Note: Descriptions are shown in the official language in which they were submitted.
CA 02874763 2014-12-15
METHODS AND APPARATUS FOR WELLBORE CONSTRUCTION AND
COMPLETION
CA 02874763 2014-12-15
BACKGROUND OF THE INVENTION
Field of the Invention
[00041 .1 ha
present invention relates apparatus and methods for drilling and
completing t wetlbore. Particularly. the present invention roiates to
apparatus and
methods ler ferming a weiioore. lining a vrnitbere, and cirdulatinj iluccis in
the wellonre.
The present invention also retates to apparatus and methods ior
f.:".;tnentinE.; a wellhoro.
Description of the Related Art
100051 In the
drilling of oil and gas wells, a wellbore is formed using a drill bit that is
urged downwardly at a Ioi.ver end of a drill string. Alter drilling a
predetermined depth.
IV the drill strieg and bit are removed. and the weilbore is lined with
a string of casing. An
annular area is thus tiefined between the outside of the casing and the eatth
formation.
This annuictr area is filled 1.vith cement to permanently set the casing in
the welibore and
!aciEt:ite the isolation of production zor.es and fluies
dillerent depths within the
`NO !bore.
; 100061 It is
common to employ more than ono string ot casing n a wellborn. 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
20 casing resulting in a smaller diameter than the one above .1 The
reductic.in tri the
diameter recuces the cross-sectional area ir. wh:ch circulatini."3 ftuid may
travel. Nso,
lhe smaller casing at the bottom at the hole may limit the hynreearbon
production rate.
Thus. oil companies aro trying to maximize the diameter cl casing at the
desired depth
in order to maximize hydrocarbon production. To this f.-:nd, the clearance
between
'25 subsequent casing strings having been trending smaller because larger
subsequent
casings are used to ma.ximize production. When drilling with these small-
clearance
casings it is difficult, if not impossible, to circulate drilled cuttings in
the small annulus
formed hetv:een the set casing inner diameter and the subsequent casing outer
diameter.
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10007j fluid is circulated throught..)et tho inu
(hiding
operation to ixfol a rotating bit and removo wellbore euttings, rho tloid is
gorieraily
pumped front the surface of the wellbore through the dull stririg :o the
rotating bit.
Thereafter. the fluid is circulated through an annulus formed between the
drill string and
ti -- the string of casing and subsequently returr,ed to the surface to be
disposed of or
reused. As the fluid travels up the wellbore. the cross-sectionai area of the
fluid path
increases as each larger diameter string oi casing is encountered. For
example. ihe
fluid initially travels up an annulus formed between the drill string and the
newly formed
wellbore at high annular velocity due to stralier annular clearance.. However.
as the
1(1 fluid
travi: he portion of the weilbore that was previ=:lusly lined casing, ine
enlarged eross-sectional area deline.c.i by the larger diameter casing results
,n a larger
annular eiearance between the drill string and the easen wellbore. thereby
reducing tile
ìnriular velocity ei the fluid. This reduction in annular veiocity decreases
the overall
carrying capacity of the fluid, resulting in the drill cuttings dropping out
01 the fluid flow
15 -- and settling somewhere in the wellbore. This settling of the drill
cuttings and debris can
cause a number of difficulties to subsequent downhole operations. For example,
it is
we:I known that the setting of tools, such as liner hangers, against a casing
wall is
hampered by lne presence of debris on the
100081 To prevent the settling of the drill cuttings and debris. the flow
rate of the
20 circuit-sting fluid may be increased to increase the annular vetocity in
the laruer annular
areas. However, the higher annular velocity also increases the equivaleet
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
25 EGO. The pressure created by ECD is sometimes usefui while drilling
because it can
exceeci the pore pressure of formations intersected by the wellborc and
prevents
hydrocarnors from entering the wellbore. However. too high an ECD cari be a
problem
when it exceeds the tracture pressure of lhe formation, thereby forcing the
µ.velibore
fluid into the formations and hampering the Vow of hydrocarbons into the
wellbore after
z=-:',0 !tie well is completed.
(00091 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.
rattler than run
a (kill bit on smaller diameter drill string, :he bit is run at the end of
larger diameter
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tubing or easing eke will remain :n the %Nellbore and be eementect therein.
The
advantages of drilling with casing are obvious. Because the same string of
tubulars
transporis the bit and lines the borehole, no separate trip out of or into the
wellbore is
necessaiy l'etereon the forming oi the borehole and the lining of the
borehole. Dril:ing
b with casing is Qspecially useful :=1 certain situations whe!,1 an
operator wants to drill and
line a lior..A.olo as quickly as 1essib6 to minimize
borehole 10f0C181k;
unfine.d 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
foor is much more subject to cave in or collapse as the subsequent sections of
borehole. Sections of a borehole that intersect areas ot high pressure can
lead to
oamage of the botehole between the time the borehole is formed and when it is
tined.
An irezt of exceptionally tow pressure Will drain expensive ciriiliric tiuid
from the
w,Albori.3 betifieen the time it is intersected and ,;=Then the bweholo is
feted. In cetcii c,i
the pitibleins cafa elinlinated ur ti e:i etto:;:s induded
(::tsing.
foam The
challenges and problems associated with milling with casing are as
obvious as the advantages. For example, each string of casing must fit within
any
preexisting easing 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 arid underreamer, and bits intearally formed at the end of casing string
have been
used te evereome the problems. For exampie, a two-piece bit as an mite;
portiori with
a diamoter exceeding the diameter of the cas!ng str:ng. Whet the borehele 5
totrren,
the Wei portion is disconnected from an inner porton that can be retrieved to
the
sur%de of the well. Typically, a mud motor is used near the end of the liner
string to
rotate !he bit as the connection between the pieces of casing are not designed
to
withstand the tortuous forces associatea with rotary driliing. Mud
motors are
sometimes operated to turn the bit (and underrearner) at adequate rotation
rates lo
make hole:, without having to turn thc casing string at high rate, thereby
minimizirig
it.3 casing connection fatigue accurnuiation. In this manner. it-i. casing
stting can ba
rotated :It a moderate speed at the suilace as it is i'iserer and :he bit
rolatias at 0
MUCil taster speed 4.-Jue to the ildid-powered mud motor.
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Nem Another et:allunge for a drilling e,!i-t ce:eng onteaiio(1 :s
controlling F.CD.
()ailing with casing requires cireulating fluid through the arnall annular
clearance
between the casing and the newly formed wellbore. The small Einnular cleainnee
causes the circulating fluid to travei 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
ernall-clearance linei drilling, a smaller annulus is also formed between the
set casing
inner diameler and the drilling liner outer diameter, which further increases
ECD and
may prevert large drillod cuttings from being circulated from TrIi.; well.
1 10012j A need, theretore, exists for apparatus and methods for
circulating fluid
dueng a drilling operation. There !s also a need for apparatus and methods for
louring
a µweillbore and linin!.7 the wellbore in a single trip. There is a furtnor
need for aii
apparatus ard methods for circulating fluid to facilitate the torming and
lining of a
welibore in a singie trip. They is yet a further need to cement the tined
wellbore.
if, SUMMARY OF THE INVENTION
toolsj Tee present invention relates to time saving inethods iiind
apparatus !CY.
l;onstructing and completing offshore hydrocarbon v.sits. in one embodiment.
an
offshore wellbore is formed when an initial string of conductor is inserted
into tne earth
at the mud line. The conductor includes a smaller string of casing nested
coaxially
20 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
25 of wellbore is created by rotating the drilling device as the casing is
urged downwards
iitto the earth. Typically, thà casing stritig is lowcrecl to depth whereby an
annular
area remains defined between the casing string and the condector. Thereafter,
the
casing stnn;: is cemented into the conductor.
[00141 Alter the cement job is complete, a second string of smaller
easing is run into
:30 the well with a drill string and art expandable bit disposed :herein.
Once the smaller
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ctinj!:i 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.
100151 In one
aspoct, the present invention provides a method for lining a wellborn.
The mothon includes providing a drilling assembly oomprising an earth remevai
member and n ..ivellbere lining conduit, whorein the dr;;:irig jaduries a
first tiii
flow path zwiti a second fluid flow path. The drill:nc.j assombly is
manipuialed 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
anti leavint; the '..vellbore 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.
Atter dniling has iAtC=I'? completed. :he rIcAhoci may furt!.:e: i. ciLido
oemernin
(00 I6J In
another embodiment, the drilling assembly further comprises a tubular
-- assembly, a portion of the tubular assembly being disposed within the
i.vellbore tirung
conduit. The method may further include relatively moving a portion of the
tubular
assembly and the wellbore lining conduit. In a further embodiment. the tnethod
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.
[owl In another aspect, the present invertion provides an apparatus tor
lining a
welbore. The apparatus includes a Uniting assembly having an earth removal
member,
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 retumabie through the
second fluid flow
path :viten the drilling assembly is disposed in the wellbore. In another
embodiment.
the drillino assembly further comprises a third fluid flow path.
[0018J In ;11nolhor at:pect. ihe present :nvention provides method
for placing
tubuiars irr an earth formation. The method includes advanclng
....:oncurrently a portion
;in of a first tubular and a ponion of a second tubular to a first location
in the earti.,.
Thereafter. the second tubular is advanced to a seconci location in the earth.
in one
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i:1111)0(.1111101), till) IIItiAllOti may inciude fAdvancing a portion of a
third tubular to a third
'ocation. Additionally, al least a portion of one of the first and seconci
tuntilars may be
Gk.:merited into place.
100191 In another aspect. a method of drilling a wellbore 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 wellboro ar,d urging the string of casing axially
downward tu
form a new section ot wellbore. The method further includes pumping fluid
through the
string of easing into an annulus formed between the string of casing and the
new
section of wellbero. The method also includes diverting a portion of the fluid
into an
to upper annulus in the previously formed weilbore.
100201 In nnothcir aspect. an apparatus for forming a wellbore is
provided. -I tie
aP9i.irOtUS comprises a casing string with a dui! 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 filo
wellbore is formed.
(00211 In another aspect. the present invention provides a method et
drilling with
liner. comprising forming a iNellbore 'Nth an assembly iroiuding an earth
removal
member roounted on a work strirg and a section of liner disposed tneroaround,
lite
earth removal rnember extending below a lower end of the liner; lowering the
liner to a
location ill the wellbore adjacent the earth removal member; circulating a
fluid through
Ai the earth removal member; fixing the liner section in the wellbore; and
removing the
work string and the earth removal member from the wellbore.
100221 In another aspect, the present inventbn provides a method of
casing a
weribore, 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 exter.ding below the casing; lowering the
cirillIng assembly
into a formation; lowering the casing over the portion of thc drilling
assembly; and
circulating IWO through the casing.
1002.31 Iv another aspect, the present invention provcies a method of
drilling with
COtTIP,ISCrla torming a sect:on of wellbore with an earth removal member
operative:, r:()111V3CleCi tO n sction of iowi.mng the soctoP of iiner to a
lo:;ation
urox:mate a ower end of the weltore: and circiAtry,3 tr-td *Hie lowcfnng.
thereby
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urging debris from the bottom of the welibore upward utilizing a liotv path
formed within
the liner section.
100241 In
another ;Aspect. the present invention provides a method uf drilling teith
liner, comprising forming a section of tvellbore witri an asscinhly eompris;ng
an ealli I
i., removel too on a work string fixec at a prerieterrnined distnnee oelow
a lower end of a
section ot lieer; fixing an upper end of the liner section to a section of
casing lining the
wellbore: teleasing a latch between the work string and the liner section;
reducing fhe
predelermineci distance between the lower end of the liner section and the
earth
reitilOVal 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
weilbore.
[002e] in
another aspect. the present mvention provides a method of casing a
wellbore. comprising providing a drilling assembly comprising a casing and a
tubular
string releasably corinected to the casing, the tubular string having an earth
removal
13 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
wellbore: hanging the casing within the wellbore: moving the portion of the
tubular
string into the casing; and lowering the casing into the wellbore.
100261 In
another aspect, the present invention provides a method of cementirg a
liner section in a weIlbore, comprising removing a drilling assembly from a
lower end of
the linei section, the drilling assembly including an earth removal tool and a
wont sting:
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 aiterable bonding matorial through the tubular path and upwards in
an
0.11rVUS between the liner section and the weltbore therearounci; closing the
valve; and
removal the tubular pain, theieby leaving the valve assembly in the wellborc.
10027j In
another aspect, the present invention provicies a method of drilling with
liner, comprising providing a drilling assembly comprising a Iner having a
tubular
memoer therein, the tubular member operatively cOrinCeted to an earth remoiat
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 mentber; lowering the drilling assembly into the
earth,
thereby forming a wellbore; sealing an annulus between ;rn outer diameter of
the
tubular member and the wellbore: and sealing a longitudinal bore of the
tubular
rnember; flowing a physically alterable bonding material through the tluid
path, thereby
e preventing the physically alterable bonding material from entering the
lower portion et
the t::billar member.
[00281 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 tanner
-- advancir ig the second tubular to a second location in the earth.
10029j in another aspect. the present invention provides a method of
cementieg a
borehole, coetprising extenditg a drill string into the earth to form tile
borehole, the dill:
string ncluding an earth removal member hav;rig at least one fluid passage
therethrough. the earth removal member operatively connficit.--A to a lower
epd of !he
-- drill string: drilling the borehole to a desired location using a drilling
1111Ki 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.
[00301 in another
aspect. the present invention provides an apparatus for selectively
directing filyds flowing down a hollow portion of a tubular element to
selective
passageways leading to a location exterior to the tubular e!ernent, 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 rnember configured to maintain the second fluid
passageway in a normally blocked condition; and the first valve member
including a
valve closure e.ternent selectively positionable to close the first valve
member ant,
thereby effectuate opening of the second valve member.
;30 (00311 in
another aspect. the present invention provides a method tor lining a
weilbore. comprising forming a welibore with an assernely including an oarth
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
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testing and any can include sensing means for geophysical parameters like
ineasuiement while drilling (MWD) or logging while drilling aõVVD). Examples
of MWI)
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
I() summarized above. may be had by reference to embodiments, some of which
are
illustrated in the appended drawings it is tc 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 te
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
1-1
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[00441 Figure 8 is a viow of the second drilling system after driilitig
is cornpieted.
10045J Figure 9 is a view of the second drilling system snowing the
litter hangor at
the beginning of the settino sequence.
10046) Flylire 10 show a view of the second drilling atter the liner has
been set.
[00471 Figure 11 is a view of the second drilling system showing the
it.el opening tool
tr. the open position.
10048) i-igure, 12 is a view of the second tirillila SYStan :.ifter (Ito
cementing
cooration has completed.
[90491 Figure I2A is an exploded VIEDN of the full opening toot in the
actuated
pot:iiticit.
10050] Figure 13 shows another embodiment of the second drilling system
according lc aspects of the present invention.
100511 Figure 13A shows (he bypass mernber of the second drilling system
of Figure
13.
!'..) [00521 Figure 14 shows the second drilling system of Figure 13
after the bypass
ports have been ciosed.
(0053j Figure 15 shows the second drilling system of Figure 13 after the
liner hanger
IlEIS been set.
[0054] igure 16 shows the second drilling system of Figure 13 after the
BHA has
20 been belled up anci the internal packer has been inflated.
1.0055J 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.
loose] Figure 13 shows the second drilling system of Figure i 3 after
internal packer
has beo deflated.
2% [00571 Figure 79 shows the second drilling system of Figure 13
after the BHA has
been retrieved and the litter hanger packer has been set
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100581 1,igere 20 shows another embodiment of the second drilling system
itcconiaig to aspects ef the present invention.
10059i Fiyurfi 20A is perspective view of the bypass member of (he
Se8;01/(i
SyStt1T1 of f-.1tirti, 20.
10060) Figure 21 shows the second (Wing 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.
100621 FiiTiure 23 shows the second drilling system ol Figuro 20 after
BHA lye; hem
rotrievee beoloyirent valve has di.)sed.
E00631 Figure 2,1 shows the second drilling system of Figure 20 after a
cement
retainer has been inserted above the deployment valve.
Iowa) Figure 25 shows another embodiment of the second drilling system
according to aspects of the present invention.
15 {00651 Figure 25A is a perspective view of the bypass member of the
second drilling
systom of Figure 25.
(0066] Figure 26 shows the second drilling system of Figure 25 after
bypass ports
have beer closed.
[00671 Figure 27 shows the second drilling system of Figure 25 alter the
liner hanger
20 Nis been set.
[0068] Figure 28 shows the second drilling system of Figure 25 after a
packer
assembly has latched into the second casing string.
[00601 Figure 2s shows the second drilling system of Figure 25 after
sincle direction
plug has been set.
25 100701 Figure 30 shows an embodiment of a liner assernbly ziccording
to aspects of
the present uivention.
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100711
Figure 30A shows a fluid bypass assembiy suitable for use with the liner
assembly of Figure 30.
(0072)
Figure 31 shows the liner assembly of Figure 30 after latch has been
releaser].
[00731 Figure 32 shows the lino' assembly of Figurr.õ atto!
!!-07, !la], har; beol
iiurnped into tile baffle.
[00741
Figure 33 shows the liner assembly of Figure 30 after the litter has been
reamed deµ....µa over the BHA.
100751
Figure 34 shows the 11ner assembly of Figure 30 after the hanger has been
nettiatect.
10076)
Figure 35 shows the liner assembly of Figure 30 after the running assembly
is partially r=7;trieved.
100771 Figure 36 shows another embodiment of a :iner assembly according
to
aspects of iho I.resent invention.
15 (0078) Figure 37 shows the liner assembly of Figure 36 after the
hanger has been
sot.
[0079) Figure 38 shows the liner assembly of Figure 30 atter running
tool has been
reloasorl
100801 Figure 39 ShOWS the liner assembly of F:gure 20 aftor tne BHA has
bcren
20 retracted.
10081j Figure 40 shows the liner assembly ot Figure SO after the hanger
has been
released.
jorgq Figure 41 shows the liner assembly of Figure 30 after liner is
clrilleci down to
bottom.
25 [00831 .7:vire 42 shows the tiler assembly of Figure 30 atter the
banger as been
reset.
CA 02874763 2014-12-15
100841 Figure 43 shows the liner assembly of Figure 30 after the
seconciery latch
has bee..n released.
100051 Figure 44 stio.õ,.:s the liner aSSOnitily of Figure 30 after n is
partially retrieved.
100861 Figure 45 shows cementing assembly according to aspects of the
present
flvention. 'Pie cementing assembly is suitable to pet fonn a eemenung
operation atter
wellbore has been lined using tho methods disclosed in Figures 130-35 or
Figures 36-
44.
í 087i Figure 46 shows the cementing assembly of Figure 45 as the cement
is
chased by a dart.
1( (0088) Figure 47
ShOWS the cementing assembly of Rgere after the circulating
ports have been openic:ti.
100891 Figure 48 shows the cementing assembly of Figure 45 after weight
is stacked
on top of the liner.
10090] Figure 49 shows the cementing assembly of Figure 45 after the
packer has
bc-;c.,:n set and the work string of the cementino assembly has beer:
retrieved.
100911 Figure 50 shows an embodiment of a tiller assembly for lining and
cementing
the liner in one trip.
f0092) Figure 50A is a cross sectional view of the liner assembly of
Figure 50 taken
at line A-A.
10093] Figure 51 shows the liner assembly of Figure 50 after the hanger has
been
set.
[OONJ Figure 52 shows the liner assembly of Figure 50 a.1;er ;he BHA is
coupled to
the casing sealing member.
[00951 Figure 53 shows the Iner assembly ef Figure 50 efter second
sealing
member has beer; inflated.
00961 Figure 54 shows the liner assembly of Figure 50 alter the first
dart has
landed.
CA 02874763 2014-12-15
(1.1097jUre 55 shows the liner assembly oi Figure 50 after circulation sub has
boon opened for ix-orienting.
(0098] Hgure 56 :3hows the liner assembly ot Figure it.) alter second dap
has
;ander!.
[00991 1:I9ure 57 shows tile ;iler aSSOribiy
Fig;i:e attzr= the flztsinti
Memix;r ìì been inflated.
leolool Figure:. 58 shows the liner assembly of Figure 50 after the
second sealing
z.noriliwir hart i)een cienctuated.
[001(111 Figure. 59 shows the liner assembly of Fioure 50 liner assembly
during
[001021 Figure 60 is a cross-5.iectional vier; of a cihiiy :ssutn!y having
a t!..iw
apparatus dIsposed at the lower end of the µ..:ork string.
[00103] Figure 6 l is a cross-sectional view of a (killing assembly having
an auxiliary
flow tube partially formed in a casing string.
l 5 jootorti Figure 62 is a cross-sectional view of a drilling assembly
having a main flow
tube formed in the casing string.
{00105J Figure 63 is a cross-sectional view of a drilling assembly having a
Cow
apparatus aro an auxiliary flow tube combination in zif.:oce with tno wesenr
nvention.
20 moms) 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.
1001071 Figure 65 is a. cross-sectional view of a diverting apparatus used
tor
expnr.oing casinc!.
[00108) FieLite 66 is a cross-sectional view of the divertinc2 apparatus of
Figure i35
'25 the process cif =axpanciing the casino.
[00109] Figure Eì7 is a schematic view of a wellbore. snowing prior art
drill string in
a downhole location suspended frorn a drillino platform.
I 6
CA 02874763 2014-12-15
[001 lei Figure 68 is a sectional vlevi int-)
LirII strir:g. ailovang tirst einhodirreat oi
itle in 08'0111 invention.
[00111) Figure 59 is a further view of the drAl string as shown in Figure
68, showing
the driil string positioned for cementing operations.
loom! :--igure 70 is a ;lather view oi the drill string as t3ht)1A11
!r! Figure 6.O. showing
the drill string after cementing thereof has occurred.
[00113] Figure 71 is a sectional view of tne drill string, showing an
additional
enibodirnent of the present iiwentian.
100114.1 Fgure 72 is a further view of the drill string of Figure 71,
showing tho ririll
atter :ernoriting has occurred.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT
(00115J l= (jilfE; 1 is a cross-sectional view of one embodiment of the
chilling system
100 of the present invention in the run-in position. The drilling :;ystem 100
inelta les n
first casing string 10 disposed in a housing 20 such as a conductor pipe arid
t;electivdy
15 -- connected thereto. The housing 20 defines a tubular having a larger
diameter than the
first casing string 10. Embodinients 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
20 -- 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 (>4 the rous.ng 20. Trle.
muu matt
25 has an outer diameter that is arger than th.c outer diameter ot the housing
20 to
allow the mud matt 25 to sil atop a surface. such as a mud line on the sea
floor 2. in
25 -- order to support the housing 20.
(Delia] The drilling system 100 may also include an inner btring 30
disposed within
the f!rst casing string 10. The inner string 30 may be connected to the first
casing string
using i releasable latch mechanism 40. During operation. the latch mechanism
40
may seal in a landing seat 27 provided in an upper erd of the housing 20. An
exampre
-
CA 02874763 2014-12-15
of an appropriate latch mechanism usable with the present invention includes a
latch
mechanism such as ABB VGI 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 cr
earth removal member 60 fot forming a borehole .7 Prefeiably an outer diameter
of the
drilling member 60 is larger than an cuter diameter of the first casing string
10. I he
drilling rnember 60 may include fluid channels 62 for circulating fluid. In
another
e.mbodimenr. the flt d channels 62_ or nozzles. may be adapted for directional
drilling
Art exemplary drilling member 60 having such a nozzle is disclosed in co-
pending U.S
Patent Application PublIcatton No. 2004/0245020 filed Febrary 2. 2004. A
centralizer 5S
may be utiley.;:d to keep the drilling member 60 centeree The first castng
stneg 10 may
also include a float collar 50 having an orienting device b2, 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-
111 collar 90 at its lower end Preferably. the ball seat 70 is an extruciable
ball seat 70
wherein a ball 72 disposed rnay be extruded therethrough. in one example. the
bail 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 ui 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 i)e 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 bail seat 70. The ball
receiver S0
receives the ball 72 and allows fluid communication in the inner string 30 to
be re-
established
3t) [00119]
Disposed below the ball seat 70 is a stab-in collar 90 Preferably the stab-uì
coIlar 90 includes a stinger 93 se:ectively connected to a stinger receiver
';.)4 DuriPg
operation, the stinger 93 may be caused to disconnect from the stinger
receiver 94
18
CA 02874763 2014-12-15
100120] SilOVitt Plgure
2 is an erirbo:iiment or tat releasable connection 20o
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
íirst casing string 10. The piston 215 is temporarily connected to the inner
sleeve 210
iising a shearable pin 230. A port 225 is fonnod in the 4irst casing siring 10
for fluid
eommunication between the ;nterior of the first casing sterg 10 anci the
annular area
220. The inner sleeve 210 is selectively connected :o
.s.:ter sleeve 2:35 using a
locking clog 2.40. The outer sleeve 235 is connected to the. nciusing 20 using
a biasire
member 245 such as a spring loaded dog 245. 'Ulie outer sleeve 235 may
optionally be
connected to the housing 20 using an emergency release pin 250. A locking dog
profile 255 :s former: or the piston 215 for receiving the locking dog 240
dulieg
operation. In another embodiment, the releasable connection includes a J-slot
release
as is known to a person of ordinary skill in the art.
[001211 Figure lA is a cross-sectional view of Figure 1 taken along line 1A-
1A. It can
be seen trot releasable connection 200 is fluid bypass -nember 17. The bypass
member 1 1 may comprise one or more radial spokes eiieumferentially eisposec
be.ti.veen the first casing string 10 and the housing 20, le :his respeet, one
or more
bypass slots are formed between the spokes for fluid ílow therethrough. The
fluid
bypass member 17 allows fluid to circulate during wellbore operations, as
described
beim.
t001221 In operation, the drilling system 100 of the present invention is
partially
!owered 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 62 of the drilling member 60.
The fluid
rnay 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 ihe
housing 20 :o be inserted inlo the sea floor 2. The drilling sysiern 100 is
inserted into
the sea floor 2 until the mud matt 25 at the upper Qnd et the housing 20 is
situateci
proximate the mud line of the sea floor 2 as shown in Figure 3.
[001231 The first casino string 10 is now ready for release from !he
housing 20. At
this point. a hall 72 is dropped into the inner string 30 and lands in the
ball seat in.
19
CA 02874763 2014-12-15
After seating, the ball 72 blocks fluid communication from above the ball 72
to berm."
the ball 72 in tile inner string 30. As a result, fluid in thc: intior siring
30 above the ball
72 is diverted out of the ports 74 in the ball soat 70. This allo,,vs pressure
to build up in
the annular area 12 between the inner string 30 and the: first easing string
10.
1001241 The
fluid in the annular area 12 may be used to actuate the reteasable
connection 200. Specifically, fluid in the annular area 12 fiev.is through the
port 225 in
the tirst casing string 10 and into the annular area 220 between inner sleeve
210 and
the first cas;ng string 10. The pressure increase CaUfsElti the she.arable pin
230 to tail,
thereby allowing ibe piston 215 to move axially. As the piston 213 moves. the
locking
it) dog profile slides
uAor the locking dog 240. thereby allowing the locking deg 240
movt., ava:x C'tlie!" sleeve 235 Onii soat in Irle
protito 256. th$
u.Ispect. :ili= :;11,er Ste-.,iile 21Q iS frE.'efi to ITifiVe inCiereiletlt4c.
IN:. f.)1.11Eg SieeVil 235.
in this manner, tho first cnsing string 10 is released from the housing 20.
100125)
Thereatter, the pressure is increased above the ball 72 to extrude the bali 72
15 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 cornmuhication from the inner string 30 to the drilling member 60. In
addition, the
increase fn pressure causes the sliding sleeve 76 of the ball seat 'TO to
close tne ports
14 of the bail seat 70.
1001261 The
drilling member 60 is row 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 loaned between the borehole 7 and the first casing string 10. Fluid is
circulated
through the inner string 30, the drilling member 60, lhe annular area 97, the
housing 20.
and the bypass members 17. The depth of the borehole 7 is determined by the
Iongth
25 ot the first casing string 10. The drilling continues until the latch
mechanism 40 on the
lirst casing string 10 lands in the landing seat 27 disposed at the upper end
of the
housing 20 s sho:vr. in Figure 5.
1001271
Thereafter: a physically alterable bonding rna.tcrial such zs cement Is
pumped down the inner string 30 to set the first casing, string 10 in the
wellbore. The
30 cvment flows out ot the ciri:ling 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 02874763 2014-12-15
ind tills the tilnular 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 thii drill string 5 and the inner string 30 aro removed from the
first casing
string 10. 1 he inner siring :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 ilong 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 characteristcs of the borehole. The
survey
tool 96 may traiismit any collected information to surface using timeline
telemetry, mud
pulse technology, or any other manner known to a person of ordinary skift in
the art.
lb [00129J 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 r is
a second drilling system 102 at least partially disposed within the first
casino string 10.
In addition to the seuond 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 rnay include components such as a mud motor; iogging
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
clriiiing
member 115 such as a pilot bit and underreamer combination, a bi-center bit
with or
wiilieut an irlderrearner. an expandable bit, or any other drilling member
that may be
uscd to drill a hole having a larger inner dietrneter than the outer diameter
of any
component c.tisposed on the drill string 110 or the first casing string 10, as
is known in
the art. Thc; drilling member 115 may include noz.=kles or jetting orifices
for directicriat
drilling. As shown. the drilling member 115 is an expandable drill bit 115.
[00130] File 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 oi
21
CA 02874763 2014-12-15
the second casing string 120. As shown in Figure 7A, the firs: bali seat 140
comprises
a Nid oypass member 145. Preferably. the bypass ports 142 are disposed within
the
spokes cí the byeass member 14ti. The spokes extend radiaily feirn the chill
string 110
le :he ;ifintiiar area 146 between the first casing string 10 and the second
casing string
b 120. rile Spokes are adapted to form one or snore bypass slots 147 for
fluid
communiceon along the interior of the second casing string 120. Specilioally,
bypass
member 145 is shown with four spokes aro 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 cominunication between the ar.nular area 146 and the
interior
of the first easing string 10 above tne second easing strirg 120. In one
embodiment.
tee first bap ;seat 140 !nay be tin extatuahle Pall scat.
i001311 drf!! string 1 !a fiStle!" ;rclucles a ;f11.11" Manger
itSSi.:!ribiy 130 '..i:sposed at
an upper eed thereof. The iiner hange! 130 temporarily connects the drill
string 110 to
ine sewed casing string 120 by way of a running too: and may be USW,: to hang
the
second casing string 120 off of the first casing string 10. The liner eanger
130 includes
a sealing element and one or more gripping members. An example of suitable
scaling
element is a packer, and an example of a suitable gripping member is a rt.-
daftly
extendable slip mechanism. Other types of suitable sual:ng elements and
gripping
members krotvn to a person 0 ordinary skill in the art are also contemplated.
1001321 The liner hanger 130 is placed in fluid communication with a second
ba:1 seat
136 ilisposed 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
iiner
hanger 130. The packing element may be set when the slips are set or
mechanically
set when tne drill string 110 is retrieved. Preferably, the packing element is
set
2.5 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.
footss] The second drilling system 02 may also include a !ul: opening tool
150
disposed on the second casing string 120 for cementing operations. The tull
opening
ioo! 150 is actuated by an actuating tool 160 ,zisposco on 0-ie drill string
110. The
cictuating too; 160 may also ccmprise 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 ccmmunication axially along
the
22
CA 02874763 2014-12-15
interior of the second casing string 120. It must be noted that the spokes of
the bypass
mumbe.rs 145 discussed herein may comprise other types ut support member of
design
capable of ;Mowing fluid flow in an annular area as is known 10 a person of
ordinary skill
in the art. he
actuating tool 160 includes a sleeve 162 having sealing cups 164
dispose at euen end The sealing cups 164 enclose an annular area 167 between f
he
sleeve !62 and the secone casing string 12). Disposed beitween the seeling
cups are:
opper and lower collets 163 ior openieg and closing the ports 155 of the full
opening
tool 150. iespectively.
[00134] A
third uali seat 180 is disposed on the &ill 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 bvpass ports 170 for fluid
eorienunication between tile interior of the drill stiinc.3 110
encloseci annular
area 1e-7. lhe drill string 110 may further include circ
u.aVng ports 185 disposed above
the third Deli seal 18u. Figure 12A in an exploded view of full penile tool
;50
actuated h ;he actuating tool 160.
miss! The
chill siring 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 desige capable of
allowing fluid
flow in an annular area as is known to a person of ordinary skill in the arl.
in one
embodiment, the centralizer 190 may comprise a bladed stabilizer.
[00136J 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 drillino member 60 of the first drilling
system 100. Thc
expandable bit 115 may be expanded to lorni a borehole 105 larger than an
outer
diameter of the second casing string 120. The bit 115 continues to drill until
iL reaches
a desired depth in the wellbore to hang the secono casing string 120 as shown
in
Figure 8. During drilling, some of the fluid is ailoweci to flow ciut of the
ports 142 r 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 (livened
fluid in the
23
CA 02874763 2014-12-15
ilnnular area 146 to nevi downwaqi in the wollbore. The advantages ot the
diverted
fluid include lubricating the easing string 120 and hips remove cuttings front
the
borehole 105. Fluid in the :over portion ei the Wed!) Oro.: IS circulated up
tho wellbore
inside the second casing string 120. The bypass members 1-15. '175 disposed
along
the second casing string 120 allow the circulated fluid, which may contain
drill cuttings.
to travei axially :11SKIC.' an) SOCOP.1 casing string 120. In this respect.
Alai may be
circulatW inside the second casing string 120 instead of the small annular
area
between the second casing string 120 and the newly formed wollbore. in this
manner,
fluid circulation problems associated with drilling and lininn the ..veilbore
in one trip may
to no alloviatee.
00137] VPItin the drilling stops. a ball is dropped sno the tirst bali
seat 140 as shown
in Figwe 8. Pressure is increased fr.) extrude the bali through the first ball
seat 140 and
close oil the ports 142 ot the first ball seat 140. The ball is allowed to
land ,n a ball
catcher (110i SII0V41') in the drill string 110. Alternatively, :he ball may
and in the second
bail seat 1&;.
f001381 If the ball does not land in the second ball seat 135, a second
ball may be
dropped into the second ball seat 135 ot the liner hanger asse.rnbly 130 as
snown iti
Figure 9. Preferably, the second ball is larger in size than the first ball.
Atter the ball
seats, pressure is supplied to the liner hanger 130 through the ball seat
ports 137 to
20 actuate the liner hanger 130. Initially, the packer is set and the slip
mechanism :s
actuated to support the weight of the second casing string 120. Thereafter,
the
pressure is increased to disengage the drill string 10 froin the second casing
string 120.
thereby treeing the drill string 110 to move independently of :he second
casing string
120 as shown in Figure 10. The ball is allowed to extrude the secono bail seal
135 and
25 land in the ball catcher in the drill string 110.
(.001311 Thereafter. the drill string 1 1 0 is axially traversed to move
the actuating tool
160 relstive to the full opening tool 150. As the actuating 1001 160 is pulled
up, the
upper collets i 66 of the actuating tool 160 grab a sleeve in the full opening
tool 150 to
open the ports 155 ot 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 µ.vith bit 115 is above the final height of the cement.
24
CA 02874763 2014-12-15
[00140] A third ball, or a second ball if the lirst 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 ott
communication below the drill string 110. Fluid may now bo pumped down the
drill
etring 110 and direceed through purts 170. lnitialey, a counterbalance tluid
is pumped ir
head ot the cement in order to control the height of the cement. Thereafter.
cement
eupplied to the drill string 110 flows through ports 110 and 1:05 et tiìe fie!
opening too;
150 arid 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 SUCOIld
casing
string 120. The fluid bypass capability of the actuating tool 160 and the
centralizer 19()
facilitate the triovernent of fluids in the second c;asing string 120.
Preferably. ttìe. height
of the k;einent in the second ca.siere string 120 is mail:mince: belov, the =
rill bit 115 ue
the counterbalance ibid. in this respect. the bottom hole assembly 12S, whlch
may
include the drilling member 115. the motor, LWD tool, and IvPleD tool may be
preserved
and retrieved for later uso.
1001411 Alter
a sufficient amount of cement has been supplied. a dart 104 is pumped
in behinn the cement as shown in Figure 12. 'File 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 183 of
the drill string
110. Once opened, fluid may optionally be circulated in reverse. i.e., down
the exterior
oi 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 wellbore may be drilled, lined, and cemented in one trip.
1.00141
Figures13-19 show another embodiment of the second drilling systom
according to aspects of the present invention. The second drilling system 302
includes
eeeond cesing string 320, a drill string 310, and a reottom hole assembly
t'.25. SIM!i0f
to the embodiment shown in Figure 7. the dill! strina 310 is equipped with a
second brei
seat 335 and a hydraulically actuatable liner hanger asserribiy 330. The liner
hanger
330 lr.cluOes a liner hanger packing element and slip mechanisms as is known
to a
person of ordinary skill in the art. The driil string 310 also inciudes a
first ball seat 340
coupled to a bypass member 345 having bypass ports 337 in fluid communication
with
CA 02874763 2014-12-15
the drill string 310 and the annulus 346 between the second casing string 320
and the
first easing string 10. Preferably, the spokes of the bypass member 345 are
arranged
aro shown in Figure 13A. A sealing member 348 is used to block fluid
communication
between tile annulus 346 and the interior ot the first casing string 10 above
the second
easing string 320. Because mary of the components in Figure 13 are
substantially the
sostnc, :le the components shown ere described i Figure 7. the above
descriptien and
eperatien Of the similar components witn respect to Figure. 7 appiy equally to
the
eomponents of Figure 13.
[001431 Ihe second driliing system 302 utilizes one or more packers to
facilitate the
cementing operation. In one embodiment. the second drilling system 302
includes an
extcenal casing packer 351 located near the bottom of the outer surface of the
second
easing stele; 320. Preferably, the external packer 351 comprises a metal
bladder
inflatable eacker. The external packer 351 may be inflate usieg gases
generated by
mixing 0110 or more enernicals. In one embodiment, the ceereicEes are mixed
together
by en internal packer system that is activated by mud puiso signals sent from
the
surtace.
[00144J The second drilling system 302 also incledes an internal packer
352
disposed on the drill string 310 adapted to close off fluid communication in
the annulus
botvveen 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 cne embodiment, one or oath of the packers
351,
352 may be constructed of an eastomeric materiai. It is contemplated that
other types
of selective:v actuatable packers or sealing members may be used without
deviat:ng
trot:1 aspects of the present invention.
toeuel In operation, the drill string 310 is operated to advance the
second casing
string 320 as shown in Figure 13. During orilling, return fluid is circulated
up to the
surface through the interior of the second casing string 320. The return fluid
may
include the divetted fluid in the annulus 346 between the first casing string
10 and the
second casieg string 320.
26
CA 02874763 2014-12-15
eroeue After a desired inte: val has been drilled, a bail
dropped to elose off the
bypass ports 337 of the oypass member 345. as illustratecr in Figure 14.
Thereafter;
the ball may extrude through the first ball seat 340 to land in trie second
ball seat 336,
as shown in Figure 15. Alternatively, a second bail may be dropped to land in
the
seuond ball seat 335. Prossure is supplied to set the liner hanger 330 to hang
the
second casing string 320 oft of the first casing string 10. I lowever, 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 bail seal 335 may be forced
through to lenci in a ball catcher (not shovel). Thereafter, the drill string
31u is pulled up
1u well the BHA 325 is inside the second casing string 320, EIS shown in
Figure 16.
[001471 Tee cementing cpceation is initated when another bat; dropped Ifl
strirg 310 lands in the frerd ball seat 380. The bail shifts tee 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
15 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
puree) 370, ..lovirt the annulus between the second casing string 320 and the
bottom
hole assembly 325 to the bottom of the second casing strinr3 320, and up the
annulus
between the second casing string 320 and the borehole.
20 [00148] In Figure 17, cement is pumped down the dhli string 310
followed by a latch
in dart 377. After the dart 377 latches in to signal cement placement, murt
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.
100149] Pressure is applied on the dart 377 to cause the sleeve to shift
further, which,
;11 turn, caus,-2s the int3rnat packer 352 to deflate, as shown in Figure 7 8.
Additi0110:!y.
Shitino tile sleeve opens the ceculalion port tor reverse rerculation. Fluid
is thrn
reverso circulated to remove excess cement from the interior oi the drill
string 310.
memo] Upon completion, the drill string 310 is pulled out of the second
casing string
30 320 to retrieve the BHA 325, as shown in Figure 19. Tile liner hanger
packer is set as
the drill string 310 is retrieved.
27
CA 02874763 2014-12-15
(00151I Figure 20 shuws another embodiment of till3 second drilling
system
accoiding to aspects of the present invention. The second drilling system 402
includes
a seCend casing string 420, a drill string 410, and a bottom hole assembly
425, which is
shown in Figure 23. Similar to thec.,.mboctiment shown in Figure 7, the drill
string 410 is
equipped wall a ::incond bail seat 435 and a hydraulically acivatablo liner
hanger
tissembly 430. "Thu= iiner hanger 430 includes a liner hanger ;.ticking
element 432 and
slip mechanisms 434 as is known to a person of crdinaiy skill in the art. i he
drili string
410 also ineludes a first ball seat 440 coupled to a bypass member 445 having
bypass
ports 437 in fluid coinmunication with the drifl string 410 and the F11111LAUS
446 between
the second easing string 420 and Ine 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 pioeic fluid communication beteeen the annulus 446 and the 81teNOf
of the
first casing suing Z 0 above the second casing strieg 420. Because many oi the
comporg:fits in Figure 20. 0.9.. the first arid second eall seats 435. 440.
are
si:Lisfsetis11./ no same as the components StIOVitl 0:1(-14.10801ibt,C ill
F:iyUre 7. the above
dese.:ription sna operation of the z;imilar components veith respect to Figure
7 appiy
equally to the components of Figure 20.
001521 .1he second drilhng system 402 features a deptoyinent valve 453
dispesed al
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
;Elr;i111()!Oc17.
(00153/ The second drilling system 402 may a:se inelede a full opening
tool 450
disposed oe ihe second casing string 420. The full opening tool 450 comprises
a
:)5 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 casino string 420. The flow control sleeve 454 may be actuated
to align
(misaiign) the alignment port 456 with the casino port 455 to establish
(close) floe
eommuniention.
lo0r541 in .veration. tee dri:i string 410 is operated le advance the
second casing
string :420 as shown ;i1 Figure 20. The deployment valve 453 fs rur,-in in the
open
position. During drilling, return fluid :s circulated up :o the surface
through the interior of
28
CA 02874763 2014-12-15
the second easing string i fie fetuin fleid (Oetti.:(! iti
fix;
annulus 446 between the first casing string 11"; ane the secene easing stiing
420.
toolsst /liter
a desired inteival 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 '135, ,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.
tiowevce. the liner flange:* pack:ng e=iement 432 has riot been siti. Atter
the second
!Li casin9 skint; ;120 is supported by Int! first casino string I. th
runrii,ig tool is reit,ased
ircns. the liner hanger 430 and ;ire o; :!l stnr.g 410 is rota:veil.
[001561 Az.;
shown in Figure 23. when the BHA 425 is retrieeed past the deployment
valve 453, a mud pulse may be transmitted to close the deployment valve 453.
In tnis
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 reilleci out of the wellbore.
1001571 -
Thereafter, a eement reteir=or 458 arti ai acteat:ng teoi 4t30 to; µ;peratiiig
the
fu:1 opening tool 450 is tripped into the wellbore. as shov,11 in F"gure 24.
lito tools 458.
460 may be located above the deployment valve 453 using conveying member 411.
such as a work stnng as is known to a person of ordinary skill :n 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 sealinc,1 cups and the cement relaner 'rile
cementing port
tool 480 may be actusted to allow fluid communication between the conveying
member
4 t and the annulus between tne conveying rnornbr 411 filo
:.,econd casirl!,! S:firit7
420.
A toutssj The
cement retainer is set in the interior of the second casing string 420
above. the doployment valve 453. Cement is then supplied through the drill
string 410
29
CA 02874763 2014-12-15
and pumped through cement retainer 4Z.i8 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. I hereatter, a setting
tool not
is 1.311-1(wed from the eement retainer 453, and the drill string 4 le is
pulled up
f. ltele. ree ceploymont valve 453 and the cement retaii.:er 458 are
ellowed lo close and
,.iontain ic .iernent below the"1:eritei re!iiirli3f -TSB r.d tht.:
4ieoloyinent valve 453.
tuois9) As the
drill string 410 is pulled up, the collets 466 of the actuating tool 460
engage the flow controi sleeve 454. The flow control sleeve 454 is shifteci 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 v.,ith the lower portion of the drill string 410 and the
cement retainer
settl1i4 too/ iltor shown). Pressen--; is supplied to oper tr:o cc=r-,-.1;:ng
port tool 480 lo
s(liltthzo Llornont into an upper portion ct the ann...lus second
casing string
420 and the wellbore. Spec;lica!iy. cement is ;:difiV7eci to tii out of
..;unveying
5 member 411 anci through the casing poil 4135. Orect.. the upper pertion
ot the annulus is
squeezed off, the cementing retainer setting tool (not shown) and the
actuating tool 460
may ho retrieved.
[001601 Figure
25 shows another embodiment ot the second drilling system
according to aspects of the present invention. The second drilling system 502
includes
a second easing string 520, a cirill string 510, and a bottom nolo assernbiy
i'not shown!.
Simile, to the embodiment shovel in Figure 7, the drill strinc; 510 is equpped
with a
second ball seat 535 and a hydraulically actuatablo liner hanger assembly 530
having
one or more slip mechanisms 534. The drill string 510 aiso 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 tho bypass member 545
arc
arranged as shown in Figure 25. A sealing member 548 is used to block fluid
communication between the annulus 546 and the interior of tne first casing
siring 10
above the second casing string 520. Because many of
....omporienIs in Figure 25,
e.g.. first and second ball seats 535, 540. are substartia:iy the same as tile
components shown and described ,r. Figure 7, :he above desnription and
operation of
the similar components with respect to Figure 7 apply equaily to the
components of
Fvu'e
' .1 =
CA 02874763 2014-12-15
[00161] In operation. the drill string 510 is operated to advance the
second casing
string 520 as shown in Figiire 25 During drilling return fluid is circulated
up to the
surface through the interior of the second casing string 520. 1 he return
fluid may include
the diverted fluid in the annulus 546 between the first casing string 10 and
the second
cnsing 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 Irl Figure
27
Alternatively additional pressure is applied to extrude the first bail though
the first ball
seat 540 to land in the sc:cond 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
shewn the slips 534 nave been expanded to engage the first casing string 10.
It can to
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 catchei (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
lelative to tubular. The plug 560 further comprises a
31
CA 02874763 2014-12-15
sealing member 566 for sealing a fluid path between the body 562 and the
tubular.
Preferably, tbe 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
movablo ;n the first direction due to fluid pressure.
1001651 Cumeiit is pumped down the drill string 510 aed the Send nazi1119
String 520
followed by a dart 504. rite dart 504 travels behind the cornert until it
!arias in tele
single dirtie.0011 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
:0 differential is created to set the single direution plug 560. In this
respect, the single
direction p:ug 560 wiil prevent the cement from floating back into the second
casing
stririg 52e.
[00166) Thereafter. a 'circa is apniied to the plug retiring packer
setting tool 558 to
set the packer 557 to seal off the annulus 546 between the seeond Ca !Alit)
string 520
e 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 seconci casing
string 520 after
it has been cemented into place,
001671 Alternate embodiments of the present invention provide methods and
20 apparatus ior subsequently casing a section Ot
wellbore which was previously
spanned by a portion of a bottom hole assembly f"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 ane while casing the section ol the wellbore previously spanned by
the
25 portion or the BHA extending below the lower end of the liner.
100188J Figure
30 shows a first casing 805 which was previously lowered into a
wellbore 881 afro set therein, preferably by a physically alteraole bending
material SUCil
as ccrrient. In the alternative. the easing 805 may be set withie :he
*.vellbore 881 using
any type of hanging tool. Preferably, the first casing 805 is drilled into an
earth
30 formation by jetting andfor rotating the first casing 805 to form the
wellbore 881.
32
CA 02874763 2014-12-15
(00169) Itisposed within the first casing t305 is a second easing ur
liner 810.
Conneuted to an outer surface of an upper end of the liner 810 is a setting
sleeve 802
having one or more sealing rneinbers 803 disposed directly below the setting
sleeve
802, the sealing members 803 preferably including one or mere 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 driil string 815 (see below) has an
inner
ditimeter adiacent to an outer diameter of a running tool 825, and a recess in
tile
setting Slet:VC guard 801 houses a shoulder of the seWng sleeve 802 therein. A
shoulder on the drill string 815 prevents the setting sleeve guard 801 froni
stroking the
setting sleeve 802 dowewards vale working the drill string 815 up and down in
the
wellbere 881 during the drilling process two below). The settAg sleeve guard
801
prevents the setting sleeve 802 from being actuated prior to ;he cementation
process
and described beim in relation to Figures 45-49).
[001701 Tho ;iner 810 includes a liner hanger 820 on a portion ol its
(Alter 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. rho finer 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 ineer diameter of the casing 805. At a lower end of
the liner
81U, a liner shoe 889 may exist.
[00171) The liner 810 has a drill string 815, which may also be termed a
circulating
string. disposed substantially ccaxially therein and releasably connected
thereto. The
drill string 815 is a generally tubular-shaped body -laving a longitudinal
bore
therethrough. Thc 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.
[00172j 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 325 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.
Tile
!etching member 82t3 is radiaily extendable rtto a recess 828 in an inner
surface of the
33
CA 02874763 2014-12-15
iintif 810 to releasably engage the liner 810. When the !etching member 826 is
extended into the recess 828 of tho liner 810. the liner 810 arid the drill
string 815 are
latited logef iter.
100173I The BHA 885 inCit:(10$ a first telescoping joint 850 at its upper
end which is
disposod concontr:cally ..vithin the loi..ver end of the running tool 825 so
that the fiist
telescoping joint 850 and the running tool 825 are rnoveablo longitudinally
relative to
one another. The lower end of the first telescoping jo!nt 850 is then disposed
ooncentrically around an upper end of a second telescoping joirit I.355. The
first and
secoed telescoping joints 850 and 855 are also moveable longitudinally
relative to one
anotlier.
pot 741 It is contemplated that a plurality of telescoping jeints 850.
855 may be
utilized rather than merely the two telescoping joints 850, 855 shown.
ziependisig at
least partially upon the length of the F3HA 885 that is exposed below the
lower end of
the liner 810. This portion of the BHA 885 must be swalowed by collapsing the
15 telescoping joints 850, 855, thus lewering the liner 81(1 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 aed positioned
toward a
lower end ot the drill string 815 because of their reduced cross-section
caused by an
effort to MiniMIZO their hydraulic area. When the telescoping loints 850 and
855 are
20 extended to telescope outward, the telescoping joints 850. 855 are
preferably splined,
or selectively splined, to permit torque transmission through tne 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
1de-seeping joints may be coupled using any other manner that is capable of
:)5 transmitting torque while allowing relative axial movement between the
telescoping
joints.
looris) The second teleszoping joint 855 :neiudes a etch 862 with one or more
recesses 887 in its outer surface. The one or more recesses 887 house orie or
more
latching members 886 therein. Th6 one or more latching members 880 are also
30 disposed within one or more recesses 888 in an inner surface of the
liner shoe 889 (et
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 02874763 2014-12-15
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 arid lower portions
of the liner
810. respectively. Both attachment locations are capable of handling tension
and
compression as well as torque.
[00177j 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 mime a recess 884 in an inner
surface of
the wali of the circulating sub 860 to selectively open and cicse the port 863
A baffio
877. which acts as a holding chamber for a ball 876 (see Figure 311 after the
ball 6/6
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
rriclude:-.s a
measuring-while-drilling (lAWD") sub 896 capable of locating one or more
measuring
tools therein for measuring formation parameters. Also, a resistivity sub mot
showm r ay
be located within the lower portion 870 of the BHA 885 for locating one cr
more
resistivity tools for measuring additional formation parameters.
2:3 [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
3G 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 mto the formation to form the wellbore 881. In one einbodiment.
the
CA 02874763 2014-12-15
131-IA 885 mily also include an apparatus to i;.t=illti.1143 directional
drilling, such as a bent
motor housing. an adjustable housing motor, or a luta,/ steerable system.
Moreover.
the earth removal member may also include one or more fluid deflectors or
n07zIes for
selectively introducing fluid into the formation to deflect the trajectory of
the wellbore. trì
another embodiment. a 3D rotary steeruble system may be used. As such. it may
be
desire.ble torAace the LIND tool above the underreamer.
loom] :n
=,tdclition to the components shown in Figure 30 and described above, the
fewer portion 810 of the. BHA 886 may further include ono or more stabilvers
ancl;or
;-I.IND".; sub capable oi receiving etie or more LIND tools for
IO measuring
pan-mit:tem while drilling. Al least the lower portion 870 of the BHA 885 may
extend below the lower end of the liner 810 %,vhilà d'illing the liner
assembiy Hit() int() the
trifrriat.f
[001811 In the
embodiment of Figures 30-35, the setting sle.eve guard 801. the latch
840 of the running tool 825, and the latcn 8F32 of the second telescoping
joint 855 are
each fluid bypass assemblies 813. Figure 30A shows a fluid bypass assembly 813
capable or use as the se,Itine sleeve guar 801, latch 840, and'or latch 882.
i.-:ach
bypass assi?mhly 813 may ;oreprise one or more spokes 804 having erre or more
annuluses 806 therebetween for flowing fluid therethroJgh. The one or more
bypass
assemblies 813 allow drilling fluid to circulate during wellbore operations.
as described
20 below
loom] In
operation, the liner drilling assembly 800 is lowered into the formation to
form a welibore 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 tho drilling assembly 800 is preferably the earth removal
member
25 893. The motor 804 in the BHA 885 preferably provides the rotational
force to rotate
the earth renlovai member 893.
toolszl Figure 30 ShOW3 the liner drilling EISSeMily 800 in the run-in
position. 'Usually
the lower portion 870 of the BHA 885 extends beicm the liner 810 upon run-lit.
The
underrearner 892, in the embodiment shown, includes one or more cutting blades
that
30 extend past the outer dierneter 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 02874763 2014-12-15
((Mahon, therein. In alternative einbodiments which employ an expandable bit
lo drill
ahead of the liner 810. the expandable bit cutting blades extend past the
outer diameter
ef the liner 810 to drill ;ellbore 881 of sufficient diameter.
10018,1) Upon run-in of the ;iner assembly 800, the latching member 820 of
the lateh
:3 -- 840 :s radiate/ extended to releasably engerre the recess 828 in the
liner 810.
fv1oreover, the :etching member 88( is radially extended to engage the recess
888 in
the inner diameter of the liner 810 or the liner shoe 889). In his way, the
drill string
815 arid 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 arid 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 131-1A 870.
1001851 Du-ing oi the liner assembly 810. the teleeeepic joints 850,
85!., are
preferably extended at least pi-oniony to a iength A. .3ecouse ot 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 shearabie member 852 perform tee
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 shearabie connections.
1001661 While drilling into thc formation with the liner drilling assembly
800. drilling
fluid is preferably circulated. The port 883 in the circulating sub 800 is
initially closed
n0 on by the bail seat 861 within the recess 884 the inner wall of the
circuit:I:int) sub 800.
Drilling fluid is introduced into Ehe inner longitudinal bore of the cleil
string 815 from the
surface, and then flows thrcugh tne drill string 815 into and through one or
more
37
CA 02874763 2014-12-15
nozzies (not shown) forrned throutili the drill bit 890. Tee fluid filen flows
upwarci
around the lower portion 870 of the 81-IA 885, then the one or more bypass
assemblies
813 of the latches 840. 882 and the setting sleeve guard 801 allow fluid to
firm up
through the ;nner diameter of the liner 810 between the inner diameter of the
liner 810
b and the outer diameter of the drill string 815. Additionally, some fluid
may flow around
the outer ameter of 'ihelner 810 between the outer diameter c)f the FMK 810
and the
vvellbore 8131. Titus, the volume of fluid whieh may be circulated while
drilling is
iecreased clue to the multjple fluid paths (one fluid path between the
wellbore 881 and
the outer air:meter Of the liner 810. the ether 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 driliing assembly 800. In another
ernbociintent, this
system is not litniied to itliS One particular annular flow regime betweee the
outer
diameter of the liner 810 and the ,.eailbore 1381, but the system may employ
the same
equipment to achieve downward annular flow, as ciescribed above. Specifically,
this
16 system may involve USE.) of the sealing member 448 and the bypass member
445.
Noun Noe/ referring to Figure 31, when the underreamer 892 i.or other
earth
reinow)Imember 893) has reached the desired depth at wiNch it is desired to
ultimately
place the liner 810 in the wellbore 881 to case the weilbore 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 bail 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 881 (tilt?
ball seat 881 :s 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 trOfr, the recess 888 in the
liner 810, thus
releasing the releasable connection between the drill string 815 and the liner
810. The
:atc.hing member 886 is shown released from the liner shoe 88) in Figure 31.
laws? 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.
.11.1 ['he bail 876 is caugnt in the baffle 877 above the lower portion
1570 of the BHA 885.
Blowing the ball 876 through the ball seat 861 allows circulation thiough the
bore of the
circulating sub 860 again. as durint..-; run-in of the firer cirillieg
assembly 800.
38
CA 02874763 2014-12-15
1001891 A
downward load is then applied to the drill string 815 from the surface of the
%.,vellboro i381 to shear the shearable members 851 and 1352 so that the first
telescoping
joint 850 slides within the running tool 825 until it reaches a shoulder 841
or the running
tool 825 and the second telescopfng joint 855 slides Lvithin the first
telescoping joint 850
unlit 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 %Neither 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 dev.fnwarc.1 WO within the wellhore 881 in relation to the
lowermost end
to of the drill string 1315 (to just above the blades on the undetrearrief
8i2). The distaoces
beiween the shoulders 841. 842 and the initial locations of the telescoping I-
nee:bens
825, 850 f: 850. 850. 855 are predetermined prior to locating the linc:1*
driliì,ìa assemb.,y
800 *.vithin
foonatieh so that the telescoping of the teiesc;oping members 825, 850
and 850, 855 allows the liner 810 to rnove downward to a location proximate
the bottom
of the welibore 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 (SOO 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 wellhore 881. Because of the bypass assembi!es 81:3 which
exist in
the latches 840 and 882 as well as the setting sleeve guard 801, floid may be
circuiated
within ono or more annuluses 806 between one or tr:c.)re 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 aftor
1001901 Figure
34 shows the next step in the operation. A second bait 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 tho bore of the drill string 815 to provide sufficient
pressure within the
drill strife.; 815 to sei 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
3P
CA 02874763 2014-12-15
to grippingly engage the inner surface of the first casing 805 (see Figure
35). In an
alternate embodiment, tho liner hanger 820 may be expandable.
Norge! Once the liner 810 is hung off the first casing 005, pressure is
further
increased above the second ball 844 to etract the latching mumbe; 826 from
engagement with the inner surface: of the liner 810, thus rlisenjingiiig the
liner 8 le from
the drill oterig 015. The drill string 815 is now MOVeable I t.:.ative to tho
finer 810 to allow
retrieval thereof.
I001921 As depicted in Figure 35, pressure is then increased yet further
within the
bore of the drill string 815 so that the second ball 844 within the bell seal
861 forces the
bat' seat 361 to shift downward within the recess 884, thereby opening the
port 853 to
need flow and allowing fluid circulatior through the port 363. Fluid flow is
eow poesibie
Through file here of the drill string 815. out through the port 863. then up
andeir dc)wri
withir the annulus between the outer eiiameter of the cri.i string 815 and the
inner
diameter of :he liner 810. Figure 35 shoies 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 CEISCCJ welfbore 881.
1001931 An alternate embodiment of the present invention which allows for
subsequently casing a portion of the open hole wellbore which was previousiy
spanned
by at feast 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
drittir.g
wellbore with a liner having en 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 weilbore occupied oy
the BHA.
f001e4) 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 oi Figures 36-4,i which are substantially the same as components of
Figures 30-35 labolocl in the "800 series are labeled weh like numpers in the -
000"
series. 1µ1arrii.31y. the liner assembly 900; welbore 981: Vest cesine 905:
setting sleeve
$0 guard 901 end setting sleeve 902; sealing member 903; liner e10 and its
recosf; Fi26
therein, one or more gripping rnembers 921, liner hanger 920 anti its sloped
surtace
CA 02874763 2014-12-15
922. and liner shoe 989; drill string 915 including running tool 925. latch
940, recess
927, latchine member 926. ciiculating sub 960, one or more ports 903, recess
984, halt
seat 961. baffle 917, BEIA 985, MWD sub 996, rnotor )94, underreamer 992,
drill bit
990, earth removal member 993. and lower portion 970 (of BHA 985); anci balls
976
and 944 are :;tibstantially the same as the liner assembly 800, weilbore 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 360, ports 863, recess 884, ball seat 861, baffle 877, BHA
fl85, MWD
sub 895, motor 894. underreamer 892, drill bit 890, earth removal member 893.
lov,rer
portion 870. and balls 876 and 844 shown and described in relation to Figures
30-35.
[00195j io
latch 982 and itsreiatc.,c.i components inc!uding the latching member 98e
recess 987 in the latch 982, and recess 988 in the liner 910, ano Ole
operation of the
latch 982. are also similar to Me latch 882, recesses 887 and 888. and
latching member
13 886 shown and described in relation to Figures 30-35; however, the latch
982 ot
Figures 36-44 and its components may be located at a higher location aiong 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 35-44. The laten 982 is a secondary latcn.
[00196j in addition to the absence of the telescoping joints 850, 855 in
the
t.?.0 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 tength of the liner 910.
The
centralizing mernber 999 centralizes and stabilizes the drill string 915
relative to the
25 liner 910. 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 83.
as shown and described in retation to Figure 30A.
[001.9i) 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 desireci to oilimately
sot the liner
30 910, with only one ot the latches ce.g.. latch 940) engaging the
inner diameter of the
liner 910. 'The liner assembly 900 is drilled to the desired oeptn within the
formation,
preferably to a depth i.vhere at least a portion of the liner 910 is
overlapping at least a
41
CA 02874763 2014-12-15
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 linc:r 910
and the wellbore 981, but may also employ the same equipment ;is (lescribed
above to
;iclii 'v. naciditional dovinward annular flow path. Sp.:41;1ot*, this sysune
may
involve M01180 of the sealing member 448 and the bypass member 445.
[001981 Next, as shown in Figure 37, the first ball 976 is placed in tho
ball seat 961,
fluid pressure is increaseo, and the liner hanger 920 is actuateci to hang the
liner 910
on the first easing 905, as shown anti described in relation to Figures 30-35.
Fluid
pressure s increased further within the bore r.if the drill string 91;i so
that the latcninc
:,)erniter 926 is re.leased from the recess 028 in the liner 910. At this
pcint in trif:
eneration. the drill string 915 is moveable reiative to the liner 9'10 anti
61E) firs! ensile
205. Thon, just as shown and described in relation to Figures 30-Z.6 fluid
pressure is
increased yet further within the bore of the drill string 915 to force the
ball 976 into the
baffle 9/7, as shown in Figure 38, so that fluid may flow through the lower
end 970 of
the BHA 985 again.
1001991 ihe drill string 915 is then translated upward rotative 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 tha:
when
the latching member 988 engages the recess 928, the majority of the BHA 985 !s
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 weithore 981. In this
manner,
substantially all of the open hole wellbore may be cased by the liner 910.
1002o01 Oece the latching member 988 engages the recess 928, the gripping
rnembers 9 f the liner hanger 920 are released from their gripping
enuagerneni with
firtif c,rtsny 005 as shown irt Figure 40. The ;r1e..r driJJiìgassembiy Cf00
is now
i traristatable :dative lo the first f;aSing 905.
42
CA 02874763 2014-12-15
[00201] As shown ir Figure 41, the liner aSSkinibly a00 is then lowered
to the bottom
of the open hole wellbore 981. Referring now to Figure 42. a seeond ball 944
is next
introduced into the bore of the drill string 915 and stops in the hall seat
061, thus
preventing fluid flow therethrough. Increased fluid pressure above the second
ball 944
e sets the liner hanger 920 at a new location on the first casing 905, as
shown and
described in ;elation to Figures SO-35. The liner 910 :s now ;lung on the
first Casing
905 Zit its desired positior for lining the open hole welibore.
1002021 Figure 43 shows the next step in the operation. Aft' flanging the
liner 910
on the first eEiSing 905, the secondary latching mernoer eh8 Is released
(e.g., by
16 increased fluid pressure within the bore of the drill string 111 5 above
the ball 944) from
the recess 028 in the drier 910 so that the drill string 915 may be retrievect
from within
the liner 910. Ruiit pressure is then further increased 1.vithin the bore to
shift the bail
seat 961, thereby uncovering tne Cud port 963. Fluid circulation from the bore
of the
drill string i :5. then up and'or down through the inner diameter of the liner
910 outside
le the drill steng 915 is then possible while retrieving the drill siring
915 to the surface.
Figure 44 i;hu,.-vs the fluid port 963 uncovered.
(002031 The drill string 915 is then pulled up to the surface. the
liner 910
remains hung on the first casing 905. When the underreamer e92 reaches the
liner
910 upon pulling the drill string 915 up through the liner 910, the
underreamer 992
20 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
KT:111)0re 881, 981. The cementation process is a two-trip system for drilling
casing into
the weilbore and cementing the casing into the wellbore which avoids pumping
of
25 cement through the BHA 885, 985. which couid damage or rdn expensive
equipmero_
disposed within the BHA 835, 985 such as a iviVeD tool or mud motor.
[oonos) The embodiment of the cementation process ciepicted in Figures 45-49
iricluees 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
30 910 of Ficures 36-44, all of which are left in the wellbore 981 after
the drill string 915 is
removect from the weithere 981. The cementation prouess VI:hiCh is beiow
descnbe(1111
CA 02874763 2014-12-15
reinti011 to tne components of Figures 36-4,1 is equally applicable to the
ce:nentation 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, ;mess
828.
and liner 810 remain in the wellbore 881 subsequent to removal of the drill
string 815
from the liner 810.
(00206J lieferring to Figure 45, a cementing assembly 930 which is run
into the
casing 905, 805, selling sleeve 902, 802, and liner 91(), 810 includes a
tubing string
935 attached to a float valve sub 932. The tubing string 935 is preferably
minnected to
itfl tippOr end of the flea valve sub 932. At least a portion of tilt; tubieg
string 935
inGludes a eirculating sub 936 having one or more ports 934 w:thin a wall of
the
circulating sub 936 for communicating fluid from the inner bore of tl.te
tubing string 935
to the annulus bee..ee.ert the outer diameter of the tubing strirg 935 and tne
inner
diameter of the. liner 910. 810. Disposed within a recess 937 ().! the
ciiculating sub 936
is a hydraulic isolation sleeve 931 to selectively isolate the inner ciiameter
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
pc:it 93.1.
Nom! A further portion of the tubing string 935, which is ()Tolerably located
below
the circuiating sub 936 in the tubing string 935. is a sealing member setting
tool 938
anti 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 too! 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 98 are disposable within a recess 997 in the settng tool 939 when
inactivated, at shown in Figure 45.
(MOM .4`,t the. lower end of the tubing string 935 is the float
/.==11µre sub 932 tor
preventing backflu.v of cement upon removal of the tubing string 935 (see
below). The
Ci float valve sub 932 includes a longitudinal bore therothrough 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 940 permits cement to
flow
44
CA 02874763 2014-12-15
downward through the bore of the float valve sub 932 and into the wollbore
981, 881,
yet prevents fluid from flowing into the bore of the float valve sub 932 from
the wellboro
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
a end of tho float valve sub 932 when closed.
(00209J Disposed around the outer diameter of the float valve :::ub 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 been gipping
inii,,,mbers 941. 943.
[00210] In operation, tee cementing assembly 930 is 1owered into the
inner diameter
of the first cas:ng 905. 805. settir.g sleeve 902, 802, anti iner 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 veive 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 andror 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 vall/e sub 932 and
the inner
diameter of the liner 910. 810. Because the annulus between the liner 910, 810
end
The tubing, string 935 is now substantially sealed from fluid flow. fluid flow
through tne
tubing string 935 bore mest travel up the annulus between the outer diameter
of ihe
liner 910. 310 and the wellbore 981. 881.
[00211] 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 02874763 2014-12-15
seeing operation is then peri ormeri. as a physically alterable bonding
material,
preteratily eement 948, is :ntrodueek..I into the bore of the tubing string
935. The cement
948 is introduced into the tubing string 935, then the cement fluter, 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 desire.d height H.
a wiper
dart 99' is iowered info the bore el the tubing string 936 behind the cement
948. it
another embodiment, a ball may be used in place of a dart for the cementing
operation.
[002121 Figure
47 depicts the next step in the operation of the cementing process.
deo 991, upon reaching the hydraulic isolation sleeve 931, catches on the
sleeve 931 i.ind seals the inner bore of the tubing string .93f). Fluid
pressure on the
wipe; dart 9fcl cezeses ashear' rneenanisir of the 931 to
ffet L-1714.1 moves to
93 t !!oi.vri .:vitien the reeese 97. themby c=xv.qpnk, port
93.; 1.c. fiz..A Cow
theretnrough beu.veen tho bore of the tubing string 935 and the annulus
between ihe
inner diameter of the finer 910, 810 and the outer diameter of the tubing
string 935.
Tile wiper dart 991 travels further below the sleeve 931 within fin: Pore.
[00213j
Opening the ports 934 to allow circulating of fluid therethrough permits the
tubing string 935 to be re.rnoved trorr the liner 910. 810. Upward force is
applied to the
tubing suing 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 Haat valve tieb 932. the
one-way
valve 946 is elleasec.1 so that the biasing force causes tne one-way valve 946
to pivot
upward around its hinge 945 into the recess 933. At this point, the one-way
valve 948
prevents fluid such as cement from flowing upward into the bore of the liner
910. 810.
(002141 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
26 force. To radially extend the sealir,g member 903, 803 around an upper
portion of the
liner 910, 810 into sealing engagement with the inner diameter ot the first
casing 905.
805. the tubing string 935 is lowered onto the setting sleeve 1.";02, 602
after exiting the
setting sleele:; 902, 802 so that the setting members 996 .el the sealing
member 903,
803, prefurabiy by compression of the elastemeric seal or; the compression -
set sealing
11101Tible.r 803. 903. in alternate embodiments of the present invention, a
seal may oc
created by e different a)proach. 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 02874763 2014-12-15
metal seal or using an expandable tube clad with an elastomene seal on its
outer
%Dieu?.
1002151 Jhe
tubing string 935 is then removed from the welluore 981. 881 to leave
the liner 910. 810 set and sealed within the formation, as shown in Figure.
ele. The
5: eon
inonents within the float valve sub 932 are preferably cirillaolo {including
the sealing
member 942. so that a subsequent earth removal member :not shown; may drill
through the flout valve SUD 932 ard possibly further Into the formation to
tonn 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
aeclitional
deeing asseinbiy (which may optionaily include the same drill string 915. 815
IvNch was
removed from the ...xl:bore) similar to the dritiing assembly 900, 800 sho?in
and
described in relation to Figures 30-44, tne liner drilNig asseetbly capable of
casing n
fuither depth of a wellbore in the formation. An additional cerneniieg
OrAgalioti Ina), be
pertormed en the additional liner !eft within the wet:bore. The process may be
repeated
as desired any number of times to complete the wellbore to total ciepth within
the
formation.
[00216] Aspects of the present invention also orovicie 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 (381 and set therein, preferably by a
physically
alterable bonding rnaterial such as cement. In the alternative. the easing 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 ,etting and/or rotating the first
casing 605 to
form the weilbore 681.
100217) Disposed within the first casing 605 is a second easing 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 mernbers 621, preferably slips. The hanger 620 further
includes a
sloped surliwe 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
a0 (305.
47
CA 02874763 2014-12-15
[002181 1.1:011110C1011 to an outer sunaiie of a lower end ef the liner
610 is one or mole
sealing members 603 oe its Miter diarneter. The sealing members 603 preferably
being one or more paokers and even more preferably being one or more
inflatable
pacKers constructed of an elastornoric :nateriai. The sealing members 603
include one
or more inflation ports 612 in selectively fluid communication with tho
interior of trie liner
610. The sealing member 003 may he actuated to seal off an annulus between
tile,
liner 610 are: the .,,vollbere 681.
1002191 The liner 610 has a drill string 615. which may also be termed a
circulating
string. disposed substantially coaxialiy therein and releasably connected
thereto. The
Orin string 615 is a generally tubular-shaped body 'flaying a longitudinal
bore
therethrough. The drill string 615 arc the liner 610 form a liner essembiy
600. Figure
50 shows the liner assernbl.; e00 &lied to the liner i.31. 0 setting depth
e4ithin the
(00220) The drill string 615 includes a running tool 625 at its upper eild
arld a BHA
;385 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 latbh
640. The
latch 6:10 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
tecess 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 615 to translate together while connected.
[00221) Preferably, the running tool comprises a fluid bypass assembly
613. Figure
50A Sil0V.'S 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 606 therebetween for Mowing fluid therethrough. The one ot more
bypass
assemblies 613 Mow drilling fluid to circulate through the a.noulus between
the liner
and the drAt string during the wellbore operations, as described below. 11
should also
bc nctcrl that aspects of the drilling systems discussed herein are applicable
lo the
present einbcdiment and other embodiments. For example, the drilling system
shown
F!gtIril 50 may further include a ftuid bypass assembly having one or more
bypass
pens In in.s respect, fluid frorn the drill string 615 Mily be diverted 11110
the arinuiar
t;po but,.=k:en the liner 610 and :he wellbore 681. Adaitiona!Ily. the
dr!Ilinj system may
4P.
CA 02874763 2014-12-15
employ n sealing member 448 to seal otf an annular area between the existing
casing
and the !mfg.
1002221 The BHA 685 is adapted to perform several functions during the
drilling of the
liner assembiy 600. Specifically, the BHA 685 ;nclucles a measuring-while-
drilling
i-rowrr) sub 096 capable of :ocating one er more rneasueng toots therein for
measuring formation parameters. A motor 694. preferably a mud motor, is aiso
disposed within the BHA 685 above an earth removal member 693, which is
preferably
a cutting apparatus. As shovin in Figures 50-59, the earth removal member 693
includes an enderrearner 692 located above a drill bit 690. Because many of
the
components in Figure 50 are substantially the same as tee components shown and
deseribed in efgure 30, the above deseeption and operation of the similar
components
k.vitir raspy:Am Figure 3!) appiy equally to the uomponents of Figure, 50.
1002231 Tee BHA 685 further ircludes a first circulating sub 630. Within
an inner.
longitudinal ii.)re of the first eircutating sub 630 is a ball seat 631. A
wail 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 t$33.
f002241 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.
[00225) The BHA further includes a second circulating sub 652 and a third
circulating
sub 653 disposed above the second sealing member 640. Eacn of the circulating
subs
(352, 653 has a ball seat 654, 655 disposed therein and one or more pors 656,
657
iormed through a wail of the circulating sub 652. 653. The ball seat 654, 655
is sliclably
ciisposed and moveable relative to the ports 656. 657 te selecfeely open and
etose the
ports 656, 657. A pod sleeve 658, 659 enclosing the ports 556. 657 is mei/ably
disposect on lee outer surface of the ceculating sub 6b2. 653. The port sleeve
658, 659
may be actuated by fluid flow through the port 656, 057. ln 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 02874763 2014-12-15
(00226)
TheI3HA also includes a packoff sub 660. The pacleAf sub 660 comprises a
locator member 665 for engaging the liner 610 to ini.licate position.
Preferably, the
locator member 665 comprises ono er more ;etch flogs 666 adepted to engage a
profile
61i 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 (frill string 615. The ball
scat 670
may be actueted to open the one or more setting perts 672 eisposed through a
wall of
the paukuif sub 660. One or more seals 67,1 are disposed on either side of the
seteng
ports 672. When the latch dogs 666 engage the profile 617. the setting pints
672 are
placed in aiienment with the inflation port 612 of the casino sealing meniber
603.
In
Additionally. the seals 674 on either of the setting ports 672 form an
e,nciosed area for
!Suitt commueication oetween the setting ports 672 and the inflation ports
612.
Preferaby,he packoff sub 660 of tne BHA 685 is disposed. the 10Vier end of the
ii!iesT
610 while driirig the liner assembly 600 into :he formation. .fe this end, the
peekoff
sub 660 win not obstruct `j-Ie annular space between the Once diameter of the
title, 610
15 kind
the euter diameter el the drill string 615, thereby allowing for cuttings from
the
drilling process to be circulated up through the inside oí the liner ;310 and
the past the
running tool 625.
W2271 In
operation, the liner dniiing assembly 600 Is towered into the formation to
form a wellbore 681. During run-in of the liner assembly 600, the :etch 640 is
radially
2o extended to selectively engage the recess in the liner 610. In this
1Nay, the drill string
615 and the litter 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
atter
reaching the uesinxi depth.
25 (00228] 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 oft 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 (jail string 615 into and through one or more nozzles not shown)
of the drill
30 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 throuca the
annulus
between the drill string arid the liner anci between the spokes of the field
byuass
assembly ;31Ze Additienaliy, a small amount of 'fluid may flow between the
liner 610 and
CA 02874763 2014-12-15
the wellboue 681. ThIJS, the volume of fluid which may be circulated while
drilling is
inereased due to the multiple fluid paths (one fluid path between t.ne
welltx)re 681 and
the outer diameter of the liner 610, the other iluid 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 rioted that
aspects ot
the present invention are equally applicable to annular circulation systems.
as is known
to a person oi 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 (frilling system shown in Figure 50 may further
include.
a fluid bypass assembly having one or more bypass ports. it: this r ()spoof.
fluid from
the. drill stripg 615 rhay be diverted the.'
annular space between the liner Me and
the kti el!bot r; 155! . Additionally. the erittirig systern may ernp;oy
sealipg member 44N
to seal off an annular area belween the existing casing any; the liner,
1002291
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.
j00230)
Thereafter, more pressure is applied to shift the bail seat 631 of the first
240
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.
1002311 After
the running tool is released, the drill string 616 is raised until the latch
dogs 666 of the locating member 665 engage the profile 617 on the liner 610.
The
locator member 665 onSUres that the setting port 672 is aligned witn the
inflation port
612 ot ihe casing sealing member 603, and that the seals 674 are located on
both
sides rit t'ne ports 672. 612.
toozsl In Figure 53. a. second ll 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, 663 and the secord sealing
member
640, it trips the isolation sleeves ot these components. As a result, the
components
652, 653, 640 are ready to sense any applied pressure differential across
their
54
CA 02874763 2014-12-15
WSpl:t;tiVe; activation devices. In the embociimeet shown, the ball seats 645.
654, 6b5
have ueen 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
1;56. 657.
1002331 Thereafter. pressure is increased to inflate the second sealing
member 640.
The inflated sealing member 64d blocks fluid commudeation in the annulus
between
the drill siring 615 end the wellbore ;381. Then, pressure is increased
further to shift the
poit sleeve 658 of the second circutating sub 652 to the open position.
Because of the
inflated second sealing rember 640. fluid exiting the open port 656 is
circulated up the
annulus.
to0234j ;ri :,-Inother aspect, the second sealing member 640 may be used
as a tiow
out preventor during run in of the drill string assembly into the nole on an
offshore
dnIfing vessel or platform. if the i.ve:1 shoal() kick, which is an influx of
fluid. such as
gas, corniog into the well bore in an uncontrolled fashion. during the running
in of the
drilling assembly through the blow-out preventor and :he !leer :s physically
located in
the weventor and the inner diameter of the liner annulus between the drill
string is open
to flow, then tne blow-out preventer 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
0 the liner hanger. In this respect. the second sealing member 640 may seal
off the
annulus between the driii string and the liner. After the seconci sealing
member 640 's
set, the rupture dart will rupture and allow iluiti to by-pass te the teottem
of the drill
string. This will allow the pumping of kili fluid, to kill tho kick and regain
control of the
veil. By rotation of the drilling assembly after the woll is urrler 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.
Loves) A first dart 641 is released from surface, as shown in Figure 64.
Prelerabiy,
the first dart eel is adapted to wipe the inner surface of the driii string
615 as it travels
cown the drill string 615. in one embodiment, the first dart ;341 IS traiibC
by a FAN*
polymer sug, a scavenger slurry, the cement, aed another F;Ma polymer slug.
The
dart 641 is displaced until it !antis in a receiving profile below ire port
65i of tit thrd
,o-roulatirly sub 653, thereby sealing off the driil string 610 at the
profile.
52
CA 02874763 2014-12-15
f00236) In
Hgure 55, pressure Li inereased to shift pee sleeve 659 of the third
eirculating sub 653 to the open position. Fluid behind the filst dart 641 is
displaced
through the opened port 657 and up the annulus between the liner 615 and trio
wellbore 681.
1002371 In 1-
igure 56, a second dart 642 is shown chasing the slurry to bottom. As
the second dart passes the ball seat 670 of the packolf 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 dell stnng 615. The second dart 642 will eventually and in a profile
above the
ports 057 of tile third eirculatrng sub 653.
[002381 Alter the second dart 642 .74niis in the profile, p:essure is
increased e.) inflate.
thc casing scaling member 603. As shrew, in Figure 57, the erliatet.1 easing
sealing
inernbet 603 seals o;í the annulus between the liner 610 aeci the weitbo:e
e81. in this
respect. the cement is held in place by the casing sealing member 603 and
cannot te
tube back into the liner 610.
(002391 Thereafter, drill string 615 is rotated to deflate and reiease 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. V,Inen the setting ports 672 of the peekoif
sub 660
clears the liner top, fluid can equalize through the setting ports 672 trom
the (frill string
615 to the tirst 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 tor fluid
equalization through
circulating sub 653.
1002401 Aspects of the present invention also provide apparatus and methods
for
effectively increasing the carrying capacity of the circulating fluid.
[meet] Figure 60 is a section view of a welibore 1300. For clarity, ;he
wellbore 1300
is divided into an upper wellbore 1300A and a lower wellbore 13008. The upper
wellbere i300p. is lined with casing 1310, arid an anuular area between the
casing
1310 and the upper wellbore 1300A is filled with cement 1315 to strengthen and
isolate
the upper weilbore 1300A from the surrounding earth. The lower wellbore 1300B
comprises the newly formed section as the drilling operation progresses.
53
CA 02874763 2014-12-15
[002,121
Coaxially disposed in the wellbore 1300 is a drilling assembly. The drilling
assembly rnay include a work string 1320, a running tool 1330, and a casing
string
1350. The running tool 1330 may be used to couple the ir.ork string 1320 to
the casing
string 1350. Preferably. the running tool 1330 may ;JO
tttatec1 lo release the casing
string 1:350 alter the !ewer welibore 1300B is foirraiid and the casing string
1350 is
si !cured.
[002431 As illustrated, a drill bit 1325 is disposed at the lower end of
casino string
1350. Generaily. the lower wellbore 1300B is formed as the driil bit 1325 is
rotated and
urged axially downwarc. The drill bit 1325 may be rotated by a mud motor not
shown)
located in the casing string 1350 proximate the drill bit 1323. Alternatively,
the drill bit
1325 rnay ae rotating by rotating the casing string 1350. in either case. the
drill nit
1325 ;s altaChtiel tO the casing string 1350 Mat iÞsoi.israeuentiv rernan
clo,oaindia to
line the lower a:ellbore 1300B. As such, there s no oppuilurity to retrieve
the (Mil bit
1325 in the aenventional manner. In this respect. call bits made of (killable
material,
two-pieca driil nits 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 1360, and exits the
drill bit 1325.
The fluid typically provides lubrication tor the drill bit 1325 as the lower
wellbore 13008
is formed. Thereafter, the fluid combines with other wellbore fluid to
transport cuttings
and or.her wellbore debris out of the wellbore 1300. As illustrated with arrow
1370, the
fluid initially travels upward through a smalier annular area 1315 former:
between the
outer diameter of the casing string 1350 and the lower weilbore 13003. Because
of the
smaller annuiar area 1373, the fluid travets at a high annuiar velocity.
1002451 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 fransitions 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 ar around the
upper end ei the
casing atring 1350.
54
CA 02874763 2014-12-15
1802461 Tu
aiurease the annular velocity, a flow zipparales 1400 ;s 1./SUd 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 lirav apparatus
1400
attached to the work string 1320. any number of flow apparatus may be coupled
to the
..vorli 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 uncierstood,
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 Fgure 60 or twiner up the work
string
t 0 320. Furthermore, the flow apparatus 1400 rnay be disposed the
slring 1350
or below the easing, string 1350. so !any as the lower weilbore 13006 will not
be eroded
or over preseurized by the. circulating Nice
1002471 Ili
another aspect, the flow apparatus may comprise a flow operated external
pump to increase the annular velocity. The flow operated pump would take
energy (IP
15 the flow, stream being pumped down the tubular assembly instead of
diverting fluid off
!he flow stream e.g.. the fluid pressure in the flow stream above the drive
mechanism of
the external pump would be higher tnan the fluid pressure in the flow stream
below the
thive mechaniam. The external purnp would reduce the equivalent circulating
density
of the fluid in the annulus 1340 helping to lift the fluid and cuttings to the
surface. The
20 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, rnud pulse, hard
wring,
25 hydraulic line. or any manner known to a person of ordinary skill in the
art. In a further
aspect, ii1:3 drill string may be equipped with one or more of a fluid
diverting flow
apparatus, a Hoy.; operated external pump, or combinations thereof.
feee.481 One or more pelts 1415 in the flow apparatue 1400 may be modified to
control the percentage of flow that passes to drill bit 1325 and the
percentage of flow
30 that is diverted to the larger annular area 1340. The parts 1415 may
also be oriented in
art upward ;:lirect!on to direct the fluid flow up the larger annular area
1340, thereby
encouraging the drill cuttings and debris out of the wellbore 1300.
rerthermore.
=
CA 02874763 2014-12-15
porte 1415 may be systematically opened and closed as required tu modify the
circiilation system or to allow operation of a pressure controlled downhole
device.
1002491 The flow apparatus 1400 is arranged to divert a predetermined
amount of
circulating fluid from the flow path down the -,,vork string 1320. The
diverted how. as
e &stetted by arrow 1360, is subsequently combined with the fluid traveling
upward
Ihroutiii the larger annular area 1340. In this manner, the artneler velocity
0; fluid i the
iarger 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 re,spect. damage or erosior to the lower e.reilbore 130013 by
the fluid
traveling up the anr u!ar area 1'375 is ininirriziA.
maw Figure 61 e.; a eross-sectional view iilustratino another
embodiment of a
aesembly having an auxiliary flow tube 1405 partially fermod in tha casing
sinng
1f; 1350. As illustrated with arrotv 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 wt.:Hoare 1300.
(002511 As
illustrated with arrow 1370, the fiuid travels at a high annular
velocity upward through a portion of the smailer annular area 1375 formed
between t'ne
outer diameter of the casing siring 1350 anci 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 1ube 1405.
In one
embodiment, the auxiliary flow tube 1405 may be systematically opened and
closed as
desired, to modify the circulation system or 10 allow operation et a pressure
controlled
dt/WIli1010 device. Preferably, the auxiliary flow tube 1,405 is constructed
and arranged
to remove and redirect a poem: of the high annular veloiety hod traveling up
the
smaller annular area 1375. By diverting a portion of high annuiar velocity
fluid in tne
3e smaller annular area 1375 to the larger annuiar area 1340, the auxiliary
flow tube 1405
intxceses the annular vet0Oity of the fluid traveling up Vie larger anrufar
araa 1340. In
this rnannor, the carrying capacity et the fluid is increases. In addition.
the anntiar
56
CA 02874763 2014-12-15
velocity uf the fluid traveling up the smaller annular area 1:375 is rodueed,
thereby
minimizing erosion or pressure damage in the lower weilbore 13006 by tho fluid
traveling up the annular area 1375. Although Figure 61 shows one auxiliary
fiow 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 Vow tube 1405 may be disposed on lite easing
string /350 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.
einzezi Figure 62
is a cross-sectional view illustrating anothie embodiment al a
drilling assembly having a main flow tube 1420 formed in the casing string
1350. In this
emboeinient, 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 drift
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 annulat area
1375 is
reduced. thereby minimizing erosion or pressure damage in the lower wellbore
130013
by the fluid traveling up the annular area 1375.
1002531 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 flot.v 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. AdeiLonally, a portion
of the
57
CA 02874763 2014-12-15
nigh velocity fluid traveling up tho smaller annular area 1375 may be
oommunicated
thruunh the auxiliary flow tube 1405 into the larger annular arca 1340.
[0025,3] Figuro
134 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 tu the
drill
e hi! 1325. In the embodiment shown, the flow ;apparatus 1400 is
disposoe on the woi k
wing 1320. or the main flow tube 1420 is formeu 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. Addit:onally, it :s within the scope of this irwenton to employ a number
of flovti
apparatus. In this embodiment, a portion of the fluid pumped through the work
string
1320 may be divertc:d through the flow apparatus 1400 .nio the larger annular
area
:340.r portfon of ltq: high velocity fluid traveling up tt;e fifftzliter
aren 13/5 way be communicated through the main flow tube '142.0 into the
larger
Unfluial area 134Ø
I i) (00255] The
operator may selectively open and close the flow apparatus 1400 or the
main flow tube 1420. individually or collectively, to modify the f_trculation
system. For
example, nn uporalor may completely open lit low apparatus 1400 and partially
close
the main flow tube 1420, thereby injecting circulating fluid in an upper
portion ot !ne
larger annular area 1340 while maintaining a high annular velocity fluid
traveling up the
smaller annular area 1375. In the same fas'nion, the opera:or may partiafly
dose 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
Qontemplateci 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
modificatien to the circulation system. Adciitionally, the flow apparatus 1400
and Tie
main flow tut o 1420 may he hydraufically opcnod or cioscd oy control lines
;not shown'
or by other methods well known in the art.
(00255] in operation, the driiling assembly having a work string 1320, a
running tool
1330, and a casing string 1350 with a drill bit 1325 disposed at a lover end
thereof s
inserted into an upper wellbore 1300A. Subsequently, the casing string 1350
and the
drill bit 1325 aro rotated and urged axially downward to form the lower
wellbore 1300B.
58
CA 02874763 2014-12-15
At are same tune, circulating fluid or nuc ì circulated to facilitate the
drilling process.
The fluid provides lubrication tor the rotating drill bit 1325 and carries the
cuttings up to
surface.
1002571 During circulation, a portion of the fluid pumped through the
work siring 1320
3 may he diverted thrortgh the flow apparatus 1400 into the lamer 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 IVO into the larger
annular
area 1340. In this respect, diverted fluid from the flow apparatus 1400 and
the main
!Iota tube 1420 increases the annular velocity of the larger annular area
1340.
Additionally, annular velocity uf the fluid in the smaller annular area 1375
re reduced. in
this manner. the carry-mg capacity of the circulating fluid sinc.reased, and
tee
ce4eiveleat circulating density at the bottom et thel.ecilbore 1. 3(0B is
reouced.
(002581 The methods and apparatus of the present invention are usable
i.vitit
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 cane can then be urged upwards mechanically. by fluid pressure. or
a
?0 combination thereof to enlarge the entire casing string to an internal
diaineter 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 weilbore is formed. After completion of the
wellbore. the
fluid passageways are selectively closed. Thereafter, fluid is pressurized
against the
25 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 lhe bit. In this manner,
the casing
expanded Mid its diameter enlarged in a bottom up fashion.
(0025PI P. further alternate embodiment of the present invention involves
accomplishing a nudging operation To directionally drill a casino 'in into
the formation
30 and expandieg the casing 740 in a single run of the casing 740 into the
formation, as
show: 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 02874763 2014-12-15
tOrMati011. Figures ti5 show a diverting apparatus 710, ineiticling casing
740= tin earth
removal member or cutting apparatus 750, one or 1110/0 fluid deflectors 775.
and a
landing aeat 745.
[002601 Additional components of tile embodimeat of Figures 65 and 66
include an
expanaion tool 742 capable t)f. radially expanding the casing 740, preferably
an
expansion cone; a latching dart 781.3; and a dart seat 782. The expansion cone
742
may nave a smaller outer ciiarneter at its upper end than at its lower end,
and preferably
slopes radially outward from the upper end to the lames end. The expansion
cone. 742
may be mechanically andior hydraulically actuated. The latchinct earl 786 and
dart seat
782 are used in a cementing operation.
j00261) fri operation. the diverting apparatus 710 is lowore-n into the
weilbere with the
expansion Gono 742 located therein by alternately jetting ardor rotating iiie
casing 740.
The diverting apparatus 710 is preferably lowered into the '..vellbore by
ft:Aging 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
wellboro.
Stoking may also be utilized to keep track of the location of the fluid
cieflectorfs) 775.
(002621 Once the location of the fluid deflector(s) 775 \-=.,ithiri the
,Nellbore is
determined, the casing 740 is rotated if necessary to aim the fluid
defiector(s) 775 in
I) the desired direction in which to detect the casing 740. Fluid is ther
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 no :he formation.
When
desired, the casing 740 is rotated, forcing the casing 740 to follow the
cavity in the
iormation. The locating and aiming of the fluid dellectona) 775, flowing 01
fluid through
the tiuiti detlectors) 775, and further jetting and/or rotating :he casing 740
into the
formation may be repeated as desired to cause the casing 740 deflect the
wellbore in
ale desired chreciion within the formation.
[00263] r.'et. a running tool 725 is introduced into :he casing 740. A
physically
alterable bonding material, preferably cement, is pumped through the running
too! 725.
preferably aii inner string. Cement is flowed from the surface into he casing
140. out
the fluid cieflector(s) 775, and up through the annulus Oetweer; the casing
740 and :he
CA 02874763 2014-12-15
wellbore. When the desinx1 amount of cement has been pumped, the dart 786 is
introduced into the inner string 726. The dart 786 lands irld seals on the
dart seat 782.
'the dad 7116 stops flow from exitin!.3 past the dart seat, thus forming a
fluid-tight seal.
Pressure t=ipplied throu9h the inner string 723 may help urga the expansion
cone i42
up to expand the casing 740. In addition to or in lieu of the pressure through
the inner
siting 72. mechanical pustirìg on the inner string 725 ho!ps ;Age 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
u seat 782, preferably by a latching mechanism.
1002651 1-ho
runninq tool 725 rnitY be any type of fottii-Nui tool. Pieterably. the
ui the expansion cone 742
threadedly or tater; engagirg iloitgituuitia
boro through the expansion cone 42 with a lower enn of the running too. Z.
Fite
running tool 726 is the mechanically pulled up to the surface through the
casing 740,
15 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 rotative to the casing 740, the expansion cone 742 pushes against
the
2u interior surface of the casing 740. thereby radially expanding the
casing 740 as the
expansOn cone 742 travels upwardly toward the surface. 'thus. the casing 740
is
expanded to a larger internal diameter along :ts length as :he expansion cone
742 is
etrieVild to the surface.
(002661 Proferably, expansion of the casing 740 is performed prior to the
cement
25 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 casino 740 in the
formation.
,o.ithough the above operation was described in relation to cementing the
casing 740
within the =otellboro, expansion of the casing 740 by the expansion cone 742
in the
30 method des(.:nbed may e;so be performed 'thle11 the casing 740 is set
WithIn trio
vellbore in a flannel other than by cement.
61
CA 02874763 2014-12-15
[00267) The
cutting apparatus 760 may be drilled through by a subsequent Gutting
structure (possibly attached to a subsequent casing) or may be retrieved from
the
vvellbore, depending on the type of cutting structure 750 utilized (e.g.,
expan(iable,
drillable, or bi-center bit). Regardless of whether the cutting structure 750
is retrievable
or drillable. the subsequent casing tray he lowered through the casing 740 and
drilled
flYthii.,1" 'VIA within the fermaton. The subsequent c:a.tItinti may
optionally be
cemented witMri the lwelibore. The process may Lie repeater; wilt( additional
easir9
strings
[002681 The
present invention provides methods anti apparatus whereby drill string
:nay be used as casing, and the drill string may be cemented ir place without
using the
....I'M bit mod passages to flow the cement to the annulus bemeen the drill
string and the
borenole. Sioiectiveiy openable passages are localec in the drii string to
alith%, cement
to flow therethrough to cement the drill string in place ir the borehole after
the well has
been completed.
[00269) Rererring initially to Figure 67, tnere is shown at the bottom of a
borehole.
1020 the terminal end portion of a prior art tlrill string 1010. having a
float suu 10115
connected to the distal end of a length of drill pipe 1018, and having an
earth removai
member. prefo.rably a &id bit /012, positioned on the terminai end 1014 et tne
Hoar sub
7016. 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 siring 1010 is a float
collar 1022.
which is tixced in position within float sub 101t3. and which is used to
prevent backflow of
cenienting solution injected into the annulus 1024 between the dril! suing
1010 lino the
borehole 1020 back up the hollow region 1626 in the Ohl) sinrg 1010. It is to
be
oederstoori that the float collar 1022 is shown in Figure 67 for ease of
illustration. and it
is riot positioned within float sub during drilling operations, and thus thud
is free to flow
through the float sub 1016 and thence onward to the drill bit 1012. when tioat
coiiar
36 W22 is not located therein.
(002101 Drill bit 1012 is turned, about the axis of drill string 1010 by
the rotation of the
drill suing 1010 at the upper end there/of (not shown?, to further drill the
borehole 1020
62
CA 02874763 2014-12-15
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 pessagenn 1028 in the bit
1012, whence it fiows upwardly through the
annulus 102-1 between the drill string 1010 and the valt of the borehole 1020
to the
surface location. When tile dilling operation is completed, water may be
flowed down
the hol;ok.,:. region 1026 to flush out ,ernaining mud anu thence returnee to
the surface
through annulus 1024, and a physically alterable bonding material such at;
cement is
then flowed (town through the hollow region 1026 arid thus into the annulus
1024 to
forrn 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
horow. portion of the drill string 101C1 and latched into float sub 1016.
%.vhich
thus pnrivides ;It sealing niednanisrn to prevent uncured cement
annulut: 10.4trou
throuoh oril1bil tul2 and thus into hollow nigien 1025 of chili SZTing
ft collar 1f.)22 may also include central passage t 029 therethrough, the
peeing of
whicn is controlled by a valve 1030, such that cement may stiil be injected
into the
annulus 1024 after float collar 1022 is in place, but the valve 1030 will
close if cement
attetnpts to pass from the annulus 1024 and back into the 0611 string 1010.
Alter
sufficient cement is flowed down the drill string 101(1, valve 1030 prevents
cement from
iiowing back up the bore of the drill string 1010 while the oef130/11 cures.
:n the event
2) cement leaks past vaNe 1030, wiper plugs 1034. 1032 are also positioned
in the hollow
iegion 102i3 of the drill string to physically block fluids passing upwardly
in drill string
1010.
1002711
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 hollo..v region 1026
z.lnd
annulus 1024, atter the mud passages 1028 of the dral bii 012 are seleetivcly
closed-
off from communication with hollow region 1026. '.hereby COSLIting that cement
may tie
redirected from the drill bit passages 1028 on its way to annulus 1024.
[002721
Referring still to Figures 68 and 69, drill bit 1012 lnciudes 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
63
CA 02874763 2014-12-15
and an interior end 111,1, the interior oncls 1114 thereui Joining !fl
COMMUnieitti011 Viith a
central aperture 1115 preferabiy configured to include a generally spherical
manifold
1116 roving 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 trom the surface:. Extending from the manifold 1116 in the
direction of
the hollow passage 1026 in (JO string 1010 is a reduced cross section, as
eurnpared to
the width of hollow region 102t3, throat region 1120, through a ball
1122 (Figure
69 only) can be selectively provided Bali 1122 is sized such that its
spherical diameter
is the same as, or substantially the same as. that of Erie spheccal neat i
;18. such that
when bal ; 1122 is caged into contact with spherical seat 1118. the eitorior
ends of the
passages 1028 will be sealed such that fluids in the hollow region cannot pass
through
lite 11111 bit 1012 to e.nter annulus 1024. Bali 1122 is preferably
manufactured of an
k.lastonIcric or other conformable. and easily miliee or driiiou. materiai,
such that it can
deform slightly to ensure coverage over all drill bit passages 1028 When
located in
f; manifold 1116.
(00273j Drill
bit 1012 is connected to the drill string 1100 through a threacieci, or office
such connection, to the end of the float sub 1016. Float sub 1016 is
configured to have
art :reel-nal float shoe 1151 received :n the inner bore thereof, such that a
float collar
1022 as shown in Figures 67 and 70, is selectively engageabie therewith as. or
atter,
the eementing 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
fixect. Within central bore 1124 is provided a float shoe locking region, to
enable a
2.5 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 cylindrica! latching bore 1136. Centrai bore 1124
communicates,
at the lower terminal end 1132 c.)f !bat sub 1016. with a manifold )116. and,
Wither
111Ciiid4715 tapered guiding region 1134 opening into a receiving bore 1138
terminating
'JO le a latching Hp 1140 extending as a hump. semicircular :n crous
St;Cii011 exlendinn
inwardly irto receiving central bore 1138 about its circumference. The lloal
shoe -.151
portion of float sub 1016 may be provided by molding or machining a plastic.
cement, kg
6 4
CA 02874763 2014-12-15
otherwise easil / machined material, and press-titting, molding in place, or
otherwise
securing this tc.itm into the tubular body of the float sub 1016.
(002741 The !ewer end of float sub :0;6 is specifically configured to
enable redirect of
fluids passing 1.10Wil the chili string 1100 from tile passages 1026 itt the
iinfl bit 1012 into
alternative eement passages 1158 specificatly configured for passage of
ceinent
there:through to enable cementing of the drill string 1010 ìr' place in the
borehole 1020.
"rho 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
:he annulus 1024. In this embodiment. the port collar 1102 is eonfiguied in
inelude
tlt.ef;rai pis3oh therewith. and the remainder of the port col!at 1 LP. in
,:;tinjurti-ttc:;t1
the Liody of the float sub 1016.. forms i.: caeity 1104 eiali preSS:,NA-
Ai
:he piston portion of the port =-;ollar !102 to fiNCIF, tram a position
blocking ihe cement
passages 1153 to a position in which the cement passages ;158 form a f;uid
aassa(Jeway from the hollow region 1026 of drill string 1010 to annulus 1024.
To
eriab/e 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 e&ch extencis (mon face 1150 to
the full
Outer diameter of the float sub 1016. and further includes a plurality of pin
receiving
apertures 11f54 extending therein. Face 1150 extends. hern luta 1152, to a
tapered
wall 1155 which ends at a second recessed, again gene.iraily right Cit-Cu!zir,
face 1156,
through which a plurality of cement passage bores 1156 extend into
communication
with hollow region 1026. Second recessed face 1156 ends tt an additional
tapered
wall 1169, which terminates at a generally right, circular cylindrical port
collar lace
1159.
100275j Disposed over this plurality of faces 1150, 1156, 1169 and tapered
walls
1155. 1459 is the port collar 1102. Port collar 1102 is gerierally configured
as a
doglegged sleeve, and thus includes a tubular body ii60 having a first and
1162
including a first seai annulus :164 in the inner face 1166 therc.4of adjacent
the first cad
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.
Fach (if sea! annuli 1164, 1172 have a seal. such as an o-ring seal, located
therein.
such that he inner face of such seai sealingly engages with the corresponding
surface
CA 02874763 2014-12-15
of the i(AVOt tin 11 of float sub 1016, i.e.. sea! 1164 contacts r.tgainst
lace 1150, and seal
1172 contacts port collar tace 1159, and the inner surface soalingly engages
the
respective annuli 1164, 1112 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
1109.
Preferably, t..A.fal 1104 is larger than seal 1172 to form a differential area
for pressure to
act Lso. ArldiVonaily, a plurality of pin holes 1174 ire provided throtigh
Ýhe 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 10
16. Thus.
the port collar 1102 both forms a seal between the bores 1158 and the annulus
1024
to and is secured against undesired movement on the float sub 1016 by pins
1/78.
Additionally, the dogleg portion 1168 forms an annular piston such that. upon
pressurization of the piston cavity 1104. it will cause poi: collar 1102 to
skit: Wong the
outer surrace of float suu 016 an':; thereby open corrrnumui-cion ,)i passages
?
With. ;Annulus 1024.
1;3 1002761 Referring to Figuies 68 and (39, the opiaT:tion u; port
collar 1 l 02
tiornonstrcated as between the closed position of i-igure 68 and ihe open
position ot
Figure 69. In the position of the port coilar 1102 shown in Figure 68,
drilling mud
flowing down the hoilow portion 1026 of the drill string passes through the
bore 1124 ot
float sub 1016, thence into manifold 1116 of drill bit 1012 whence it passes
through
passages 1028 therein arid into annulus 1024 where it is returned to :he
surface. This,
the port collar 1102 position of Figure 68 enables traditional flow ot fluids
through the
passac,tos 1028 in the dri1l bit 1012, such as during drilling operations. To
initiate
cementing operations, water may be ffowed down the hol:ow portion 1026 ot
drill string,
and thence through float sub 1016 and drill bit 1012, to flush remaining ;uose
mud from
25 the drill string components and the annulus 1024. Then, cement will be
flowed clown
the hollow portion 1026 to be flowed into, and cement the cid!! string 1010
within, the
annulus 1024. To enable diversion of the cement to cement passages 1158, and
thus
prevent nerr.ent flow through the drill bit passages 1028, ball 1122 is
inserted into the
hollosõ.: portion not shown) of drill string 1010 al the surface :oeation,
jpst before or just
..-;ement ;s being t!owed dovm the hollow region =:026. !I being understood tl-
at
cement a or slurry form is flowed down the hollow portion 1026
immediately
over another f!uici, such as wazer or mud, already therein and ;n i annulus
1024. bah
1122 is thus carried down the hollow portion 1026, through tho bore 1124 of
float sub
66
CA 02874763 2014-12-15
1016, and thence into manifold 1116 of drill bit 1012 whro it covers, and thus
seals off,
the openings al the interior ends 1114 of mud passages 1028 of drill bit 1012
from the
flow ot fluids down the 110110W portion 1026 of the drill string 1010.
f00277) 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, anci this fluid
creates a
iarge 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 fcree Waring against the inner perlion or surface of dogleg portion
1168
(exposed to the iluid in pistor cavity 1104). port collar 1102 will siide
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 fiowert down the hollow portion 1026 to pass through the cement
passages
1158 to flow into annulus 1024.
1002781 Referring now to Rome 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. ceinenting is completed through cement passages 1158, to provide a
blocking
mechanism imd thereby prevent fluid flow of cement back into hellor., portion
1026 of
drill string 1010.
[002791 Float
collar 1022 includes a main body portion 1180, having a generally
cylindrical. rod like appearance, provided with a central apertore 1182
therethrough,
configured to enable selected communication of fluids iron-) hollow portion
)026
therethroup,h to cement passages 1-i 58. 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
67
CA 02874763 2014-12-15
t 151 to ruti.:tin float collar 1022 therein. The float collar 1022 further
includes, at the
ond thereof furthest from the drill bit 1012 location, al:Alper soal 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,
in..vardiy
protruding spring ledge 1193. an uppe.r, serri-spherical va:wi seat 1194,
t7a.1 a spring
1196 loaded valve 1198 having a semi-spherical scaling surface 1200. Spring
1196 is
carried on spring ledge 1193, and it extends therefrom to the rear side ol
sealing
surface 12.00. Valve seat 119.1 is positioned such that aperture 1182
intersects valve
e seat 119.,
and when spring 1196 urges valve 1198 thereagainst, see1ing surface 1200
blocks aperture 1182, thereby preventing fluid flow lherothrough in a
direction whore
would othemise ente.r hollow portion 1028. Thes, if :he pressure in central
aperture 1182. formed by the fiwris flowing ociwit nuilow rs
greater ttlatt
1110 pressure in the region of cement passages 1158 pi..s the force of swing
1196
15 tending to
urge the valve 1190 to a ciosed position, rhe valve sealing surface 1200 will
back ofi seat 1194, allowing flow Iherethrough in lite 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 qpring 1196. the
valve
1/90 wiit close positioning the sealing surface 1200 against the sea: 1194,
preventing
20 lbw in the
direction from cement passages 1158 to hollow portion 1026 of drill string
1010.
(=sal 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, it necessary, on a more rigid mechanism, such that the valve 1190
end of the
25 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, thc
float collar 1022 substantially bloc's the bore 1-124 and the weight of the
cement in the
noitovi, portion 1020 (including other fluids which may be located above the
cement in
30 the hollow portion i026). bears upon the noel. collar 1022 and tends to
force it into the
float sub 1016. Dogs 1136 may be rì a retracted ;:obition. such that a trigger
mechanism ShOWC?) is previded c.vhich causes thore:n expansion from the
recess
118.4 and into latching bore 1136, or the dogs 1186 may enter into the drill
string 1010
68
CA 02874763 2014-12-15
In the extended position shc.twri in Figure 70, stioh that the tapered policm
1134 of bore
1124 will cause the clogs 1186 to recess into latching bore 1136 and the dogs
1186 wilI
re-extend upon reaching latching bore 1136. Alternatively. the float collar
1022 may be
pumped down with plug 1121 ahead of the cement.
f) 1002811 Referring still to Figure 70, a plurality of wiper plugs
1121, 1123 (nay WS() be
provided downhole durng cementing operations. The first, or bottoin wiper
plot: 1121
is a generally cylindrical member having an outer contoured surface ;125
forming a
plurality of ridges 1126 of a sinusoidal cross-section, terminating in opposed
flat ends
1127. /129. and further including a central bore l 131 therethro411, .1.11e
lowermost of
0 the ridges 1126 is positionable over latching lip 1140 on float shoe 1151
to :eck firs(
wiper plug 1121 in position in the borehole 1020. Second wiper plug 1123
likewise
inctAles opposed flat ends 1127, 1129 and ridges 1126. but no through-t.)ore.
Ridges
1120 on both wiper plugs 1121, 1123 are sized to contact. in compression. the
interior
of the drill strmy 1010 and thereby form a barrier or seal between the areas
on either
tiide 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 frorn the
annulus 1024 and back up the hollow portion 1026 of the drill striog 1010.
(002821 Once the cement has hardened in the annulus 1024, fioal collar 1022
may be
removed from the float sub 1016. Typically, float collar 1022 includes a
mechanism for
20 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 via,
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.
25 Alternatively. wiper plugs 1121, 1123, float collar 1022, bail 1122, and
drill bit 1012 may
be drilled up with a subsequent (Pill string so that the well may 13e 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
.torte can
be established above the upper wiper plug 1123. by perforating the drill
string 1010 at
30 that location.
1002831 In another embodiment, the float collar may comprise a flapper
valve. In this
respect, the flapper valve may be run in place. Thereafter, a tali may be
pumped
69
CA 02874763 2014-12-15
thlough U flapper vaive. theikA3y zii u1A =owi-g-
or pump eie float collar
let the float
(002841
Rehsrring 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 embociiment, all other features of the
invention
and application of the invention to a cementing operation remain tne same as
in the
embodiment desuribed with respect to Figures 68-70, except Mat the pOtt COliar
1102
and the modifications to the float sub 1016 needed to use the port uollar 1102
are not
neuessary. in their place is provided a cement aperture 1202. eonfigured to be
HI
communivation with spherical manifold 1116. The membrane I '133, configured of
a
i;n:4;iabie '...:ithstanding the eressure ol= the drli,ng nue
circulathig titrou9n
:;rin;; !OW anr7uius I 02-- whi:eiu.i ni.j.
Otriers the cemil:nt
apenufo 1202 so as to seal off from comraunicaticin beteer the annulus 1024
and
manifold l 16.
L002851 To
enable cementing in this embodiment, ball 1122 is placed into the drill
sot ig 1010 as before, as shown in Figure 72, where the ball 1122 passes
through bore
112,1 of float sub 1016 and thence makes its way to spherical manifold 1116 of
drill bit
1012 to be received against. and tieform against. spherical seat 1116 vinare
it blocks
passage of mud through drill bit passages 1028. Thus. :he hydrostatic
head el
20 tho &Dry.; moo. or. if desired at this point. water or c.ennent. 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
irt the
borehole 1020. As in the first embodiment, the float collar 1022 anci wiper
piugs 1121,
1123 (as shown in Figure 70) are used to ensure that cement does not flow back
out
25 the annulus 1024 and up the drill string 1010, and, the wiper plugs may
be either
removeci, ground or drilled through, or left in place, as ciiscusset.1 with
respect to the first
einhotliment.
(ocree) Althouch the port collar 1102, or cement aperture 1202. is
described herein
ds be.inv positioned in the drill string 1010 with respect to a float sub 1016
'coated
irnmediatoiy adjacent to :he drill bit 1C12. t should be understood that such
features
may be prvided in any location intermediate the dril: bit 1012 and the surface
location.
Cementing operations for deep wells may require cement introduction at several
depth
CA 02874763 2014-12-15
locations along the casing 1010 to create proper cementing conditicns
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 10'10 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 poll 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 driiiing
assembly 100
comprising an earth removal member 60 and a wellbore lining conduit 10,
wherein the
drriting 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 rnethod 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 fiuld 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 02874763 2014-12-15
[00288]
',Nall 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 aspeet. 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 meniber and a wellbore I,ning conduit. wherein the
drilling
assembly includes a first fluid flow path and a second fluid flow path:
advancing the
drilling assen-ibly 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 tubuiar 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 seconci 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: arid 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 02874763 2014-12-15
physically alterable bonding rnaterial 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 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
drrlting 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 wilerein the
drilling assembly
comprises a tubular assembly at least a portion of the tubular asserribly
being disposed
within the vvellbore 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 ot 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 emboament, the present ,nvention
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 flutd 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. wheiein the
drilling
assembly includes a first fluid flow path and a second fluid flow path,
advancing the
73
CA 02874763 2014-12-15
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 rtiember 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
conduit 120. wherein the drilling assemby 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 titiing conduit at a location within the
wellbore, vvherein
the drilling assembly comprises a tubular assembly, at least a portion of the
tubular
74
CA 02874763 2014-12-15
assembly being disposed within the wellbore lining conduit, wherein the
dril/ing assembiy
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 coinprises 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 feference to Figure 7 and paragtaph [00129]. 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
'15 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 anci returning at least a portion of the fluid through the seconci fluid
flow path:
leaving the wellbore lining conduit at a location within the weilbore, 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 coinprising 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 iatching
assembly.
[00297] With reference to Figure 7, yet another embodiment of the present
invention
provides a .rnethod for lining a weltore comprising providing a drilling
assembly
comprising an earth removal member and a wellbore Jrnirig conduit, wherein the
drilling
assembly includes a first fluid flow path and a second fluid flow path:
advancing the
CA 02874763 2014-12-15
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 weilbore 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
fiuid through the second fluid flow path r leaving the wellbore lining conduit
at a location
within the wellbore. wherein the drilling assembly compnses 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
[002981 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 arid
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 mernber is adjustable
[002991 With reference to Figure 30 and paragraph [001791 another
embodiment of
the present invention provides a method for lining a welibore 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 througn the
first fluid flow
path and returning at least a portion of the fluid through the second fluid
flow path
76
CA 02874763 2014-12-15
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 iining
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]
VVith 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.
77
CA 02874763 2014-12-15
[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
dniling assembly into the eai th. 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 I n6udes 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 ftuid
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. anci 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 lrnsng 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 lsrìing conduit.
[003031 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 oath,
advancing the
78
CA 02874763 2014-12-15
firilling 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 weilbore lining conduit
at a location
within the wellbore. and relatively i-noving 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
floiN 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 Jíning conduit, wherein the drilling assembly includes a first fluid
flow path and a
= 25 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
79
CA 02874763 2014-12-15
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.
(003051 VVIth 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 welibore 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 arid an inner
surface of the
weilbore. 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
(003061 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 patft
and leaving the
welibore 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
aspecL 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 cornprising 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 iodation
within the weilbore: and conveying a cementing assembly into the wellbore. in
one
CA 02874763 2014-12-15
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 well-bore 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
througn the second fluid flow path; leavino 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
[00309] With reference to Figure 7: in one embodiment, the present
invention
provides a method for lining a wellbore comprising providing a drilling
assembly
c.ornonsing 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
welibore 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 flod to an annular area between the wellbore lrning
conduit and
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CA 02874763 2014-12-15
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
[003101 With
reference to Figure 7 and paragraph [00'1291. 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 welibore 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
1 5 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 rnethoci 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: arid
leaving the wellbore lining conduit at a location within the wellbore, wherein
the drilling
assembly further comprises a geophysical sensor.
[003111
With reference to Figure 7 and paragraph [001291, 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 02874763 2014-12-15
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. and selectively altering a trajectory of the drilling assembly
[00312] VVith reference to Figure 24. in one embodiment, the present
invention
provides a method for lining a wellbor:e 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 anci
returning at least a portion of .the 'flurd through the second fluid flow path
leaving the
wellbore lining conduit at a location \ivithin 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 inember 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
sealing member 351 on an outer portion of the wellbore lining conduit.
[00313] With reference to Figure 11 and paragraph [00140], rì one
embodiment. the
present invention provides a method for lining a wellbore cornprisina
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 arid 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
wellbore comprising providing a drilling assembly comprising an earth removal
member and a welfbore lining conduit. wherein the drilling assembly includes a
first fluid
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CA 02874763 2014-12-15
flow path and a second fluid flow path. advancing the drilling asserribly 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 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
assembiy
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 comonses 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
eaith 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 assernbly 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
3C) movable from the first end through the hrst fiuid flow path and
returnable through the
second fluid flow path when the drilling assembly is disposed in the
vvellbore, wherein
the drilling assembly further comprises a drill string. In an additional
embodiment the
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CA 02874763 2014-12-15
present inve.ntion 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 drillint.i asserribly 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 ncluding 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
*15 measunng 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
mernber
circulating a fluid through the earth removal member fixing the liner section
in the
weilbore: and removing the work String and the earth removal member from the
welibore. In one aspect. CliCUlatIng the fluid includes flowing the fluid
through an annular
CA 02874763 2014-12-15
area defined between an outer surface of the work string and an inner surface
of the
liner section
(00319i With reference to Figure
an additional embodiment of the present invention
provides a method of drilling vvith 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 iron, 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,
(003201 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
weilbore:
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
assemb!y including an earth removal member mounted on a work string and a
section of
liner disposed therearound, the earth retnoval 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
86
CA 02874763 2014-12-15
the wellbore: removing the work string and the earth removal member from the
wellbore,
and flowing fluid through the section of liner and the wellbore
(00321j
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 includi-3s a method of casing a
welltore.
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
!east two fluid paths through the casing and at least one of the at least two
fluid paths
flows to a surface of the wellbore.
100322)
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 predetennmed 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 locationi and
circulating fluid
In the wellbore
87
CA 02874763 2014-12-15
[003231 With reference to Figure 36, another embodiment includes a
method of
casing a wellbore. comprising providing a drilling assembly comprising a
casing. and a
tubular stung 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
[003241 VVith reference to Figure 45, m 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 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. In one aspect. the valve assembly includes one or
rnore
sealing members to seal an annulus between the valve assembly and an inside
surface
of the liner section.
[00325] VVith 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
88
CA 02874763 2014-12-15
section and including a valve assembly permitting the cement to flovy front
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 vaive
assembly in the wellbore, 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 ..hernber:
lowering the drilling
assembly into the earth, thereby forming a wellbore: 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 ot 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.
[003271
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
[003281 With reference to Figures 1 and 7, another embodiment of the
present
invention Includes a method for placing tubulars in art 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
89
CA 02874763 2014-12-15
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 m 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 composing advancing concurrently a portion of a first tubular and a
portion of a
second tubular lo a fiist iocation Irl 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
[00330) 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 02874763 2014-12-15
[00331] With reference to Figure 7. another embodiment of the present
invention
provides a method for placing tubuiars 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
'I D tubular. In one aspect at least a portion of the drilling assembly is
retrievable.
[003321 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 eartft 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 weilbore
as the wellbore is formed In one aspect. the fluid bypass is formed at least
partially
within the casing string
[00334J 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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CA 02874763 2014-12-15
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 betvveen the interior of the drill string and the
borehole. and
directing a physically alterable bonding matenal into an annulus between the
drill string
and the borehoie 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] VVith reference to Figures 71-72. another embodiment of the present
invention includes a method of cementing a borehole comprising extending a
drill string
;nto the earth to form the borehole. the drill string including an earth
removal member
haying 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 rnaterial 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
afterable bonding material reaches the location of the at least one secondary
passage
after flowing the physically alterable bonding material through the drir
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 02874763 2014-12-15
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
men-ter 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 rnud 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 rnaterial 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 prOviOing a ball seat positioned in intersection with the at least
one fluid
passage: and selectively positroning 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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CA 02874763 2014-12-15
[00338)
With reference to Figures 68-70. another e.mbodiinent of the present
invention provides a method of cementing a borehole., comprising extending a
drill string
into th,e earth to form the borehole, the drill string including an eaith
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 east (me 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 interrnediate 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
nydrostatic 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 !east one fluid passage. providing
at ieast
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 02874763 2014-12-15
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
[003401
With reference to Figures 71-72. another embodiment of the present
invention includes a method of cementing a borehole comprising extending a
doll 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 banding material into an annulus between the
(Intl 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
5
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 embodiments the present
invention provides an apparatus for selectively directing fluids flowing clown
a hollow
portion of a tubuiar element to selective passageways lead:rig 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 ,rt/her,
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 ineirber,
CA 02874763 2014-12-15
[00342] With reference to Figures 68-10. 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
(003431 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
tubuiar
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
blcck the
first fluid passageway. and a second valve mernber 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 ieast one
separation
member has a generally tubular profile.
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CA 02874763 2014-12-15
[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. wnerein the second
valve
member comprises a sleeve sealingly engaged about the second fiuid passageway,
and
at least one separatron 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.
[003451 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 cf 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 02874763 2014-12-15
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.
[003461 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 inernber disposed on an outer portion of the liner lowering
the liner to
a location in the ,4vellbore 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 weilbore. 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 n the wellbore comprises supplying a
physically
alterable bonding material to an annular area between the liner and the
welibore-:. 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
98
