engineered with large
surface areas and are manufactured with grooves or teeth (not shown) to
specifically fit and
bite the outer surface area of the tubing being installed into the well. The
surface areas of
the dies fitted against the pipe are engineered to handle the forces and loads
which the pipe
16 will be under in various applications as it is inserted into the well
against the pressure
acting over the cross-sectional area of the plugged end of the pipe 16 being
installed into the
well. The hydraulic pressure at which the slip assembly 76 is operated, as
well as the sizes
of the cylinders 67, the rods 69a and the pistons 69, are all correlated with
the surface area
of the slip dies and the teeth cut into them to perform safely within the
scope of the intended
application. The cylinders 67 are hydraulically pressurized simultaneously,
thus forcing the
CA 02211835 1997-07-29
-14-
rods 69a to inwardly to a point where the dies make contact with the pipe 16a,
thus gripping
or locking, centering and holding the pipe 16a in a stationary position. Ports
75 extending
at both sides of the pistons 69 through the walls of the cylinders 67 allow
hydraulic fluid to
be pumped into cavities on opposite sides of the pistons. The outer ends of
the rods 69a
serve as indicators to show what position the slips are in. If the rods 69a
are in the slips are
closed, and if the rods 69a are out the slips are open
Fig. 17 shows the jack assembly 71 of Figs. 14 and 15 installed in a snubbing
configuration,
indicated generally by reference numeral l Ob, in place of conventional
equipment used in
the prior art snubbing configuration of Figs. 1 to 7. For convenience, parts
of the equipment
shown in Fig. 17 which correspond to those shown in Figs. 1 to 7 are indicated
by the same
reference numerals.
In Fig. 17, the pipe 16a has been lowered towards the pressured well bore 26
so as to position
the tool assembly 61 just above the upper pipe sealing device, i.e. the
annular BOP 28a,
which is closed in sealing engagement with the pipe 16a to maintain well bore
pressure
below the annular BOP 28a.
In Fig. 18, the safety pipe rams 48 in the lower pipe sealing device, i.e. the
double-gate
blowout preventor 46, are then closed into sealing engagement with the pipe
16a. The
pressure between the pipe rams 48 and.the annular BOP 28a is then bled off and
the annular
BOP 28a is then opened.
The jack assembly 71 is then telescopically extended to raise the annular BOP
28a along the
pipe 16a to a position above the tools 61, as shown in Fig. 19. Then, the
annular BOP 28a
is closed into sealing engagement with the pipe 16a, as shown in Fig. 20, and
the pressure
between the pipe rams 48 and the annular BOP 28a is equalized with the
pressure in the well
bore. The pipe rams 48 are opened, and the tools 61 are ready to be lowered
into the well
bore 26.
CA 02211835 1997-07-29
-15-
In Fig. 21, the tools 61 are lowered into the well bore 26 and the jack
assembly 71 is
contracted to its original position, allowing continued operations at
desirable working heights
and away from the line of fire of the well bore.
Fig. 22 shows the jack assembly 71 inserting pipe 16a (snubbing) while
maintaining well
pressure. Pressure is below the blind rams 50. The plugged pipe 16a is lowered
to just
above the blind rams 50. The jack 71 is extended and both slip assemblies 76
and 85 are
closed on the pipe 16a to secure it. The annular BOP 28a is closed.
The pressure is then equalized from below the blind rams 50 to the space above
the blind
rams 50 and below the annular BOP 28a, as shown in Fig. 23, and the blind rams
50 are then
opened (Fig. 24) and the bottom slip assembly 85 is opened. The pipe 16a is
ready to snub
in the well bore 26 against the forces from the pressure against the cross-
sectional area of the
pipe 16a. Then, as shown in Fig. 25, the jack assembly 71 is contracted,
forcing the pipe 16a
into the bore of the well bore 26.
As shown in Fig. 26, the bottom slip assembly 85 is then used to secure the
pipe 16a; the
upper slip assembly 76 is opened; the jack assembly 71 is extended upwardly;
the upper slip
assembly 76 is closed the lower slip assembly 85 is opened and the jack
assembly 71 again
is contracted so as to force the pipe 16a down the well bore 26.
These steps are repeated until the pipe 16a reaches a pipe-heavy position.
When each stroke
of the jack assembly 71 is taken upwardly, the annular BOP 28a maintains well
pressure
while it slides up the surface of the pipe 16a. During conventional snubbing
operations, the
pipe 16a is forced into the annular BOP 28, which is located below the actual
jack assembly,
as illustrated in Figs. 1 and 2, and all operations are performed while
standing over the well
bore. This method according to the present invention is therefore much more
desirable from
a safety standpoint as the line of fire from the well pressure is moved up and
away from
working personnel and all operations are effected from a remote location away
from the well
bore.
CA 02211835 1997-07-29
-16-
As will be apparent to those skilled in the art, modifications may be made in
the above
embodiments of the invention and the method of operation thereof within the
scope of the
invention as defined in the appended claims.
For example, the equalizer and bleed-off spool 32a shown in Figure 14 as being
connected
to the lower snubbing slips 86, could be replaced by an equalizer incorporated
in the
hydraulic telescopic jack 70a by extending the latter downwardly sufficiently
to enable the
appropriate ports to be provided in the telescopic jack.
Also, while the above-described embodiments of the invention employ an annular
BOP as
the upper blowout preventor, it is alternatively possible to use a hydraulic
or mechanical
stripping head as the upper sealing device. An annular BOPs is desirable in
most low to
medium pressure applications for stripping the tubing through as this type of
blowout
preventor allows the passage of couplings and other slightly non-conforming
items in the
string without any delay or extra steps. A coupling, for example, simply
enters the top of a
pliable element in the BOP which is typically of a soft enough composition
that it gives away
to the coupling. A combination of the memory within the composition of the
element and
the constant hydraulic pressure activating the BOP, in addition to the well
pressure
compressing the element, allow passage of the coupling without losing control
of the
pressure or slowing up the installation procedure.
In higher-pressure applications, a stripping ram type BOP may replace the
annular BOP.
Ram type preventors generally allow the nominal portion of the pipe to be
moved within the
rams that are closed on the pipe at considerably higher pressures then annular
BOPs. Such
rams have a steel body cut out to conform to the nominal size of the pipe,
with a thin rubber
face. When the opposing rams come together around the pipe, they essentially
are two steel
bodies with a highly compressed thin center sealing off the pressure. The
tolerance of the
rubber between the two opposing rams is very slight, thus allowing maintenance
of higher
pressures.
CA 02211835 1997-07-29
-17-
An annular BOP element is mostly comprised of rubber. When the pliable element
is
compressed around the pipe, there is considerable tolerance in the 2 -3 inches
of rubber
closed around the pipe. Because of the amount and area of rubber around the
pipe and the
fact that it is pliable, the possibility exists that the rubber could be blown
out of the BOP,
causing temporary loss of control of the pressure on the well.
In a high pressure application, with a ram type stripping BOP replacing an
annular BOP, the
pipe would be stripped through the rams to a point just above the coupling
(where the next
pipe is connected to the previous one), then the safety rams in the double-
gate BOP are
closed, the pressure is bleed off between the two BOPS, the top stripping rams
are opened
and the telescopic spool is extended up over the top of the coupling. The
stripping ram is
then closed, the pressure equalized and the safety rams are then opened. The
pipe is then
lowered into the well to the next coupling and the same procedure is be
repeated until all the
pipe and/or tools are in the well. This is a slow process, but is considered
much safer in
high-pressure application.
Thus, the present invention may employ a ram-type stripping BOP and or other
annular,
spherical or any type of BOP or stripping device designed to move pipe through
its sealing
surface or element while maintaining well pressure.
Also, the telescopically extendible chamber may be mechanically extendible,
instead of
hydraulically extendible and the snubbing slips may be replaced by any other
suitable pipe
gripping devices.
