Note: Descriptions are shown in the official language in which they were submitted.
CA 02760504 2011-11-30
METHODS AND APPARATUS FOR WELLBORE CONSTRUCTION AND
COMPLETION /
CA 02760504 2011-11-30
BACKGROUND OF THE INVENTION
Field of the Invention
[0004] The present invention relates apparatus and methods for drilling and
completing a welibore. Particularly, the present invention relates to
apparatus and
methods for forming a welibore, lining a welibore, and circulating fluids in
the weilbore.
The present invention also relates to apparatus and methods for cementing a
welibore.
Description of the Related Art
[ooos] In the drilling of oil and gas wells, a weilbore is formed using a
drill bit that is
urged downwardly at a lower end of a drill string. After drilling a
predetermined depth,
the drill string and bit are removed, and the welibore is lined with a string
of casing. An
annular area is thus defined between the outside of the casing and the earth
formation.
This annular area is filled with cement to permanently set the casing in the
welibore and
to facilitate the isolation of production zones and fluids at different depths
within the
wellbore.
[0006] It is common to employ more than one string of casing in a weilbore. In
this
respect, a first string of casing is set in the wellbore when the well is
drilled to a first
designated depth. The well is then drilled to a second designated depth and
thereafter
lined with a string of casing with a smaller diameter than the first string of
casing. This
process is repeated until the desired well depth is obtained, each additional
string of
casing resulting in a smaller diameter than the one above it. The reduction in
the
diameter reduces the cross-sectional area in which circulating fluid may
travel. Also,
the smaller casing at the bottom of the hole may limit the hydrocarbon
production rate.
Thus, oil companies are trying to maximize the diameter of casing at the
desired depth
in order to maximize hydrocarbon production. To this end, the clearance
between
subsequent casing strings having been trending smaller because larger
subsequent
casings are used to maximize production. When drilling with these small-
clearance
casings it is difficult, if not impossible, to circulate drilled cuttings in
the small annulus
formed between the set casing inner diameter and the subsequent casing outer
diameter.
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[00071 Typically, fluid is circulated throughout the weilbore during the
drilling
operation to cool a rotating bit and remove weilbore cuttings. The fluid is
generally
pumped from the surface of the weilbore through the drill string to the
rotating bit.
Thereafter, the fluid is circulated through an annulus formed between the
drill string and
the string of casing and subsequently returned to the surface to be disposed
of or
reused. As the fluid travels up the wellbore, the cross-sectional area of the
fluid path
increases as each larger diameter string of casing is encountered. For
example, the
fluid initially travels up an annulus formed between the drill string and the
newly formed
weilbore at a high annular velocity due to smaller annular clearance. However,
as the
fluid travels the portion of the weilbore that was previously lined with
casing, the
enlarged cross-sectional area defined by the larger diameter casing results in
a larger
annular clearance between the drill string and the cased weilbore, thereby
reducing the
annular velocity of the fluid. This reduction in annular velocity decreases
the overall
carrying capacity of the fluid, resulting in the drill cuttings dropping out
of the fluid flow
and settling somewhere in the weilbore. This settling of the drill cuttings
and debris can
cause a number of difficulties to subsequent downhole operations. For example,
it is
well known that the setting of tools, such as liner hangers, against a casing
wall is
hampered by the presence of debris on the wall.
[0o0a] To prevent the settling of the drill cuttings and debris, the flow rate
of the
circulating fluid may be increased to increase the annular velocity in the
larger annular
areas, However, the higher annular velocity also increases the equivalent
circulating
density ("ECD") and increases the potential of wellbore erosion. ECD is a
measure of
the hydrostatic head and the friction head created by the circulating fluid.
The length of
wellbore that can be formed before it is lined with casing sometimes depends
on the
ECD. The pressure created by ECD is sometimes useful while drilling because it
can
exceed the pore pressure of formations intersected by the weilbore and
prevents
hydrocarbons from entering the wellbore. However, too high an ECD can be a
problem
when it exceeds the fracture pressure of the formation, thereby forcing the
wellbore
fluid into the formations and hampering the flow of hydrocarbons into the
wellbore after
the well is completed.
[0009) Drilling with casing is a method of forming a borehole with a drill bit
attached
to the same string of tubulars that will line the borehole. In other words,
rather than run
a drill bit on smaller diameter drill string, the bit is run at the end of
larger diameter
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tubing or casing that will remain in the weilbore and be cemented therein. The
advantages of drilling with casing are obvious. Because the same string of
tubulars
transports the bit and lines the borehole, no separate trip out of or into the
wellbore is
necessary between the forming of the borehole and the lining of the borehole.
Drilling
with casing is especially useful in certain situations where an operator wants
to drill and
line a borehole as quickly as possible to minimize the time the borehole
remains
unlined and subject to collapse or the effects of pressure anomalies. For
example,
when forming a sub-sea borehole, the initial length of borehole extending from
the sea
floor is much more subject to cave in or collapse as the subsequent sections
of
borehole. Sections of a borehole that intersect areas of high pressure can
lead to
damage of the borehole between the time the borehole is formed and when it is
lined.
An area of exceptionally low pressure will drain expensive drilling fluid from
the
wellbore between the time it is intersected and when the borehole is lined. In
each of
these instances, the problems can be eliminated or their effects reduced by
drilling with
casing.
[0010] The challenges and problems associated with drilling with casing are as
obvious as the advantages. For example, each string of casing must fit within
any
preexisting casing already in the wellbore. Because the string of casing
transporting
the drill bit is left to line the borehole, there may be no opportunity to
retrieve the bit in
the conventional manner. Drill bits made of drillable material, two-piece
drill bits, pilot
bit and underreamer, and bits integrally formed at the end of casing string
have been
used to overcome the problems. For example, a two-piece bit has an outer
portion with
a diameter exceeding the diameter of the casing string. When the borehole is
formed,
the outer portion is disconnected from an inner portion that can be retrieved
to the
surface of the well. Typically, a mud motor is used near the end of the liner
string to
rotate the bit as the connection between the pieces of casing are not designed
to
withstand the tortuous forces associated with rotary drilling, Mud motors are
sometimes operated to turn the bit (and underreamer) at adequate rotation
rates to
make hole, without having to turn the casing string at high rates, thereby
minimizing
casing connection fatigue accumulation. In this manner, the casing string can
be
rotated at a moderate speed at the surface as it is inserted and the bit
rotates at a
much faster speed due to the fluid-powered mud motor.
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[0011] Another challenge for a drilling with casing operation is controlling
ECD.
Drilling with casing requires circulating fluid through the small annular
clearance
between the casing and the newly formed wellbore. The small annular clearance
causes the circulating fluid to travel through the annular area at a high
annular velocity.
The higher annular velocity increases the ECD and may lead to a higher
potential for
wellbore erosion in comparison to a conventional drilling operation.
Additionally, in
small-clearance liner drilling, a smaller annulus is also formed between the
set casing
inner diameter and the drilling liner outer diameter, which further increases
ECD and
may prevent large drilled cuttings from being circulated from the well.
[0012] A need, therefore, exists for apparatus and methods for circulating
fluid
during a drilling operation. There is also a need for apparatus and methods
for forming
a wellbore and lining the wellbore in a single trip. There is a further need
for an
apparatus and methods for circulating fluid to facilitate the forming and
lining of a
wellbore in a single trip. They is yet a further need to cement the lined
wellbore.
SUMMARY OF THE INVENTION
[0013] The present invention relates to time saving methods and apparatus for
constructing and completing offshore hydrocarbon wells. In one embodiment, an
offshore wellbore is formed when an initial string of conductor is inserted
into the earth
at the mud line. The conductor includes a smaller string of casing nested
coaxially
therein and selectively disengageable from the conductor. Also included at a
lower end
of the casing is a downhole assembly including a drilling device and a
cementing
device. The assembly including the conductor and the casing is "jetted" into
the earth
until the upper end of the conductor string is situated proximate the mud
line.
Thereafter, the casing string is unlatched from the conductor string and
another section
of wellbore is created by rotating the drilling device as the casing is urged
downwards
into the earth. Typically, the casing string is lowered to a depth whereby an
annular
area remains defined between the casing string and the conductor. Thereafter,
the
casing string is cemented into the conductor.
[0014] After the cement job is complete, a second string of smaller casing is
run into
the well with a drill string and an expandable bit disposed therein. Once the
smaller
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casing is installed at a desired depth, the bit and drill string are removed
to the surface
and the second casing string is then cemented into place,
[0015) In one aspect, the present invention provides a method for lining a
wellbore.
The method includes providing a drilling assembly comprising an earth removal
member and a wellbore lining conduit, wherein the drilling assembly includes a
first fluid
flow path and a second fluid flow path. The drilling assembly is manipulated
to
advance into the earth. The method also includes flowing a fluid through the
first fluid
flow path and returning at least a portion of the fluid through the second
fluid flow path
and leaving the wellbore lining conduit at a location within the wellbore. In
one
embodiment, the method also includes providing the drilling assembly with a
third fluid
flow path and flowing at least a portion of the fluid through the third fluid
flow path.
After drilling has been completed, the method may further include cementing
the
wellbore lining conduit.
[0016t In another embodiment, the drilling assembly further comprises a
tubular
assembly, a portion of the tubular assembly being disposed within the wellbore
lining
conduit. The method may further include relatively moving a portion of the
tubular
assembly and the wellbore lining conduit. In a further embodiment, the method
may
further comprise reducing the length of the drilling assembly. In yet another
embodiment, the method includes advancing the wellbore lining conduit
proximate a
bottom of the wellbore.
[0017] In another aspect, the present invention provides an apparatus for
lining a
wellbore. The apparatus includes a drilling assembly having an earth removal
member,
a weilbore lining conduit, and a first end. The drilling assembly may include
a first fluid
flow path and a second fluid flow path there through, wherein a fluid is
movable from
the first end through the first fluid flow path and returnable through the
second fluid flow
path when the drilling assembly is disposed in the wellbore. In another
embodiment,
the drilling assembly further comprises a third fluid flow path.
[0018] In another aspect, the present invention provides a method for placing
tubulars in an earth formation. The method includes advancing concurrently a
portion
of a first tubular and a portion of a second tubular to a first location in
the earth.
Thereafter, the second tubular is advanced to a second location in the earth.
In one
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embodiment, the method may include advancing a portion of a third tubular to a
third
location. Additionally, at least a portion of one of the first and second
tubulars may be
cemented into place.
[0019] In another aspect, a method of drilling a welibore with casing is
provided.
The method includes placing a string of casing with a drill bit at the lower
end thereof
into a previously formed wellbore and urging the string of casing axially
downward to
form a new section of welibore. The method further includes pumping fluid
through the
string of casing into an annulus formed between the string of casing and the
new
section of weilbore. The method also includes diverting a portion of the fluid
into an
upper annulus in the previously formed weilbore.
[0020] In another aspect, an apparatus for forming a wellbore is provided. The
apparatus comprises a casing string with a drill bit disposed at an end
thereof and a
fluid bypass formed at least partially within the casing string for diverting
a portion of
fluid from a first to a second location within the casing string as the
weilbore is formed.
[0021] In another aspect, the present invention provides a method of drilling
with
finer, comprising forming a weilbore with an assembly including an earth
removal
member mounted on a work string and a section of liner disposed therearound,
the
earth removal member extending below a lower end of the liner; lowering the
liner to a
location in the weilbore adjacent the earth removal member; circulating a
fluid through
the earth removal member; fixing the liner section in the welibore; and
removing the
work string and the earth removal member from the welibore.
[0022] In another aspect, the present invention provides a method of casing a
welibore, comprising providing a drilling assembly including a tubular string
having an
earth removal member operatively connected to its lower end, and a casing, at
least a
portion of the tubular string extending below the casing; lowering the
drilling assembly
into a formation; lowering the casing over the portion of the drilling
assembly; and
circulating fluid through the casing.
[0023] In another aspect, the present invention provides a method of drilling
with
liner, comprising forming a section of weilbore with an earth removal member
operatively connected to a section of liner; lowering the section of liner to
a location
proximate a lower end of the welibore; and circulating fluid while lowering,
thereby
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urging debris from the bottom of the wellbore upward utilizing a flow path
formed within
the liner section.
[0024} In another aspect, the present invention provides a method of drilling
with
liner, comprising forming a section of wellbore with an assembly comprising an
earth
removal tool on a work string fixed at a predetermined distance below a lower
end of a
section of liner; fixing an upper end of the liner section to a section of
casing lining the
wellbore; releasing a latch between the work string and the liner section;
reducing the
predetermined distance between the lower end of the liner section and the
earth
removal tool; releasing the assembly from the section of casing; re fixing the
assembly to the section of casing at a second location; and circulating fluid
in the
wellbore.
[0025] In another aspect, the present invention provides a method of casing a
wellbore, comprising providing a drilling assembly comprising a casing and a
tubular
string releasably connected to the casing, the tubular string having an earth
removal
member operatively attached to its lower end, a portion of the tubular string
located
below a lower end of the casing; lowering the drilling assembly into a
formation to form
a wellbore; hanging the casing within the wellbore; moving the portion of the
tubular
string into the casing; and lowering the casing into the wellbore.
[0026] in another aspect, the present invention provides a method of cementing
a
liner section in a wellbore, comprising removing a drilling assembly from a
lower end of
the liner section, the drilling assembly including an earth removal tool and a
work string;
inserting a tubular path for flowing a physically alterable bonding material,
the tubular
path extending to the lower end of the liner section and including a valve
assembly
permitting the cement to flow from the lower section in a single direction;
flowing the
physically alterable bonding material through the tubular path and upwards in
an
annulus between the liner section and the wellbore therearound; closing the
valve; and
removing the tubular path, thereby leaving the valve assembly in the wellbore.
[0027] In another aspect, the present invention provides a method of drilling
with
liner, comprising providing a drilling assembly comprising a liner having a
tubular
member therein, the tubular member operatively connected to an earth removal
member and having a fluid path through a wall thereof, the fluid path disposed
above a
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lower portion of the tubular member; lowering the drilling assembly into the
earth,
thereby forming a welibore; sealing an annulus between an outer diameter of
the
tubular member and the welibore; and sealing a longitudinal bore of the
tubular
member; flowing a physically alterable bonding material through the fluid
path, thereby
preventing the physically alterable bonding material from entering the lower
portion of
the tubular member.
[0028] In another aspect, the present invention provides a method for placing
tubulars in an earth formation comprising advancing concurrently a portion of
a first
tubular and a portion of a second tubular to a first location in the earth,
and further
advancing the second tubular to a second location in the earth.
[0029] In another aspect, the present invention provides a method of cementing
a
borehole, comprising extending a drill string into the earth to form the
borehole, the drill
string including an earth removal member having at least one fluid passage
therethrough, the earth removal member operatively connected to a lower end of
the
drill string; drilling the borehole to a desired location using a drilling mud
passing
through the at least one fluid passage; providing at least one secondary fluid
passage
between the interior of the drill string and the borehole; and directing a
physically
alterable bonding material into an annulus between the drill string and the
borehole
through the at least one secondary fluid passage.
[0030] In another aspect, the present invention provides an apparatus for
selectively
directing fluids flowing down a hollow portion of a tubular element to
selective
passageways leading to a location exterior to the tubular element, comprising
a first
fluid passageway from the hollow portion of the tubular member to a first
location; a
second passageway from the hollow portion of the tubular member to a second
location; a first valve member configurable to selectively block the first
fluid
passageway; a second valve member configured to maintain the second fluid
passageway in a normally blocked condition; and the first valve member
including a
valve closure element selectively positionable to close the first valve member
and
thereby effectuate opening of the second valve member.
[0031] in another aspect, the present invention provides a method for lining a
wellbore, comprising forming a wellbore with an assembly including an earth
removal
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member mounted on a work string, a liner disposed around at least a portion of
the work string,
a first sealing member disposed on the work string, and a second sealing
member disposed on
an outer portion of the liner; lowering the liner to a location in the
wellbore adjacent the earth
removal member while circulating a fluid through the earth removal member;
actuating the first
sealing member; fixing the liner section in the wellbore; actuating the second
sealing member;
and removing the work string and the earth removal member from the wellbore.
[0032] At any point in the forgoing process, any of the strings can be
expanded in place by
well known expansion methods, like rolling or cone expansion. An example of a
cone method is
taught in U.S. Patent No. 6,354,373. In simple terms, the cone is placed in a
wellbore at the
lower end of a tubular to be expanded. When the tubular is in place, the cone
is urged upwards
by fluid pressure, expanding the tubular on the way up. An example of a roller-
type expander is
taught in U.S. Patent No 6,457,532. In simple terms, the roller expander
includes radially
extendable roller members that are urged outwards due to fluid pressure to
expand the walls of
a tubular therearound past its elastic limits. Additionally, the apparatus can
utilize ECD
(Equivalent Circulation Density) reduction devices that can reduce pressure
caused by
hydrostatic head and the circulation of drilling fluid. Methods and apparatus
for reducing ECD
are taught in co-pending U.S. Patent No. 6,896,075. In simple terms, that
application describes
a device that is installable in a casing string and operates to redirect fluid
flow traveling between
the inner tubular and the annulus therearound. By adding energy to the fluid
moving upwards in
the annulus, the ECD is reduced to a safer level, thereby reducing the chance
of formation
damage and permitting extended lengths of borehole to be formed without
stopping to case the
wellbore. Energy can be added by a pump or by simply redirecting the fluid
from the inside of
the tubular to the outside.
[0033] Additionally, any of the strings of casing can be urged in a
predetermined direction
through the use of direction changing devices and methods like rotary
steerable systems and
bent housing steerable mud motors. Examples of rotary steerable systems usable
with casing
are shown and taught in U.S. Patent No. 6,708,769. Additionally, any of the
strings can include
testing apparatus, like leak off
CA 02760504 2011-11-30
testing and any can include sensing means for geophysical parameters like
measurement while drilling (MWD) or logging while drilling (LWD). Examples of
MWD
are taught in U.S. Patent No. 6,364,037.
BRIEF DESCRIPTION OF THE DRAWINGS
[0034] So that the manner in which the above recited features of the present
invention
can be understood in detail, a more particular description of the invention,
briefly
summarized above, may be had by reference to embodiments, some of which are
illustrated in the appended drawings, It is to be noted, however, that the
appended
drawings illustrate only typical embodiments of this invention and are
therefore not to be
considered limiting of its scope, for the invention may admit to other equally
effective
embodiments.
[0035] Figure 1 shows an embodiment of the drilling system according to
aspects of
the present invention. The drilling system is shown in the run-in position.
[0036] Figure 1A is a cross-sectional view of Figure 1 take along line 1A-1A.
[0037] Figure 2 is an exploded view of the releasable connection for
connecting the
first casing to the housing of Figure 1.
[0038] Figure 3 is a view of the drilling system after the housing has been
jetted in.
[0039] Figure 4 is a view of the drilling system after the first casing has
been lowered
relative to the housing.
[0040] Figure 5 is a view of the drilling system after the cementing operation
is
completed.
[0041] Figure 6 is a view of the drilling system with a survey tool disposed
therein.
[0042] Figure 7 is a view of a second drilling system according to aspects of
the
present invention.
[0043] Figure 7A is a cross sectional view of the drilling assembly.
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[0044] Figure 8 is a view of the second drilling system after drilling is
completed.
100451 Figure 9 is a view of the second drilling system showing the liner
hanger at
the beginning of the setting sequence.
[00461 Figure 10 show a view of the second drilling after the liner has been
set.
[0047] Figure 11 is a view of the second drilling system showing the full
opening tool
in the open position,
[0048] Figure 12 is a view of the second drilling system after the cementing
operation has completed.
[0049] Figure 12A is an exploded view of the full opening tool in the actuated
position.
[0050] Figure 13 shows another embodiment of the second drilling system
according to aspects of the present invention,
[00511 Figure 13A shows the bypass member of the second drilling system of
Figure
13.
[0052] Figure 14 shows the second drilling system of Figure 13 after the
bypass
ports have been closed.
[00531 Figure 15 shows the second drilling system of Figure 13 after the liner
hanger
has been set.
[00541 Figure 16 shows the second drilling system of Figure 13 after the BHA
has
been pulled up and the internal packer has been inflated.
[0055] Figure 17 shows the second drilling system of Figure 13 after the dart
has
closed the cementing ports and the external casing packer has been inflated.
[00561 Figure 18 shows the second drilling system of Figure 13 after internal
packer
has bee deflated.
[00571 Figure 19 shows the second drilling system of Figure 13 after the BHA
has
been retrieved and the liner hanger packer has been set.
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[00581 Figure 20 shows another embodiment of the second drilling system
according to aspects of the present invention.
[00591 Figure 20A is perspective view of the bypass member of the second
drilling
system of Figure 20.
[00601 Figure 21 shows the second drilling system of Figure 20 after the
bypass
ports have been closed.
[00611 Figure 22 shows the second drilling system of Figure 20 after liner
hanger
has been set.
[00621 Figure 23 shows the second drilling system of Figure 20 after BHA has
been
retrieved and the deployment valve has closed.
[0063] Figure 24 shows the second drilling system of Figure 20 after a cement
retainer has been inserted above the deployment valve.
[00641 Figure 25 shows another embodiment of the second drilling system
according to aspects of the present invention.
[00651 Figure 25A is a perspective view of the bypass member of the second
drilling
system of Figure 25.
[00661 Figure 26 shows the second drilling system of Figure 25 after bypass
ports
have been closed.
[00671 Figure 27 shows the second drilling system of Figure 25 after the liner
hanger
has been set.
[0068] Figure 28 shows the second drilling system of Figure 25 after a packer
assembly has latched into the second casing string.
[00691 Figure 29 shows the second drilling system of Figure 25 after single
direction
plug has been set.
[00701 Figure 30 shows an embodiment of a liner assembly according to aspects
of
the present invention.
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[0071] Figure 30A shows a fluid bypass assembly suitable for use with the
liner
assembly of Figure 30.
[0072] Figure 31 shows the liner assembly of Figure 30 after latch has been
released.
[0073] Figure 32 shows the liner assembly of Figure 30 after the ball has been
pumped into the baffle.
[0074] Figure 33 shows the liner assembly of Figure 30 after the liner has
been
reamed down over the BHA.
[0075] Figure 34 shows the liner assembly of Figure 30 after the hanger has
been
actuated.
[0076] Figure 35 shows the liner assembly of Figure 30 after the running
assembly
is partially retrieved.
[0077] Figure 36 shows another embodiment of a liner assembly according to
aspects of the present invention.
[0078] Figure 37 shows the liner assembly of Figure 36 after the hanger has
been
set.
[0079] Figure 38 shows the liner assembly of Figure 30 after running tool has
been
released.
[0080] Figure 39 shows the liner assembly of Figure 30 after the BHA has been
retracted.
[0081] Figure 40 shows the liner assembly of Figure 30 after the hanger has
been
released.
[0062] Figure 41 shows the liner assembly of Figure 30 after liner is drilled
down to
bottom.
[0083] Figure 42 shows the liner assembly of Figure 30 after the hanger has
been
reset.
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[0084[ Figure 43 shows the liner assembly of Figure 30 after the secondary
latch
has been released.
[0085] Figure 44 shows the liner assembly of Figure 30 after it is partially
retrieved.
[0086] Figure 45 shows cementing assembly according to aspects of the present
invention. The cementing assembly is suitable to perform a cementing operation
after
wellbore has been lined using the methods disclosed in Figures 30-35 or
Figures 36-
44.
[0087] Figure 46 shows the cementing assembly of Figure 45 as the cement is
chased by a dart.
[0088] Figure 47 shows the cementing assembly of Figure 45 after the
circulating
ports have been opened.
[0089] Figure 48 shows the cementing assembly of Figure 45 after weight is
stacked
on top of the liner.
[0090] Figure 49 shows the cementing assembly of f=igure 45 after the packer
has
been set and the work string of the cementing assembly has been retrieved.
[0091] Figure 50 shows an embodiment of a liner assembly for lining and
cementing
the liner in one trip.
[0092] Figure 50A is a cross sectional view of the liner assembly of Figure 50
taken
at line A-A.
[0093] Figure 51 shows the liner assembly of Figure 50 after the hanger has
been
set.
[0094] Figure 52 shows the liner assembly of Figure 50 after the BHA is
coupled to
the casing sealing member.
[0095] Figure 53 shows the liner assembly of Figure 50 after second sealing
member has been inflated.
[0096] Figure 54 shows the liner assembly of Figure 50 after the first dart
has
landed.
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(00971 Figure 55 shows the liner assembly of Figure 50 after circulation sub
has
been opened for cementing.
(00981 Figure 56 shows the liner assembly of Figure 50 after second dart has
landed.
[0099] Figure 57 shows the liner assembly of Figure 50 after the casing
sealing
member has been inflated.
(001001 Figure 58 shows the liner assembly of Figure 50 after the second
sealing
member has been deactuated.
(00101) Figure 59 shows the liner assembly of Figure 50 liner assembly during
retrieval.
[001021 Figure 60 is a cross-sectional view of a drilling assembly having a
flow
apparatus disposed at the lower end of the work string.
[00103] Figure 61 is a cross-sectional view of a drilling assembly having an
auxiliary
flow tube partially formed in a casing string.
(00104) Figure 62 is a cross-sectional view of a drilling assembly having a
main flow
tube formed in the casing string.
(001051 Figure 63 is a cross-sectional view of a drilling assembly having a
flow
apparatus and an auxiliary flow tube combination in accordance with the
present
invention.
(00106] Figure 64 is a cross-sectional view of a drilling assembly having a
flow
apparatus and a main flow tube combination in accordance with the present
invention.
(00107] Figure 65 is a cross-sectional view of a diverting apparatus used for
expanding a casing.
(oolosi Figure 66 is a cross-sectional view of the diverting apparatus of
Figure 65 in
the process of expanding the casing.
[00109] Figure 67 is a schematic view of a welibore, showing a prior art drill
string in
a downhole location suspended from a drilling platform.
16
CA 02760504 2011-11-30
[ooi1ot Figure 68 is a sectional view of the drill string, showing a first
embodiment of
the present invention.
[00111] Figure 69 is a further view of the drill string as shown in Figure 68,
showing
the drill string positioned for cementing operations.
[001121 Figure 70 is a further view of the drill string as shown in Figure 69,
showing
the drill string after cementing thereof has occurred.
[001131 Figure 71 is a sectional view of the drill string, showing an
additional
embodiment of the present invention.
[001141 Figure 72 is a further view of the drill string of Figure 71, showing
the drill
string after cementing has occurred.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT
[oo1i51 Figure 1 is a cross-sectional view of one embodiment of the drilling
system
100 of the present invention in the run-in position. The drilling system 100
includes a
first casing string 10 disposed in a housing 20 such as a conductor pipe and
selectively
connected thereto. The housing 20 defines a tubular having a larger diameter
than the
first casing string 10. Embodiments of the housing 20 and the first casing
string 10 may
include a casing, a liner, and other types of tubular disposable downhole.
Preferably,
the housing 20 and the first casing string 10 are connected using a releasable
connection 200 that allows axial and rotational forces to be transmitted from
the first
casing string 10 to the housing 20. An exemplary releasable connection 200
applicable
to the present invention is shown in Figure 2 and discussed below. The housing
20
may include a mud matt 25 disposed at an upper end of the housing 20. The mud
matt
has an outer diameter that is larger than the outer diameter of the housing 20
to
allow the mud matt 25 to sit atop a surface, such as a mud line on the sea
floor 2, in
25 order to support the housing 20.
[001161 The drilling system 100 may also include an inner string 30 disposed
within
the first casing string 10. The inner string 30 may be connected to the first
casing string
10 using a releasable latch mechanism 40. During operation, the latch
mechanism 40
may seat in a landing seat 27 provided in an upper end of the housing 20. An
example
17
CA 02760504 2011-11-30
of an appropriate latch mechanism usable with the present invention includes a
latch
mechanism such as ABB VGl Fullbore Wellhead manufactured by ABB Vetco. At one
end, the inner string 30 may be connected to a drill string 5 that leads back
to the
surface. At another end, the inner string 30 may be connected to a stab-in
collar 90.
[00117] Disposed at a lower end of the first casing string 10 is a drilling
member or
earth removal member 60 for forming a borehole 7. Preferably, an outer
diameter of the
drilling member 60 is larger than an outer diameter of the first casing string
10. The
drilling member 60 may include fluid channels 62 for circulating fluid. In
another
embodiment, the fluid channels 62, or nozzles, may be adapted for directional
drilling.
An exemplary drilling member 60 having such a nozzle is disclosed in co-
pending U.S.
Patent Application Publication No. 2004/0245020 filed February 2, 2004. A
centralizer 55
may be utilized to keep the drilling member 60 centered. The first casing
string 10 may
also include a float collar 50 having an orienting device 52, such as a mule
shoe, and a
survey seat 54 for maintaining a survey tool.
[00118] The inner string 30 may include a ball seat 70, a ball receiver 80,
and a stab-
in collar 90 at its lower end. Preferably, the ball seat 70 is an extrudable
ball seat 70,
wherein a ball 72 disposed may be extruded therethrough. In one example, the
ball seat
70 may be made of brass. Aspects of the present invention contemplate other
types of
extrudable ball seat 70 known to a person of ordinary skill in the art. The
ball seat 70
may also include ports 74 for fluid communication between an interior of the
inner string
and an annular area 12 between the inner string 30 and the first casing string
10. The
ports 74 may be opened or closed using a selectively connected sliding sleeve
76 as is
25 known in the art. The ball receiver 80 is disposed below the ball seat 70
in order to
receive the ball 72 after it has extruded through the ball seat 70. The ball
receiver 80
receives the ball 72 and allows fluid communication in the inner string 30 to
be re-
established.
30 [00119] Disposed below the ball seat 70 is a stab-in collar 90. Preferably,
the stab-in
collar 90 includes a stinger 93 selectively connected to a stinger receiver
94. During
operation, the stinger 93 may be caused to disconnect from the stinger
receiver 94.
18
CA 02760504 2011-11-30
[00120) Shown in Figure 2 is an embodiment of the releasable connection 200
capable of selectively connecting the housing 20 to the first casing string
10. The
connection 200 includes an inner sleeve 210 disposed around the first casing
string 10.
A piston 215 is disposed in an annular area 220 between the inner sleeve 210
and the
first casing string 10. The piston 215 is temporarily connected to the inner
sleeve 210
using a shearable pin 230. A port 225 is formed in the first casing string 10
for fluid
communication between the interior of the first casing string 10 and the
annular area
220. The inner sleeve 210 is selectively connected to an outer sleeve 235
using a
locking dog 240. The outer sleeve 235 is connected to the housing 20 using a
biasing
member 245 such as a spring loaded dog 245. The outer sleeve 235 may
optionally be
connected to the housing 20 using an emergency release pin 250. A locking dog
profile 255 is formed on the piston 215 for receiving the locking dog 240
during
operation. In another embodiment, the releasable connection includes a J-slot
release
as is known to a person of ordinary skill in the art.
[00121] Figure 1A is a cross-sectional view of Figure 1 taken along line 1A-1
A. It can
be seen that releasable connection 200 is fluid bypass member 17. The bypass
member 17 may comprise one or more radial spokes circumferentially disposed
between the first casing string 10 and the housing 20. In this respect, one or
more
bypass slots are formed between the spokes for fluid flow therethrough. The
fluid
bypass member 17 allows fluid to circulate during welibore operations, as
described
below.
[00122) In operation, the drilling system 100 of the present invention is
partially
lowered into the sea floor 2 as shown in Figure 1. The drilling system 100 is
initially
inserted into the sea floor 2 using a jetting action. Particularly, fluid is
pumped through
the inner string 30 and exits the flow channels 162 of the drilling member 60.
The fluid
may create a hole in the sea floor 2 to facilitate the advancement of the
drilling system
100. At the same time, the drilling system 100 is reciprocated axially to
cause the
housing 20 to be inserted into the sea floor 2. The drilling system 100 is
inserted into
the sea floor 2 until the mud matt 25 at the upper end of the housing 20 is
situated
proximate the mud line of the sea floor 2 as shown in Figure 3.
[00123) The first casing string 10 is now ready for release from the housing
20. At
this point, a ball 72 is dropped into the inner string 30 and lands in the
ball seat 70.
19
CA 02760504 2011-11-30
After seating, the ball 72 blocks fluid communication from above the ball 72
to below
the ball 72 in the inner string 30. As a result, fluid in the inner string 30
above the ball
72 is diverted out of the ports 74 in the ball seat 70. This allows pressure
to build up in
the annular area 12 between the inner string 30 and the first casing string
10.
[00124] The fluid in the annular area 12 may be used to actuate the releasable
connection 200. Specifically, fluid in the annular area 12 flows through the
port 225 in
the first casing string 10 and into the annular area 220 between inner sleeve
210 and
the first casing string 10, The pressure increase causes the shearable pin 230
to fail,
thereby allowing the piston 215 to move axially. As the piston 215 moves, the
locking
dog profile 255 slides under the locking dog 240, thereby allowing the locking
dog 240
to move away from the outer sleeve 235 and seat in the locking dog profile
255. In this
respect, the inner sleeve 210 is freed to move independently of the outer
sleeve 235.
In this manner, the first casing string 10 is released from the housing 20.
[00125) Thereafter, the pressure is increased above the ball 72 to extrude the
ball 72
from the ball seat 70. The ball 72 falls through the ball seat 70, through the
stab-in
collar 90, and lands the ball receiver 80, as shown in Figure 4. This, in
turn, re-opens
fluid communication from the inner string 30 to the drilling member 60. In
addition, the
increase in pressure causes the sliding sleeve 76 of the ball seat 70 to close
the ports
74 of the ball seat 70.
[001261 The drilling member 60 is now actuated to drill a borehole 7 below the
housing 20. The outer diameter of the drilling member 60 is such that an
annular area
97 is formed between the borehole 7 and the first casing string 10. Fluid is
circulated
through the inner string 30, the drilling member 60, the annular area 97, the
housing 20,
and the bypass members 17. The depth of the borehole 7 is determined by the
length
of the first casing string 10. The drilling continues until the latch
mechanism 40 on the
first casing string 10 lands in the landing seat 27 disposed at the upper end
of the
housing 20 as shown in Figure 5.
[00127Thereafter, a physically alterable bonding material such as cement is
pumped down the inner string 30 to set the first casing string 10 in the
wellbore. The
cement flows out of the drilling member 60 and up the annular area 97 between
the
borehole 7 and the first casing string 10. The cement continues up the annular
area 97
CA 02760504 2011-11-30
and fills the annular area between the housing 20 and the first casing string
10. When
the appropriate amount of cement has been supplied, a dart 98 is pumped in
behind
the cement, as shown in Figure 5. The dart 98 ultimately positions itself in
the stinger
93. Thereafter, the latch 40 is release from the housing 20 and the first
casing string
10. Then the drill string 5 and the inner string 30 are removed from the first
casing
string 10. The inner string 30 is separated from the stab-in collar 90 by
removing the
stinger 93 from the stinger receiver 94. The stinger 93 is removed with the
inner string
30 along with the ball seat 70.
[00128] In another aspect, a wellbore survey tool 96 landed on orientation
seat 52
may optionally be used to determine characteristics of the borehole before the
cementing operation as illustrated in Figure 6. The survey tool 96 may contain
one or
more geophysical sensors for determining characteristics of the borehole. The
survey
tool 96 may transmit any collected Information to surface using wireline
telemetry, mud
pulse technology, or any other manner known to a person of ordinary skill in
the art.
[001291 In another aspect, the present invention provides methods and
apparatus for
hanging a second casing string 120 from the first casing string 10. Shown in
Figure 7 is
a second drilling system 102 at least partially disposed within the first
casing string 10.
In addition to the second casing string 120, the second drilling system 102
includes a
drill string 110 and a bottom hole assembly 125 disposed at a lower end
thereof. The
bottom hole assembly 125 may include components such as a mud motor; logging
while drilling system; measure while drilling systems; gyro landing sub; any
geophysical
measurement sensors; various stabilizers such as eccentric or adjustable
stabilizers;
and steerable systems, which may include bent motor housings or 3D rotary
steerable
systems. The bottom hole assembly 125 also has a earth removal member or
drilling
member 115 such as a pilot bit and underreamer combination, a bi-center bit
with or
without an underreamer, an expandable bit, or any other drilling member that
may be
used to drill a hole having a larger inner diameter than the outer diameter of
any
component disposed on the drill string 110 or the first casing string 10, as
is known in
the art. The drilling member 115 may include nozzles or jetting orifices for
directional
drilling. As shown, the drilling member 115 is an expandable drill bit 115.
fool3o] The drill string 110 may also include a first ball seat 140 having
bypass ports
142 for fluid communication between an interior of the drill string 110 and an
exterior of
21
CA 02760504 2011-11-30
the second casing string 120. As shown in Figure 7A, the first ball seat 140
comprises
a fluid bypass member 145. Preferably, the bypass ports 142 are disposed
within the
spokes of the bypass member 145. The spokes extend radially from the drill
string 110
to the annular area 146 between the first casing string 10 and the second
casing string
120. The spokes are adapted to form one or more bypass slots 147 for fluid
communication along the interior of the second casing string 120.
Specifically, bypass
member 145 is shown with four spokes are shown in Figure 7A. A sealing member
148
may be disposed in the annular area 146 at an upper portion of the second
casing
string 120 to block fluid communication between the annular area 146 and the
interior
of the first casing string 10 above the second casing string 120. In one
embodiment,
the first ball seat 140 may be an extrudable ball seat.
[00131] The drill string 110 further includes a liner hanger assembly 130
disposed at
an upper end thereof. The liner hanger 130 temporarily connects the drill
string 110 to
the second casing string 120 by way of a running tool and may be used to hang
the
second casing string 120 off of the first casing string 10. The liner hanger
130 includes
a sealing element and one or more gripping members- An example of suitable
sealing
element is a packer, and an example of a suitable gripping member is a
radially
extendable slip mechanism. Other types of suitable sealing elements and
gripping
members known to a person of ordinary skill in the art are also contemplated.
[001321 The liner hanger 130 is placed in fluid communication with a second
ball seat
135 disposed on the drill string 110. The second ball seat 135 comprises a
fluid bypass
member. Fluid may be supplied through ports 137 to actuate the slips of the
liner
hanger 130. The packing element may be set when the slips are set or
mechanically
set when the drill string 110 is retrieved. Preferably, the packing element is
set
hydraulically when the slips are set. In one embodiment, the second ball seat
135 is an
extrudable ball seat similar to the ones described above.
[00153] The second drilling system 102 may also include a full opening tool
150
disposed on the second casing string 120 for cementing operations. The full
opening
tool 150 is actuated by an actuating tool 160 disposed on the drill string
110. The
actuating tool 160 may also comprise a fluid bypass member 145. The spokes of
the
actuating tool 160 may also contain cementing ports 170. The bypass slots 147
disposed between the spokes allow continuous fluid communication axially along
the
22
CA 02760504 2011-11-30
interior of the second casing string 120. It must be noted that the spokes of
the bypass
members 145 discussed herein may comprise other types of support member of
design
capable of allowing fluid flow in an annular area as is known to a person of
ordinary skill
in the art. The actuating tool 160 Includes a sleeve 162 having sealing cups
164
dispose at each end. The sealing cups 164 enclose an annular area 167 between
the
sleeve 162 and the second casing string 120. Disposed between the sealing cups
are
upper and lower collets 166 for opening and closing the ports 155 of the full
opening
tool 150, respectively.
[00134] A third ball seat 180 is disposed on the drill string 110 and in fluid
communication with the annular area 167 between the sealing cups 164. The ball
seat
180 is a fluid bypass member 175 having one or more bypass ports 170 for fluid
communication between the interior of the drill string 110 and the enclosed
annular
area 167. The drill string 110 may further include circulating ports 185
disposed above
the third ball seat 180. Figure 12A in an exploded view of full opening tool
150
actuated by the actuating tool 160.
[00135] The drill string 110 may further include a centralizer 190 or a
stabilizer. The
centralizer 190 may also comprise a fluid bypass member. Preferably, the
spokes of
the centralizer 190 do not have bypass ports. The bypass slots disposed
between the
spokes allow continuous fluid communication axially along the interior of the
second
casing string 120. It must be noted that the spokes of the bypass members
discussed
herein may comprise other types of support member or design capable of
allowing fluid
flow in an annular area as is known to a person of ordinary skill in the art.
In one
embodiment, the centralizer 190 may comprise a bladed stabilizer.
[00136] In operation, the second drilling system 102 is lowered into the first
casing
string 10 as illustrated in Figure 7. In this embodiment, the second drilling
system 102
is actuated to drill through the drilling member 60 of the first drilling
system 100. The
expandable bit 115 may be expanded to form a borehole 105 larger than an outer
diameter of the second casing string 120. The bit 115 continues to drill until
it reaches
a desired depth in the wellbore to hang the second casing string 120 as shown
in
Figure 8. During drilling, some of the fluid is allowed to flow out of the
ports 142 in the
first ball seat 140 and into the annular area 146 between the first and second
casing
string 10, 120. The position of the sealing member 148 forces the diverted
fluid in the
23
CA 02760504 2011-11-30
annular area 146 to flow downward in the weilbore. The advantages of the
diverted
fluid include lubricating the casing string 120 and helps remove cuttings from
the
borehole 105. Fluid in the lower portion of the wellbore is circulated up the
wellbore
inside the second casing string 120. The bypass members 145, 175 disposed
along
the second casing string 120 allow the circulated fluid, which may contain
drill cuttings,
to travel axially inside the second casing string 120. In this respect, fluid
may be
circulated inside the second casing string 120 instead of the small annular
area
between the second casing string 120 and the newly formed wellbore. In this
manner,
fluid circulation problems associated with drilling and lining the wellbore in
one trip may
be alleviated.
[00137] When the drilling stops, a ball Is dropped into the first ball seat
140 as shown
in Figure 8. Pressure is increased to extrude the ball through the first ball
seat 140 and
close off the ports 142 of the first ball seat 140. The ball is allowed to
land in a ball
catcher (not shown) in the drill string 110. Alternatively, the ball may land
in the second
ball seat 135.
[00138] if the ball does not land in the second ball seat 135, a second ball
may be
dropped into the second ball seat 135 of the liner hanger assembly 130 as
shown in
Figure 9. Preferably, the second ball is larger in size than the first ball.
After the ball
seats, pressure is supplied to the liner hanger 130 through the ball seat
ports 137 to
actuate the liner hanger 130. Initially, the packer is set and the slip
mechanism is
actuated to support the weight of the second casing string 120. Thereafter,
the
pressure is increased to disengage the drill string 10 from the second casing
string 120,
thereby freeing the drill string 110 to move independently of the second
casing string
120 as shown in Figure 10. The ball is allowed to extrude the second ball seat
135 and
land in the ball catcher in the drill string 110.
[001391 Thereafter, the drill string 110 is axially traversed to move the
actuating tool
160 relative to the full opening tool 150. As the actuating tool 160 is pulled
up, the
upper collets 166 of the actuating tool 160 grab a sleeve in the full opening
tool 150 to
open the ports 155 of the opening tool 150 for cementing operation as shown in
Figure
11. Preferably, the drill string 110 is pulled up sufficiently so that the
bottom hole
assembly 125 with bit 115 is above the final height of the cement.
24
CA 02760504 2011-11-30
[001401 A third ball, or a second ball if the first ball was used to activate
both the first
and second ball seats 135, 140, is now dropped into the third ball seat 180 to
close off
communication below the drill string 110. Fluid may now be pumped down the
drill
string 110 and directed through ports 170. Initially, a counterbalance fluid
is pumped in
ahead of the cement in order to control the height of the cement. Thereafter,
cement
supplied to the drill string 110 flows through ports 170 and 155 of the full
opening tool
150 and exits into the annular area between the borehole 105 and the second
casing
string 120. The sealing cups 164 ensure the cement between the upper and lower
collets 166 exit through the port 155. The cement travels down the exterior of
the
second casing string 120 and comes back up through the interior of the second
casing
string 120. The fluid bypass capability of the actuating tool 160 and the
centralizer 190
facilitate the movement of fluids in the second casing string 120. Preferably,
the height
of the cement in the second casing string 120 is maintained below the drill
bit 115 by
the counterbalance fluid. In this respect, the bottom hole assembly 125, which
may
include the drilling member 115, the motor, LWD tool, and MWD tool may be
preserved
and retrieved for later use.
[001411 After a sufficient amount of cement has been supplied, a dart 104 is
pumped
in behind the cement as shown in Figure 12. The dart 104 lands above the ball
in the
third ball seat 180, thereby closing off fluid communication to the full open
tool 150.
Additionally, the landing of the dart 104 opens the circulating ports 185 of
the drill string
110. Once opened, fluid may optionally be circulated in reverse, i.e., down
the exterior
of the drill string 110 and up the interior of the drill string 110, to clean
the interior of drill
string 110 and remove the cement. Thereafter, the drill string 110, including
the bottom
hole assembly 125, may be removed from the second casing string 120. In this
manner, a welibore may be drilled, lined, and cemented in one trip.
[00142] Figuresl3-19 show another embodiment of the second drilling system
according to aspects of the present invention. The second drilling system 302
includes
a second casing string 320, a drill string 310, and a bottom hole assembly
325. Similar
to the embodiment shown in Figure 7, the drill string 310 is equipped with a
second ball
seat 335 and a hydraulically actuatable liner hanger assembly 330. The liner
hanger
330 includes a liner hanger packing element and slip mechanisms as is known to
a
person of ordinary skill in the art. The drill string 310 also includes a
first'ball seat 340
coupled to a bypass member 345 having bypass ports 337 in fluid communication
with
CA 02760504 2011-11-30
the drill string 310 and the annulus 346 between the second casing string 320
and the
first casing string 10. Preferably, the spokes of the bypass member 345 are
arranged
are shown in Figure 13A. A sealing member 348 is used to block fluid
communication
between the annulus 346 and the interior of the first casing string 10 above
the second
casing string 320. Because many of the components in Figure 13 are
substantially the
same as the components shown and described in Figure 7, the above description
and
operation of the similar components with respect to Figure 7 apply equally to
the
components of Figure 13.
[00143] The second drilling system 302 utilizes one or more packers to
facilitate the
cementing operation. In one embodiment, the second drilling system 302
includes an
external casing, packer 351 located near the bottom of the outer surface of
the second
casing string 320. Preferably, the external packer 351 comprises a metal
bladder
inflatable packer. The external packer 351 may be inflated using gases
generated by
mixing one or more chemicals. In one embodiment, the chemicals are mixed
together
by an internal packer system that is activated by mud pulse signals sent from
the
surface.
[00144) The second drilling system 302 also includes an internal packer 352
disposed on the drill string 310 adapted to close off fluid communication in
the annulus
between the drill string 310 and the second casing string. 320. Preferably,
the internal
packer 352 comprises an inflatable packer and is disposed above one or more
cementing ports 370. The inflation port of the internal packer 352 may be
regulated by
a selectively actuatable sleeve. In one embodiment, one or both of the packers
351,
352 may be constructed of an elastomeric material. It is contemplated that
other types
of selectively actuatable packers or sealing members may be used without
deviating
from aspects of the present invention,
[00145) In operation, the drill string 310 is operated to advance the second
casing
string 320 as shown in Figure 13. During drilling, return fluid is circulated
up to the
surface through the interior of the second casing string 320. The return fluid
may
include the diverted fluid in the annulus 346 between the first casing string
10 and the
second casing string 320.
26
CA 02760504 2011-11-30
[001461 After a desired interval has been drilled, a ball is dropped to close
off the
bypass ports 337 of the bypass member 345, as illustrated in Figure 14.
Thereafter,
the ball may extrude through the first ball seat 340 to land in the second
ball seat 335,
as shown in Figure 15. Alternatively, a second ball may be dropped to land in
the
second ball seat 335. Pressure is supplied to set the liner hanger 330 to hang
the
second casing string 320 off of the first casing string 10. However, the liner
hanger
packing element is not set. Then, the running tool is released from the liner
hanger
330, as shown in Figure 15. The ball in the second ball seat 335 may be forced
through to land in a ball catcher (not shown). Thereafter, the drill string
310 is pulled up
until the BHA 325 is inside the second casing string 320, as shown in Figure
16.
[00147] The cementing operation is initiated when another ball dropped in the
drill
string 310 lands in the third ball seat 380. The ball shifts the sleeve to
expose the
inflation port of the internal casing packer 352. Then, the internal packer
352 is inflated
to block fluid communication in the annulus between the drill string 310 and
the second
casing string 320. After inflation, pressure is increased to shift the sleeve
down to open
the cementing port. In this respect, fluid Is circulated down the drill string
310, out the
port(s) 370, down the annulus between the second casing string 320 and the
bottom
hole assembly 325 to the bottom of the second casing string 320, and up the
annulus
between the second casing string 320 and the borehole.
[001481 In Figure 17, cement is pumped down the drill string 310 followed by a
latch
in dart 377. After the dart 377 latches in to signal cement placement, mud
pulse is sent
from the surface to cause the external casing packer 351 to inflate. Once
inflated, the
external casing packer 351 holds the cement between the second casing string
320
and the borehole in place.
[00149] Pressure is applied on the dart 377 to cause the sleeve to shift
further, which,
in turn, causes the internal packer 352 to deflate, as shown in Figure 18,
Additionally,
shifting the sleeve opens the circulation port for reverse circulation. Fluid
is then
reverse circulated to remove excess cement from the interior of the drill
string 310.
[001501 Upon completion, the drill string 310 is pulled out of the second
casing string
320 to retrieve the BHA 325, as shown in Figure 19. The liner hanger packer is
set as
the drill string 310 is retrieved.
27
CA 02760504 2011-11-30
[001511 Figure 20 shows another embodiment of the second drilling system
according to aspects of the present invention. The second drilling system 402
includes
a second casing string 420, a drill string 410, and a bottom hole assembly
425, which is
shown in Figure 23. Similar to the embodiment shown in Figure 7, the drill
string 410 is
equipped with a second ball seat 435 and a hydraulically actuatable liner
hanger
assembly 430. The liner hanger 430 includes a liner hanger packing element 432
and
slip mechanisms 434 as is known to a person of ordinary skill in the art. The
drill string
410 also includes a first ball seat 440 coupled to a bypass member 445 having
bypass
ports 437 in fluid communication with the drill string 410 and the annulus 446
between
the second casing string 420 and the first casing string 10. Preferably, the
spokes of
the bypass member 445 are arranged as shown in Figure 20A. A sealing member
448
is used to block fluid communication between the annulus 446 and the interior
of the
first casing string 10 above the second casing string 420. Because many of the
components in Figure 20, e.g., the first and second ball seats 435, 440, are
substantially the same as the components shown and described in Figure 7, the
above
description and operation of the similar components with respect to Figure 7
apply
equally to the components of Figure 20.
[001521 The second drilling system 402 features a deployment valve 453
disposed at
a lower end of the second casing string 420. In one embodiment, the deployment
valve
453 is adapted to allow fluid flow in one direction and is an integral part of
the second
casing string 420. Preferably, the deployment valve 453 is actuated using mud
pulse
technology.
[00153) The second drilling system 402 may also include a full opening tool
450
disposed on the second casing string 420. The full opening tool 450 comprises
a
casing port 455 disposed in the second casing string 420 and an alignment port
456
disposed on a flow control sleeve 454. The flow control sleeve 454 is disposed
interior
to the second casing string 420. The flow control sleeve 454 may be actuated
to align
(misalign) the alignment port 456 with the casing port 455 to establish
(close) fluid
communication.
X30 [001541 in operation, the drill string 410 is operated to advance the
second casing
string 420 as shown in Figure 20. The deployment valve 453 is run-in in the
open
position. During drilling, return fluid is circulated up to the surface
through the interior of
28
CA 02760504 2011-11-30
the second casing string 420. The return fluid may include the diverted fluid
in the
annulus 446 between the first casing string 10 and the second casing string
420.
[00156] After a desired interval has been drilled, a ball is dropped to close
off the
bypass ports 437 of the bypass member 445, as illustrated in Figure 21.
Thereafter,
additional pressure is applied to extrude the ball through the first ball seat
440 to land in
the second ball seat 435, as shown in Figure 22. More pressure is then applied
to set
the liner hanger 430 to hang the second casing string 420 off the first casing
string 10.
As shown, the slips 434 have been expanded to engage the first casing string
10.
However, the liner hanger packing element 432 has not been set. After the
second
casing string 420 is supported by the first casing string 10, the running too]
is released
from the liner hanger 430 and the drill string 410 is retrieved.
[00156] As shown in Figure 23, when the BHA 425 is retrieved past the
deployment
valve 453, a mud pulse may be transmitted to close the deployment valve 453.
In this
respect, risk of damage to the BHA 425 during the cementing operation is
prevented.
The liner hanger packing element 432 may also be mechanically set as the drill
string
410 is being pulled out of the wellbore.
[001571 'thereafter, a cement retainer 458 and an actuating tool 460 for
operating the
full opening tool 450 is tripped into the wellbore, as shown in Figure 24. The
tools 458,
460 may be located above the deployment valve 453 using conveying member 411,
such as a work string as is known to a person of ordinary skill in the art. In
one
embodiment, the cement retainer 458 includes a packer 457 and a flapper valve
459.
The actuating tool 460 may include one or more collets 466 for engaging the
flow
control sleeve 454. Additionally, one or more sealing cups 464 are disposed
above the
collets 466 so as to enclose an area between the sealing cups 464 and the
cement
retainer 458. The conveying member 411 also includes a cementing port tool 480
disposed between the sealing cups and the cement retainer 458. The cementing
port
tool 480 may be actuated to allow fluid communication between the conveying
member
411 and the annulus between the conveying member 411 and the second casing
string
420,
[00158] The cement retainer is set in the interior of the second casing string
420
above the deployment valve 453. Cement is then supplied through the drill
string 410
29
CA 02760504 2011-11-30
and pumped through cement retainer 458 and the deployment valve 453, and exits
the
bottom of the second casing string 420. A sufficient amount of cement is
supplied to
squeeze off the bottom of the second casing string 420. Thereafter, a setting
tool (not
shown) is removed from the cement retainer 458, and the drill string 410 is
pulled up
hole. The deployment valve 453 and the cement retainer 458 are allowed to
close and
contain the cement below the cement retainer 458 and the deployment valve 453.
[ootasf As the drill string 410 is pulled up, the collets 466 of the actuating
tool 460
engage the flow control sleeve 454. The flow control sleeve 454 is shifted to
align the
alignment port 456 with the casing port 455, thereby opening the casing port
455 for
fluid communication, Then, a ball is dropped into the cementing port tool 480
to block
fluid communication with the lower portion of the drill string 410 and the
cement retainer
setting tool (not shown). Pressure is supplied to open the cementing port tool
480 to
squeeze cement into an upper portion of the annulus between the second casing
string
420 and the welibore. Specifically, cement is allowed to flow out of the
conveying
member 411 and through the casing port 455. Once the upper portion of the
annulus is
squeezed off, the cementing retainer setting tool (not shown) and the
actuating tool 460
may be retrieved.
[oot6o] Figure 25 shows another embodiment of the second drilling system
according to aspects of the present invention. The second drilling system 502
includes
a second casing string 520, a drill string 510, and a bottom hole assembly
(not shown).
Similar to the embodiment shown in Figure 7, the drill string 510 is equipped
with a
second ball seat 535 and a hydraulically actuatable liner hanger assembly 530
having
one or more slip mechanisms 534. The drill string 510 also includes a first
ball seat
540 coupled to a bypass member 545 having bypass ports 537 in fluid
communication
with the drill string 510 and the annulus 546 between the second casing string
520 and
the first casing string 10. Preferably, the spokes of the bypass member 545
are
arranged as shown in Figure 25A. A sealing member 548 is used to block fluid
communication between the annulus 546 and the interior of the first casing
string 10
above the second casing string 520. Because many of the components in Figure
25,
e.g., first and second ball seats 535, 540, are substantially the same as the
components shown and described in Figure 7, the above description and
operation of
the similar components with respect to Figure 7 apply equally to the
components of
Figure 25.
CA 02760504 2011-11-30
[00161] In operation, the drill string 510 is operated to advance the second
casing
string 520 as shown in Figure 25. During drilling, return fluid is circulated
up to the
surface through the interior of the second casing string 520. The return fluid
may include
the diverted fluid in the annulus 546 between the first casing string 10 and
the second
casing string 520.
[00162] After a desired interval has been drilled, a ball is dropped to close
off the
bypass ports 537 of the bypass member 545, as illustrated in Figure 26.
Thereafter, a
second ball is dropped to land in the second ball seat 535, as shown in Figure
27.
Alternatively, additional pressure is applied to extrude the first ball
through the first ball
seat 540 to land in the second ball seat 535. More pressure is then applied to
set the
liner hanger 530 to hang the second casing string 520 off the first casing
string 10. As
shown, the slips 534 have been expanded to engage the first casing string 10.
It can be
seen that, in this embodiment, the liner hanger assembly 530 does not have a
packing
element to seal the annulus 546 between the first casing string 10 and the
second
casing string 520. Additional pressure is then applied to the ball to extrude
it through the
second ball seat 535 so that it can travel to a ball catcher (not shown) in
drill string 510.
After the second casing string 520 is supported by the first casing string 10,
the running
tool is released from the liner hanger 530, and the drill string 510 and the
BHA 525 are
retrieved.
(00163] To cement the second casing string 520, a packer assembly 550 is
tripped
into the wellbore using the drill string 510. The packer assembly 550 may
latch into the
top of the liner hanger 530 as shown in Figure 28. To this end, the interior
of the second
casing string 520 is placed in fluid communication with the packer assembly
550.
[00164] In one embodiment, the packer assembly 550 includes a single direction
plug
560, a packer 557 for the top of the liner hanger 530, and a plug running
packer setting
tool 558 for setting the packer 557. Preferably, the single direction plug is
adapted for
subsurface release. An exemplary single direction plug is disclosed in a U.S.
patent no.
7,128,154. For example, the single direction plug 560 may include a body 562
and
gripping members 564 for preventing movement of the body 562 in a first axial
direction
relative to tubular. The plug 560 further comprises a
31
CA 02760504 2011-11-30
sealing member 566 for sealing a fluid path between the body 562 and the
tubular.
Preferably, the gripping members 564 are actuated by a pressure differential
such that
the plug 560 is movable in a second axial direction with fluid pressure but is
not
movable in the first direction due to fluid pressure.
[00165] Cement is pumped down the drill string 510 and the second casing
string 520
followed by a dart 504. The dart 504 travels behind the cement until it lands
in the
single direction plug 560. The increase in pressure behind the dart 504 causes
the
single direction plug 560 to release downhole. The plug 560 is pumped downhole
until
it reaches a position proximate the bottom of the second casing string 520. A
pressure
differential is created to set the single direction plug 560. In this respect,
the single
direction plug 560 will prevent the cement from flowing back Into the second
casing
string 520.
[001661 Thereafter, a force is applied to the plug running packer setting tool
558 to
set the packer 557 to seal off the annulus 546 between the second casing
string 520
and the first casing string 10. The drill string 510 is then released from the
liner hanger
530. Reverse circulation may optionally be performed to remove excess cement
from
the drill string 510 before retrieval. Figure 29 shows the second casing
string 520 after
it has been cemented into place.
(001671 Alternate embodiments of the present invention provide methods and
apparatus for subsequently casing a section of a weilbore which was previously
spanned by a portion of a bottom hole assembly ("BHA") extending below a lower
end
of a liner or casing during a drilling with the casing operation. Embodiments
of the
present invention advantageously allow for circulation of drilling fluid while
drilling with
the casing and while casing the section of the weilbore previously spanned by
the
portion of the BHA extending below the lower end of the liner.
[00166) Figure 30 shows a first casing 805 which was previously lowered into a
wellbore 881 and set therein, preferably by a physically alterable bonding
material such
as cement. In the alternative, the casing 805 may be set within the wellbore
881 using
any type of hanging tool Preferably, the first casing 805 is drilled into an
earth
formation by jetting and/or rotating the first casing 805 to form the wellbore
881.
32
CA 02760504 2011-11-30
[00169] Disposed within the first casing 805 is a second casing or liner 810,
Connected to an outer surface of an upper and of the liner 810 is a setting
sleeve 802
having one or more sealing members 803 disposed directly below the setting
sleeve
802, the sealing members 803 preferably including one or more sealing elements
such
as packers. The sealing members 803 could also be an expandable packer, with
an
elastomeric material creating the seal between the liner 810 and the first
casing 805. A
setting sleeve guard 801 disposed on a drill string 815 (see below) has an
inner
diameter adjacent to an outer diameter of a running tool 825, and a recess in
the
setting sleeve guard 801 houses a shoulder of the setting sleeve 802 therein.
A
shoulder on the drill string 815 prevents the setting sleeve guard 801 from
stroking the
setting sleeve 802 downwards while working the drill string 815 up and down in
the
wellbore 881 during the drilling process (see below). The setting sleeve guard
801
prevents the setting sleeve 802 from being actuated prior to the cementation
process
(shown and described below in relation to Figures 45-49).
[00170] The liner 810 includes a liner hanger 820 on a portion of its outer
diameter;
the liner hanger 820 having one or more gripping members 821, preferably
slips, on its
outer diameter, The liner hanger 820 is disposed directly below the sealing
member
803. The liner hanger 820 further includes a sloped surface 822 on the outer
diameter
of the liner 810 along which the gripping members 821 translate radially
outward to
hang the liner 810 off the inner diameter of the casing 805. At a lower end of
the liner
810, a liner shoe 889 may exist.
[00i7i] The liner 810 has a drill string 815, which may also be termed a
circulating
string, disposed substantially coaxially therein and releasably connected
thereto. The
drill string 815 is a generally tubular-shaped body having a longitudinal bore
therethrough. The drill string 815 and the liner 810 form a liner assembly
800. Figure
shows the liner assembly 800 drilled to the liner 810 setting depth within the
formation.
[001721 The drill string 815 includes a running tool 825 at its upper end and
a BHA
885 telescopically connected to a lower end of the running tool 825.
Specifically, the
30 running tool 825 includes a latch 840. An outer surface of the running tool
825 has a
recess 827 therein for receiving a radially extendable latching member 826.
The
latching member 826 is radially extendable into a recess 828 in an inner
surface of the
33
CA 02760504 2011-11-30
liner 810 to releasably engage the liner 810. When the latching member 826 is
extended into the recess 828 of the liner 810, the liner 810 and the drill
string 815 are
latched together.
[001731 The BHA 885 includes a first telescoping joint 850 at its upper end
which is
disposed concentrically within the lower end of the running too[ 825 so that
the first
telescoping joint 850 and the running tool 825 are moveable longitudinally
relative to
one another. The lower end of the first telescoping joint 850 is then disposed
concentrically around an upper end of a second telescoping joint 855. The
first and
second telescoping joints 850 and 855 are also moveable longitudinally
relative to one
another.
[001743 It is contemplated that a plurality of telescoping joints 850, 855 may
be
utilized rather than merely the two telescoping joints 850, 855 shown,
depending at
least partially upon the length of the BHA 885 that is exposed below the lower
end of
the liner 810. This portion of the BHA 885 must be swallowed by collapsing the
telescoping joints 850, 855, thus lowering the liner 810 to case substantially
the depth
of the wellbore 881 drilled (see description of operation below). Preferably,
the
telescoping joints 850, 855 are pressure and volume balanced and positioned
toward a
lower end of the drill string 815 because of their reduced cross-section
caused by an
effort to minimize their hydraulic area. When the telescoping joints 850 and
855 are
extended to telescope outward, the telescoping joints 850, 855 are preferably
splined,
or selectively splined, to permit torque transmission through the telescoping
joints 850,
855 as required (specifically during run-in and/or drilling of the liner
drilling assembly
800, as described below). In addition to a spline coupling, it must be noted
that the
telescoping joints may be coupled using any other manner that is capable of
transmitting torque while allowing relative axial movement between the
telescoping
joints.
tool rsl The second telescoping joint 855 includes a latch 882 with one or
more
recesses 887 In its outer surface. The one or more recesses 887 house one or
more
latching members 886 therein. The one or more latching members 886 are also
disposed within one or more recesses 888 in an inner surface of the liner shoe
889 (or
the liner 810). To act as a releasable latch selectively holding the drill
string 815 and
the liner 810 together, the latching member 886 is radially slidable relative
within the
34
CA 02760504 2011-11-30
recess 887 of the second telescoping joint 855 to either engage or disengage
the liner
shoe 889 by its recess 888.
[00176] The two attachment locations of the liner 810 to the drill string 815,
namely the
latches 840 and 882, are disposed proximate to the upper and lower portions of
the liner
810, respectively. Both attachment locations are capable of handling tension
and
compression, as well as torque.
[00177] Connected to a lower end of the second telescoping joint 855 is a
circulating
sub 860. Within an inner, longitudinal bore of the circulating sub 860 is a
ball seat 861. A
wall of the circulating sub 860 includes one or more ports 863 therethrough.
The ball
seat 861 is slidably disposed and moveable within a recess 884 in an inner
surface of
the wall of the circulating sub 860 to selectively open and close the port
863. A baffle
877, which acts as a holding chamber for a ball 876 (see Figure 31) after the
ball 876
flows through the ball seat 861, is disposed below the ball seat 861 to
prevent the ball
876 from plugging off the flow path by entering a lower portion 870 of the BHA
885.
[00178] The lower portion 870 of the BHA 885 performs various functions during
the
drilling of the liner assembly 800. Specifically, the lower portion 870
includes a
measuring-while-drilling ("MWD") sub 896 capable of locating one or more
measuring
tools therein for measuring formation parameters. Also, a resistivity sub (not
shown) may
be located within the lower portion 870 of the BHA 885 for locating one or
more
resistivity tools for measuring additional formation parameters.
[00179] A motor 894, preferably a mud motor, is also disposed within the lower
portion
870 of the BHA 885 above an earth removal member 893, which is preferably a
cutting
apparatus. As shown in Figures 30-44, the earth removal member 893, 993
includes an
underreamer 892, 992 located above a drill bit 890, 990. In the alternative,
the earth
removal member 893, 993 may be a reamer shoe, bi-center bit, or expandable
drill bit.
For an example of an expandable bit suitable for use in the present invention,
refer to
U.S. Patent Application Publication No. 2003/111267 or U.S. Patent Application
Publication No. 2003/183424. The motor 894 is utilized to provide rotational
force to the
earth removal member 893 relative to the remainder of the drill string 815 to
drill the liner
assembly 800 into the formation to form the wellbore 881. In one embodiment,
the
CA 02760504 2011-11-30
BHA 885 may also include an apparatus to facilitate directional drilling, such
as a bent
motor housing, an adjustable housing motor, or a rotary steerable system.
Moreover,
the earth removal member may also include one or more fluid deflectors or
nozzles for
selectively introducing fluid into the formation to deflect the trajectory of
the weilbore. In
another embodiment, a 3D rotary steerable system may be used. As such, it may
be
desirable to place the LWD toot above the underreamer.
[00180] In addition to the components shown in Figure 30 and described above,
the
lower portion 870 of the BHA 885 may further include one or more stabilizers
and/or a
logging-while-drilling ("LWD") sub capable of receiving one or more LWD tools
for
measuring parameters while drilling. At least the lower portion 870 of the BHA
885 may
extend below the lower end of the liner 810 while drilling the liner assembly
800 into the
formation.
[00181] In the embodiment of Figures 30-35, the setting sleeve guard 801, the
latch
840 of the running tool 825, and the latch 882 of the second telescoping joint
855 are
each fluid bypass assemblies 813. Figure 30A shows a fluid bypass assembly 813
capable of use as the setting sleeve guard 801, latch 840, and/or latch 882.
Each
bypass assembly 813 may comprise one or more spokes 804 having one or more
annuluses 806 therebetween for flowing fluid therethrough. The one or more
bypass
assemblies 813 allow drilling fluid to circulate during wellbore operations,
as described
below.
[00182] In operation, the liner drilling assembly 800 is lowered into the
formation to
form a wellbore 881. Additionally, while being lowered, one or more portions
of the
liner drilling assembly 800 may be rotated to facilitate lowering into the
formation. The
rotated portion of the drilling assembly 800 is preferably the earth removal
member
893. The motor 894 in the BHA 885 preferably provides the rotational force to
rotate
the earth removal member 893.
[00183] Figure 30 shows the liner drilling assembly 800 in the run-in
position. Usually
the lower portion 870 of the BHA 885 extends below the liner 810 upon run-in.
The
underreamer 892, in the embodiment shown, includes one or more cutting blades
that
extend past the outer diameter of the liner 810 to form a wellbore 881 having
a
sufficient diameter for running the liner 810, which follows the underreamer
892 into the
36
CA 02760504 2011-11-30
formation, therein. In alternative embodiments which employ an expandable bit
to drill
ahead of the liner 810, the expandable bit cutting blades extend past the
outer diameter
of the liner 810 to drill a wellbore 881 of sufficient diameter.
[00184] Upon run-in of the liner assembly 800, the latching member 826 of the
latch
840 is radially extended to releasably engage the recess 828 in the liner 810.
Moreover, the latching member 886 is radially extended to engage the recess
888 in
the inner diameter of the liner 810 (or the liner shoe 889). In this way, the
drill string
815 and the liner 810 are releasably connected during drilling. The latches
840, 882
are capable of transmitting axial as well as rotational force, forcing the
liner 810 and the
drill string 815 to translate together while connected. Preferably, torque is
transmitted
sequentially from the drill string 815 to latch 840, to liner 810, back to
latch 882, and
then to the BHA 870.
(00185] During run-in of the liner assembly 810, the telescopic joints 850,
855 are
preferably extended at least partially to a length A. Because of the splined
profiles of
the telescopic joints 850, 855, extension of the telescoping joints 850, 855
may allow
transmission of torque to the earth removal member 893 while drilling.
Preferably, the
extension joints 850 and 855 do not transmit torque during drilling
operations. To hold
the telescopic joints 850, 855 in an extended position during installation of
the latch
882, at least one releasable connection between the first telescoping joint
850 and the
running tool 825 exists, as well as at least one releasable connection between
the first
telescoping joint 850 and the second telescoping joint 855. Preferably, at
least one first
shearable member 851 and at least one second shearable member 852 perform the
functions of releasably connecting the first telescoping joint 850 to the
running tool 825
and releasably connecting the second telescoping joint 855 to the first
telescoping joint
850, respectively. It is contemplated that the releasable connections could
also take
the form of hydraulically releasable dogs, as is known by those skilled in the
art, rather
than shearable connections.
[00186] While drilling into the formation with the liner drilling assembly
800, drilling
fluid is preferably circulated. The port 863 in the circulating sub 860 is
initially closed
off by the ball seat 861 within the recess 884 in the inner wall of the
circulating sub 860.
Drilling fluid is introduced into the inner longitudinal bore of the drill
string 815 from the
surface, and then flows through the drill string 815 into and through one or
more
37
CA 02760504 2011-11-30
nozzles (not shown) formed through the drill bit 890. The fluid then flows
upward
around the lower portion 870 of the BHA 885, then the one or more bypass
assemblies
813 of the latches 840, 882 and the setting sleeve guard 801 allow fluid to
flow up
through the inner diameter of the liner 810 between the inner diameter of the
liner 810
and the outer diameter of the drill string 815. Additionally, some fluid may
flow around
the outer diameter of the liner 810 between the outer diameter of the liner
810 and the
wellbore 881. Thus, the volume of fluid which may be circulated while drilling
is
increased due to the multiple fluid paths (one fluid path between the wellbore
881 and
the outer diameter of the liner 810, the other fluid path between the inner
diameter of
the liner 810 and the outer diameter of the drill string 815) created by the
embodiment
shown in Figure 30 of the liner drilling assembly 800. In another embodiment,
this
system is not limited to this one particular annular flow regime between the
outer
diameter of the liner 810 and the wellbore 881, but the system may employ the
same
equipment to achieve downward annular flow, as described above. Specifically,
this
system may involve use of the sealing member 448 and the bypass member 445.
100187] Now referring to Figure 31, when the underreamer 892 (or other earth
removal member 893) has reached the desired depth at which it is desired to
ultimately
place the liner 810 in the wellbore 881 to case the wellbore to a depth
(preferably, at
the desired depth, a lower portion of the first casing 805 overlaps an upper
portion of
the liner 810), a sealing device for sealing the bore of the circulating sub
860,
preferably a ball 876 or a dart (not shown), is introduced into the bore of
the drill string
815 from the surface and circulated down the drill string 815 into the ball
seat 861 (the
ball seat 861 is preferably located above the lower portion 870 of the BHA
885). Fluid
is then introduced above the ball 876 to increase pressure within the bore to
an amount
capable of releasing the latching member 886 from the recess 888 in the liner
810, thus
releasing the releasable connection between the drill string 815 and the liner
810. The
latching member 886 is shown released from the liner shoe 889 in Figure 31.
[00188] Next, pressure is further increased above the ball 876 within the bore
of the
drill string 815 to force the ball 876 through the ball seat 861, as
illustrated in Figure 32.
The ball 876 is caught in the baffle 877 above the lower portion 870 of the
BHA 885.
Blowing the ball 876 through the ball seat 861 allows circulation through the
bore of the
circulating sub 860 again, as during run-in of the liner drilling assembly
800.
38
CA 02760504 2011-11-30
[00189] A downward load is then applied to the drill string 815 from the
surface of the
wellbore 881 to shear the shearable members 851 and 852 so that the first
telescoping
joint 850 slides within the running tool 825 until it reaches a shoulder 841
of the running
tool 825 and the second telescoping joint 855 slides within the first
telescoping joint 850
until it reaches a shoulder 842 of the first telescoping joint 850, as shown
in Figure 33.
This telescoping of joints will continue until the liner 810 has been advanced
to the
bottom of the wellbore 881. Collapsing the joints 825, 850 and 850, 855 in
length
telescopically decreases the length of the drill string 815 within the liner
810, thus
moving the liner downward 810 within the wellbore 881 in relation to the
lowermost end
of the drill string 815 (to just above the blades on the underreamer 892). The
distances
between the shoulders 841, 842 and the initial locations of the telescoping
members
825, 850 and 850, 855 are predetermined prior to locating the liner drilling
assembly
800 within the formation so that the telescoping of the telescoping members
825, 850
and 850, 855 allows the liner 810 to move downward to a location proximate the
bottom
of the wellbore 881, as shown in Figure 33. Ultimately, the liner 810 is
reamed over the
previously exposed portion of the BHA 885; therefore, the previously open hole
section
843 (see Figure 32) is cased by the liner 810 as shown in Figure 33, thereby
casing a
portion of the wellbore 881 which would otherwise remain uncased upon removal
of the
BHA 885 from the wellbore 881. Because of the bypass assemblies 813 which
exist in
the latches 840 and 882 as well as the setting sleeve guard 801, fluid may be
circulated
within one or more annuluses 806 between one or more spokes 804 of the bypass
assemblies 813 while the liner 810 is lowered into the wellbore 881 over the
BHA 870.
Thus, fluid may be circulated within the liner 810 as well as outside the
liner 810 to
circulate any residual cuttings or other material remaining at the bottom of
the wellbore
881 after drilling.
[00190] Figure 34 shows the next step in the operation. A second ball 844 (or
dart) is
introduced into the drill string 815 from the surface to rest in the ball seat
861. Fluid is
then flowed into the bore of the drill string 815 to provide sufficient
pressure within the
drill string 815 to set the liner hanger 820, thereby hanging the liner 810 on
the first
casing 805. Specifically, increased fluid pressure within the bore forces the
gripping
members 821 to move upward along the sloped surface 822 of the liner hanger
820.
Because the surface 822 is sloped, the gripping members 821 extend radially
outward
39
CA 02760504 2011-11-30
to grippingly engage the inner surface of the first casing 805 (see Figure
35). In an
alternate, embodiment, the liner hanger 820 may be expandable.
[00191] Once the liner 810 is hung off the first casing 805, pressure is
further
increased above the second ball 844 to retract the latching member 826 from
engagement with the inner surface of the liner 810, thus disengaging the liner
810 from
the drill string 815. The drill string 815 is now moveable relative to the
liner 810 to allow
retrieval thereof.
[00192] As depicted in Figure 35, pressure is then increased yet further
within the
bore of the drill string 815 so that the second bail 844 within the ball seat
861 forces the
ball seat 861 to shift downward within the recess 884, thereby opening the
port 863 to
fluid flow and allowing fluid circulation through the port 863. Fluid flow is
now possible
through the bore of the drill string 815, out through the port 863, then up
and/or down
within the annulus between the outer diameter of the drill string 815 and the
inner
diameter of the liner 810, Figure 35 shows the drill string 815 being
retrieved to the
surface. Fluid may be circulated through the liner 810 while the drill string
815 is
retrieved from the cased wellbore 881.
[00193] An alternate embodiment of the present invention which allows for
subsequently casing a portion of the open hole wellbore which was previously
spanned
by at least a portion of the BHA previously extending below a lower end of the
liner
during the drilling with casing operation is shown in Figures 36-44. The
embodiment
shown in Figure 36-44, like the embodiment of Figures 30-35, also involves
drilling a
wellbore with a liner having an inner circulating string, wherein the liner is
attachable to
the drill string. However, the embodiment of Figures 36-44 does not employ
collapsible
telescoping joints to case the open hole section of the wellbore occupied by
the BHA.
[0010,4] The embodiment shown in Figures 36-44 is substantially the same in
components and operation as the embodiment shown in Figures 30-35; therefore,
components of Figures 36-44 which are substantially the same as components of
Figures 30-35 labeled in the "800" series are labeled with like numbers in the
"900"
series. Namely, the liner assembly 900; wellbore 981; first casing 905;
setting sleeve
guard 901 and setting sleeve 902; sealing member 903; liner 910 and its recess
928
therein, one or more gripping members 921, liner hanger 920 and its sloped
surface
CA 02760504 2011-11-30
922, and liner shoe 989; drill string 915 including running tool 925, latch
940, recess
927, latching member 926, circulating sub 960, one or more ports 963, recess
984, ball
seat 961, baffle 977, BHA 985, MWD sub 996, motor 994, underreamer 992, drill
bit
990, earth removal member 993, and lower portion 970 (of BHA 985); and balls
976
and 944 are substantially the same as the liner assembly 800, wellbore 881,
first casing
805, setting sleeve guard 801, setting sleeve 802, sealing member 803, liner
810,
recess 828, gripping members 821, liner hanger 820, sloped surface 822, liner
shoe
889, drill string 815, running tool 825, latch 840, recess 827, latching
member 826,
circulating sub 860, ports 863, recess 884, ball seat 861, baffle 877, BHA
885, MWD
sub 896, motor 894, underreamer 892, drill bit 890, earth removal member 893,
lower
portion 870, and balls 876 and 844 shown and described in relation to Figures
30-35.
[00195] The latch 982 and its related components including the latching member
986,
recess 987 in the latch 982, and recess 988 in the liner 910, and the
operation of the
latch 982, are also similar to the latch 882, recesses 887 and 888, and
latching member
886 shown and described in relation to Figures 30-35; however, the latch 982
of
Figures 36-44 and its components may be located at a higher location along the
drill
string 915 relative to the lower end of the liner 910, as no telescoping
joints 850, 855
exist in the embodiment of Figures 36-44. The latch 982 is a secondary latch.
(po196] In addition to the absence of the telescoping joints 850, 855 in the
embodiment of Figures 36-44, the embodiment shown in Figures 36-44 differs
from the
embodiment shown in Figures 30-35 because one or more centralizing members 999
may be located on the drill string 915 near the lower portion of the liner
910, near the
liner shoe 989, or at other locations throughout the length of the liner 910.
The
centralizing member 999 centralizes and stabilizes the drill string 915
relative to the
liner M. Similar to the embodiment of Figures 30-35, the setting sleeve guard
901,
latch 940, latch 982, and centralizer 999 are preferably each bypass
assemblies 813,
as shown and described in relation to Figure 30A.
(ooze;] In operation, the liner assembly 900 is drilled to a depth within the
formation
so that the wellbore 981 is at the depth at which it is desired to ultimately
set the liner
910, with only one of the latches (e.g., latch 940) engaging the inner
diameter of the
liner 910, The liner assembly 900 is drilled to the desired depth within the
formation,
preferably to a depth where at least a portion of the liner 910 is overlapping
at least a
41
CA 02760504 2011-11-30
portion of the first casing, is shown in Figure 36. While drilling, drilling
fluid may be
circulated up within the liner through the latch 940, latch 982, centralizer
999, and
setting sleeve guard 901 due to their bypass assemblies 813. This system is
not
limited to one particular annular flow regime between the outer diameter of
the liner 910
and the wellbore 981, but may also employ the same equipment as described
above to
achieve an additional downward annular flow path. Specifically, this system
may
involve the use of the sealing member 448 and the bypass member 445.
[oo19a] Next, as shown in Figure 37, the first ball 976 is placed in the ball
seat 961,
fluid pressure is increased, and the liner hanger 920 is actuated to hang the
liner 910
on the first casing 905, as shown and described In relation to Figures 30-35.
Fluid
pressure is increased further within the bore of the drill string 915 so that
the latching
member 926 is released from the recess 928 in the liner 910. At this point in
the
operation, the drill string 915 is moveable relative to the liner 910 and the
first casing
905. Then, just as shown and described in relation to Figures 30-35, fluid
pressure is
increased yet further within the bore of the drill string 915 to force the
ball 976 into the
baffle 977, as shown in Figure 38, so that fluid may flow through the lower
end 970 of
the BHA 985 again.
[00199] The drill string 915 is then translated upward relative to the liner
910 until the
secondary latching member 988 engages the recess 928 in the liner 910
previously
occupied by the latching member 926. The distance between the recesses 928 and
986, as well as between latching members 926 and 988, Is predetermined so that
when
the latching member 988 engages the recess 928, the majority of the BHA 985 is
surrounded by the liner 910. Preferably, as shown in Figure 39, the lower end
of the
liner 910 is disposed proximate to the earth removal member 993, so that the
liner 910
may be lowered into a location near the bottom of the wellbore 981. In this
manner,
substantially all of the open hole wellbore may be cased by the liner 910.
[00200] Once the latching member 968 engages the recess 928, the gripping
members 921 of the liner hanger 920 are released from their gripping
engagement with
the first casing 905, as shown in Figure 40. The liner drilling assembly 900
is now
translatable relative to the first casing 905.
42
CA 02760504 2011-11-30
[00201] As shown in Figure 41, the liner assembly 900 is then lowered to the
bottom
of the open hole wellbore 981. Referring now to Figure 42, a second ball 944
is next
introduced into the bore of the drill string 915 and stops in the ball seat
961, thus
preventing fluid flow therethrough. Increased fluid pressure above the second
ball 944
sets the liner hanger 920 at a new location on the first casing 905, as shown
and
described in relation to Figures 30-35. The liner 910 is now hung on the first
casing
905 at its desired position for lining the open hole welibore.
[00202] Figure 43 shows the next step in the operation. After hanging the
liner 910
on the first casing 905, the secondary latching member 988 is released (e.g.,
by
increased fluid pressure within the bore of the drill string 915 above the
ball 944) from
the recess 928 in the liner 910 so that the drill string 915 may be retrieved
from within
the liner 910. Fluid pressure is then further increased within the bore to
shift the ball
seat 961, thereby uncovering the fluid port 963. Fluid circulation from the
bore of the
drill string 915, then up and/or down through the inner diameter of the liner
910 outside
the drill string 915 is then possible while retrieving the drill string 915 to
the surface.
Figure 44 shows the fluid port 963 uncovered.
[00203] The drip string 915 is then pulled up to the surface, while the liner
910
remains hung on the first casing 905. When the underreamer 992 reaches the
liner
910 upon pulling the drill string 915 up through the liner 910, the
underreamer 992
decreases in outer diameter.
[00204] Figures 45-49 show a cementation process for setting the liner 810,
910 of
either of the embodiments shown in Figures 30-35 or in Figures 36-44 within
the
wellbore 881, 981. The cementation process is a two-trip system for drilling
casing into
the wellbore and cementing the casing into the welibore which avoids pumping
of
cement through the BHA 885, 985, which could damage or ruin expensive
equipment
disposed within the BHA 885, 985 such as a MWD tool or mud motor.
[00205] The embodiment of the cementation process depicted in Figures 45-49
includes first casing 905, setting sleeve 902, sealing member 903, liner
hanger 920,
sloped surface of liner hanger 922, gripping member 921, recess in liner 928,
and liner
910 of Figures 36-44, all of which are left in the wellbore 981 after the
drill string 915 is
removed from the wellbore 981. The cementation process which is below
described in
43
CA 02760504 2011-11-30
relation to the components of Figures 36-44 is equally applicable to the
cementation of
the liner 810 of Figures 30-35, where the first casing 805, setting sleeve
802, sealing
member 803, liner hanger 820, sloped surface 822, gripping member 821, recess
828,
and liner 810 remain in the wellbore 881 subsequent to removal of the drill
string 815
from the liner 810.
[00206] Referring to Figure 45, a cementing assembly 930 which is run into the
casing 905, 805, setting sleeve 902, 802, and liner 910, 810 includes a tubing
string
935 attached to a float valve sub 932. The tubing string 935 is preferably
connected to
an upper end of the float valve sub 932. At least a portion of the tubing
string 935
includes a circulating sub 936 having one or more ports 934 within a wall of
the
circulating sub 936 for communicating fluid from the inner bore of the tubing
string 935
to the annulus between the outer diameter of the tubing string 935 and the
inner
diameter of the liner 910, 810. Disposed within a recess 937 of the
circulating sub 936
is a hydraulic isolation sleeve 931 to selectively isolate the inner diameter
of the bore
from fluid flow in the annulus. The hydraulic isolation sleeve 931 is
selectively
moveable over and away from the port 934 to open or close a fluid path through
the
port 934.
[00207] A further portion of the tubing string 935, which is preferably
located below
the circulating sub 936 in the tubing string 935, is a sealing member setting
tool 938
and sealing member stinger assembly 939. At least a portion of the sealing
member
stinger assembly 939 is disposed within the bore of the float valve sub 932 to
keep the
bore of the float valve sub 932 open. The sealing member setting tool 938 is
utilized to
activate the sealing member 903, 803. The sealing member setting tool 938
includes
one or more setting members 998 on one or more hinges 991 biased radially
outward
to a predetermined radial extension wingspan of the setting members 998. The
setting
members 998 are disposable within a recess 997 in the setting tool 939 when
inactivated, as shown in Figure 45.
[o02as] At the lower end of the tubing string 935 is the float valve sub 932
for
preventing backf low of cement upon removal of the tubing string 935 (see
below). The
float valve sub 932 includes a longitudinal bore therethrough and a one-way
valve 946,
examples of which include but are not limited to flapper valves or check
valves. When
the one-way valve 946 is activated, the one-way valve 946 permits cement to
flow
44
CA 02760504 2011-11-30
downward through the bore of the float valve sub 932 and into the wellbore
981, 881,
yet prevents fluid from flowing into the bore of the float valve sub 932 from
the wellbore
981, 881 ("u-tubing"). The one-way valve 946 may be biased upward around a
hinge
945, and the arm of the valve 946 may be disposable within a recess 933 in a
lower
end of the float valve sub 932 when closed.
1002091 Disposed around the outer diameter of the float valve sub 932 are one
or
more gripping members 941, 943, which are preferably slips, for grippingly
engaging
the inner surface of the liner 910, 810. One or more sealing members 942,
which are
preferably elastomeric compression-set packers, are also disposed around the
outer
diameter of the float valve sub 932 for sealingly engaging the inner surface
of the liner
910, 810. The one or more sealing members 942 are preferably drillable.
Preferably,
as is shown in Figure 45, the sealing members 942 are disposable between
gripping
members 941, 943.
[002101 In operation, the cementing assembly 930 is lowered into the inner
diameter
of the first casing 905, 805, setting sleeve 902, 802, and liner 910, 810 to
the depth at
which it Is desired to place the float valve sub 932 to prevent backflow, of
cement during
the cementation process. Upon run-in, the one-way valve 946 is propped open by
the
stinger 976, which forces the one-way valve 946 to remain open despite its
bias closed.
During run-in, fluid may be circulated through the inner bore of the tubing
string 935,
then up the inner diameter and/or outer diameter of the liner 910, 810. After
the one or
more sealing members 942 are located near a lower end of the liner 910, 810,
the
sealing members 942 are set, preferably by compressing the one or more sealing
members 942 out against the inner diameter of the liner 910, 810. Figure 45
shows the
cementing assembly 930 lowered to the desired depth within the liner 910, 810
and the
sealing member 942 contacting the inner surface of the liner 910, 810 to
substantially
seal the annulus between the outer diameter of the float valve sub 932 and the
inner
diameter of the liner 910, 810. Because the annulus between the liner 910, 810
and
the tubing string 935 Is now substantially sealed from fluid flow, fluid flow
through the
tubing string 935 bore must travel up the annulus between the outer diameter
of the
liner 910, 810 and the wellbore 981, 881.
1002111 Optionally, testing of the fluid flow path through the tubing string
935 and up
around the liner 910, 810 may be conducted prior to cementing. Referring to
Figure 46,
CA 02760504 2011-11-30
a setting operation is then performed, as a physically alterable bonding
material,
preferably cement 948, is introduced into the bore of the tubing string 935.
The cement
948 is introduced into the tubing string 935, then the cement flows up through
the
annulus between the Liner 910, 810 and the wellbore 981, 881 to the desired
height H
along the liner 910, 810. Upon the cement 948 achieving the desired height H,
a wiper
dart 991 is lowered into the bore of the tubing string 935 behind the cement
948. It
another embodiment, a ball may be used in place of a dart for the cementing
operation.
[00212] Figure 47 depicts the next step in the operation of the cementing
process.
The wiper dart 991, upon reaching the hydraulic isolation sleeve 931, catches
on the
sleeve 931 and seals the inner bore of the tubing string 935. Fluid pressure
on the
wiper dart 991 causes a shear mechanism of the sleeve 931 to fail and moves
the
sleeve 931 down within the recess 937, thereby exposing the port 934 to fluid
flow
therethrough between the bore of the tubing string 935 and the annulus between
the
inner diameter of the liner 910, 810 and the outer diameter of the tubing
string 935.
The wiper dart 991 travels further below the sleeve 931 within the bore.
[002131 Opening the ports 934 to allow circulating of fluid therethrough
permits the
tubing string 935 to be removed from the liner 910, 810. Upward force is
applied to the
tubing string 935 to pull the tubing string 935 to the surface, as shown in
Figure 48. As
the stinger 976 is removed from the inner bore of the float valve sub 932, the
one-way
valve 946 is released so that the biasing force causes the one-way valve 946
to pivot
upward around its hinge 945 into the recess 933. At this point, the one-way
valve 946
prevents fluid such as cement from flowing upward into the bore of the liner
910, 810.
(00214) Also shown In Figure 48, upon exiting the setting sleeve 902, 802, the
setting
members 998 are allowed to extend to their full radial extension due to the
biasing
force. To radially extend the sealing member 903, 803 around an upper portion
of the
liner 910, 810 into sealing engagement with the inner diameter of the first
casing 905,
805, the tubing string 935 is lowered onto the setting sleeve 902, 802 after
exiting the
setting sleeve 902, 802 so that the setting members 998 set the sealing member
903,
803, preferably by compression of the elastomeric seal on the compression-set
sealing
member 803, 903. In alternate embodiments of the present invention, a seal may
be
created by a different approach. For example, the seal could be created
through
expansion of a metal tube against the casing 905, 805, employing either a
metal-to-
46
CA 02760504 2011-11-30
metal seal or using an expandable tube clad with an elastomeric seal on its
outer
surface.
[002151 The tubing string 935 is then removed from the wellbore 981, 881 to
leave
the liner 910, 810 set and sealed within the formation, as shown in Figure 49.
The
components within the float valve sub 932 are preferably drillable (including
the sealing
member 942) so that a subsequent earth removal member (not shown) may drill
through the float valve sub 932 and possibly further into the formation to
form a
wellbore of a further depth. The subsequent earth removal member may be
attached to
a liner or casing to case the further depth of the formation. Also, the
subsequent earth
removal member may be attached to an additional liner which is part of an
additional
drilling assembly (which may optionally include the same drill string 915, 815
which was
removed from the wellbore) similar to the drilling assembly 900, 800 shown and
described in relation to Figures 30-44, the liner drilling assembly capable of
casing a
further depth of a weiibore in the formation. An additional cementing
operation may be
performed on the additional liner left within the wellbore. The process may be
repeated
as desired any number of times to complete the weiibore to total depth within
the
formation.
[002161 Aspects of the present invention also provide methods and apparatus
for
casing a section of the wellbore in one trip. Figure 50 shows a first casing
605 which
was previously lowered into a wellbore 681 and set therein, preferably by a
physically
alterable bonding material such as cement. In the alternative, the casing 605
may be
set within the wellbore 681 using any type of hanging tool. Preferably, the
first casing
605 is drilled into an earth formation by jetting and/or rotating the first
casing 605 to
form the wellbore 681.
[002171 Disposed within the first casing 605 is a second casing or liner 610.
The liner
610 includes a hanger 620 on a portion of its outer diameter, the hanger 620
having
one or more gripping members 621, preferably slips. The hanger 620 further
includes a
sloped surface on the outer diameter of the liner 610 along which the gripping
members
621 translate radially outward to hang the liner 610 off the inner diameter of
the casing
605.
47
CA 02760504 2011-11-30
[00218] Connected to an outer surface of a lower end of the liner 610 is one
or more
sealing members 603 on its outer diameter. The sealing members 603 preferably
being one or more packers and even more preferably being one or more
inflatable
packers constructed of an elastomeric material. The sealing members 603
include one
or more inflation ports 612 in selectively fluid communication with the
interior of the liner
610. The sealing member 603 may be actuated to seal off an annulus between the
liner 610 and the wellbore 681.
[o0219) The liner 610 has a drill string 615, which may also be termed a
circulating
string, disposed substantially coaxially therein and releasably connected
thereto. The
drill string 615 is a generally tubular-shaped body having a longitudinal bore
therethrough, The drill string 615 and the liner 610 form a liner assembly
600. Figure
50 shows the liner assembly 600 drilled to the liner 610 setting depth within
the
formation.
[002201 The drill string 615 includes a running tool 625 at its upper end and
a BHA
685 at its lower end. Specifically, the running tool 625 includes a latch 640.
An outer
surface of the running tool 625 has a recess therein for receiving the latch
640. The
latch 640 is radially extendable into a recess in an inner surface of the
liner 610 to
selectively engage the liner 610. When the latch 640 is extended into the
recess of the
liner 610, the liner 610 and the drill string 615 are latched together. The
latch 640 is
capable of transmitting axial as well as rotational force, forcing the liner
610 and the drill
string G15 to translate together while connected.
[00221) Preferably, the running tool comprises a fluid bypass assembly 613.
Figure
50A shows a fluid bypass assembly 613 capable of use with the running tool.
Each
bypass assembly 613 may comprise one or more spokes 607 having one or more
annuluses 608 therebetween for flowing fluid therethrough. The one or more
bypass
assemblies 613 allow drilling fluid to circulate through the annulus between
the liner
and the drill string during the wellbore operations, as described below. It
should also
be noted that aspects of the drilling systems discussed herein are applicable
to the
present embodiment and other embodiments. For example, the drilling system
shown
in Figure 50 may further include a fluid bypass assembly having one or more
bypass
ports. In this respect, fluid from the drill string 615 may be diverted into
the annular
space between the liner 610 and the wellbore 681. Additionally, the drilling
system may
48
CA 02760504 2011-11-30
employ a sealing member 448 to seat off an annular area between the existing
casing
and the liner.
[002221 The BHA 685 is adapted to perform several functions during the
drilling of the
liner assembly 600. Specifically, the BHA 685 Includes a measuring-while-
drilling
("MW D") sub 696 capable of locating one or more measuring tools therein for
measuring formation parameters. A motor 694, preferably a mud motor, is also
disposed within the BHA 685 above an earth removal member 693, which is
preferably
a cutting apparatus. As shown in Figures 50-59, the earth removal member 693
includes an underreamer 692 located above a drill bit 690. Because many of the
components in Figure 50 are substantially the same as the components shown and
described in Figure 30, the above description and operation of the similar
components
with respect to Figure 30 apply equally to the components of Figure 50.
[00223] The BHA 685 further includes a first circulating sub 630. Within an
inner,
longitudinal bore of the first circulating sub 630 is a ball seat 631. A wall
of the
circulating sub 630 includes one or more ports 633 therethrough. The ball seat
631 is
slidably disposed and moveable relative to the ports 633 to selectively open
and close
the ports 633.
[002241 A second sealing member 640 is disposed adjacent the first circulating
sub
630. Preferably, the second sealing member 640 comprises an inflatable packer.
Within the inner bore of the drill string 615 is a ball seat 645 to
selectively open the
inflation ports 643 of the second sealing member 640.
[002251 The BHA further includes a second circulating sub 652 and a third
circulating
sub 653 disposed above the second sealing member 640. Each of the circulating
subs
652, 653 has a ball seat 654, 655 disposed therein and one or more ports 656,
657
formed through a wall of the circulating sub 652, 653. The ball seat 654, 655
is slidably
disposed and moveable relative to the ports 656, 657 to selectively open and
close the
ports 656, 657. A port sleeve 658, 659 enclosing the ports 656, 657 is movably
disposed on the outer surface of the circulating sub 652, 653. The port sleeve
658, 659
may be actuated by fluid flow through the port 656, 657. In another
embodiment, one
or more rupture disks may be used to enclose ports 656, 657. The rupture disks
may
be adapted to fail at a predetermined pressure.
49
CA 02760504 2011-11-30
1002261 The BHA also includes a packoff sub 660. The packoff sub 660 comprises
a
locator member 665 for engaging the liner 610 to indicate position-
Preferably, the
locator member 665 comprises one or more latch dogs 666 adapted to engage a
profile
617 on the inner surface of the liner 610. The packoff sub 660 also includes
ball seat
670 movably disposed within the inner bore of the drill string 615. The ball
seat 670
may be actuated to open the one or more setting ports 672 disposed through a
wall of
the packoff sub 660. One or more seals 674 are disposed on either side of the
setting
ports 672. When the latch dogs 666 engage the profile 617, the setting ports
672 are
placed in alignment with the inflation port 612 of the casing sealing member
603.
Additionally, the seals 674 on either of the setting ports 672 form an
enclosed area for
fluid communication between the setting ports 672 and the Inflation ports 612.
Preferably, the packoff sub 660 of the BHA 685 is disposed the lower end of
the liner
610 while drilling the liner assembly 600 into the formation. To this end, the
packoff
sub 660 will not obstruct the annular space between the inner diameter of the
liner 610
and the outer diameter of the drill string 615, thereby allowing for cuttings
from the
drilling process to be circulated up through the inside of the liner 610 and
the past the
running tool 625.
[00227] In operation, the liner drilling assembly 600 is lowered into the
formation to
form a wellbore 681, During run-in of the liner assembly 600, the latch 640 is
radially
extended to selectively engage the recess in the liner 610. In this way, the
drill string
615 and the liner 610 are releasably connected during drilling. The motor 694
may be
operated to rotate the earth removal member 693 to facilitate the advancement
to the
liner drilling assembly 600. Figure 50 shows the liner drilling assembly 600
after
reaching the desired depth.
1002281 While drilling into the formation with the liner assembly 610,
drilling fluid is
preferably circulated. The ports 633, 643, 656, 657, 672 in the BHA 685 are
initially
closed off by their respective ball seats 631, 645, 654, 655, 670. The
drilling fluid
introduced into the inner longitudinal bore of the drill string 615 from the
surface flows
through the drill string 615 into and through one or more nozzles (not shown)
of the drill
bit 690. The fluid then flows upward around the lower portion of the BHA 685
carrying
cuttings generated by the drilling process. The fluid then flow through the
annulus
between the drill string and the liner and between the spokes of the fluid
bypass
assembly 613. Additionally,,a small amount of fluid may flow between the liner
610 and
CA 02760504 2011-11-30
the wellbore 681. Thus, the volume of fluid which may be circulated while
drilling is
increased due to the multiple fluid paths (one fluid path between the wellbore
681 and
the outer diameter of the liner 610, the other fluid path between the inner
diameter of
the liner 610 and the outer diameter of the drill string 615) created by the
embodiment
shown in Figure 50 of the liner drilling assembly 600. It must be noted that
aspects of
the present invention are equally applicable to annular circulation systems,
as is known
to a person of ordinary skill in the art. It should also be noted that aspects
of the drilling
systems discussed herein are applicable to the present embodiment and other
embodiments. For example, the drilling system shown in Figure 50 may further
include
a fluid bypass assembly having one or more bypass ports. In this respect,
fluid from
the drill string 615 may be diverted into the annular space between the liner
610 and
the wellbore 681. Additionally, the drilling system may employ a sealing
member 448
to seal off an annular area between the existing casing and the liner.
[00229] Initially, a ball is released in the drill string 615 and lands in the
ball seat 631
of the first circulation sub 630, as shown Figure 51. Pressure is applied to
the drill
string 615 to set the liner hanger 620 by extending the slips 621 outward to
engage the
first casing 605. Additionally, the pressure increase also releases the latch
640,
thereby freeing running tool 625 from the liner 610.
[00230] Thereafter, more pressure is applied to shift the ball seat 631 of the
first
circulation sub 630, as illustrated in Figure 52. In one embodiment, the
pressure
increase causes a shear mechanism retaining the ball seat 631 to fail.
[00231] After the running tool is released, the drill string 615 is raised
until the latch
dogs 666 of the locating member 665 engage the profile 617 on the liner 610.
The
locator member 665 ensures that the setting port 672 is aligned with the
inflation port
612 of the casing sealing member 603, and that the seals 674 are located on
both
sides of the ports 672, 612.
[oor32] In Figure 53, a second ball has been released in the drill string 615.
The
second ball is circulated down to the bottom of the drill string 615. As the
second
passes the second and third circulation subs 652, 653 and the second sealing
member
640, it trips the isolation sleeves of these components. As a result, the
components
652, 653, 640 are ready to sense any applied pressure differential across
their
51
CA 02760504 2011-11-30
respective activation devices. In the embodiment shown, the ball seats 645,
654, 655
have been shifted down as the second ball is circulated down. In turn, the
port sleeves
658, 659 are exposed to the pressure in the drill string 615 through the
respective ports
656, 657.
[002331 Thereafter, pressure is increased to inflate the second sealing member
640.
The inflated sealing member 640 blocks fluid communication in the annulus
between
the drill string 615 and the wellbore 681. Then, pressure is increased further
to shift the
port sleeve 658 of the second circulating sub 652 to the open position.
Because of the
inflated second sealing member 640, fluid exiting the open port 656 is
circulated up the
annulus.
[002341 In another aspect, the second sealing member 640 may be used as a blow
out preventor during run in of the drill string assembly into the hole on an
offshore
drilling vessel or platform. If the well should kick, which is an influx of
fluid, such as
gas, coming into the well bore in an uncontrolled fashion, during the running
in of the
drilling assembly through the blow-out preventor and the liner Is physically
located in
the preventor and the inner diameter of the liner annulus between the drill
string is open
to flow, then the blow-out preventor can not shut off the kick which can flow
up the open
annular area. To this end, the second sealing member 640 may be inflated with
a
special rupture dart (not shown) that will set the second sealing member 640
but not
the liner hanger. In this respect, the second sealing member 640 may seal off
the
annulus between the drill string and the liner. After the second sealing
member 640 is
set, the rupture dart will rupture and allow fluid to by-pass to the bottom of
the drill
string. This will allow the pumping of kill fluid, to kilt the kick and regain
control of the
well. By rotation of the drilling assembly after the well is under control the
second
sealing member 640 can be deflated and the drilling assembly pulled out of the
hole to
redress the second sealing member 640 for use in the cementing operation.
[00235] A first dart 641 is released from surface, as shown in Figure 54.
Preferably,
the first dart 641 is adapted to wipe the inner surface of the drill string
615 as it travels
down the drill string 615. In one embodiment, the first dart 641 is trailed by
a small
polymer slug, a scavenger slurry, the cement, and another small polymer slug.
The
dart 641 is displaced until it lands in a receiving profile below the port 657
of the third
circulating sub 653, thereby sealing off the drill string 610 at the profile.
52
CA 02760504 2011-11-30
[00236] In Figure 55, pressure is increased to shift port sleeve 659 of the
third
circulating sub 653 to the open position. Fluid behind the first dart 641 is
displaced
through the opened port 657 and up the annulus between the liner 615 and the
wellbore 681.
[00237] In Figure 56, a second dart 642 is shown chasing the slurry to bottom.
As
the second dart passes the ball seat 670 of the packoff sub 660, it shifts the
ball seat
670 to expose the inflation port 612 of the casing sealing member 603 to the
pressure
in the drill string 615. The second dart 642 will eventually and in a profile
above the
ports 657 of the third circulating sub 653.
[0023x] After the second dart 642 lands in the profile, pressure is increased
to inflate
the casing sealing member 603. As shown in Figure 57, the inflated casing
sealing
member 603 seals off the annulus between the liner 610 and the wellbore 681.
In this
respect, the cement is held in place by the casing sealing member 603 and
cannot u-
tube back into the liner 610.
[00239] Thereafter, drill string 615 is rotated to deflate and release the
second
sealing member 640, as shown in Figure 58. Thereafter, drill string 615 Is
pulled out of
the hole, as shown in Figure 59. When the setting ports 672 of the packoff sub
660
clears the liner top, fluid can equalize through the setting ports 672 from
the drill string
615 to the first casing 605, so a wet drill string 615 is not pulled. This
feature could also
be achieved by a burst disk in dart 642, which would allow for fluid
equalization through
circulating sub 653.
[00240] Aspects of the present invention also provide apparatus and methods
for
effectively increasing the carrying capacity of the circulating fluid.
[o0241J Figure 60 is a section view of a wellbore 1300. For clarity, the
wellbore 1300
is divided into an upper wellbore 1300A and a lower wellbore 13008. The upper
wellbore 1300A is lined with casing 1310, and an annular area between the
casing
1310 and the upper wellbore 1300A is filled with cement 1315 to strengthen and
isolate
the upper wellbore 1300A from the surrounding earth. The lower wellbore 13006
comprises the newly formed section as the drilling operation progresses.
53
CA 02760504 2011-11-30
[00242] Coaxially disposed in the wellbore 1300 is a drilling assembly. The
drilling
assembly may include a work string 1320, a running tool 1330, and a casing
string
1350. The running tool 1330 may be used to couple the work string 1320 to the
casing
string 1350. Preferably, the running tool 1330 may be actuated to release the
casing
string 1350 after the lower wellbore 1300B is formed and the casing string
1350 is
secured.
[00243] As illustrated, a drill bit 1325 is disposed at the lower end of the
casing string
1350. Generally, the lower wellbore 1300B is formed as the drill bit 1325 is
rotated and
urged axially downward. The drill bit 1325 may be rotated by a mud motor (not
shown)
located in the casing string 1350 proximate the drill bit 1325. Alternatively,
the drill bit
1325 may be rotating by rotating the casing string 1350. In either case, the
drill bit
1325 is attached to the casing string 1350 that will subsequently remain
downhole to
line the lower wellbore 1300B. As such, there is no opportunity to retrieve
the drill bit
1325 in the conventional manner. In this respect, drill bits made of drillable
material,
two-piece drill bits or bits integrally formed at the end of casing string are
typically used.
[00244] Circulating fluid or "mud" is circulated down the work string 1320, as
illustrated with arrow 1345, through the casing string 1350, and exits the
drill bit 1325.
The fluid typically provides lubrication for the drill bit 1325 as the lower
wellbore 1300E
is formed. Thereafter, the fluid combines with other wellbore fluid to
transport cuttings
and other wellbore debris out of the wellbore 1300. As illustrated with arrow
1370, the
fluid initially travels upward through a smaller annular area 1375 formed
between the
outer diameter of the casing string 1350 and the lower wellbore 13008. Because
of the
smaller annular area 1375, the fluid travels at a high annular velocity.
[00245] Subsequently, the fluid travels up a larger annular area 1340 formed
between
the work string 1320 and the inside diameter of the casing 1310 as illustrated
by arrow
1365. As the fluid transitions from the smaller annular area 1375 to the
larger annular
area 1340, the annular velocity of the fluid decreases. Because the annular
velocity
decreases, the carrying capacity of the fluid also decreases, thereby
increasing the
potential for drill cuttings and wellbore debris to settle on or around the
upper end of the
casing string 1350.
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CA 02760504 2011-11-30
[00246] To increase the annular velocity, a flow apparatus 1400 is used to
inject fluid
into the larger annular area 1340. In Figure 60, the flow apparatus 1400 is
shown
disposed on the work string 1320. Although Figure 60 shows one flow apparatus
1400
attached to the work string 1320, any number of flow apparatus may be coupled
to the
work string 1320 or the casing string 1350. The flow apparatus 1400 may divert
a
portion of the circulating fluid into the larger annular area 1340 to increase
the annular
velocity of the fluid traveling up the wellbore 1300. It is to be understood,
however, that
the flow apparatus 1400 may be disposed on the work string 1320 at any
location, such
as adjacent the casing string 1350 as shown on Figure 60 or further up the
work string
1320. Furthermore, the flow apparatus 1400 may be disposed in the casing
string 1350
or below the casing string 1350, so long as the lower wellbore 1300E will not
be eroded
or over pressurized by the circulating fluid.
[00247] In another aspect, the flow apparatus may comprise a flow operated
external
pump to increase the annular velocity. The flow operated pump would take
energy off
the flow stream being pumped down the tubular assembly instead of diverting
fluid off
the flow stream e.g., the fluid pressure in the flow stream above the drive
mechanism of
the external pump would be higher than the fluid pressure in the flow stream
below the
drive mechanism. The external pump would reduce the equivalent circulating
density
of the fluid in the annulus 1340 helping to lift the fluid and cuttings to the
surface. The
external pump can be selectively operated from being shut off to maximum flow.
Also
the external pump can be supplied with energy from the surface other than the
flow
stream, e. g., electrical energy, hydraulic energy, pneumatic, etc. Also the
external
pump may have it's own energy supply such as compressed gas. Further, the
control
of the external pump from the surface may be by fiber optics, mud pulse, hard
wring,
hydraulic line, or any manner known to a person of ordinary skill in the art.
In a further
aspect, the drill string may be equipped with one or more of a fluid diverting
flow
apparatus, a flow operated external pump, or combinations thereof.
[00248] One or more ports 1415 in the flow apparatus 1400 may be modified to
control the percentage of flow that passes to drill bit 1325 and the
percentage of flow
that is diverted to the larger annular area 1340. The ports 1415 may also be
oriented in
an upward direction to direct the fluid flow up the larger annular area 1340,
thereby
encouraging the drill cuttings and debris out of the wellbore 1300.
Furthermore, the
CA 02760504 2011-11-30
ports 1415 may be systematically opened and closed as required to modify the
circulation system or to allow operation of a pressure controlled downhole
device.
[00249] The flow apparatus 1400 is arranged to divert a predetermined amount
of
circulating fluid from the flow path down the work string 1320, The diverted
flow, as
illustrated by arrow 1360, is subsequently combined with the fluid traveling
upward
through the larger annular area 1340. In this manner, the annular velocity of
fluid in the
larger annular area 1340 is increased which directly increases the carrying
capacity of
the fluid, thereby allowing the cuttings and debris to be effectively removed
from the
wellbore 1300. At the same time, the annular velocity of the fluid traveling
up the
smaller annular area 1375 is lowered as the amount of fluid exiting the drill
bit 1325 is
reduced. In this respect, damage or erosion to the lower wellbore 13008 by the
fluid
traveling up the annular area 1375 is minimized.
[oo2so] Figure 61 is a cross-sectional view illustrating another embodiment of
a
drilling assembly having an auxiliary flow tube 1405 partially formed in the
casing string
1350. As illustrated with arrow 1345, circulating fluid is circulated down the
work string
1320, through the casing string 1350, and exits the drill bit 1325 to provide
lubrication
for the drill bit 1325 as the lower wellbore 1300B is formed. Thereafter, the
fluid
combines with other wellbore fluid to transport cuttings and other wellbore
debris out of
the wellbore 1300.
[00251] As illustrated with arrow 1370, the fluid initially travels at a high
annular
velocity upward through a portion of the smaller annular area 1375 formed
between the
outer diameter of the casing string 1350 and the lower wellbore 1300B.
However, at a
predetermined distance, a portion of the fluid in the smaller annular area
1375, as
illustrated by arrow 1410, is redirected through the auxiliary flow tube 1405.
In one
embodiment, the auxiliary flow tube 1405 may be systematically opened and
closed as
desired, to modify the circulation system or to allow operation of a pressure
controlled
downhole device. Preferably, the auxiliary flow tube 1405 is constructed and
arranged
to remove and redirect a portion of the high annular velocity fluid traveling
up the
smaller annular area 1375. By diverting a portion of high annular velocity
fluid in the
smaller annular area 1375 to the larger annular area 1340, the auxiliary flow
tube 1 405
increases the annular velocity of the fluid traveling up the larger annular
area 1340. In
this manner, the carrying capacity of the fluid is increases. In addition, the
annular
56
CA 02760504 2011-11-30
velocity of the fluid traveling up the smaller annular area 1375 is reduced,
thereby
minimizing erosion or pressure damage in the lower wellbore 1300E by the fluid
traveling up the annular area 1375. Although Figure 61 shows one auxiliary
flow tube
1405 attached to the casing string 1350, any number of auxiliary flow tubes
may be
attached to the casing string 1350 in accordance with the present invention.
Additionally, the auxiliary flow tube 1405 may be disposed on the casing
string 1350 at
any location, such as adjacent the drill bit 1325 as shown on Figure 61 or
further up the
casing string 1350, so long as the high annular velocity fluid in the smaller
annular area
1375 is transported to the larger annular area 1340,
[00252] Figure 62 is a cross-sectional view illustrating another embodiment of
a
drilling assembly having a main flow tube 1420 formed in the casing string
1350. In this
embodiment, the work string 1320 extends down to the drill bit 1325. As
Illustrated with
arrow 1345, circulating fluid is circulated down the work string 1320 and
exits the drill
bit 1325 to provide lubrication to the drill bit 1325. Thereafter, the fluid
exiting the drill
bit 1325 combines with other wellbore fluids to transport cuttings and
wellbore debris
out of the wellbore 1300. As the fluid travels up the smaller annular area
1375, a
portion of the fluid is diverted through one or more openings in the main flow
tube 1420,
where it eventually exits into the larger annular area 1340. For the same
reasons
discussed with respect to Figure 61, the annular velocity of fluid in the
larger annular
area 1340 is increased, thereby increasing the carrying capacity of the fluid.
Additionally, the annular velocity of the fluid in the smaller annular area
1375 is
reduced, thereby minimizing erosion or pressure damage in the lower wellbore
1300B
by the fluid traveling up the annular area 1375.
[oo2531 Figure 63 is a cross-sectional view illustrating a drilling system
having a flow
apparatus 1400 and an auxiliary flow tube 1405. In the embodiment shown, the
flow
apparatus 1400 is disposed on the work string 1320 and the auxiliary flow tube
1405 is
disposed on the casing string 1350. It is to be understood, however, that the
flow
apparatus 1400 may be disposed at any location on the work string 1320 as well
as on
the casing string 1350. Similarly, the auxiliary flow tube 1405 may be
positioned at any
location on the casing string 1350. Additionally, it is within the scope of
this invention to
employ a number of flow apparatus or auxiliary flow tubes. In this embodiment,
a
portion of the fluid pumped through the work string 1320 may be diverted
through the
flow apparatus 1400 into the larger annular area 1340. Additionally, a portion
of the
57
CA 02760504 2011-11-30
high velocity fluid traveling up the smaller annular area 1375 may be
communicated
through the auxiliary flow tube 1405 into the larger annular area 1340.
[00254) Figure 64 is a cross-sectional view illustrating a drilling system
having a flow
apparatus 1400 and a main flow tube 1420. The work string 1320 extends to the
drill
bit 1325. In the embodiment shown, the flow apparatus 1400 is disposed on the
work
string 1320, and the main flow tube 1420 is formed between the casing string
1350 and
the work string 1320. It is to be understood, however, that the flow apparatus
1400
may be disposed at any location on the work string 1320 as well as on the
casing string
1350. Additionally, it is within the scope of this invention to employ a
number of flow
apparatus. In this embodiment, a portion of the fluid pumped through the work
string
1320 may be diverted through the flow apparatus 1400 into the larger annular
area
1340. Additionally, a portion of the high velocity fluid traveling up the
smaller annular
area 1375 may be communicated through the main flow tube 1420 into the larger
annular area 1340.
[00255] The operator may selectively open and close the flow apparatus 1400 or
the
main flow tube 1420, individually or collectively, to modify the circulation
system. For
example, an operator may completely open the flow apparatus 1400 and partially
close
the main flow tube 1420, thereby injecting circulating fluid in an upper
portion of the
larger annular area 1340 while maintaining a high annular velocity fluid
traveling up the
smaller annular area 1375. In the same fashion, the operator may partially
close the
flow apparatus 1400 and completely open the main flow tube 1420, thereby
injecting
high velocity fluid to a lower portion of the larger annular area 1340 while
allowing
minimal circulating fluid into the upper portion of the larger annular area
1340. It is
contemplated that various combinations of selectively opening and closing the
flow
apparatus 1400 or the main flow tube 1420 may be selected to achieve the
desired
modification to the circulation system. Additionally, the flow apparatus 1400
and the
main flow tube 1420 may be hydraulically opened or closed by control lines
(not shown)
or by other methods well known in the art.
[00255) In operation, the drilling assembly having a work string 1320, a
running toot
1330, and a casing string 1350 with a drill bit 1325 disposed at a lower end
thereof is
inserted into an upper wellbore 1300A. Subsequently, the casing string 1350
and the
drill bit 1325 are rotated and urged axially downward to form the lower
wellbore 13008.
58
CA 02760504 2011-11-30
At the same time, circulating fluid or "mud" is circulated to facilitate the
drilling process.
The fluid provides lubrication for the rotating drill bit 1325 and carries the
cuttings up to
surface.
[00257] During circulation, a portion of the fluid pumped through the work
string 1320
may be diverted through the flow apparatus 1400 into the larger annular area
1340.
Additionally, a portion of the high velocity fluid traveling up the smaller
annular area
1375 may be communicated through the main flow tube 1420 into the larger
annular
area 1340. In this respect, diverted fluid from the flow apparatus 1400 and
the main
flow tube 1420 increases the annular velocity of the larger annular area 1340.
Additionally, annular velocity of the fluid in the smaller annular area 1375
is reduced. In
this manner, the carrying capacity of the circulating fluid is increased, and
the
equivalent circulating density at the bottom of the wellbore 1300E is reduced.
[0025x] The methods and apparatus of the present invention are usable with
expandable technology to increase an inside and outside diameter of the casing
in the
wellbore. For example, when drilling a section of wellbore with casing having
a drilling
device at a lower end, the drilling device is typically a bit portion that has
a greater
outside diameter than the casing string portion there above. The enlarged
portion can
be used to house an expansion tool, like a cone. When the string has been
drilled into
place, the cone can then be urged upwards mechanically, by fluid pressure, or
a
combination thereof to enlarge the entire casing string to an internal
diameter at least
as large as the cone. In a more specific example, casing is drilled into the
earth using a
bit disposed at a lower end thereof. The bit includes fluid pathways that
permit drilling
fluid to be circulated as the wellbore is formed. After completion of the
wellbore, the
fluid passageways are selectively closed. Thereafter, fluid is pressurized
against the
bottom of the string in order to provide an upward force to an expander cone
that is
housed in an enlarged portion of the casing adjacent the bit. In this manner,
the casing
is expanded and its diameter enlarged in a bottom up fashion.
[oow5ef A further alternate embodiment of the present invention involves
accomplishing a nudging operation to directionally drill a casing 740 Into the
formation
and expanding the casing 740 in a single run of the casing 740 into the
formation, as
shown in Figures 65 and 66. Additionally, cementing of the casing 740 into the
formation may optionally be performed in the same run of the casing 740 into
the
59
CA 02760504 2011-11-30
formation. Figures 65 show a diverting apparatus 710, including casing 740, an
earth
removal member or cutting apparatus 750, one or more fluid deflectors 775, and
a
landing seat 745.
[00260] Additional components of the embodiment of Figures 65 and 66 include
an
expansion tool 742 capable of radially expanding the casing 740, preferably an
expansion cone; a latching dart 786; and a dart seat 782. The expansion cone
742
may have a smaller outer diameter at its upper end than at its lower end, and
preferably
slopes radially outward from the upper end to the lower end. The expansion
cone 742
may be mechanically and/or hydraulically actuated. The latching dart 786 and
dart seat
782 are used in a cementing operation.
[00261] In operation, the diverting apparatus 710 is lowered into the wellbore
with the
expansion cone 742 located therein by alternately jetting and/or rotating the
casing 740.
The diverting apparatus 710 is preferably lowered into the wellbore by nudging
the
casing 740. Specifically, to form a deviated wellbore, the rotation of the
casing 740 is
halted, and a surveying operation is performed using the survey tool (not
shown) to
determine the location of the one or more fluid deflectors 775 within the
wellbore.
Stoking may also be utilized to keep track of the location of the fluid
deflector(s) 775.
[002621 Once the location of the fluid deflector(s) 775 within the wellbore is
determined, the casing 740 is rotated if necessary to aim the fluid
deflector(s) 775 in
the desired direction in which to deflect the casing 740. Fluid is then flowed
through the
casing 740 and the fluid deflector(s) 775 to form a profile (also termed a
"cavity") in the
formation. Then, the casing 740 may continue to be jetted into the formation.
When
desired, the casing 740 is rotated, forcing the casing 740 to follow the
cavity in the
formation. The locating and aiming of the fluid deflector(s) 775, flowing of
fluid through
the fluid deflector(s) 775, and further jetting and/or rotating the casing 740
into the
formation may be repeated as desired to cause the casing 740 to deflect the
wellbore in
the desired direction within the formation.
[002631 Next, a running tool 725 is introduced into the casing 740. A
physically
alterable bonding material, preferably cement, is pumped through the running
tool 725,
preferably an inner string. Cement is flowed from the surface into the casing
740, out
the fluid deflector(s) 775, and up through the annulus between the casing 740
and the
CA 02760504 2011-11-30
wellbore. When the desired amount of cement has been pumped, the dart 786 is
introduced into the inner string 725. The dart 786 lands and seals on the dart
seat 782.
The dart 786 stops flow from exiting past the dart seat, thus forming a fluid-
tight seal.
Pressure applied through the inner string 725 may help urge the expansion cone
742
up to expand the casing 740. In addition to or in lieu of the pressure through
the inner
string 725, mechanical pulling on the inner string 725 helps urge the
expansion cone
742 up.
[002641 Rather than using the latching dart 786, a float valve may be utilized
to
prevent back flow of cement. The latching dart 786 is ultimately secured onto
the dart
seat 782, preferably by a latching mechanism.
[002651 The running tool 725 may be any type of retrieval tool. Preferably,
the
retrieval of the expansion cone 742 involves threadedly or latch engaging a
longitudinal
bore through the expansion cone 742 with a lower end of the running tool 725.
The
running tool 725 is then mechanically pulled up to the surface through the
casing 740,
taking the attached expansion cone 742 with it. Alternately, the expansion
cone 742
may be moved upward due to pumping fluid, down through the casing 740 to push
the
expansion cone 742 upward due to hydraulic pressure, or by a combination of
mechanical and fluid actuation of the expansion cone 742. As the expansion
cone 742
moves upward relative to the casing 740, the expansion cone 742 pushes against
the
interior surface of the casing 740, thereby radially expanding the casing 740
as the
expansion cone 742 travels upwardly toward the surface. Thus, the casing 740
is
expanded to a larger internal diameter along its length as the expansion cone
742 is
retrieved to the surface.
[002661 Preferably, expansion of the casing 740 is performed prior to the
cement
curing to set the casing 740 within the wellbore, so that expansion of the
casing 740
squeezes the cement into remaining voids in the surrounding formation,
possibly
resulting in a better seal and stronger cementing of the casing 740 in the
formation.
Although the above operation was described in relation to cementing the casing
740
within the wellbore, expansion of the casing 740 by the expansion cone 742 in
the
method described may also be performed when the casino 740 is set within the
wellbore in a manner other than by cement.
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CA 02760504 2011-11-30
[002671 The cutting apparatus 750 may be drilled through by a subsequent
cutting
structure (possibly attached to a subsequent casing) or may be retrieved from
the
welibore, depending on the type of cutting structure 750 utilized (e.g.,
expandable,
drillable, or bi-center bit). Regardless of whether the cutting structure 750
is retrievable
or drillable, the subsequent casing may be lowered through the casing 740 and
drilled
to a further depth within the formation. The subsequent casing may optionally
be
cemented within the welibore. The process may be repeated with additional
casing
strings.
[00268] The present invention provides methods and apparatus whereby drill
string
may be used as casing, and the drill string may be cemented in place without
using the
drill bit mud passages to flow the cement to the annulus between the drill
string and the
borehole. Selectively openable passages are located in the drill string to
allow cement
to flow therethrough to cement the drill string in place in the borehole after
the well has
been completed.
[00269] Referring initially to Figure 67, there is shown at the bottom of a
borehole
1020 the terminal end portion of a prior art drill string 1010, having a float
sub 1016
connected to the distal end of a length of drill pipe 1018, and having an
earth removal
member, preferably a drill bit 1012, positioned on the terminal end 1014 of
the float sub
1016. Float sub 1016 is threaded over terminus of drill pipe 1018, it being
understood
that drill pipe 1018 is typically configured in sections of a finite length,
and a plurality of
such sections are threadingly interconnected so as to connect drill bit 1012
to a drilling
platform (not shown) at the earth surface or, where drilling is performed over
water, at a
position above such water. Also shown within drill string 1010 is a float
collar 1022,
which is fixed in position within float sub 1016, and which is used to prevent
backflow of
cementing solution injected Into the annulus 1024 between the drill string
1010 and the
borehole 1020 back up the hollow region 1026 in the drill. string 1010. It is
to be
understood that the float collar 1022 is shown in Figure 67 for ease of
illustration, and it
is not positioned within float sub during drilling operations, and thus mud is
free to flow
through the float sub 1016 and thence onward to the drill bit 1012, when float
collar
1022 is not located therein.
[00270] Drill bit 1012 is turned, about the axis of drill string 1010 by the
rotation of the
drill string 1010 at the upper end thereof (not shown), to further drill the
borehole 1020
62
CA 02760504 2011-11-30
into the earth. As drilling is ongoing, drilling "mud" is flowed from the
surface location,
down the hollow region 1026 of the drill string 1010, through float sub 1016
and thence
out through passage(s) 1028 in the drill bit 1012, whence it flows upwardly
through the
annulus 1024 between the drill string 1010 and the wall of the borehole 1020
to the
surface location. When the drilling operation is completed, water may be
flowed down
the hollow region 1026 to flush out remaining mud and thence returned to the
surface
through annulus 1024, and a physically alterable bonding material such as
cement is
then flowed down through the hollow region 1026 and thus into the annulus 1024
to
form a seal and support for the drill string 1010 in the borehole 1020. After,
or as, the
cementing operation is completed, float collar 1022 is pushed or lowered down
the
interior, hollow, portion of the drill string 1010 and latched into float sub
1016, which
thus provides a sealing mechanism to prevent uncured cement in annulus 1024
from
flowing back through drill bit 1012 and thus into hollow region 1026 of drill
string 1010.
Float collar 1022 may also include central passage 1029 therethrough, the
opening of
which is controlled by a valve 1030, such that cement may still be injected
into the
annulus 1024 after float collar 1022 is in place, but the valve 1030 will
close if cement
attempts to pass from the annulus 1024 and back into the drill string 1010.
After
sufficient cement is flowed down the drill string 1010, valve 1030 prevents
cement from
flowing back up the bore of the drill string 1010 while the cement cures. In
the event
cement leaks past valve 1030, wiper plugs 1034, 1032 are also positioned in
the hollow
region 1026 of the drill string to physically block fluids passing upwardly in
drill string
1010.
[00271] Referring to Figures 68 and 69, there is shown a first embodiment of
an
improved drill string 1100 for use as casing of the present invention. In this
embodiment, the earth removal member, preferably a drill bit 1012, and float
sub 1016
are configured to provide a port collar 1102 therebetween, which is configured
to
selectively provide an alternative fluid passage between hollow region 1026
and
annulus 1024, after the mud passages 1028 of the drill bit 1012 are
selectively closed-
off from communication with hollow region 1026, thereby ensuring that cement
may be
redirected from the drill bit passages 1028 on its way to annulus 1024.
[oo2721 Referring still to Figures 68 and 69, drill bit 1012 includes cutter
portion 1110,
through which a plurality of passages 1028 are disposed to enable transmission
of
drilling mud through the bit 1012. Each of the passages 1028 includes a bore
end 1112
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CA 02760504 2011-11-30
and an interior end 1114, the interior ends 1114 thereof joining in
communication with a
central aperture 1115 preferably configured to include a generally spherical
manifold
1116 having a generally spherical seat surface 1118 through which each of the
passages 1028 intersect and communicate with the hollow region 1026 through
which
mud is flowed from the surface. Extending from the manifold 1116 in the
direction of
the hollow passage 1026 in drill string 1010 is a reduced cross section, as
compared to
the width of hollow region 1026, throat region 1120, through which a ball 1122
(Figure
69 only) can be selectively provided. Ball 1122 is sized such that its
spherical diameter
is the same as, or substantially the same as, that of the spherical seat 1118,
such that
when ball 1 122 is urged into contact with spherical seat 1118, the interior
ends of the
passages 1028 will be sealed such that fluids in the hollow region cannot pass
through
the drill bit 1012 to enter annulus 1024. Ball 1122 is preferably manufactured
of an
elastomeric or other conformable, and easily milled or drilled, material, such
that it can
deform slightly to ensure coverage over all drill bit passages 1028 when
located in
manifold 1116.
[00273] Drill bit 1012 is connected to the drill string 1100 through a
threaded, or other
such connection, to the end of the float sub 1016. Float sub 1016 is
configured to have
an internal float shoe 1151 received in the inner bore thereof, such that a
float collar
1022 as shown in Figures 67 and 70, is selectively engageable therewith as, or
after,
the cementing of the drill string 1100 within the borehole 1020 is completed.
Thus, float
sub 1016 generally comprises a tubular element having a central bore 1124, a
threaded
first end 1128 which is threaded over the threaded end 1130 of the lowermost
piece of
pipe 1034 in the drill string 1100 and a lower terminal end 1132 to which
drill bit 1012 is
fixed. Within central bore 1124 is provided a float shoe locking region, to
enable a
downhole tool, such as a float collar 1022 (see Figure 67) to be selectively
secured
thereto, which in this embodiment is provided by including within the central
bore 1124
a second, larger right cylindrical latching bore 1136. Central bore 1124
communicates,
at the lower terminal end 1132 of float sub 1016, with a manifold 1116, and,
further
includes a tapered guiding region 1134 opening into a receiving bore 1138
terminating
in a latching lip 1140 extending as a hump, semicircular in cross section
extending
inwardly into receiving central bore 1138 about its circumference. The float
shoe 1151
portion of float sub 1016 may be provided by molding or machining a plastic,
cement, or
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CA 02760504 2011-11-30
otherwise easily machined material, and press-fitting, molding in place, or
otherwise
securing this form into the tubular body of the float sub 1016.
[00270 The lower end of float sub 1016 is specifically configured to enable
redirect of
fluids passing down the drill string 1100 from the passages 1028 in the drill
bit 1012 into
alternative cement passages 1158 specifically configured for passage of cement
therethrough to enable cementing of the drill string 1010 in place in the
borehole 1020.
The alternative cement passages 1158 are selectively blocked by a port collar
1102,
which is a sleeve configured to sealingly cover the cement passages 1158
during
drilling operations, and then move to enable communication of the passages
1158 with
the annulus 1024. In this embodiment, the port collar 1102 is configured to
include an
integral piston therewith, and the remainder of the port collar 1102, in
conjunction with
the body of the float sub 1016, forms a cavity 1104 which may be pressurized
to cause
the piston portion of the port collar 1102 to slide from a position blocking
the cement
passages 1158 to a position in which the cement passages 1158 form a fluid
passageway from the hollow region 1026 of drill string 1010 to annulus 1024.
To
enable this structure, the lower end of float sub 1016 includes a first,
generally right
cylindrical recessed (with respect to the main body portion of the float sub
1016) face
1150, which terminates at an upper ledge 1152 which extends from face 1150 to
the full
outer diameter of the float sub 1016, and further includes a plurality of pin
receiving
apertures 1154 extending therein. Face 1150 extends, from ledge 1152, to a
tapered
wall 1155 which ends at a second recessed, again generally right circular,
face 1156,
through which a plurality of cement passage bores 1158 extend into
communication
with hollow region 1026. Second recessed face 1156 ends at an additional
tapered
wall 1169, which terminates at a generally right, circular cylindrical port
collar face
1159.
[00275] Disposed over this plurality of faces 1150, 1156, 1169 and tapered
walls
1155, 1159 is the port collar 1102. Port collar 1102 is generally configured
as a
doglegged sleeve, and thus includes a tubular body 1160 having a first end
1162
including a first seal annulus 1164 in the inner face 1166 thereof adjacent
the first end
1162, and an inwardly projecting dogleg portion 1168 forming in the second end
1170
thereof, and likewise including an annular seal annulus 1172 in the inner face
thereof.
Each of seal annuli 1164, 1172 have a seal, such as an o-ring seal, located
therein,
such that the inner face of such seal sealingly engages with the corresponding
surface
CA 02760504 2011-11-30
of the lower end of float sub 1016, i.e., seal 1164 contacts against face
1150, and seal
1172 contacts port collar face 1159, and the inner surface sealingly engages
the
respective annuli 1164, 1172 base or sides, such that a sealed piston cavity
1104 is
formed of the portion of the float collar 1016 covered by the port collar
1102.
Preferably, seal 1164 is larger than seal 1172 to form a differential area for
pressure to
act on. Additionally, a plurality of pin holes 1174 are provided through the
tubular body
1160 of the port collar 1102 adjacent first end 1162 thereof, such that pins
1178
sealingly extend therethrough and then into pin apertures 1154 in float sub
1016. Thus,
the port collar 1102 both forms a seal between the bores 1158 and the annulus
1024
and is secured against undesired movement on the float sub 1016 by pins 1178.
Additionally, the dogleg portion 1168 forms an annular piston such that, upon
pressurization of the piston cavity 1104, it will cause port collar 1102 to
slide along the
outer surface of float sub 1016 and thereby open communication of passages
1158
with annulus 1024.
(00276] Referring to Figures 68 and 69, the operation of port collar 1102 is
demonstrated as between the closed position of Figure 68 and the open position
of
Figure 69. In the position of the port collar 1102 shown in Figure 68,
drilling mud
flowing down the hollow portion 1026 of the drill string passes through the
bore 1124 of
float sub 1016, thence into manifold 1116 of drill bit 1012 whence it passes
through
passages 1028 therein and into annulus 1024 where it is returned to the
surface. Thus,
the port collar 1102 position of Figure 68 enables traditional flow of fluids
through the
passages 1028 in the drill bit 1012, such as during drilling operations. To
initiate
cementing operations, water may be flowed down the hollow portion 1026 of
drill string,
and thence through float sub 1016 and drill bit 1012, to flush remaining loose
mud from
the drill string components and the annulus 1024. Then, cement will be flowed
down
the hollow portion 1026 to be flowed into, and cement the drill string 1010
within, the
annulus 1024. To enable diversion of the cement to cement passages 1158, and
thus
prevent cement flow through the drill bit passages 1028, ball 1122 is inserted
into the
hollow portion (not shown) of drill string 1010 at the surface location, just
before or just
as cement is being flowed down the hollow region 1026, it being understood
that
cement in a liquid or slurry form is flowed down the hollow portion 1026
immediately
over another fluid, such as water or mud, already therein and in the annulus
1024. Ball
1122 is thus carried down the hollow portion 1026, through the bore 1124 of
float sub
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CA 02760504 2011-11-30
1016, and thence into manifold 1116 of drill bit 1012 where it covers, and
thus seals off,
the openings at the interior ends 1114 of mud passages 1028 of drill bit 1012
from the
flow of fluids down the hollow portion 1026 of the drill string 1010.
[00277) Although the flow of fluids through the mud passages 1028 of the drill
bit
1012 is prevented by positioning of the ball 1122 in manifold 1116, fluid is
still being
pumped into the hollow region 1026 from a surface location, and this fluid
creates a
large pressure in the piston cavity 1104. When this pressure is sufficiently
greater than
the pressure in the annulus 1024, such that the force bearing against the
outer surface
of dogleg portion 1168 (exposed to fluid in the annulus 1024), in combination
with the
shear strength of the pins 1178 holding the port collar 1102 to the float sub
1016 is less
than the force bearing against the inner portion or surface of dogleg portion
1168
(exposed to the fluid in piston cavity 1104), port collar 1102 will slide
downwardly about
port collar face 1159, to the position shown in Figure 69, thereby opening
communication of the cement passages 1158 with the annulus 1024 and enabling
cement flowed down the hollow portion 1026 to pass through the cement passages
1158 to flow into annulus 1024.
[00278) Referring now to Figure 70, float collar 1022, which is selectively
positionable
within float sub 1016, is shown received within float sub 1016. Float collar
1022 is
essentially a one-way valve having the capability to be remotely positioned in
a remote
borehole 1020 location as or after fluid which it is intended to control the
flow of has
entered the borehole 1020. It will typically be positioned in the float sub
1016 after, or
just as, cementing is completed through cement passages 1158, to provide a
blocking
mechanism and thereby prevent fluid flow of cement back into hollow portion
1026 of
drill string 1010.
[00279) Float collar 1022 includes a main body portion 1180, having a
generally
cylindrical, rod like appearance, provided with a central aperture 1182
therethrough,
configured to enable selected communication of fluids from hollow portion 1026
therethrough to cement passages 1158. The outer cylindrical surface thereof
includes
a latch recess 1184, within which are positioned a plurality of spring loaded
dogs 1186.
When float collar 1022 is positioned within float shoe 1151, dogs 1186 are
urged
outwardly from collar 1022 by springs positioned between the dogs 1186 and the
body
of float collar 1022, and thereby engage within the latching bore 1136 of
float shoe
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CA 02760504 2011-11-30
1151 to retain float collar 1022 therein. The float collar 1022 further
includes, at the
and thereof furthest from the drill bit 1012 location, a wiper seal 1188, in
the form of an
annular ring, and at the end thereof closest to the drill bit 1022, a check
valve 1190 in
fluid communication with central aperture 1182 of float collar 1022. Check
valve 1190
comprises a valve cavity 1192 integral of float collar body, having a lower,
inwardly
protruding spring ledge 1193, an upper, semi-spherical valve seat 1194, and a
spring
1196 loaded valve 1198 having a semi-spherical sealing surface 1200. Spring
1196 is
carried on spring ledge 1193, and it extends therefrom to the rear side of
sealing
surface 1200. Valve seat 1194 is positioned such that aperture 1182 intersects
valve
seat 1194, and when spring 1196 urges valve 1198 thereagainst, sealing surface
1200
blocks aperture 1182, thereby preventing fluid flow therethrough in a
direction where
such fluid would otherwise enter hollow portion 1026. Thus, if the pressure in
central
aperture 1182, formed by the fluids flowing down hollow portion 1026, is
greater than
the pressure in the region of cement passages 1158 plus the force of spring
1196
tending to urge the valve 1190 to a closed position, the valve sealing surface
1200 will
back off seat 1194, allowing flow therethrough in the direction of cement
passages
1158. However, if the pressure in the central aperture 1182 drops below that
in the
cementing passages 1158 plus the force associated with the spring 1196, the
valve
1190 will close positioning the sealing surface 1200 against the seat 1194,
preventing
flow in the direction from cement passages 1158 to hollow portion 1026 of
drill string
1010.
[0028o] To position the float collar 1022 in the float sub 1016, the float
collar 1022 is
lowered down the hollow portion 1026 of the drill string 1010, such as on a
wire or
cable, or, if necessary, on a more rigid mechanism, such that the valve 1190
end of the
float collar 1022 enters through bore 1124 of the float sub 1016. As the float
collar
1022 is lowered, cement is flowing down the hollow portion 1026, so that upon
insertion
of the valve 1190 end of the float collar 1022 into the bore 1124 of float sub
1016, the
float collar 1022 substantially blocks the bore 1124 and the weight of the
cement in the
hollow portion 1026 (including other fluids which may be located above the
cement in
the hollow portion 1026), bears upon the float collar 1022 and tends to force
it into the
float sub 1016. Dogs 1186 may be in a retracted position, such that a trigger
mechanism (not shown) is provided which causes therein expansion from the
recess
1184 and into latching bore 1136, or the dogs 1186 may enter into the drill
string 1010
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CA 02760504 2011-11-30
in the extended position shown in Figure 70, such that the tapered portion
1134 of bore
1124 will cause the dogs 1186 to recess into latching bore 1136 and the dogs
1186 will
re-extend upon reaching latching bore 1136. Alternatively, the float collar
1022 may be
pumped down with plug 1121 ahead of the cement.
too2s11 Referring still to Figure 70, a plurality of wiper plugs 1121, 1123
may also be
provided downhole during cementing operations. The first, or bottom wiper plug
1121
is a generally cylindrical member having an outer contoured surface 1125
forming a
plurality of ridges 1126 of a sinusoidal cross-section, terminating in opposed
flat ends
1127, 1129, and further including a central bore 1131 therethrough. The
lowermost of
the ridges 1126 is positionable over latching lip 1140 on float shoe 1151 to
lock first
wiper plug 1121 in position in the borehole 1020. Second wiper plug 1123
likewise
includes opposed flat ends 1127, 1129 and ridges 1126, but no through-bore.
Ridges
1126 on both wiper plugs 1121, 1123 are sized to contact, in compression, the
interior
of the drill string 1010 and thereby form a barrier or seal between the areas
on either
side thereof. Wiper plugs 1121, 1123 provide additional security against the
backing
out of the float collar 1022 from float sub 1016, and against leakage of
cement from the
annulus 1024 and back up the hollow portion 1026 of the drill string 1010.
[00282] Once the cement has hardened in the annulus 1024, float collar 1022
may be
removed from the float sub 1016. Typically, float collar 1022 includes a
mechanism for
retracting the dogs 1186, such as by twisting the float collar 1022 or
otherwise, thereby
retracting dogs 1186 and allowing float collar 1022 to be pulled from the
well, after first
pulling wiper plugs 1121, 1123. Alternatively, float collar 1022, wiper plugs
1121, 1123
and drill bit 1012, along with float sub 1016, may be ground up at the base of
the well
by a grinding or milling tool (not shown) sent down the drill string 1010 for
that purpose.
Alternatively, wiper plugs 1121, 1123, float collar 1022, ball 1122, and drill
bit 1012 may
be drilled up with a subsequent drill string so that the well may be drilled
deeper.
Alternatively still, float collar 1022, float shoe 1151, drill bit 1012, and
wiper plugs 1121,
1123 may be left in place at the base of the borehole 1020, and a production
zone can
be established above the upper wiper plug 1123, by perforating the. drill
string 1010 at
that location.
[00283] In another embodiment, the float collar may comprise a flapper valve.
In this
respect, the flapper valve may be run in place. Thereafter, a ball may be
pumped
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CA 02760504 2011-11-30
through the flapper valve, thereby eliminating the need to lower or pump the
float collar
into the float sub. .
[00284] Referring now to Figures 71 and 72, there is shown an alternative
embodiment of the present invention, wherein the port collar 1102 of Figures
68-70 is
replaced with a membrane 1133. In this embodiment, all other features of the
invention
and application of the invention to a cementing operation remain the same as
in the
embodiment described with respect to Figures 68-70, except that the port
collar 1102
and the modifications to the float sub 1016 needed to use the port collar 1102
are not
necessary. In their place is provided a cement aperture 1202, configured to be
in
communication with spherical manifold 1116. The membrane 1133, configured of a
material capable of withstanding the pressure of the drilling mud circulating
through the
drill string 1010 and annulus 1024 while drilling is occurring, covers the
cement
aperture 1202 so as to seal it off from communication between the annulus 1024
and
manifold 1116.
[002851 To enable cementing in this embodiment, ball 1122 is placed into the
drill
string 1010 as before, as shown in Figure 72, where the ball 1122 passes
through bore
1124 of float sub 1016 and thence makes its way to spherical manifold 1116 of
drill bit
1012 to be received against, and deform against, spherical seat 1116 where it
blocks
passage of drilling mud through drill bit passages 1028. Thus, the hydrostatic
head of
the drilling mud, or, if desired at this point, water or cement, bears upon
membrane
1133, causing it to rupture, thereby causing the fluid to pass though cement
aperture
1202 and thence up into annulus 1024 to cement the drill string 1010 in place
in the
borehole 1020. As in the first embodiment, the float collar 1022 and wiper
plugs 1121,
1123 (as shown in Figure 70) are used to ensure that cement does not flow back
out
the annulus 1024 and up the drill string 1010, and, the wiper plugs may be
either
removed, ground or drilled through, or left In place, as discussed with
respect to the first
embodiment.
[00286] Although the port collar 1102, or cement aperture 1202, .is described
herein
as being positioned in the drill string 1010 with respect to a float sub 1016
located
immediately adjacent to the drill bit 1012, it should be understood that such
features
may be provided in any location intermediate the drill bit 1012 and the
surface location.
Cementing operations for deep wells may require cement introduction at several
depth
CA 02760504 2011-11-30
locations along the casing 1010 to create proper cementing conditions.
Therefore, it is
specifically contemplated that the drill string 1010 can include a plurality
of fluid diversion
members along its length. For example, once the cementing operation is
completed at
the bottom of the well, the cement may only extend up the annulus 1024 between
the
drill string 1010 and borehole 1020 a fraction of the length of the borehole
1020. As
such level of cement may be predicted and/or controlled, the fluid diversion
apparatus
such as the port collar 1102 or the membrane 1133 of the present invention can
be
placed at predictable locations for its use. To enable a cementing operation,
the
selected diverting apparatus is provided in the drill string 1010 in a known
location or
locations, and a plug may be placed at a location in the drill string 1010
below the
diverting apparatus, to seal off the drill string 1010 below that location,
Then a float sub
such as float sub 1016, may be positioned above the diverting apparatus, and
the
cement flowed to cause the diverting apparatus to open and thus direct cement
into the
annulus 1024 at that location The various collars and other peripheral devices
placed
downhole during cementing may be drilled out with a bit or mill placed down
the drill
string 1010 after each sequential cementing operation, or, alternatively,
after all
cementing has been completed.
[00287] With reference to Figures 1-6, in one embodiment, the present
invention
includes a method for lining a wellbore comprising providing a drilling
assembly 100
comprising an earth removal member 60 and a wellbore lining conduit 10,
wherein the
drilling assembly includes a first fluid flow path 30 and a second fluid flow
path 97;
advancing the drilling assembly into the earth; flowing a fluid through the
first fluid flow
path and returning at least a portion of the fluid through the second fluid
flow path; and
leaving the wellbore lining conduit at a location within the wellbore. In one
aspect, the
drilling assembly further includes a third fluid flow path and the method
further comprises
flowing at least a portion of the fluid through the third fluid flow path. In
another
embodiment, the present invention includes a method for lining a wellbore
comprising
providing a drilling assembly comprising an earth removal member and a
wellbore lining
conduit, wherein the drilling assembly includes a first fluid flow path and a
second fluid
flow path; advancing the drilling assembly into the earth; flowing a fluid
through the first
fluid flow path and returning at least a portion of the fluid through the
second fluid flow
path; and leaving the wellbore lining conduit at a location within the
wellbore, wherein
the first and second fluid flow paths are in opposite directions.
71
CA 02760504 2011-11-30
[00288] With reference to Figures 1-6, in another embodiment, the present
invention
includes a method for lining a wellbore comprising providing a drilling
assembly
comprising an earth removal member and a wellbore lining conduit, wherein the
drilling
assembly includes a first fluid flow path and a second fluid flow path;
advancing the
drilling assembly into the earth; flowing a fluid through the first fluid flow
path and
returning at least a portion of the fluid through the second fluid flow path;
and leaving the
wellbore lining conduit at a location within the wellbore, wherein the
drilling assembly
comprises a tubular assembly, at least a portion of the tubular assembly being
disposed
within the wellbore lining conduit. In one aspect, the first fluid flow path
is within the
tubular assembly.
[00289] With reference to Figures 1-6, one embodiment of the present invention
includes a method for lining a wellbore comprising providing a drilling
assembly
comprising an earth removal member and a wellbore lining conduit, wherein the
drilling
assembly includes a first fluid flow path and a second fluid flow path;
advancing the
drilling assembly into the earth; flowing a fluid through the first fluid flow
path and
returning at least a portion of the fluid through the second fluid flow path;
and leaving the
wellbore lining conduit at a location within the wellbore, wherein the
drilling assembly
comprises a tubular assembly, at least a portion of the tubular assembly being
disposed
within the wellbore lining conduit, wherein the second fluid flow path is
within the tubular
assembly.
[00290] With reference to Figure 50, yet another embodiment of the present
invention
includes a method for lining a wellbore comprising providing a drilling
assembly
comprising an earth removal member 693 and a wellbore lining conduit 610,
wherein the
drilling assembly includes a first fluid flow path and a second fluid flow
path; advancing
the drilling assembly into the earth; flowing a fluid through the first fluid
flow path and
returning at least a portion of the fluid through the second fluid flow path;
and leaving the
wellbore lining conduit at a location within the wellbore, wherein the
drilling assembly
comprises a tubular assembly, at least a portion of the tubular assembly being
disposed
within the wellbore lining conduit; and providing a first sealing member 603
on an outer
portion of the wellbore lining conduit. In one aspect, the method further
comprises
supplying a physically alterable bonding material through the drilling
assembly to an
annular area defined by an inner surface of the wellbore and an outer surface
of the
wellbore lining conduit. In another aspect of the present invention, supplying
the
72
CA 02760504 2011-11-30
physically alterable bonding material through the drilling assembly to the
annular area
comprises flowing the physically alterable bonding material into a second
annular area
between the tubular assembly and the wellbore lining conduit at a location
below the
second sealing member 640.
[00291] With reference to Figure 50, in another embodiment, the present
invention
includes a method for lining a wellbore comprising providing a drilling
assembly
comprising an earth removal member and a wellbore lining conduit, wherein the
drilling
assembly includes a first fluid flow path and a second fluid flow path;
advancing the
drilling assembly into the earth; flowing a fluid through the first fluid flow
path and
returning at least a portion of the fluid through the second fluid flow path;
leaving the
wellbore lining conduit at a location within the wellbore, wherein the
drilling assembly
comprises a tubular assembly, at least a portion of the tubular assembly being
disposed
within the wellbore lining conduit; providing a first sealing member on an
outer portion of
the wellbore lining conduit; supplying a physically alterable bonding material
through the
drilling assembly to an annular area defined by an inner surface of the
wellbore and an
outer surface of the wellbore lining conduit; and actuating the first sealing
member to
retain the physically alterable bonding material in the annular area.
[00292] With reference to Figure 50, in one embodiment, the present invention
includes a method for lining a wellbore comprising providing a drilling
assembly
comprising an earth removal member and a wellbore lining conduit, wherein the
drilling
assembly includes a first fluid flow path and a second fluid flow path;
advancing the
drilling assembly into the earth; flowing a fluid through the first fluid flow
path and
returning at least a portion of the fluid through the second fluid flow path;
leaving the
wellbore lining conduit at a location within the wellbore, wherein the
drilling assembly
comprises a tubular assembly, at least a portion of the tubular assembly being
disposed
within the wellbore lining conduit; providing a first sealing member on an
outer portion of
the wellbore lining conduit; and providing a second sealing member on an outer
portion
of the tubular assembly.
[00293] With reference to Figure 50, another embodiment of the present
invention
provides a method for lining a wellbore comprising providing a drilling
assembly
comprising an earth removal member and a wellbore lining conduit, wherein the
drilling
assembly includes a first fluid flow path and a second fluid flow path;
advancing the
73
CA 02760504 2011-11-30
drilling assembly into the earth; flowing a fluid through the first fluid flow
path and
returning at least a portion of the fluid through the second fluid flow path;
leaving the
wellbore lining conduit at a location within the wellbore, wherein the
drilling assembly
comprises a tubular assembly, at least a portion of the tubular assembly being
disposed
within the wellbore lining conduit, wherein the earth removal member is
operatively
connected to the tubular assembly. In one aspect, the earth removal member is
an
underreamer 692. In another aspect, the earth removal member is an expandable
bit.
[00294] With reference to Figure 50, another embodiment of the present
invention
provides a method for lining a wellbore comprising providing a drilling
assembly
comprising an earth removal member and a wellbore lining conduit, wherein the
drilling
assembly includes a first fluid flow path and a second fluid flow path;
advancing the
drilling assembly into the earth; flowing a fluid through the first fluid flow
path and
returning at least a portion of the fluid through the second fluid flow path;
leaving the
wellbore lining conduit at a location within the wellbore, wherein the
drilling assembly
comprises a tubular assembly, at least a portion of the tubular assembly being
disposed
within the wellbore lining conduit, wherein the drilling assembly further
comprises a
motor 694. Another embodiment includes a method for lining a wellbore
comprising
providing a drilling assembly comprising an earth removal member and a
wellbore lining
conduit, wherein the drilling assembly includes a first fluid flow path and a
second fluid
flow path; advancing the drilling assembly into the earth; flowing a fluid
through the first
fluid flow path and returning at least a portion of the fluid through the
second fluid flow
path; leaving the wellbore lining conduit at a location within the wellbore,
wherein the
drilling assembly comprises a tubular assembly, at least a portion of the
tubular
assembly being disposed within the wellbore lining conduit, wherein the
drilling assembly
further comprises at least one measuring tool 696.
[00295] With reference to Figure 7 and paragraph [00129), another embodiment
of
the present invention provides a method for lining a wellbore comprising
providing a
drilling assembly 102 comprising an earth removal member 115 and a wellbore
lining
conduit 120, wherein the drilling assembly includes a first fluid flow path
and a second
fluid flow path; advancing the drilling assembly into the earth; flowing a
fluid through the
first fluid flow path and returning at least a portion of the fluid through
the second fluid
flow path; leaving the wellbore lining conduit at a location within the
wellbore, wherein
the drilling assembly comprises a tubular assembly, at least a portion of the
tubular
74
CA 02760504 2011-11-30
assembly being disposed within the welibore lining conduit, wherein the
drilling assembly
further comprises at least one logging tool. In another embodiment, the
present
invention provides a method for lining a wellbore comprising providing a
drilling
assembly comprising an earth removal member and a wellbore lining conduit,
wherein
the drilling assembly includes a first fluid flow path and a second fluid flow
path;
advancing the drilling assembly into the earth; flowing a fluid through the
first fluid flow
path and returning at least a portion of the fluid through the second fluid
flow path;
leaving the wellbore lining conduit at a location within the wellbore, wherein
the drilling
assembly comprises a tubular assembly, at least a portion of the tubular
assembly being
disposed within the wellbore lining conduit, wherein the drilling assembly
further
comprises a steering system.
[00296] With reference to Figure 7 and paragraph [001297, one embodiment of
the
present invention includes a method for lining a wellbore comprising providing
a drilling
assembly comprising an earth removal member and a wellbore lining conduit,
wherein
the drilling assembly includes a first fluid flow path and a second fluid flow
path;
advancing the drilling assembly into the earth; flowing a fluid through the
first fluid flow
path and returning at least a portion of the fluid through the second fluid
flow path;
leaving the wellbore lining conduit at a location within the wellbore, wherein
the drilling
assembly comprises a tubular assembly, at least a portion of the tubular
assembly being
disposed within the wellbore lining conduit, wherein the drilling assembly
further
comprises a landing sub for a measuring tool. Another embodiment includes a
method
for lining a wellbore comprising providing a drilling assembly comprising an
earth
removal member and a wellbore lining conduit, wherein the drilling assembly
includes a
first fluid flow path and a second fluid flow path; advancing the drilling
assembly into the
earth; flowing a fluid through the first fluid flow path and returning at
least a portion of the
fluid through the second fluid flow path; leaving the wellbore lining conduit
at a location
within the wellbore, wherein the drilling assembly comprises a tubular
assembly, at least
a portion of the tubular assembly being disposed within the wellbore lining
conduit,
wherein the drilling assembly further comprises at least one latching
assembly.
[00297] With reference to Figure 7, yet another embodiment of the present
invention
provides a method for lining a wellbore comprising providing a drilling
assembly
comprising an earth removal member and a wellbore lining conduit, wherein the
drilling
assembly includes a first fluid flow path and a second fluid flow path;
advancing the
CA 02760504 2011-11-30
drilling assembly into the earth; flowing a fluid through the first fluid flow
path and
returning at least a portion of the fluid through the second fluid flow path;
leaving the
wellbore lining conduit at a location within the wellbore, wherein the
drilling assembly
comprises a tubular assembly, at least a portion of the tubular assembly being
disposed
within the wellbore lining conduit, wherein the drilling assembly further
comprises a liner
hanger assembly 130. Another embodiment of the present invention provides a
method
for lining a wellbore comprising providing a drilling assembly comprising an
earth
removal member and a wellbore lining conduit, wherein the drilling assembly
includes a
first fluid flow path and a second fluid flow path; advancing the drilling
assembly into the
earth; flowing a fluid through the first fluid flow path and returning at
least a portion of the
fluid through the second fluid flow path; leaving the wellbore lining conduit
at a location
within the wellbore, wherein the drilling assembly comprises a tubular
assembly, at least
a portion of the tubular assembly being disposed within the wellbore lining
conduit,
wherein the drilling assembly further comprises at least one sealing member
148
thereon.
[00298] With reference to Figure 7, another embodiment of the present
invention
provides a method for lining a wellbore comprising providing a drilling
assembly
comprising an earth removal member and a wellbore lining conduit, wherein the
drilling
assembly includes a first fluid flow path and a second fluid flow path;
advancing the
drilling assembly into the earth; flowing a fluid through the first fluid flow
path and
returning at least a portion of the fluid through the second fluid flow path;
leaving the
wellbore lining conduit at a location within the wellbore, wherein the
drilling assembly
comprises a tubular assembly, at least a portion of the tubular assembly being
disposed
within the wellbore lining conduit, wherein the drilling assembly further
comprises at least
one stabilizing member 190 thereon. In one aspect, the at least one
stabilizing member
is eccentrically disposed on at least a portion of the tubular assembly, In
another
aspect, the at least one stabilizing member is adjustable.
[00299] With reference to Figure 30 and paragraph [00179], another embodiment
of
the present invention provides a method for lining a wellbore comprising
providing a
drilling assembly comprising an earth removal member and a wellbore lining
conduit,
wherein the drilling assembly includes a first fluid flow path and a second
fluid flow path;
advancing the drilling assembly into the earth; flowing a fluid through the
first fluid flow
path and returning at least a portion of the fluid through the second fluid
flow path;
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CA 02760504 2011-11-30
leaving the wellbore lining conduit at a location within the wellbore, wherein
the drilling
assembly comprises a tubular assembly, at least a portion of the tubular
assembly being
disposed within the wellbore lining conduit, wherein the drilling assembly
further
comprises a bent housing. With reference to Figure 7 and paragraph [00129], an
embodiment of the present invention provides a method for lining a wellbore
comprising
providing a drilling assembly comprising an earth removal member and a
wellbore lining
conduit, wherein the drilling assembly includes a first fluid flow path and a
second fluid
flow path; advancing the drilling assembly into the earth; flowing a fluid
through the first
fluid flow path and returning at least a portion of the fluid through the
second fluid flow
path; leaving the wellbore lining conduit at a location within the wellbore,
wherein the
drilling assembly comprises a tubular assembly, at least a portion of the
tubular
assembly being disposed within the wellbore lining conduit, wherein the earth
removal
member includes at least one jetting orifice for flowing a fluid therethrough.
[00300] With reference to Figures 1-6. in yet another embodiment, the present
invention includes a method for lining a wellbore comprising providing a
drilling assembly
comprising an earth removal member and a wellbore lining conduit, wherein the
drilling
assembly includes a first fluid flow path and a second fluid flow path;
advancing the
drilling assembly into the earth; flowing a fluid through the first fluid flow
path and
returning at least a portion of the fluid through the second fluid flow path;
leaving the
wellbore lining conduit at a location within the wellbore, wherein the
drilling assembly
comprises a tubular assembly, at least a portion of the tubular assembly being
disposed
within the wellbore lining conduit, wherein the second fluid flow path is
within an annular
area formed between an outer surface of the tubular assembly and an inner
surface of
the wellbore lining conduit. Another embodiment of the present invention
provides a
method for lining a wellbore comprising providing a drilling assembly
comprising an earth
removal member and a wellbore lining conduit, wherein the drilling assembly
includes a
first fluid flow path and a second fluid flow path; advancing the drilling
assembly into the
earth; flowing a fluid through the first fluid flow path and returning at
least a portion of the
fluid through the second fluid flow path; leaving the wellbore lining conduit
at a location
within the wellbore, wherein the drilling assembly comprises a tubular
assembly, at least
a portion of the tubular assembly being disposed within the wellbore lining
conduit,
wherein the first fluid flow path is within an annular area formed between an
outer
surface of the tubular assembly and an inner surface of the wellbore lining
conduit.
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CA 02760504 2011-11-30
[00301] With reference to Figures 1-6, an embodiment of the present invention
includes a method for lining a wellbore comprising providing a drilling
assembly
comprising an earth removal member and a wellbore lining conduit, wherein the
drilling
assembly includes a first fluid flow path and a second fluid flow path;
advancing the
drilling assembly into the earth; flowing a fluid through the first fluid flow
path and
returning at least a portion of the fluid through the second fluid flow path;
and leaving the
wellbore lining conduit at a location within the wellbore, wherein the first
and second fluid
flow paths are in fluid communication when the drilling assembly is disposed
in the
wellbore. Another embodiment includes a method for lining a wellbore
comprising
providing a drilling assembly comprising an earth removal member and a
wellbore lining
conduit, wherein the drilling assembly includes a first fluid flow path and a
second fluid
flow path; advancing the drilling assembly into the earth; flowing a fluid
through the first
fluid flow path and returning at least a portion of the fluid through the
second fluid flow
path; and leaving the wellbore lining conduit at a location within the
wellbore, wherein
advancing the drilling assembly into the earth comprises rotating at least a
portion of the
drilling assembly. In one aspect, the rotating portion of the drilling
assembly comprises
the earth removal member.
[00302] With reference to Figures 1-6, an additional embodiment of the present
invention provides a method for lining a wellbore comprising providing a
drilling
assembly comprising an earth removal member and a wellbore lining conduit,
wherein
the drilling assembly includes a first fluid flow path and a second fluid flow
path;
advancing the drilling assembly into the earth; flowing a fluid through the
first fluid flow
path and returning at least a portion of the fluid through the second fluid
flow path;
leaving the wellbore lining conduit at a location within the wellbore; and
removing at least
a portion of the drilling assembly from the wellbore. In one aspect, the
method further
comprises conveying a cementing assembly into the wellbore. In another aspect,
the
method further comprises supplying a physically alterable bonding material
through the
cementing assembly to an annular area defined by an inner surface of the
wellbore and
an outer surface of the wellbore lining conduit.
[00303] With reference to Figures 30-35, an embodiment of the present
invention
provides a method for lining a wellbore comprising providing a drilling
assembly
comprising an earth removal member and a wellbore lining conduit, wherein the
drilling
assembly includes a first fluid flow path and a second fluid flow path;
advancing the
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CA 02760504 2011-11-30
drilling assembly into the earth; flowing a fluid through the first fluid flow
path and
returning at least a portion of the fluid through the second fluid flow path;
and leaving the
wellbore lining conduit at a location within the wellbore, wherein at least a
portion of the
drilling assembly extends below a lower end of the wellbore lining conduit
while
advancing the drilling assembly into the earth. An additional embodiment
provides a
method for lining a wellbore comprising providing a drilling assembly
comprising an earth
removal member and a wellbore lining conduit, wherein the drilling assembly
includes a
first fluid flow path and a second fluid flow path; advancing the drilling
assembly into the
earth; flowing a fluid through the first fluid flow path and returning at
least a portion of the
fluid through the second fluid flow path; leaving the wellbore lining conduit
at a location
within the wellbore; and relatively moving a portion of the drilling assembly
and the
wellbore lining conduit. In one aspect, the method further comprises reducing
a length
of the drilling assembly.
[00304] With reference to Figures 30-35, another embodiment includes a method
for
lining a wellbore comprising providing a drilling assembly comprising an earth
removal
member and a wellbore lining conduit, wherein the drilling assembly includes a
first fluid
flow path and a second fluid flow path; advancing the drilling assembly into
the earth;
flowing a fluid through the first fluid flow path and returning at least a
portion of the fluid
through the second fluid flow path; leaving the wellbore lining conduit at a
location within
the wellbore; relatively moving a portion of the drilling assembly and the
wellbore lining
conduit; and advancing the wellbore lining conduit proximate a bottom of the
wellbore.
In another embodiment, the present invention includes a method for lining a
wellbore
comprising providing a drilling assembly comprising an earth removal member
and a
wellbore lining conduit, wherein the drilling assembly includes a first fluid
flow path and a
second fluid flow path; advancing the drilling assembly into the earth;
flowing a fluid
through the first fluid flow path and returning at least a portion of the
fluid through the
second fluid flow path; leaving the wellbore lining conduit at a location
within the
wellbore; relatively moving a portion of the drilling assembly and the
wellbore lining
conduit: and engaging a cementing orifice with the drilling assembly. In one
aspect, the
method further comprises supplying a physically alterable bonding material
through a
portion of the first fluid flow path and through the cementing orifice to an
annular area
defined by an outer surface of the wellbore lining conduit and an inner
surface of the
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CA 02760504 2011-11-30
wellbore. In another aspect, the method further comprises disengaging the
cementing
orifice and removing at least a portion of the drilling assembly from the
wellbore.
[00305] With reference to Figures 30-35, an embodiment of the present
invention
provides a method for lining a wellbore comprising providing a drilling
assembly
comprising an earth removal member and a wellbore lining conduit, wherein the
drilling
assembly includes a first fluid flow path and a second fluid flow path;
advancing the
drilling assembly into the earth; flowing a fluid through the first fluid flow
path and
returning at least a portion of the fluid through the second fluid flow path;
leaving the
wellbore lining conduit at a location within the wellbore; and closing at
least a portion of
the first fluid flow path. In one aspect, the method further comprises
introducing a
physically alterable bonding material through the first fluid flow path to an
annular area
defined by an outer surface of the wellbore lining conduit and an inner
surface of the
wellbore. In another aspect, the method further comprises activating one or
more
sealing elements to substantially seal the annular area. In yet another
aspect, the inner
surface of the wellbore comprises an inner surface of a wellbore casing.
[00306) With reference to Figures 30-35, in another embodiment, the present
invention includes a method for lining a wellbore comprising providing a
drilling assembly
comprising an earth removal member and a wellbore lining conduit, wherein the
drilling
assembly includes a first fluid flow path and a second fluid flow path;
advancing the
drilling assembly into the earth; flowing a fluid through the first fluid flow
path and
returning at least a portion of the fluid through the second fluid flow path;
and leaving the
wellbore lining conduit at a location within the wellbore, wherein the
wellbore lining
conduit comprises at least one fluid flow restrictor on an outer surface
thereof. In one
aspect, the method further comprises flowing the fluid through an annular area
defined
by an inner surface of the wellbore and an outer surface of the wellbore
lining conduit.
[00307] With reference to Figures 20-23, yet another embodiment includes a
method
for lining a wellbore comprising providing a drilling assembly comprising an
earth
removal member and a wellbore lining conduit, wherein the drilling assembly
includes a
first fluid flow path and a second fluid flow path; advancing the drilling
assembly into the
earth; flowing a fluid through the first fluid flow path and returning at
least a portion of the
fluid through the second fluid flow path; leaving the wellbore lining conduit
at a location
within the wellbore; and conveying a cementing assembly into the wellbore. In
one
CA 02760504 2011-11-30
aspect, the method further comprises providing the wellbore lining conduit
with a one-
way valve disposed at lower portion thereof. In another aspect, the method
further
comprises supplying a physically alterable bonding material at a first
location in an
annular area defined by an outer surface of the wellbore lining conduit and an
inner
surface of the wellbore and a second location in the annular area. In yet
another aspect,
supplying the physically alterable bonding material to the first location
comprises
supplying the physically alterable material through the one way valve, and
supplying the
physically alterable bonding material to the second location comprises
supplying the
physically alterable material to the second location through a port disposed
above the
one way valve.
[00308] With reference to Figure 24, another embodiment includes a method for
lining
a wellbore comprising providing a drilling assembly comprising an earth
removal
member and a wellbore lining conduit, wherein the drilling assembly includes a
first fluid
flow path and a second fluid flow path; advancing the drilling assembly into
the earth;
flowing a fluid through the first fluid flow path and returning at least a
portion of the fluid
through the second fluid flow path; leaving the wellbore lining conduit at a
location within
the wellbore; conveying a cementing assembly into the wellbore; and providing
the
cementing assembly with a single direction plug 458. In one aspect, the method
further
comprises supplying a physically alterable bonding material to an annular area
defined
by an outer surface of the wellbore lining conduit and an inner surface of the
wellbore.
In another aspect, the method further comprises releasing the single direction
plug in the
wellbore conduit and positioning the single direction plug at a desire
location in the
wellbore lining conduit. In yet another aspect, the single direction plug is
positioned by
actuating a gripping member.
[003091 With reference to Figure 7, in one embodiment, the present invention
provides a method for lining a wellbore comprising providing a drilling
assembly
comprising an earth removal member and a wellbore lining conduit, wherein the
drilling
assembly includes a first fluid flow path and a second fluid flow path;
advancing the
drilling assembly into the earth; flowing a fluid through the first fluid flow
path and
returning at least a portion of the fluid through the second fluid flow path;
leaving the
wellbore lining conduit at a location within the wellbore; and flowing a
second portion of
the fluid through a third flow path 170. In one aspect, the third flow path
directs the
second portion of the fluid to an annular area between the wellbore lining
conduit and
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CA 02760504 2011-11-30
the wellbore. Another embodiment of the present invention provides a method
for lining
a wellbore comprising providing a drilling assembly comprising an earth
removal
member and a wellbore lining conduit, wherein the drilling assembly includes a
first fluid
flow path and a second fluid flow path; advancing the drilling assembly into
the earth;
flowing a fluid through the first fluid flow path and returning at least a
portion of the fluid
through the second fluid flow path; leaving the wellbore lining conduit at a
location within
the wellbore; and flowing a second portion of the fluid through a third flow
path, wherein
the third flow path comprises an annular area between the wellbore lining
conduit and
the wellbore.
(00310] With reference to Figure 7 and paragraph [00129], the present
invention
provides in another embodiment a method for lining a wellbore comprising
providing a
drilling assembly comprising an earth removal member and a wellbore lining
conduit,
wherein the drilling assembly includes a first fluid flow path and a second
fluid flow path;
advancing the drilling assembly into the earth; flowing a fluid through the
first fluid flow
path and returning at least a portion of the fluid through the second fluid
flow path; and
leaving the wellbore lining conduit at a location within the wellbore, wherein
the earth
removal member is capable of forming a hole having a larger outer diameter
than an
outer diameter of the wellbore lining conduit. An additional embodiment of the
present
invention provides a method for lining a wellbore comprising providing a
drilling
assembly comprising an earth removal member and a wellbore lining conduit,
wherein
the drilling assembly includes a first fluid flow path and a second fluid flow
path;
advancing the drilling assembly into the earth; flowing a fluid through the
first fluid flow
path and returning at least a portion of the fluid through the second fluid
flow path; and
leaving the wellbore lining conduit at a location within the wellbore, wherein
the drilling
assembly further comprises a geophysical sensor.
[00311] With reference to Figure 7 and paragraph [00129], another embodiment
provides a method for lining a wellbore comprising providing a drilling
assembly
comprising an earth removal member and a wellbore lining conduit, wherein the
drilling
assembly includes a first fluid flow path and a second fluid flow path;
advancing the
drilling assembly into the earth; flowing a fluid through the first fluid flow
path and
returning at least a portion of the fluid through the second fluid flow path;
and leaving the
wellbore lining conduit at a location within the wellbore, wherein the first
fluid flow path
comprise an annular area between the wellbore lining conduit and the wellbore.
In
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CA 02760504 2011-11-30
another embodiment, the present invention provides a method for lining a
weilbore
comprising providing a drilling assembly comprising an earth removal member
and a
wellbore lining conduit, wherein the drilling assembly includes a first fluid
flow path and a
second fluid flow path; advancing the drilling assembly into the earth;
flowing a fluid
through the first fluid flow path and returning at least a portion of the
fluid through the
second fluid flow path; leaving the wellbore lining conduit at a location
within the
wellbore; and selectively altering a trajectory of the drilling assembly.
[00312] With reference to Figure 24, in one embodiment, the present invention
provides a method for lining a weilbore comprising providing a drilling
assembly
comprising an earth removal member and a wellbore lining conduit, wherein the
drilling
assembly includes a first fluid flow path and a second fluid flow path;
advancing the
drilling assembly into the earth; flowing a fluid through the first fluid flow
path and
returning at least a portion of the fluid through the second fluid flow path;
leaving the
wellbore lining conduit at a location within the wellbore; and providing the
cementing
assembly with a cementing plug 458. With reference to Figure 14, the present
invention
provides in another embodiment a method for lining a wellbore comprising
providing a
drilling assembly comprising an earth removal member and a wellbore lining
conduit,
wherein the drilling assembly includes a first fluid flow path and a second
fluid flow path;
advancing the drilling assembly into the earth; flowing a fluid through the
first fluid flow
path and returning at least a portion of the fluid through the second fluid
flow path;
leaving the wellbore lining conduit at a location within the weilbore; and
providing a
sealing member 351 on an outer portion of the wellbore lining conduit.
[00313] With reference to Figure 11 and paragraph [00140], in one embodiment,
the
present invention provides a method for lining a wellbore comprising providing
a drilling
assembly comprising an earth removal member and a wellbore lining conduit,
wherein
the drilling assembly includes a first fluid flow path and a second fluid flow
path;
advancing the drilling assembly into the earth; flowing a fluid through the
first fluid flow
path and returning at least a portion of the fluid through the second fluid
flow path;
leaving the wellbore lining conduit at a location within the wellbore; and
providing a
balancing fluid followed by a physically alterable bonding material. With
reference to
Figures 60-64, another embodiment of the present invention provides a method
for lining
a wellbore comprising providing a drilling assembly comprising an earth
removal
member and a weilbore lining conduit, wherein the drilling assembly includes a
first fluid
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CA 02760504 2011-11-30
flow path and a second fluid flow path: advancing the drilling assembly into
the earth;
flowing a fluid through the first fluid flow path and returning at least a
portion of the fluid
through the second fluid flow path; leaving the wellbore lining conduit at a
location within
the welibore; and increasing an energy of the return fluid.
[00314] With reference to Figures 1-6, in one embodiment, the present
invention
provides an apparatus for lining a wellbore, comprising a drilling assembly
comprising an
earth removal member, a wellbore lining conduit, and a first end, the drilling
assembly
including a first fluid flow path and a second fluid flow path therethrough,
wherein fluid is
movable from the first end through the first fluid flow path and returnable
through the
second fluid flow path when the drilling assembly is disposed in the wellbore.
In one
aspect, the drilling assembly further comprises a third fluid flow path.
[00315] With reference to Figure 7, in another embodiment, the present
invention
provides an apparatus for lining a wellbore, comprising a drilling assembly
comprising an
earth removal member, a wellbore lining conduit, and a first end, the drilling
assembly
including a first fluid flow path and a second fluid flow path therethrough,
wherein fluid is
movable from the first end through the first fluid flow path and returnable
through the
second fluid flow path when the drilling assembly is disposed in the wellbore,
wherein
the drilling assembly further comprises a liner hanger assembly 130. Another
embodiment of the present invention includes an apparatus for lining a
wellbore,
comprising a drilling assembly comprising an earth removal member, a wellbore
lining
conduit, and a first end, the drilling assembly including a first fluid flow
path and a
second fluid flow path therethrough, wherein fluid is movable from the first
end through
the first fluid flow path and returnable through the second fluid flow path
when the drilling
assembly is disposed in the wellbore, wherein the drilling assembly further
comprises at
least one sealing member 148.
[00316] With reference to Figure 7, in one embodiment, the present invention
includes an apparatus for lining a wellbore, comprising a drilling assembly
comprising an
earth removal member, a wellbore lining conduit, and a first end, the drilling
assembly
including a first fluid flow path and a second fluid flow path therethrough,
wherein fluid is
movable from the first end through the first fluid flow path and returnable
through the
second fluid flow path when the drilling assembly is disposed in the wellbore,
wherein
the drilling assembly further comprises a drill string. In an additional
embodiment, the
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CA 02760504 2011-11-30
present invention provides an apparatus for fining a wellbore, comprising a
drilling
assembly comprising an earth removal member, a wellbore fining conduit, and a
first
end, the drilling assembly including a first fluid flow path and a second
fluid flow path
therethrough, wherein fluid is movable from the first end through the first
fluid flow path
and returnable through the second fluid flow path when the drilling assembly
is disposed
in the wellbore, wherein the drilling assembly further comprises at least one
flow splitting
member.
[00317] With reference to Figure 7 and paragraph (001291, an embodiment of the
present invention provides an apparatus for lining a wellbore, comprising a
drilling
assembly comprising an earth removal member, a wellbore lining conduit, and a
first
end, the drilling assembly including a first fluid flow path and a second
fluid flow path
therethrough, wherein fluid is movable from the first end through the first
fluid flow path
and returnable through the second fluid flow path when the drilling assembly
is disposed
in the wellbore, wherein the drilling assembly further comprises at least one
geophysical
measuring tool. Another embodiment includes an apparatus for lining a
wellbore,
comprising a drilling assembly comprising an earth removal member, a wellbore
lining
conduit, and a first end, the drilling assembly including a first fluid flow
path and a
second fluid flow path therethrough, wherein fluid is movable from the first
end through
the first fluid flow path and returnable through the second fluid flow path
when the drilling
assembly is disposed in the wellbore, further comprising at least one
component
selected from the group consisting of a mud motor; logging while drilling
system;
measure while drilling system; gyro landing sub; a geophysical measurement
sensor; a
stabilizer; an adjustable stabilizer; a steerable system; a bent motor
housing; a 3D rotary
steerable system; a pilot bit; an underreamer; a bi-center bit; an expandable
bit; at least
one nozzle for directional drilling; and combination thereof.
[00318] With reference to Figure 7, an embodiment of the present invention
provides
a method of drilling with liner, comprising forming a wellbore with an
assembly including
an earth removal member mounted on a work string and a section of liner
disposed
therearound, the earth removal member extending below a lower end of the
liner;
lowering the liner to a location in the wellbore adjacent the earth removal
member;
circulating a fluid through the earth removal member; fixing the liner section
in the
wellbore; and removing the work string and the earth removal member from the
wellbore. In one aspect, circulating the fluid includes flowing the fluid
through an annular
CA 02760504 2011-11-30
area defined between an outer surface of the work string and an inner surface
of the
liner section,
[00319] With reference to Figure 7, an additional embodiment of the present
invention
provides a method of drilling with liner, comprising forming a wellbore with
an assembly
including an earth removal member mounted on a work string and a section of
liner
disposed therearound, the earth removal member extending below a lower end of
the
liner; lowering the liner to a location in the wellbore adjacent the earth
removal member;
circulating a fluid through the earth removal member; fixing the liner section
in the
wellbore; and removing the work string and the earth removal member from the
wellbore, wherein the liner section is fixed at an upper end to a casing
section. Another
embodiment includes a method of drilling with liner, comprising forming a
wellbore with
an assembly including an earth removal member mounted on a work string and a
section of liner disposed therearound, the earth removal member extending
below a
lower end of the liner; lowering the liner to a location in the wellbore
adjacent the earth
removal member; circulating a fluid through the earth removal member; fixing
the liner
section in the wellbore; and removing the work string and the earth removal
member
from the wellbore, wherein the earth removal member and the work string are
operatively connected to the liner section during drilling and disconnected
therefrom
prior to removal of the work string and the earth removal member,
[00320] With reference to Figure 7, another embodiment of the present
invention
provides a method of drilling with liner, comprising forming a wellbore with
an assembly
including an earth removal member mounted on a work string and a section of
liner
disposed therearound, the earth removal member extending below a lower end of
the
liner; lowering the liner to a location in the wellbore adjacent the earth
removal member;
circulating a fluid through the earth removal member; fixing the liner section
in the
wellbore; removing the work string and the earth removal member from the
wellbore;
and cementing the liner section in the wellbore, Another embodiment of the
present
invention provides a method of drilling with liner, comprising forming a
wellbore with an
assembly including an earth removal member mounted on a work string and a
section of
liner disposed therearound, the earth removal member extending below a lower
end of
the liner; lowering the liner to a location in the wellbore adjacent the earth
removal
member; circulating a fluid through the earth removal member; fixing the liner
section in
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CA 02760504 2011-11-30
the wellbore; removing the work string and the earth removal member from the
weilbore;
and flowing fluid through the section of liner and the wellbore,
[00321] With reference to Figures 30-35, an embodiment of the present
invention
includes a method of casing a wellbore, comprising providing a drilling
assembly
including a tubular string having an earth removal member operatively
connected to its
lower end, and a casing, at least a portion of the tubular string extending
below the
casing; lowering the drilling assembly into a formation; lowering the casing
over the
portion of the drilling assembly; and circulating fluid through the casing. In
one aspect,
circulating fluid through the casing comprises flowing at least two fluid
paths through the
casing. In another aspect, the at least two fluid paths are in opposite
directions.
Another embodiment of the present invention includes a method of casing a
wellbore,
comprising providing a drilling assembly including a tubular string having an
earth
removal member operatively connected to its lower end, and a casing, at least
a portion
of the tubular string extending below the casing; lowering the drilling
assembly into a
formation; lowering the casing over the portion of the drilling assembly; and
circulating
fluid through the casing, wherein circulating fluid through the casing
comprises flowing at
least two fluid paths through the casing and at least one of the at least two
fluid paths
flows to a surface of the wellbore.
[00322] With reference to Figure 36, in another embodiment, the present
invention
provides a method of drilling with liner, comprising forming a section of
wellbore with an
earth removal member operatively connected to a section of liner; lowering the
section of
liner to a location proximate a lower end of the wellbore; and circulating
fluid while
lowering, thereby urging debris from the bottom of the wellbore upward
utilizing a flow
path formed within the liner section. In yet another embodiment, the present
invention
provides a method of drilling with liner, comprising forming a section of
wellbore with an
assembly comprising an earth removal tool on a work string fixed at a
predetermined
distance below a lower end of a section of liner; fixing an upper end of the
liner section
to a section of casing lining the wellbore; releasing a latch between the work
string and
the liner section; reducing the predetermined distance between the lower end
of the liner
section and the earth removal tool; releasing the assembly from the section of
casing;
re-fixing the assembly to the section of casing at a second location; and
circulating fluid
in the wellbore.
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[00323] With reference to Figure 36, another embodiment includes a method of
casing a weilbore, comprising providing a drilling assembly comprising a
casing, and a
tubular string releasably connected to the casing, the tubular string having
an earth
removal member operatively attached to its lower end, a portion of the tubular
string
located below a lower end of the casing; lowering the drilling assembly into a
formation
to form a wellbore; hanging the casing within the wellbore; moving the portion
of the
tubular string into the casing; and lowering the casing into the wellbore. In
one aspect,
the method further comprises circulating fluid while lowering the casing into
the wellbore.
Another embodiment includes a method of casing a wellbore, comprising
providing a
drilling assembly comprising a casing, and a tubular string releasably
connected to the
casing, the tubular string having an earth removal member operatively attached
to its
lower end, a portion of the tubular string located below a lower end of the
casing;
lowering the drilling assembly into a formation to form a wellbore; hanging
the casing
within the wellbore; moving the portion of the tubular string into the casing;
lowering the
casing into the wellbore; and releasing the releasable connection prior to
moving the
portion of the tubular string into the casing.
[00324] With reference to Figure 45, in one embodiment, the present invention
provides a method of cementing a liner section in a wellbore, comprising
removing a
drilling assembly from a lower end of the liner section, the drilling assembly
including an
earth removal too[ and a work string; inserting a tubular path for flowing a
physically
alterable bonding material, the tubular path extending to the lower end of the
liner
section and including a valve assembly permitting the cement to flow from the
lower
section in a single direction; flowing the physically alterable bonding
material through the
tubular path and upwards in an annulus between the liner section and the
wellbore
therearound; closing the valve; and removing the tubular path, thereby leaving
the valve
assembly in the wellbore. In one aspect, the valve assembly includes one or
more
sealing members to seal an annulus between the valve assembly and an inside
surface
of the liner section.
[00325] With reference to Figure 45, in another embodiment, the present
invention
provides a method of cementing a liner section in a wellbore, comprising
removing a
drilling assembly from a lower end of the liner section, the drilling assembly
including an
earth removal tool and a work string; inserting a tubular path for flowing a
physically
alterable bonding material, the tubular path extending to the lower end of the
liner
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CA 02760504 2011-11-30
section and including a valve assembly permitting the cement to flow from the
lower
section in a single direction; flowing the physically alterable bonding
material through the
tubular path and upwards in an annulus between the liner section and the
welibore
therearound; closing the valve; and removing the tubular path, thereby leaving
the valve
assembly in the weilbore, wherein the valve assembly is drillable to form a
subsequent
section of wellbore.
(00326] With reference to Figure 50, in an embodiment, the present invention
provides a method of drilling with liner, comprising providing a drilling
assembly
comprising a liner having a tubular member therein, the tubular member
operatively
connected to an earth removal member and having a fluid path through a wall
thereof,
the fluid path disposed above a lower portion of the tubular member; lowering
the drilling
assembly into the earth, thereby forming a welibore; sealing an annulus
between an
outer diameter of the tubular member and the wellbore; sealing a longitudinal
bore of the
tubular member; and flowing a physically alterable bonding material through
the fluid
path, thereby preventing the physically alterable bonding material from
entering the
lower portion of the tubular member. In one aspect, the method further
comprises
activating at least one sealing member to seal an annulus above the fluid
path, the
annulus being between the wellbore and an outer diameter of the liner.
(00327] With reference to Figures 1-6, an embodiment of the present invention
provides a method for placing tubulars in an earth formation comprising
advancing
concurrently a portion of a first tubular and a portion of a second tubular to
a first location
in the earth; and further advancing the second tubular to a second location in
the earth.
In one aspect, the method further comprises cementing a portion of one of the
first and
second tubulars. Another embodiment includes a method for placing tubulars in
an
earth formation comprising advancing concurrently a portion of a first tubular
and a
portion of a second tubular to a first location in the earth; further
advancing the second
tubular to a second location in the earth; and cementing each of the first and
second
tubulars
[00328] With reference to Figures 1 and 7, another embodiment of the present
invention includes a method for placing tubulars in an earth formation
comprising
advancing concurrently a portion of a first tubular and a portion of a second
tubular to a
first location in the earth; further advancing the second tubular to a second
location in
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the earth; and advancing a portion of a third tubular to a third location.
Another
embodiment includes a method for placing tubulars in an earth formation
comprising
advancing concurrently a portion of a first tubular and a portion of a second
tubular to a
first location in the earth; further advancing the second tubular to a second
location in
the earth: and expanding a portion of one of the first and second tubulars,
[00329] With reference to Figures 1-6, another embodiment provides a method
for
placing tubulars in an earth formation comprising advancing concurrently a
portion of a
first tubular and a portion of a second tubular to a first location in the
earth; and further
advancing the second tubular to a second location in the earth, wherein the
advancing
includes drilling. Another embodiment provides a method for placing tubulars
in an earth
formation comprising advancing concurrently a portion of a first tubular and a
portion of a
second tubular to a first location in the earth; and further advancing the
second tubular to
a second location in the earth, wherein the further advancing includes
drilling. Yet
another embodiment provides a method for placing tubulars in an earth
formation
comprising advancing concurrently a portion of a first tubular and a portion
of a second
tubular to a first location in the earth; and further advancing the second
tubular to a
second location in the earth, wherein a trajectory of the tubulars is
selectively altered
during the advancing to the first location
[003301 With reference to Figures 1, 7, or 30, an embodiment of the present
invention
includes a method for placing tubulars in an earth formation comprising
advancing
concurrently a portion of a first tubular and a portion of a second tubular to
a first location
in the earth; and further advancing the second tubular to a second location in
the earth,
wherein a trajectory of the second tubular is selectively altered during the
further
advancing to the second location. An additional embodiment includes a method
for
placing tubulars in an earth formation comprising advancing concurrently a
portion of a
first tubular and a portion of a second tubular to a first location in the
earth; further
advancing the second tubular to a second location in the earth, and sensing a
geophysical parameter. With reference to Figure 46, yet another embodiment
includes a
method for placing tubulars in an earth formation comprising advancing
concurrently a
portion of a first tubular and a portion of a second tubular to a first
location in the earth;
further advancing the second tubular to a second location in the earth; and
pressure
testing one of the first and second tubulars.
CA 02760504 2011-11-30
[00331] With reference to Figure 7, another embodiment of the present
invention
provides a method for placing tubulars in an earth formation comprising
advancing
concurrently a portion of a first tubular and a portion of a second tubular to
a first location
in the earth; and further advancing the second tubular to a second location in
the earth,
wherein the second tubular is operatively connected to a drilling assembly.
Another
embodiment provides a method for placing tubulars in an earth formation
comprising
advancing concurrently a portion of a first tubular and a portion of a second
tubular to a
first location in the earth; and further advancing the second tubular to a
second location
in the earth, wherein the drilling assembly is selectively detachable from the
second
tubular. In one aspect, at least a portion of the drilling assembly is
retrievable.
[00332] With reference to Figures 1 and 7, another embodiment provides a
method
for placing tubulars in an earth formation comprising advancing concurrently a
portion of
a first tubular and a portion of a second tubular to a first location in the
earth; further
advancing the second tubular to a second location in the earth; inserting a
drilling
assembly in the second tubular; and advancing the drilling assembly through a
lower
end of the second tubular. In one aspect, the drilling assembly includes an
earth
removal member and a third tubular. In another aspect, the drilling assembly
further
includes a first fluid flow path and a second fluid flow path. In yet another
aspect, the
method further comprises flowing fluid through the first fluid flow path and
returning at
least a portion of the fluid through the second fluid flow path. In yet
another aspect, the
method further comprises leaving the third tubular in a third location in the
earth. In
another aspect, the method further comprises cementing the third tubular with
the drilling
assembly.
[00333] With reference to Figures 71-72, an embodiment of the present
invention
provides an apparatus for forming a wellbore, comprising a casing string with
a drill bit
disposed at an end thereof; and a fluid bypass operatively connected to the
casing string
for diverting a portion of fluid from a first location to a second location
within the wellbore
as the wellbore is formed. In one aspect, the fluid bypass is formed at least
partially
within the casing string.
[00334] With reference to Figures 71-72, an additional embodiment of the
present
invention includes a method of cementing a borehole, comprising extending a
drill string
into the earth to form the borehole, the drill string including an earth
removal member
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having at least one fluid passage therethrough, the earth removal member
operatively
connected to a lower end of the drill string; drilling the borehole to a
desired location
using a drilling mud passing through the at least one fluid passage; providing
at least
one secondary fluid passage between the interior of the drill string and the
borehole; and
directing a physically alterable bonding material into an annulus between the
drill string
and the borehole through the at least one secondary fluid passage. In one
aspect, the
method further comprises flowing a physically alterable bonding material
through the
drill string and into an annulus between the drill string and the borehole
prior to directing
the physically alterable bonding material into the annulus between the drill
string and the
borehole through the at least one secondary fluid passage. In another aspect,
opening
the at least one secondary fluid passage, comprises providing a barrier across
the at
least one secondary fluid passage; and rupturing the barrier. In yet another
aspect,
rupturing the barrier comprises increasing fluid pressure on one side of the
barrier to a
level sufficient to rupture the barrier.
[00335] With reference to Figures 71-72, another embodiment of the present
invention includes a method of cementing a borehole, comprising extending a
drill string
into the earth to form the borehole, the drill string including an earth
removal member
having at least one fluid passage therethrough, the earth removal member
operatively
connected to a lower end of the drill string; drilling the borehole to a
desired location
using a drilling mud passing through the at least one fluid passage; providing
at least
one secondary fluid passage between the interior of the drill string and the
borehole;
directing a physically alterable bonding material into an annulus between the
drill string
and the borehole through the at least one secondary fluid passage; flowing a
physically
alterable bonding material through the drill string and into an annulus
between the drill
string and the borehole prior to directing the physically alterable bonding
material into
the annulus between the drill string and the borehole through the at least one
secondary
fluid passage; and opening the at least one secondary passage when the
physically
alterable bonding material reaches the location of the at least one secondary
passage
after flowing the physically alterable bonding material through the drill
string and into the
annulus. In another embodiment, the present invention provides a method of
cementing
a borehole, comprising extending a drill string into the earth to form the
borehole, the drill
string including an earth removal member having at least one fluid passage
therethrough, the earth removal member operatively connected to a lower end of
the drill
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CA 02760504 2011-11-30
string; drilling the borehole to a desired location using a drilling mud
passing through the
at least one fluid passage; providing at least one secondary fluid passage
between the
interior of the drill string and the borehole; and directing a physically
alterable bonding
material into an annulus between the drill string and the borehole through the
at least
one secondary fluid passage, wherein the physically alterable bonding material
comprises cement.
[00336] With reference to Figures 71-72, another embodiment provides a method
of
cementing a borehole, comprising extending a drill string into the earth to
form the
borehole, the drill string including an earth removal member having at least
one fluid
passage therethrough, the earth removal member operatively connected to a
lower end
of the drill string; drilling the borehole to a desired location using a
drilling mud passing
through the at least one fluid passage; providing at least one secondary fluid
passage
between the interior of the drill string and the borehole: and directing a
physically
alterable bonding material into an annulus between the drill string and the
borehole
through the at least one secondary fluid passage, wherein the earth removal
member is
a drill bit.
[00337] With reference to Figures 71-72, another embodiment of the present
invention provides a method of cementing a borehole, comprising extending a
drill string
into the earth to form the borehole, the drill string including an earth
removal member
having at least one fluid passage therethrough, the earth removal member
operatively
connected to a lower end of the drill string; drilling the borehole to a
desired location
using a drilling mud passing through the at least one fluid passage; providing
at least
one secondary fluid passage between the interior of the drill string and the
borehole: and
directing a physically alterable bonding material into an annulus between the
drill string
and the borehole through the at least one secondary fluid passage, wherein
directing the
physically alterable bonding material through the secondary fluid passage
includes
blocking the at least one fluid passage through the earth removal member. In
one
aspect, blocking the at least one fluid passage through the earth removal
member
comprises providing a ball seat positioned in intersection with the at least
one fluid
passage; and selectively positioning a ball on the ball seat and in a blocking
position
over the at least one fluid passage. In another aspect, the method further
comprises
providing the ball to the ball seat from a location remote therefrom.
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[00338] With reference to Figures 68-70, another embodiment of the present
invention provides a method of cementing a borehole, comprising extending a
drill string
into the earth to form the borehole, the drill string including an earth
removal member
having at least one fluid passage therethrough, the earth removal member
operatively
connected to a lower end of the drill string; drilling the borehole to a
desired location
using a drilling mud passing through the at least one fluid passage; providing
at least
one secondary fluid passage between the interior of the drill string and the
borehole;
directing a physically alterable bonding material into an annulus between the
drill string
and the borehole through the at least one secondary fluid passage, wherein
directing the
physically alterable bonding material into the annulus through the at least
one secondary
fluid passage comprises providing a moveable barrier intermediate the at least
one
secondary passage and the annulus; and moving the moveable barrier to allow
the
physically alterable bonding material to flow through the at least one
secondary
passage. In one aspect, the moveable barrier comprises a sleeve positionable
over an
element of the drill string and slidably positionable with respect thereto;
and at least one
pin interconnecting the sleeve and the element of the drill string. In another
aspect, the
method further comprises providing a piston integral with the sleeve; and
using
hydrostatic pressure to urge the piston to open the at least one secondary
passage to
communicate with the annulus,
[00339] With reference to Figures 68-70, an additional embodiment of the
present
invention includes a method of cementing a borehole, comprising extending a
drill string
into the earth to form the borehole, the drill string including an earth
removal member
having at least one fluid passage therethrough, the earth removal member
operatively
connected to a lower end of the drill string; drilling the borehole to a
desired location
using a drilling mud passing through the at least one fluid passage; providing
at least
one secondary fluid passage between the interior of the drill string and the
borehole;
directing a physically alterable bonding material into an annulus between the
drill string
and the borehole through the at least one secondary fluid passage; providing a
float
shoe intermediate the location where the physically alterable bonding material
is
introduced into the interior of the drill string and the at least one
secondary passage; and
positioning a float collar in the float shoe, thereby preventing flow of the
physically
alterable bonding material from the location between the drill string and
borehole to the
interior of the drill string. In one aspect, positioning the float collar is
undertaken during
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CA 02760504 2011-11-30
the flowing of the physically alterable bonding material into the annulus. In
another
aspect, positioning the float collar is undertaken after the flowing of the
physically
alterable bonding material into the annulus is completed.
[00340] With reference to Figures 71-72, another embodiment of the present
invention includes a method of cementing a borehole, comprising extending a
drill string
into the earth to form the borehole, the drill string including an earth
removal member
having at least one fluid passage therethrough, the earth removal member
operatively
connected to a lower end of the drill string; drilling the borehole to a
desired location
using a drilling mud passing through the at least one fluid passage; providing
at least
one secondary fluid passage between the interior of the drill string and the
borehole;
directing a physically alterable bonding material into an annulus between the
drill string
and the borehole through the at least one secondary fluid passage; providing
at least
one additional secondary passage intermediate the lower terminus of the
borehole and a
surface location; cementing the borehole at a location adjacent to the
terminus of the
borehole; further directing the physically alterable bonding material down the
drill string;
and directing the physically alterable bonding material through the additional
secondary
passage.
[00341] With reference to Figures 71-72, in another embodiment, the present
invention provides an apparatus for selectively directing fluids flowing down
a hollow
portion of a tubular element to selective passageways leading to a location
exterior to
the tubular element, comprising a first fluid passageway from the hollow
portion of the
tubular member to a first location; a second passageway from the hollow
portion of the
tubular member to a second location; a first valve member configurable to
selectively
block the first fluid passageway; and a second valve member configured to
maintain the
second fluid passageway in a normally blocked condition, the first valve
member
including a valve closure element selectively positionable to close the first
valve member
and thereby effectuate opening of the second valve member. In one aspect, the
first
valve member comprises a seat through which the first fluid passageway extends
and
the valve closure element blocks the first fluid passageway when positioned on
the seat.
In another aspect, the second valve member comprises a membrane positioned to
selectively block the second passageway, the membrane configured to rupture as
a
result of closure of the first valve member.
CA 02760504 2011-11-30
[00342] With reference to Figures 68-70, an additional embodiment includes an
apparatus for selectively directing fluids flowing down a hollow portion of a
tubular
element to selective passageways leading to a location exterior to the tubular
element,
comprising a first fluid passageway from the hollow portion of the tubular
member to a
first location; a second passageway from the hollow portion of the tubular
member to a
second location; a first valve member configurable to selectively block the
first fluid
passageway; and a second valve member configured to maintain the second fluid
passageway in a normally blocked condition, the first valve member including a
valve
closure element selectively positionable to close the first valve member and
thereby
effectuate opening of the second valve member, wherein the second valve member
comprises a sleeve sealingly engaged about the second fluid passageway; and at
least
one separation member interconnecting the sleeve and at least a portion of the
tubular
element. In one aspect, the at least one separation member comprises at least
one
shear pin.
[00343] With reference to Figures 68-70, an embodiment of the present
invention
provides an apparatus for selectively directing fluids flowing down a hollow
portion of a
tubular element to selective passageways leading to a location exterior to the
tubular
element, comprising a first fluid passageway from the hollow portion of the
tubular
member to a first location; a second passageway from the hollow portion of the
tubular
member to a second location; a first valve member configurable to selectively
block the
first fluid passageway; and a second valve member configured to maintain the
second
fluid passageway in a normally blocked condition, the first valve member
including a
valve closure element selectively positionable to close the first valve member
and
thereby effectuate opening of the second valve member, wherein the second
valve
member comprises a sleeve sealingly engaged about the second fluid passageway;
and
at least one separation member interconnecting the sleeve and at least a
portion of the
tubular element, wherein the at least a portion of the tubular element is a
float sub. In
one aspect, the float sub includes a generally cylindrical outer surface; the
second
passage extends through the float sub and emerges therefrom at the generally
cylindrical outer surface; and the at least one separation member is
positioned over the
generally cylindrical outer surface. In another aspect, the at least one
separation
member has a generally tubular profile.
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CA 02760504 2011-11-30
[00344] With reference to Figures 68-70, another embodiment of the present
invention provides an apparatus for selectively directing fluids flowing down
a hollow
portion of a tubular element to selective passageways leading to a location
exterior to
the tubular element, comprising a first fluid passageway from the hollow
portion of the
tubular member to a first location; a second passageway from the hollow
portion of the
tubular member to a second location; a first valve member configurable to
selectively
block the first fluid passageway; and a second valve member configured to
maintain the
second fluid passageway in a normally blocked condition, the first valve
member
including a valve closure element selectively positionable to close the first
valve member
and thereby effectuate opening of the second valve member, wherein the second
valve
member comprises a sleeve sealingly engaged about the second fluid passageway;
and
at least one separation member interconnecting the sleeve and at least a
portion of the
tubular element, wherein the at least a portion of the tubular element is a
float sub,
wherein the float sub includes a generally cylindrical outer surface; the
second passage
extends through the float sub and emerges therefrom at the generally
cylindrical outer
surface; and the at least one separation member is positioned over the
generally
cylindrical outer surface, the apparatus further comprising a first seal
extendable
between the at least one separation member and the float sub; a second seal
extendable between the at least one separation member and the float sub; and
the
second passage is positioned in the float sub between the first and second
seals. In one
aspect, the at least one separation member further comprises a first
cylindrical section
having a seal groove therein in which the first seal is received; and a second
cylindrical
section having a seal groove therein in which the second seal is received,
wherein the
second cylindrical section forms an annular piston extending about the float
sub.
[00345] With reference to Figures 60-64, in another aspect, the present
invention
provides a method of drilling a wellbore with casing, comprising placing a
string of casing
operatively coupled to a drill bit at the lower end thereof into a previously
formed
wellbore; urging the string of casing axially downward to form a new section
of wellbore;
pumping fluid through the string of casing into an annulus formed between the
string of
casing and the new section of wellbore; and diverting a portion of the fluid
into an upper
annulus in the previously formed wellbore. In one embodiment, the fluid is
diverted into
the upper annulus from a flow path in a run-in string of tubulars disposed
above the
string of casing. Additionally, the flow path is selectively opened and closed
to control
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CA 02760504 2011-11-30
the amount of fluid flowing through the flow path. In another embodiment, the
fluid is
diverted into the upper annulus via an independent fluid path. The independent
fluid
path is formed at least partially within the string of casing. In yet another
embodiment,
the fluid is diverted into the upper annulus via a flow apparatus disposed in
the string of
casing.
[00346] With reference to Figures 13-19, in another aspect, the present
invention
provides a method for lining a wellbore, comprising forming a wellbore with an
assembly
including an earth removal member mounted on a work string, a liner disposed
around at
least a portion of the work string, a first sealing member disposed on the
work string, and
a second sealing member disposed on an outer portion of the liner; lowering
the liner to
a location in the wellbore adjacent the earth removal member while circulating
a fluid
through the earth removal member; actuating the first sealing member; fixing
the liner
section in the wellbore; actuating the second sealing member, and removing the
work
string and the earth removal member from the wellbore. In one embodiment, the
first
sealing member is disposed below the liner while circulating the fluid. In
another
embodiment, fixing the liner section in the wellbore comprises supplying a
physically
alterable bonding material to an annular area between the liner and the
wellbore. The
physically alterable bonding material is supplied through the work string at a
location
above the first sealing member.
[00347] While the foregoing is directed to embodiments of the present
invention, other
and further embodiments of the invention may be devised without departing from
the
basic scope thereof, and the scope thereof is determined by the claims that
follow.
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