Note: Descriptions are shown in the official language in which they were submitted.
CA 02269876 2003-09-29
UNDERBALANCED DRILL STRING DEPLOYMENT VALVE
METHOD AND APPARATUS
I . Field of the Invention
The present invention relates generally to underbalanced drilling and, more
particularly, to a deployment valve method and apparatus for removing and
inserting a
drill string into a well bore when downhole pressures such as formation
pressure are
present at the surface to act on the drill string.
2. Description of the Back. r~yound
Underbalanced drilling has many advantages. In some cases, oil/gas well flow
during underbalanced drilling of a well has been sufficient to pay for the
cost of drilling
~ 5 the well even prior to completion of the well. Other advantages include
that of avoiding
formation damage for a better performing well and more accurate logging
measurements
of the well contents. For a discussion of advantages of underbalanced drilling
including
methods of controlling the well using an exemplary rotating blow out
preventer, please
refer to U.S. Patent No. 6,059,262 to Hosie et al. (issued May 9, 2000). Thus,
there are
2o numerous and significant advantages for underbalanced drilling of a well.
However, various problems exist for underbalanced drilling. These problems
relate mainly to controlling the well in certain circumstances. A possible
problem that
may typically arise is the need to remove the drill string from the well.
There are many
25 common reasons that the drill string must be removed from the well prior to
completion
of drilling. It may be necessary to remove the drill string for reasons such
as the need to
CA 02269876 2003-09-29
change out the drill bit, steering tool, mud motor, and the like. Although
pressure is
controlled at the surface, such as with a rotating BOP, the weight of the
drill string holds
the drill string within the well bore. The string light point is the depth or
position where
the upward forces acting on the drill string become greater than the downward
forces.
Many factors are involved and may vary as to exactly where in a well the drill
string
becomes string light. Such factors include but are not necessarily limited to,
or may not
necessarily always include, the following: surface pressure, down hole
pressure, flow
rate, hole size, drill pipe size and weight, the amount of drill pipe in the
hole, bit size,
casing size, and fluid or gas properties. Generally assuming other factors
remain
constant, as the drill string is pulled further out of the hole, the
downwardly acting forces
decrease due to decreased drilling string weight.
If an attempt to remove the drill string is made with pressure at the surface,
then at
some point as the drill string is being removed the pressure may begin to push
or
accelerate the drill string out of the well bore. This is a dangerous
situation that could
conceivably lead to a blow out. Once the pipe begins to move upwardly there
may be
developed a significant momentum such that the blow out preventers may not be
able to
stop the upward movement. Once the heavy pipe string is moving upwardly,
closing the
rams may result in tearing the rams out rather than Mopping the upward
movement of the
pipe. In this case, the rams will not be available fo shut in the well after
the pipe has been
pushed from the well bore, assuming there is someone left at the rig site to
activate the
rams after the drill pipe is ejected from the well. The forces are great
enough so that
ejected drill pipe may be found quite far from the rig. As well, sparks
produced can
ignite gas to produce a hot fire that can melt a drilling rig within minutes.
Blow outs can
result in costly problems such as personnel injury, damage to the drilling
rig,
environmental damage, and loss of the hole. Presently, methods used to avoid a
blow out
situation are effective but have significant disadvantages.
While it may be possible to bleed off the surface pressure prior to reaching
the.
point where the string becomes "string light" and begins to move upwardly,
this practice
is risky. For instance, a bridge in the bore hole may form in the formation
that
2.
CA 02269876 2003-09-29
temporarily permits a bleed off to appear to occur. If the bridge should break
at the
wrong moment with the pipe nearly out of the hole, then significant formation
pressure
may be applied at the surface to result in a blow out.
A very effective and safe practice is to kill the well prior to removal of the
drilling
string. However, this practice is undesirable because the advantages of
underbalanced
drilling may then be lost. Once the drill string is lowered back into the well
bore below
the string light point it may be possible to adjust the drilling fluids so
that underbalanced
drilling continues. However, formation damage may have already occurred that
is
substantially or partially irreversible.
Another very effective and safe practice is that of providing a snubbing unit
for
removing the drilling string. However, the snubbing unit takes considerable
time to rig
up, requires considerable additional time while tripping the well, and then
requires
considerable additional time to rig down. Thus, the cost of tripping the drill
string can be
quite considerable due to the rig time costs and snubbing unit costs.
Additional tripping
of the well may also be necessary and again require the snubbing unit. This
procedure
then, while effective and safe, increases drilling costs considerably.
Consequently, an improved method and apparatus is desirable for removing drill
string from a well bore that is drilled underbalanced. Such an improved method
and
apparatus should provide for quick, but safe, removal of the drill string from
the well
without the need to kill the well. The method and apparatus should be useful
for repeated
tripping of the drill string whenever necessary without significant time and
cost increases.
Those skilled in the art will appreciate the present invention that addresses
these and
other problems.
3
CA 02269876 2005-02-07
According to one aspect of the present invention there is provided a method
for
underbalanced drilling a well bore as part of a well bore formation, the
method
comprising providing a tubular string for placement within the well bore, a
drill string
being moveable through the tubular string, and mounting a deployment valve
within the
tubular string such that the deployment valve is positioned at or below a well
bore depth
at which upwardly directed forces acting on the drill string are greater than
downwardly
directed forces acting on the drill string.
According to another aspect of the present invention there is provided a
deployment valve system for an underbalanced drilling system to form a well
bore, as
part of a well bore formation, with a drill string, the drill string having a
drill bit and the
drill bit having an outer diameter, the drill string being operable for
drilling into a
formation reservoir, the well bore having a tubular string therein securable
with respect to
the well bore formation, the drill string being moveable into and out of the
tubular string
for drilling into the formation reservoir and having a light point such that
upwardly
directed forces acting on the drill string are greater than downwardly acting
forces, the
deployment valve system comprising a deployment valve body positionable in the
tubular string such that it is mounted at or below a well bore depth at which
the upwardly
forces acting on the drill string are greater than the downwardly acting
forces, the
deployment valve comprising a deployment valve element within the deployment
valve
body being moveable from an open position to a closed position, and a seal for
the
deployment valve such that the deployment valve is closeable with the seal
therein for
controlling a pressure below the deployment valve.
According to a further aspect of the present invention there is provided a
method
for underbalanced drilling of a well bore as part of a well bore formation
with a drill
string, a tubular string being secured within the well bore, the drill string
being operable
for drilling in open hole manner at a well bore depth below the tubular
string, the method
comprising positioning a deployment valve within the tubular string within the
well bore
formation at or below a depth at which forces acting upward on the drill
string are greater
than forces acting downwardly on the drill string, controlling a fluid
pressure for opening
and closing the deployment valve, moving the drill string through the tubular
string and
the deployment valve, drilling in open hole manner below the tubular string,
pulling the
drill string back into the tubular string, and closing the deployment valve.
According to a further aspect of the present invention there is provided a
deployment valve system for an underbalanced drilling system to form a well
bore as part
of a well bore formation with a drill string, the drill string having a drill
bit and the drill
bit having an outer diameter, the drill string being operable for drilling
into a formation
reservoir, the well bore having a tubular string therein securable with
respect to the well
3a
CA 02269876 2005-02-07
bore formation, the drill string being moveable into and out of the tubular
string for
drilling into the formation reservoir and having a string light point such
that upwardly
acting forces on the drill string are greater than downwardly acting forces,
the
deployment valve system comprising a deployment valve positionable in the
tubular
string such that it is mounted at or below a well bore depth within the well
bore
formation, the deployment valve comprising a deployment valve element within
the
deployment valve being moveable from an open position to a closed position in
response
to fluid pressure, the deployment valve in the open position having a passage
therethrough sufficient to permit the drill bit to pass through the deployment
valve, and a
seal for the deployment valve such that the deployment valve is closeable with
the seal
therein for controlling a pressure below the deployment valve.
According to a further aspect of the present invention there is provided a
deployment valve system for use in a well bore, comprising deployment valve
being
mountable within the well bore the well bore having a first well bore tubular
cemented
into the well bore, the first well bore tubular having a bottom end, the
deployment valve
being mountable in a second well bore tubular as a tubular section thereof,
the second
well bore tubular being run into the well bore to a well bore depth below the
bottom end
of the first well bore tubular and being cemented into position within the
well bore such
that the deployment valve is mountahle at a subterranean position in the well
bore
adjacent the bottom end of the first well bore tubular, the second well bore
tubular having
a bore therethrough, a drill string with a drill bit for drilling through the
second tubular,
the deployment valve being mountable at or below a depth at which forces
acting
downwardly on a the drill string, a tubular body having an opening
therethrough at least
as large as the bore of the well bore tubular, and a valve element mounted
within the
tubular body, the valve element being movable for opening and closing the well
bore
tubular in response to a control pressure, the valve element being
controllable for opening
the well bore tubular to allow the drill bit and the drill string to pass
therethrough, the
valve element being controllable for closing and sealing the well bore tubular
after the
drill bit and the drill string are pulled above a position in the well bore
tubular at which
the valve element is positioned.
According to a further aspect of the present invention there is provided a
deployment valve system for an underbalanced drilling system to form a well
bore as part
of a well bore formation, the drilling system comprising a tubular string and
a drill string
movable into and out of the tubular string, the deployment valve being
positioned in the
tubular string below a well bore depth at which upwardly acting forces acting
on the drill
string are greater than downwardly acting forces.
3b
i
CA 02269876 2003-09-29
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. I is an elevational schematic view of an underbalanced wellbore operation
wherein the drill string extends through an open deployment valve in the
casing in accord
with the present invention into the reservoir formation; and
FIG. 2 is an elevationaI schematic view of removal of the drill string from
the well
bore into the casing whereupon the deployment valve is closed.
FIG. 3 is a schematic view of a deployment valve of a flapper valve type; and
FIG. 4 is a schematic sectional view of a deployment valve that may be
operated
by annulus pressure and/or hydraulic lines;
FIG. 5 is an elevational view, in section, of an annulus operated deployment
valve
positioned in a liner that is cemented within the borehole;
FIG. 6 is an elevational view, in section, of a control line operated
deployment
valve positioned in a liner that is cemented within the borehole;
I S FIG. 7 is an schematic view of an upper section of a deployment valve in
accord
with the present invention;
FIG. 8 is an elevational view, in section, of a lower section of a deployment
valve
in accord with the present invention;
FIG. 9 is a cross-sectional view, in section, taken along lines 9-9 of FIG. 8;
FIG_ 10 is an elevational enlarged view, in section, showing the deployment
flapper valve open;
FIG. 1 I is an elevational enlarged view, in section, showing the deployment
flapper valve closed;
FIG. I2 is an elevational view, partially in section, showing an indexing
sleeve for
the deployment valve; and
FIG. 13 is an elevational view spread out over 360° showing an
indexing slot
pattern for the indexing sleeve.
While the present invention is disclosed in terms of a presently preferred
embodiment or embodiments in accordance with patent laws, it will be
understood that
4
CA 02269876 2003-09-29
the present invention is not intended to be limited to the particular
embodiment or
embodiments shown for permitting understanding of the invention. Instead, it
is desired
to cover all embodiments contained within the spirit of the invention.
CA 02269876 2003-09-29
SUMMARY OF THE INVENTION
'The present invention provides a means for more quickly removing a drilling
string from a tubular string, such as a tubular string of casing, when the
tubular string is
S exposed to downhole pressure. This might occur after drilling through a
reservoir
formation with the drilling string. Attempts to remove the drilling string
when downhole
pressure is contained within the casing may be dangerous due to the
possibility of a
blowout.
A method for underbalanced drilling of a well bore through a well bore
formation
is provided herein wherein the well bore has a tubular string, such as a
casing string
secured therein. Typically but not necessarily, the casing string is cemented
within the
well bore at least over a certain length if not over substantially the entire
length of the
casing string. There may be multiple strings of casing within a well bore.
The method of the present invention comprises mounting a deployment valve
within or as part of a tubular string, typically the casing string, preferably
adjacent the
reservoir formation. However, the deployment valve should preferably be below,
preferably with a good safety margin, the string light position at which point
the forces
acting upwardly on the drilling string are greater than the forces acting
downwardly such
that the drilling string may begin to move upwardly. In one embodiment , the
deployment
valve has an open and a closed position. The tubular string is secured within
the well
bore, such as by cementing or other means, such that the deployment valve is
mounted
within. The deployment valve may be secured to the casing and run therewith or
it may
be mounted within the casing such as by running a smaller tubular string,
lowering,
wireline methods, or other methods. A drill string is provided to be operable
for drilling
into the reservoir portion of the well bore formation below the tubular
string. The drill
string is moveable through the tubular string or casing and the deployment
valve when the
deployment valve is in the open position. The deployment valve may be closed
when the
drill string is no longer positioned within the deployment valve.
The drill string may be extended through the deployment valve to drill below
the
6
CA 02269876 2003-09-29
casing such as into the reservoir portion of the well bore formation below the
tubular
string. The drill string may be pulled from the reservoir portion into the
tubular string,
and the deployment valve closed once the last of the drill string is pulled
therethrough.
For this reason, it is typically desirable that the deployment valve be as
close to the
bottom of the casing as possible so that the deployment may be closed as soon
as
possible. At a minimum, the deployment valve should be located below the
string light
point as best determinable plus additional safety margin depth. The
exact,string Light
point may not be precisely known and could even vary_ Once the drilling string
is back
within the casing or tubular string, it is desirable to reduce pressure in the
tubular string
above the deployment valve. Once reservoir pressure is bled off from the
portion of the
casing above the deployment valve, the drill string can be safely removed from
the well
bore. .After the desired service is made to the drill string, the drill string
may once again
be introduced into the tubular string when the deployment valve is closed.
'fhe casing may then be pressurized above the deployment valve to preferably
I S equalize pressures above and below the valve. The deployment valve can
then be opened
to thereby extend the drill string through the deployment valve for continued
drilling after
servicing the drill string in some way.
A deployment valve system is provided for a drilling system to form a well
bore
through a well bore formation with the drilling string. The drilling string
has a drill bit
and the drill bit having an outer diameter. A deployment valve is positionable
in the
tubular string at a selected depth within the well bore formation preferably
within the
lower portion of the tubular string as discussed above. The deployment valve
should be
able to open such that the inner diameter is large enough to allow the drill
bit to pass
therethrough. While flexible sealing elements, such as expandable tubulars or
bags could
form portions of the valve, the valve could also take other forms as discussed
below.1n
some embodiments of the present invention, the deployment valve body may have
a bore
therethrough having an inner diameter larger than the outer diameter of the
drill bit. A
deployment valve element is mounted within the deployment valve body for
movement
between an open position and a closed position. A seal surface for the
deployment valve
7
CA 02269876 2003-09-29
may also be provided. With the deployment valve element in the open position
within the
deployment valve body, the drill bit may pass through the valve. The
deployment valve
may be closeable with the seal surface for containing/controlling the
formation reservoir
presswe below the deployment valve. A rotating blowout preventer is provided
for
sealing around the drilling string at the surface.
Several options are available for the type of deployment valve used. The valve
may be inflatable as by hydraulic control. The deployment valve element may
include
one or more flapper valve elements moveable within the deployment valve. One
or more
pivot connections may then be used to secwe the one or more flapper valve
elements to
the deployment valve such that the one or more flapper valve elements are
moveable
between the open position and the closed position. The deployment valve could
also be
a ball valve or have another rotatable type of closure element. Telescoping
elements may
be used. Thus, the valve could be of many different constructions. The
deployment valve
may be hydraulically operated and have at least one hydraulic line for
controlling
movement of the deployment valve element. A biasing element(s), such as
springs or
weights, or other control lines may be used in conjunction therewith the above
or
subsequently described deployment valves. The deployment valve could also be
annularly controlled such that an annulus is provided so that presswe acting
thereon
activates an annular control system to control the valve. Some type of
combination of
annular, hydraulic, biasing means, or other control method may be used.
The method for underbalanced drilling of a well bore through a reservoir
formation with a drilling string operable for drilling into open hole at a
well bore depth
below the tubular string may also comprise positioning a deployment valve
within the
tubular string as described hereinbefore and below the string light position.
The drilling
string is moved through the tubular string and the deployment valve for
drilling open
hole below the tubular string. For various reasons, the drilling string may
require being
pulled back into the tubular from the open hole, whereupon the deployment
valve is
closed to thereby control pressure of the reservoir formation at a well depth
below the
deployment valve. The reservoir formation pressure within the tubular string
at a well
CA 02269876 2003-09-29
depth above the deployment valve is bled off The tubular string is opened to
atmospheric pressure and the drilling string is removed from the tubular
string. At a later
time, the drilling string may be reinserted into the tubular string.
An object of the present invention is to provide an improved method for
underbalanced drilling.
Another object of the present invention is to provide a method for removing
the
drilling siring from the well bore when the formation pressure acts on the
well bore as
occurs during underbalanced drilling.
Another object of the present invention is to provide a lower cost and faster
method of removing the drill string from the bore hole for underbalanced
drilling.
A feature of the present invention is a deployment valve preferably positioned
below where the drill string becomes string light.
An advantage of the present invention is reduced costs and greater flexibility
of an
underbalanced drilling operation.
1 S The above objects, features, and advantages are provided for easy review
of some
aspects of the invention and are not to be construed as limiting the invention
in any way.
It will be appreciated that other objects, features, and advantages of the
present invention
will become apparent in light of the drawings, claims and specification.
:9
CA 02269876 2003-09-29
BRIEF DESCRIPTION OF THE PREFERRED EMBODIMENTS
The present invention represents a significant improvement in underbalanced
drilling techniques and apparatus that addresses the potentially hazardous
and/or costly
problem of removing and reinserting a string of pipe such as the drill string
from a live
well.
Referring now to the drawings, and more particularly to FIG. l, there is shown
a
schematic that illustrates basic elements of the method and apparatus of the
present
system 10 of the invention. In FIG. I, drill bit 12 is shown at the bottom 14
of well bore
18 and is drilling in open hole region 16. Drilling extends through well bore
formation
19 into reservoir formation 20 below bottom 24 or shoe of casing 22. The well
is being
drilled underbalanced so that downhole pressure, which can be quite
substantial, may
reach or flow towards the upper portion of the hole. The pressure may be
controlled at
the surface by various wellbore controls, such as wellbore control 26.
Wellbore control
26 may include a well head 28 with a rotating blow out preventer 30, flow line
32 and
pressurized recovery system 33 as indicated in FIG. 2. Gas may be flared off,
solids
removed, oil and diesel separated off by a well bore control system such as a
drilling
recovery system with components such as pressure tanks, inlet manifold skid,
pump skid,
data acquisition, flow line, ESD valve, electrical generator, flare stack,
glycol heater, heat
tracing, triplex pump, and the like. The rotating blow out preventer, such as
rotating
blow out preventer 30, seals around the pipe as it moves into and out of the
well bore.
Details of an exemplary rotating blow out preventer are described in the
application
referenced above to Hosie et al. that is incorporated herein by reference. So
long as there
is no need to remove the drill pipe, the operation can proceed by simply
adding drill pipe
in drill string 34 as necessary to drill deeper as indicated in FIG. 1.
However, at some time it may become necessary to remove drill string 34 as
indicated in FIG. 2 where deployment valve 36 is open to allow drill string 34
to move
therethrough. When this occurs drill string 34 is pulled up into an outer
tubular string,
that may typically be casing string 22, and may include one or more strings of
casing.
CA 02269876 2003-09-29
Once drill string 34 is in the casing string 22 as indicated in FIG. 2,
deployment valve 36
closes with seal element 38 to seal off the formation pressure below
deployment valve 38.
Drill string 34 can be moved upwardly to within a safe margin of it becoming
string light.
The pressure above deployment valve 36 can then be bled off: In fact, the
casing above
deployment valve 36 may be bled off at anytime after deployment valve 36 is
closed.
Once the pressure is bled off above deployment valve 36, then drill string 34
can be safely
and quickly removed.
After the desired changes or repairs to drill string 34 are made, then drill
string 34
can be run back into the hole to a desired depth which may be preferably near
deployment
valve 36 and below the string light position. When the drill string is above
the string
light point, the remaining pipe in the hole is not heavy enough to hold drill
string 34 in
the hole and the pipe may therefore be blown out of the hole, i.e., the
upwardly forces
acting on drill string 34 are greater than the downwardty forces acting on the
drill string
34.
At some point after going below the string light position of the drill pipe
when
running the drill string back into the hole, casing 22 is preferably
pressurized prior to
opening the deployment valve 36. This is done so as to substantially equalize
pressure
above and below deployment valve 36. Deployment valve 36 is then opened,
whereupon
drill string 34 may be extended through deployment valve 36, out of the casing
string 22,
and back into formation 20 for continued drilling.
As discussed in the above referenced patent application, damage to the
formation
is averted because the presswe and fluids of the formation are contained
therein as during
drilling. It is not necessary to introduce additional pressure, fluids, or
materials into the
reservoir formation so as to force drilling fluid, cakes or filtrates thereof
into the
producing formation.
Deployment valve 36 may be run within casing 22 so as to be positioned
surrounded by the well formation, such as near bottom end 24 of the casing. At
a
minimum, the position of deployment valve 36 should be below the anticipated
string
light point below which pipe string 34 will not be ejected from the well and
preferably at
II
CA 02269876 2003-09-29
a depth having a good margin of safety with respect to this position. Well
bore depth may
or may not be the same as vertical depth so that references to depths in the
well bore such
as above or below certain depths generally refer to well bore depths rather
than vertical
depths.
S In some cases, well bore 18 may be considerably larger than the casing so
that the
diameter of deployment valve body 40 may be of larger diameter than that of
casing 22.
If the deployment valve body is smaller than the diameter of casing 22 or is
collapsible so
as to temporarily assume a smaller diameter, then deployment valve 36 may be
positioned
after casing 22, or one or more of the casing strings are in place, by some
conveyance
means such as wireline or tubing.
Deployment valve body 40 may have a flapper valve element 42, or other type of
valve closure element mounted therein. As indicated in FIG. 3, flapper valve
element 42,
with hinge or pivot joint 44, may be provided with spring control 46 or weight
operated to
bias close and seal against seat 48. The weight of the drill string, and
pressure above the
1 S flapper valve may be used to open flapper valve element 42. Deployment
valve 36 may
be self closing by spring and/or weight and/or seal with the valve seat due to
the force of
pressure below deployment valve 36.
Deployment valve 36 could also be controlled by control lines such as
hydraulic
control lines 50 or 52 or annular pressure control through annulus 58 between
outer string
54 and inner string 56 as indicated in FIG. 4. Thus, the valve may also be a
ball type of
valve or other design as desired for the well conditions. Bias means, annular
pressure,
mechanical control, hydraulic control, other means may be used in conjunction
with or
used for control over the deployment valve. Valve body 40 may be inflatable or
it may be
comprised of a substantially inflexible material such as metal or composite
materials.
There may be several strings of casing in the hole whereby a portion of the
valve may
extend outwardly within an annulus between two strings of casing.
Opening diameter 60 of the valve should be sufficient to allow the drill
string,
including the drill bit to pass therethrough. Thus, the outer diameter of the
drill bit
should be smaller than the inner diameter of the deployment valve bore for
some types of
12
CA 02269876 2003-09-29
valve elements such as a flapper valve or ball valve. The valve elements)
should expand
to allow the drill bit to pass if the valve elements are expandable or
flexible. Deployment
valve 36 may also be operated through interaction with the drill string or a
drill string sub
thereof such that vertical or rotational movement of the drill string controls
deployment
valve operation. More than one deployment valve may be used and if different
deployment valves are used, they may be operated differently. As well, other
types of
valves and closure means rnay be used. Some leakage may be tolerable with the
seal or
sealing surfaces of the deployment valve so long as the leakage permits
removal of the
drill string. Temporary chemical plugs such as gels, cements, or the like may
conceivably
I 0 be used above the deployment valve. However, such uses may prevent the
desirable
possibility of repeated uses of the deployment valve.
A presently preferred embodiment of the deployment valve is shown in more
detail in FIG. 5 - FIG. 13.
In FIG. S, annular operation installation 70 shows deployment valve 71
installed
in casing string 88 / liner 72 for annular operation as discussed hereinafter.
Liner 72 is
effectively an extension of intermediate casing string 88 that goes to surface
and
deployment valve 71 is mounted therebetween so that deployment valve 71 is
mounted
within a tubular string that is partially cemented in position for
installation 70. It will be
understood that depending on numerous factors such as the well program,
components in
the well such as additional casing strings, and the like, that many variations
of annular
installation operation 70 may be used. Thus, FIG. 5 is a representative basic
example of
how deployment valve would be installed and it will be understood that
numerous factors
go into each well installation such that additional components could be
added/deleted
from casing string 88 / liner 72. Liner 72 has been cemented into the borehole
as
indicated by cement 74 positioned outside liner 72. Liner hanger packer 76 is
positioned
below deployment valve 71. Liner hanger packer 76 prevents cement 74 from
proceeding
upwardly within annulus 77 past liner hanger 76 during the cementing process.
For this
purpose, liner hanger packer 76, or other packer means, is set or inflated
prior to
cementing to prevent cement from migrating into annulus 77. Thus, annulus 77
that is
13
CA 02269876 2003-09-29
around deployment valve 71 is available for use in controlling deployment
valve 71 by
applying pressure to annulus 77 at the surface. Annulus 77 is formed between
liner 72 /
casing string 88 and surface casing 86. Moreover, deployment valve 71 is
surrounded by
surface casing 86. Surface casing 86 is cemented into position as indicated by
surface
casing cement 90. Surface casing 86 extends to the surface. Pressure applied
to annulus
77 operates to open and close deployment valve 71 in a manner discussed
hereinaRer.
In installation 70, between liner hanger packer 76 and deployment valve 71 are
several components including casing coupling 78, joint of casing 80, tie back
seal
assembly 82, and tie back receptacle 84. Thus, annulus ?7 extends downwardly
past
deployment valve 71 for some distance as might be advantageous for washing out
annulus 77 as may be desired using, for instance, rotating port collar 92 or
other
components in the installation through which circulation may be established.
It will be
noted that positioned above deployment valve 71 is rotating port collar 92,
spacing nipple
93, and locating nipple 96 that is secured to intermediate casing to surface
88. As can be
I 5 seen, the point of development in the well as per FIG. 5 is just afrer
cementing of the Liner
prior to drilling out of cement float shoe 94. Above float shoe 94 is joint of
casing 96,
plug landing collar 98, liner wiper p1ug100, and drill pipe wiper plug 102.
T'he drill bit is normally only slightly smaller than the inner diameter 104
of liner
72. For instance, a 7- inch liner having 7-inch connections and with an outer
diameter in
the range of about seven inches might have a 6- inch inner diameter, in which
case the
drill bit is typically in the range of 5 3/4 to 5 7/8 inches. Thus, deployment
valve 71
opens full bore or, in other words, widely enough to allow a standard bit
therethrough.
The inner diameter of deployment valve 71 is therefore preferably at least as
large as
inner diameter I 04 of liner 72 or other relevant wellbore tubulars or casing
strings
through which drilling is effected, and may in some cases be slightly larger.
Moreover,
the outer diameter of deployment valve is small enough to fit in the next
standard size
casing string in that it is less than about 10% greater in O.D. than the size
casing upon
which it is installed since well bores typically have multiple casing strings
therein. Thus,
there is no need to have an oversized outer casing in which to use the
deployment valve.
14
CA 02269876 2003-09-29
lfiis percentage may vary depending on whether the casing is heavy weight or
light
weight and may typically be in the range from about S% to about I O% greater
that the
casing size O.D.
In FIG. 6, installation 110 is shown whereby deployment valve 112 is operated
by
S control line 114 that goes to surface. Unlike installation 70, in
installation I 10 annulus
116 between surface casing I 18 and intermediate casing string 120 is filled
with cement
121 during the cementing operation. In this way, control line 114 is rigidly
secured in
place. Surface casing 118 is also typically cemented in position (during a
previous
cement operation) as indicated by cement 123 outside of surface casing 1 I 8.
Protectors
I O such as control line coupling protector 122 may be psed to protect control
line I 14
intermediate casing string 120 is positioned within surface casing 118. Casing
120 is
centralized within surface casing 118 by centralizers such as casing
centralizer 126. After
cementing, float shoe 124 will be drilled out as drilling proceeds.
In FIG. 7 and FIG. 8, deployment valve I SO is shown in two halves with
actuator
I S section I S2 being shown in FIG. 7 and valve section 154 being shown in
F1G. 8.
Actuator section I S2 sits above valve section 1 S4 and is used to actuate an
inner slidab)e
mandrel that is upwardly and downwardly moveable for opening and closing the
flapper
valve in a manner to be explained.
Prior to running into the borehole, nitrogen chamber I SS is precharged to a
20 selected percentage of hydrostatic pressure as determined for the most
efficient opening
and closing pressures. A typical value might be about 60% of the anticipated
hydrostatic
pressure in the borehole where deployment valve 150 will be positioned. After
charging,
deployment valve 1 SO is run into the hole with the casing string. As the
depth of the
deployment valve increases, the increasing hydrostatic pressure acts on lower
equalizing
2S valve piston I S6. 'The hydrostatic pressure enters passage I S8 which may
be open to the
annulus or connected to a control line.
Hydrostatic pressure acts on seal 160 and 162 of lower equalizing valve piston
I S6 creating a downward force on lower equalizing valve piston I S6. Seal 162
is
preferably positioned on shoulder 164 of upper mandrel 1?2 for reasons to be
discussed.
IS
CA 02269876 2003-09-29
Spring 166 biases lower equalizing valve piston 156 against shoulder I64 and
seal I62
for initial sealing therebetween. Seal 168 prevents hydrostatic pressure
entering bore 170.
Due to increasing hydrostatic pressure, lower equalizing valve piston 156
pushes
against shoulder 164 on the essentially one-piece upper mandrel 172. Upper
mandrel 172
is comprised of upper seal mandrel 174, equalizing seal mandrel 176, J-slot
mandrel 180
and nitrogen chamber mandrel 178 screwed or otherwise connected together as a
one-
piece slidable mandrel 172. Thus, upper mandrel 172 is forced downwardly
relative to
top body I 82 of deployment valve in the direction of valve section 154 as
indicated in
FIG. 7 although it will be understood actual borehole orientations may vary
considerably.
For instance, deployment valve I 52 may be used in horizontal wells and may be
positioned at all borehole angles because it will be readily understood that
tool orientation
is dependent upon the borehole orientation direction in which the deployment
valve is
used. So the terms "up", "down", and the like are used for explanatory
purposes and do
not necessarily refer the position of the deployment valve in operation in the
borehole.
I S Upper mandrel 172 continues to move due to increasing hydrostatic force on
lower
equalizing valve 156 until lower face 184 of lower equalizing valve pistonl 56
comes into
contact with shoulder 186 of housing 188. The increasing hydrostatic pressure
causes
seal 162 with lower face 184 of lower equalizing valve to be broken as
pressure acts to
move upper mandrel 172 slightly until leakage may occur past seal 162 so that
the
hydrostatic pressure now engages nitrogen piston 190. Any fiu~ther movement of
upper
mandrel 172 after seal 162 with lower face I 84 is broken tends to be very
slight. Even a
small opening provides enough space to permit pressurized flow past the broken
seal to
transmit the pressure to nitrogen piston 190. Therefore, increasing
hydrostatic pressure
now begins to act on nitrogen piston 190 between nitrogen piston seals 192 and
194 and
moves nitrogen piston 190 downwardly or away from top body 182. Movement of
nitrogen piston 190 reduces the volume of nitrogen chamber 155, thereby
increasing the
pressure of the nitrogen therein. Nitrogen chamber 155 is comprised of housing
188,
nitrogen chamber mandrel 178, nitrogen piston 190, and center coupler 196
(shown in
FIG. 8). Hydrostatic pressure continues to act on nitrogen piston 190 to move
it further
16
CA 02269876 2003-09-29
downwardly until nitrogen pressure equals hydrostatic pressure. Noie that the
above and
continuing discussion is useful for describing how increasing/decreasing
pressure can be
used for operating deployment valve 1 SO in that the action of moving upper
mandrel 172
also opens and closes deployment valve 1 SO as will be discussed subsequently.
In some
S cases, this may not necessarily be the process of how the deployment valve
will be run
into the hole. For instance, in some cases it may be desirable to operate the
valve on the
surface to leave the valve in the open position while going in the hole in a
manner as
explained subsequently.
As an example of actuator section basic operation of moving upper mandrel 172
I 0 upwardly or in the opposite direction, additional pressure is applied to
hydrostatic
pressure either by annulus or control line_ This further moves piston 190
downwardly
increasing the nitrogen pressure above hydrostatic. The applied pressure is
then reduced, though perhaps not to zero. Now the nitrogen pressure is greater
than
hydrostatic and any remaining surface applied pressure. Therefore, piston 190
moves
I S upwardly due to the nitrogen pressure. Piston 190 applies a force on
volume 20U of fluid
between piston 190 and upper equalizing valve piston 198. This force creates a
pressure
in volume 200 which is greater than hydrostatic pressure and any remaining
surface
applied pressure. The pressure acts on upper equalizing valve piston198
between seals
202 and 204. Upper face 206 of upper equalizing valve piston 198 acts on seal
204 that is
20 ~ mounted on shoulder 208 of upper seal mandrel 174. Therefore, upper
equalizing valve
piston 198 pushes upper seal mandrel 174 upwardly or toward top body 182 until
upper
equalizing valve piston 198 contacts the lower edge 212 of equalizing spacer
210
whereupon upper equalizing valve piston 198 can move no further upwardly.
Along with
upper equalizing valve piston 198, upper seal mandrel 174 and upper mandrel
172 are
2S also forced upwardly as upper face 206 presses on shoulder 208 of upper
seal mandrel
1 ?4. Once upper equalizing valve piston 198 contacts lower edge 212 of
equalizing
spacer 210, upper face 206 is separated from shoulder 208 and seal 204 so that
seal 204
with upper face 206 is broken. The nitrogen pressure continues to operate on
nitrogen
piston 190 to move upwardly until pressure bleeds off in volume 200 past seal
204. Any
17
CA 02269876 2003-09-29
movement of upper mandrel 172 relative to upper equalizing valve piston 198
after seal
204 is broken tends to be very slight. As explained above, seal 204 was broken
because
upper equalizing valve piston 198 stops movement when upper face 206 thereon
engages
lower edge 212 but upper seal mandrel 174 continues to move slightly to open
or break
the seal therebetween. The end result is that nitrogen pressure is now charged
to the same
pressure as they hydrostatic pressure. Further operation of deployment valve
is conducted
by repeating the process, essentially, of applying pressure to open the valve
and reducing
pressure to close the valve. Some additional factors apply such as the
indexing function
that is explained hereinafter. The use of the nitrogen piston allows use of a
single control
line and/or use of hydrostatic control because the nitrogen piston provides a
return force
for closing the valve so that only an opening force need be applied from the
surface.
Referring now to valve section 154 in FIG. 8, 9, 10 and FIG. 1 I . Upper
mandrel
172 is rigidly connected to lower mandrel 220 by threads or other means and
moves
therewith as one piece. Lower mandrel 220 comprises upper actuator connector
222,
I 5 upper actuator extension 224, and lower actuator extension 226. Therefore,
movement
and force are transferred through upper mandrel 172 to lower mandrel 220.
Pressure is
applied to the annulus or control line and, as explained hereinbefore upper
mandrel 172
and hence lower mandrel 220 moves downward. Lower edge 228 (see FIG. 10 or
FIG.
I I) of lower actuator extension 226 applies a force to the top side of
flapper 230. The
force creates a moment on flapper 230 that pivots around flapper pin 232,
rotating flapper
230 approximately 1/4 turn around flapper pin 232 to the open position whereby
the full
bore of the casing string and/or liner is open for drilling operations. Lower
actuator
extension 226 is maintained in a downward position as shown for holding
flapper 230 in
the open position as shown in FIG. 10.
When it is desired for flapper 230 to return to the closed position, the
applied
pressure is reduced and lower mandrel 220 moves upwardly as explained
hereinbefore.
Once lower actuator extension 226 is removed from the rotational path of
flapper 230,
then flapper spring 234 creates a moment acting on flapper 230 pivoting around
flapper
pin 232 approximately 1 /4 turn to the closed position as shown in FIG. I I .
In the closed
18
CA 02269876 2003-09-29
position, flapper 230 seals off bore 236 below flapper 230. The seal is
achieved by the
upper face 238 of flapper 230 acting against lower end 240 of valve seat 242.
Seals on
the valve seat may include elastomeric seals, metal seals, other types of
seals or
combinations thereof_ FIG. 9 shows a cross-section view of flapper 230 in the
closed
S position looking upwardly from the bottom. It will be noted that at least in
this
embodiment, flapper 230 is slightly eccentrically positioned such that a
center line 231 of
bore 236 is slightly off from a center line 233 of flapper 230. While this
flapper design is
slighlty eccentric, it will be noted that this is not necessarily the case for
all embodiments.
Inother words, in some embodiments of the invention the flapper may be
concentrically
positioned with respect to the bore. Once the well is completed and valve
operation is no
longer desired, actuator extension 224 and Iower actuator extension 226 can be
operated
for permanently leaving deployment valve 150 in the open position.
In a presently preferred embodiment of the invention, deployment valve is
equipped with indexing sleeve 244 that allows deployment valve 1 SO to be held
in the
1 S open position without having applied pressure acting on the tool either
through the
annulus or the control line. Indexing sleeve 244 is shown in FIG. 7, FIG. 12,
and FIG. 13.
Indexing sleeve 244 is held on upper mandrel 172 between J-slot mandrel 180
and
equalizing valve mandrel 176. Indexing sleeve 244 indexes deployment valve I
SO by
means of slot pattern 246 that is machined into and around the circumference
thereof and
by a set of J-slot pins 248 mounted to upper housing 188.
Referring to FIG. 13, when pressure is applied to open deployment valve 1 S0,
pattern 246 aligns with 1-slot pins 248 so that J-slot pins 248 will maintain
the valve in
the open position with the loss or reduction of surface applied pressure. To
close
deployment valve 1 S0, applied pressure is reduced and then the pressure is
reapplied to
2S move slot pattern 246 to the free travel position allowing indexing sleeve
244 and upper
mandrel 172 to move upwardly freely. For instance, with J-slot pin 248 at
position 250
in slot pattern 246, deployment valve 150 is closed. Pressure is applied to
move J-slot
pin 248 to position 252. With J-slot pin 248 at position 252, the deployment
valve will
be open as long as pressure is applied. However, upon release of pressure, J-
slot pin 248
19
CA 02269876 2003-09-29
will move to position 254 whereupon deployment valve 1 SO is locked in the
open
position even with no applied pressure. To close deployment valve 150,
pressure is
applied to move J-slot pin 248 to position 256 where the valve remains open so
long as
pressure is applied. Once pressure is now released, then J-slot pin 248 moves
to position
258 and the valve is closed. Thus, indexing sleeve 244 rotates during
operation with
respect to housing 188. Deployment valve 250 fan be cycled through the
positions of
indexing sleeve as many times as necessary.
While the deployment valve of the present invention is highly suitable for use
in
underbalanced drilling as explained above, it will be appreciated that the
deployment
valve may find other uses including drilling even when the well is
overbalanced for
additional well control, or even non-drilling functions or production type
uses. Since
changes and modifications may be made in the disclosed embodiment without
departing
from the inventive concepts involved, it is the aim of this specification,
drawings, and
appended claims to cover all such changes and modifications falling within the
spirit and
1 S the scope of the present invention.
