CA2874763A1 - Methods and apparatus for wellbore construction and completion - Google Patents

Abstract

The present invention relates methods and apparatus for lining a wellbore. In one aspect, a drilling assembly having an earth removal member and a wellbore lining conduit is manipulated to advance into the earth. The drilling assembly includes a first fluid flow path and a second fluid flow path. Fluid is flowed through the first fluid flow path, and at least a portion of which may return through the second fluid flow path. In one embodiment, the drilling assembly is provided with a third fluid path. After drilling has been completed, wellbore lining conduit may be cemented in the wellbore.

Description

METHODS AND APPARATUS FOR WELLBORE CONSTRUCTION AND
COMPLETION

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.

2 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

3 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.

4 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 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 i:3 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 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 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 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 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 [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 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.

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.

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.

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.

(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.

[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 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 may seal in a landing seat 27 provided in an upper erd of the housing 20. An exampre -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 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.

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.

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 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 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 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 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 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 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.

[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 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 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.

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 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.

(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 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 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.

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 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 =

[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 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 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.

(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 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 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 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 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 ((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 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.

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 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 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 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 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.

[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 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 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, 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-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.

[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.

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, 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.

(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 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, 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 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 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.

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.

[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.

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 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.
=

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 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 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 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.

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 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 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 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.

[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 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.

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 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 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 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 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 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 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 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 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 (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 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 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 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 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 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 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 [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 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 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 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 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 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 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.

[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 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 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 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 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 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 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 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 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 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 [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 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 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 [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 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 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 [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 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 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, [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.

[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 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

Claims (29)

Claims

1. A method for lining a wellbore, comprising;
providing a drilling assembly having a wellbore lining conduit releasably coupled to a drill string, wherein the drill string is disposed in the wellbore lining conduit and includes a drilling member;
urging the drilling assembly into the formation to form the wellbore;
locating the wellbore lining conduit in the wellbore;
releasing the drill string from the wellbore lining conduit;
inflating an exterior sealing member disposed on an exterior of the wellbore lining conduit;
opening a port in the drill string above the drilling member;
supplying cement through the port, wherein the cement flows from interior of the wellbore lining conduit to an annular area between the wellbore lining conduit and the wellbore; and using the expanded sealing member to hold the cement in the annular area.

2. The method of claim 1, further comprising positioning an inner sealing member above the port.

3. The method of claim 2, further comprising expanding the inner sealing member to urge the cement to move downward.

4. The method of claim 3, wherein the inner sealing member is expanded by supplying fluid through a second port on the drill string.

5. The method of claim 1, wherein the exterior sealing member is expanded using a mud pulse.

6. The method of claim 1, wherein locating the wellbore lining conduit comprises coupling the wellbore lining conduit to an existing casing in the wellbore.

7. A method of cementing a tubular in a wellbore, comprising:
proving a tubular releasably coupled to a drill string;
forming a section of wellbore using the drill string;
fixing the tubular in the wellbore;
actuating a first sealing member disposed at a lower portion of the drill string to seal off the wellbore;
opening a side port in the drill string above the sealing member;
supplying cement through the side port to an annular area between the tubular and the wellbore;
actuating a second sealing member disposed on an exterior of the tubular to seal off the annular area;
deflating the first sealing member; and retrieving the drill string.

8. The method of claim 7, further comprising dropping a second dart to actuate the second sealing member.

9. The method of claim 7, further comprising moving the drill string to align a bypass fluid path to an inflation port of the second sealing member.

10. The method of claim 7, wherein the side port is opened by dropping a first dart.

11. A method of drilling with liner, comprising:
providing a drilling assembly having a drilling member connected to a drill string having a telescopic portion and the drilling member is operatively coupled to a liner;
forming a section of wellbore using the drilling assembly;
shortening a length of the drill string, thereby moving the liner toward and relative to the drilling member; and fixing the liner in the wellbore.

12. The method of claim 11, wherein the drilling member is releasably connected to the liner.

13. The method of claim 12, wherein the telescopic drill string is releasably connected to the liner at two locations.

14. The method of claim 13, further comprising releasing the drill string from the liner at a first location prior to moving the liner.

15. The method of claim 14, further comprising releasing the drill string from the liner at a second location after fixing the liner in the wellbore.

16. The method of claim 11, wherein the drill string has two latches located at two axially displaced positions on the drill string.

17. A method of drilling with a liner, comprising:
providing a drilling assembly having a drilling member operatively coupled to a liner, wherein the drilling member is connected to a drill string and the drill string is releasably connected to the liner;
forming a section of wellbore using the drilling assembly;
fixing the liner in the wellbore;
retrieving the drilling member axially relative to the liner, wherein the drill string is released from the liner prior to retrieving the drilling member;
releasing the liner from the wellbore;
lowering the liner toward a bottom of the wellbore; and re-fixing the liner in the wellbore.

18. The method of claim 17, further comprising re-connecting the drill string to the liner prior to releasing the liner.

19. A method of drilling with a liner, comprising:
providing a drilling assembly having a drilling member operatively coupled to a liner, wherein the drilling member is connected to a drill string and the drill string is releasably connected to the liner;
forming a section of wellbore using the drilling assembly;
fixing the liner in the wellbore;
retrieving the drilling member axially relative to the liner;
releasing the liner from the wellbore;
lowering the liner toward a bottom of the wellbore;
re-fixing the liner in the wellbore; and providing a side port in the drill string and circulating through the side port during operations.

20. A method of drilling with a liner, comprising:
drilling a section of wellbore using a drilling assembly having a drill bit connected to a lower end of a drill string, a liner, and the drill string extending through the liner and releasably connected to the liner;
after drilling the section, attaching the liner to a casing previously installed in the wellbore; then disengaging the drill string from the liner; then pulling the drill string and drill bit upward relative to the liner and re-engaging the drill string to the liner; then releasing the liner from the casing; then lowering the liner toward a bottom of the wellbore; then re-attaching the liner to the casing; and then disengaging the drill string from the liner.

21. The method of claim 20, wherein the drill string is releasably connected to the liner using a first latch during drilling of the section of the wellbore.

22. The method of claim 21, wherein the drill string re-engages the liner using a second latch.

23. The method of claim 22, wherein a lower end of the liner is proximate to the drill bit upon engagement of the second latch.

24. The method of claim 22, wherein:
the first latch engages a recess of the liner; and the second latch engages the recess of the liner.

25. The method of claim 22, further comprising, after disengaging the second latch, retrieving the drilling assembly minus the liner to surface through the re-attached liner.

26. The method of claim 22, wherein:
the drill string has a seat, the liner is attached and the first latch is disengaged by landing a first ball or dart onto the seat and exerting pressure on the seated first ball or dart, and the liner is re-attached and the second latch is disengaged by landing a second ball or dart onto the seat and exerting pressure on the seated second ball or dart.

27. The method of claim 20, wherein:
the drill bit is part of a bottomhole assembly further having an underreamer, and the underreamer reams the section during drilling.

28. The method of claim 27, wherein:
the bottomhole assembly further includes a motor, and the motor rotates the drill bit and underreamer during drilling.

29.
The method of claim 20, wherein the method is performed in a single trip down the wellbore.