CA2021518C - Liner isolation and well completion system - Google Patents
Liner isolation and well completion systemInfo
- Publication number
- CA2021518C CA2021518C CA002021518A CA2021518A CA2021518C CA 2021518 C CA2021518 C CA 2021518C CA 002021518 A CA002021518 A CA 002021518A CA 2021518 A CA2021518 A CA 2021518A CA 2021518 C CA2021518 C CA 2021518C
- Authority
- CA
- Canada
- Prior art keywords
- string
- pipe
- bore
- latch
- seal
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Expired - Fee Related
Links
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/10—Sealing or packing boreholes or wells in the borehole
- E21B33/12—Packers; Plugs
- E21B33/129—Packers; Plugs with mechanical slips for hooking into the casing
- E21B33/1293—Packers; Plugs with mechanical slips for hooking into the casing with means for anchoring against downward and upward movement
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
- E21B17/02—Couplings; joints
- E21B17/04—Couplings; joints between rod or the like and bit or between rod and rod or the like
- E21B17/06—Releasing-joints, e.g. safety joints
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B23/00—Apparatus for displacing, setting, locking, releasing, or removing tools, packers or the like in the boreholes or wells
- E21B23/02—Apparatus for displacing, setting, locking, releasing, or removing tools, packers or the like in the boreholes or wells for locking the tools or the like in landing nipples or in recesses between adjacent sections of tubing
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/10—Sealing or packing boreholes or wells in the borehole
- E21B33/12—Packers; Plugs
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/02—Subsoil filtering
- E21B43/10—Setting of casings, screens, liners or the like in wells
Abstract
LINER ISOLATION AND WELL COMPLETION SYSTEM
Abstract In a wellbore having a liner hung from a higher string of pipe, a permanent packer and a seal unit are utilized to isolate the annulus between the liner and the wellbore surface. The downhole completion assembly, which comprises an on-off tool, a latch and seal assembly and a tailpipe, can be lowered into the packer and seal unit by the production tubing, with the latch mechanism of the latch and seal assembly snapping into a threaded portion of the packer. The on-off tool can be disconnected and the production tubing withdrawn from the well. Alternatively, the latch mechanism can be disengaged and the entire downhole completion assembly can be withdrawn from the well in a single trip.
Abstract In a wellbore having a liner hung from a higher string of pipe, a permanent packer and a seal unit are utilized to isolate the annulus between the liner and the wellbore surface. The downhole completion assembly, which comprises an on-off tool, a latch and seal assembly and a tailpipe, can be lowered into the packer and seal unit by the production tubing, with the latch mechanism of the latch and seal assembly snapping into a threaded portion of the packer. The on-off tool can be disconnected and the production tubing withdrawn from the well. Alternatively, the latch mechanism can be disengaged and the entire downhole completion assembly can be withdrawn from the well in a single trip.
Description
2 ~ 8 BACRGROU~D) OF l~IE INVENTION
The drilling of an oil well generally involves drilling the borehole in successive stages with each stage having a borehole diameter which is less than the borehole diameter of the preceding stage. As each of the upper stages of the borehole ls drllled, a string of tubular casing plpe is inserted lnto the borehole, extending from the earth's surface to a location adjacent the current bottom of the borehole. This string of casing pipe is generally cemented in place.
The column of cement, in the annulus forme~ by outer surface of the casing pipe and the borehole wall, supports the casing pipe and at least substantlally prevents fluid migratlon along the annulus. Then a smaller dlameter drill is lowered through the caslng and the next stage of the borehole ls drilled. Eventually ~-extending the new caslng all the wav from the earth surface becomes undeslrable, and then the newest borehole stage is cased by lowerlng a strlng of liner plpe lnto the borehole and hanglng thls llner from the lower end of the lowermost strlng of plpe already ln the borehole, followed by cementlng the llner in place. The drilllng, lining and cementlng operatlons can contlnue untll the deslred depth is achleved.
To position and cement a llner ln a string of caslng, the llner ls made up wlth the usual bottom hsle equipment whlch includes a caslng shoe, float collar and plug catchers and ls connected up to the desired length.
At the top of the llner is a llner hanger which is an assembly having slip elements whlch are normally retracted whlle going into the borehole and whlch are released downhole when setting of the liner hanger is desired. The liner hanger is lowered into the borehole by a settlng tool which attaches to the llner hanger and ~ 0 ~ 8 a string of pipe attached to the setting tool. At the desired location where the casing shoe ls preferably located above the bottom of the open borehole, the liner hanger is set ln the next above casing by actuating the settlng tool to set the sllps on the liner hanger. Upon settlng the liner hanger, the welght of the liner ls suspended by the llner hanger on the next above casing.
The setting tool ls released and the liner hanger ls then cemented by pumplng cement through the strlng of plpe and through the liner and lnto the annulus between the llner and borehole. After the cement ~s set up, any remalnlng cement ln the llner can be removed by drllllng through the llner and destructible cement equipment at the lower end of the liner. When the open borehole reaches the pro~ected well depth and traverses the formatlons to be completed, the llner lncludes a llner hanger and oftentlmes a pollshed bore receptacle ~PBR).
The pollshed bore receptacle attaches either above or below the liner hanger and provides a bore to recelve a seallng member on a productlon tublng string.
The productlon strlng of tublng, which has a seallng element adapted to be slldlngly and seallngly recelved ln the pollshed bore receptacle, extends from the earth's surface. When the well ls completed, flulds from the earth formatlon being produced flow through the tublng strlng to the productlon equlpment at the earth's surface. The seallng element on the strlng of tublng is sub~ected to downhole hydraullc pressure forces, and the tublng strlng ls sub~ected to expanslon and contractlon forces due to changes ln the temperature of the fluld in the tubing strlng. The purpose of a slldlng seal on a strlng of tublng ln a pollshed bore receptacle generally ls to permlt movement of the seal and the string of tublng relative to the polished bore receptacle.
,. " .. , ,.. . . .. . ;-When the produclng formation ls at high pressure conditions, it is possible for high pressure fluld to sePp through the annular sleeve of concrete which exists between the outside of the liner and the surrounding earth formation. Such seepage can rise and enter the annular gap between the overlap of the top of the liner in the producing formation and the bottom of the next higher cemented string of pipe. In the absence of any sealing mechanism for the annular gap, the high pressure fluid can fill the annulus between the production tubing and the casing. The production tubing can have a higher pressure rating for a lower cost than the casing pipe because of the relatively small diameter of the production tubing compared to the diameter of the casing pipe. Accordingly, it is generally desirable to reduce costs by using casing pipe with a substantially lower pressure rating than the productior tubing. Thus, leakage of the high pressure fluid into the annulus between the production tubing and the casing can cause damage to the lower pressure rated casing.
One solution for the leakage problem is to install a packer to seal the annular gap between the liner and the casing, in combination with a second polished bore receptacle ~PBR) posltioned wlthin the packer to seal -off the annulus between the productlon tubing and the llner. Each PBR can be as much as thirty feet long and ls very expensive due to the manufacturing requirements for its polished interior surface. In many downhole completlons using a permanent packer, the tailpipe is run as part of the packer assembly and becomes a permanent part of the well, unless the permanent packer is also removed. The presence of the tailpipe in the wellbore restricts access to the llner because of the small size of the tailpipe. Some downhole completions ,,, ~ . , . .. .. , . ., . . . ~ , .... ... . . .
2~21~ 8 utillze a landed seal assembly, but thls requlres two trips to retrleve.
Accordlngly, lt ls an ob~ect of the present invention to provlde new and lmproved method and apparatus for isolatlng a llner and provldlng a seal between productlon tubing and the llner. Another ob~ect of the inventlon ls to permlt the downhole productlon completlon assembly to be dlsconnected from the llner lsolation seal and be removed from the borehole ln a single trlp. A further ob~ect of the lnvention is to permit the removal of the productlon tubing from the borehole whlle maintalning a high pressure seal between the producing formatlon and the borehole caslng above the produclng formatlon. Other ob~ects, aspects and advantages of the lnventlon wlll be apparent from the following description, the drawings and the appended claims to the lnventlon.
6 202~ 51~
The annulus around a wellbore liner can be isolated by positioning a tubular member within the liner with the tubular member extending upwardly from a first position within the axial bore of the liner to a second position within the axial bore of the next higher string of pipe above the upper end of the liner. The tubular member can be provided with a first annular seal between the tubular member and the liner, and a second annular seal between the tubular member and the next higher string of pipe.
The downhole completion can be achieved by lowering a string of production pipe, having on the lower end thereof an on-off tool, a latch and a seal assembly connected to the lower end of the on-off tool, and a tailpipe extending downwardly from the latch and seal assembly, until the latch and seal assembly is positioned within the tubular member and said tailpipe extends at least partially below the bore of the packer. The latch -and seal assembly can then be activated to releasably secure the latch and seal assembly to the tubular member and to provide a fluid seal for the annulus between the -interior surface of tubular member and the exterior surface of said latch and seal assembly.
Production fluid from the producing formation can be withdrawn via the tailpipe, the latch and seal assembly, the on-off tool, and the string of production pipe. When it is desirable to pull the production tubing, a plug can be inserted into the tailpipe to seal off the producing formation, the on-off tool can be activated for separation of the production tubing from the downhole completion assembly, and the production tubing can then be withdrawn from the borehole while leaving the producing formation at high pressure :
2~2~8 . . .
:
condltion. If access to the wellbore below the tailplpe is desired, the downhole completlon assembly can be withdrawn by activatlng the latch and seal assembly to release from the tubular member, and retrieving the downhole completlon equlpment ln a slngle trip.
BRIEF DESCRIP~ION OF THE DRAWINGS
FIGURE 1 is a vertlcal sectlonal vlew of a well bore whlch has been lined by successively smaller diameter plpe strings cemented in place, wlth at least the lowermost pipe string being a liner which has been hung from a lower portlon of the next hlgher plpe string;
FIGURE 2 corresponds to the lower portlon of FIGURE
1 with an lsolation packer and seal unit, shown partially ln cross sectlon, having been lowered into place by a drill plpe string and hydraulic settlng tool;
and FIGURE 3 corresponds to FIGURE 2 after the packer has been set ln place, the hydraulic settlng tool has been removed and productlon completlon assembly has been lowered lnto place by the productlon tublng.
- - , . ... .. . .
2~2~8 DETAILED DESCRIPTION
Referring now to PIGUR~ 1, a borehole 10 extends vertically downwardly lnto the earth traversing varlous fonmations, lncluding at least one producing formation.
The borehole 10 has been drilled ln a plurallty of stages 11, 12 and 13 wlth each stage havlng a smaller borehole diameter than the lmmedlately preceding stage.
A string of casing plpe 14 was inserted lnto upper borehole stage 11 and secured ln place by the formatlon of cement sleeve 15 filling the annular space between the exterior surface of casing 14 and the ad~acent exposed earthen surface of the borehole. Similarly, a strlng of caslng plpe 16 was lnserted lnto lntermedlate ;
borehole stage 12 and secured ln place by the formatlon ::
of cement sleeve 17, with the lower end of string 16 being substantially above the ultimate bottom of borehole 10. Thus, plpe string 14 serves as a liner or casing for the vertical portion of wellbore 10 represented by flrst stage 11, whlle plpe strlng 16 serves as a liner or caslng for the vertlcal portlon of wellbore 10 represented.by lntermedlate stage 12.
A string of liner pipe 18 has been positioned in --the lower borehole section 13. Unlike casings 14 and 16, which extend to the earth surface and are dlrectly connected to the wellhead 19, llner 18 extends upwardly ..
only lnto the lowermost portlon of the next hlgher plpe string 16. Each of pipe strings 14, 16 and 18 has an axlal bore therethrough at least generally parallel to -the axis of borehole 10. The external diameter of plpe ~ :
string 18 is less than the lnternal dlameter of the bore of pipe strlng 16. Similarly, the external diameter of pipe strlng 16 ls less than the lnternal diameter of the bore of pipe string 14. Liner strlng 18 is initially ~.
suspended from the lowermost portion of plpe strlng 16 .
2 ~ 8 by means of a conventlonal llner hanger assembly 21 positloned within the bore of strlng 16. Assembly 21 achieves a mechanical engagement with the lnner surface of the bore of plpe strlng 16 and the outer surface of llner string 18. The llner strlng 18 can then be cemented in place by the formatlon of cement sleeve 22, in the same manner as the caslng strlngs 14 and 16 were cemented ln place. Thus, pipe string 18 serves as a llner for the vertical portlon of wellbore 10 whlch extends downwardly from the lower end of pipe strlng 16.
In additlon to the liner hanger assembly 21, the strlng 18 of llner pipe ls also provlded wlth a relatlvely short polished bore receptacle (PBR) 23. In contrast to the approxlmately 30 foot length of many P8R's lntended for use as a telescoplng ~olnt, the PBR
23 can be on the order of only slx feet ln length. PBR
23 has an upper bore section 24 whlch is hlghly pollshed and a lower bore sectlon 25 whlch has a smaller internal dlameter than upper bore section 24. A normal llner plpe 26 ls attached to the lower end of PBR 23. The llner strlng 18 can be made up with the PBR 23 above the liner hanger assembly 21, as lIlustrated, or wlth the llner hanger assembly 21 above the PBR 23. Whlle the cement sleeve 22 ls shown as extendlng upwardly only to .
the bottom of caslng strlng 16 for slmpllclty of lllustratlon, lt ls generally customary for the cement 22 to contlnue upwardly to the top of the llner strlng 18, lncludlng the PBR 23 and llner hanger assembly 21.
As the cement sleeve 22 ls not completely lmpermeable to well flulds, it ls posslble for flulds under sufflciently hlgh pressure at the bottom of the borehole 10 to seep upwardly through cement sleeve 22 and lnto the lnterlor of caslng 16. ~ -202~ 51~
Referrlng now to FIGURE 2, a seal unit 31 is connected by extension sleeve 32 and crossover 33 to the bottom of tubular isolation pac~er 34. The tubular member 35 of seal unit 31 has an external diameter which ls slightly smaller than the internal diameter of the upper bore section 24 of PBR 23, and is provided with a plurality of circumferentially extending seals 36 to contact the interior surface of bore section 24 and thereby seal the annular space between the exterior of seal unit 31 and the interior surface of bore section 24. Isolation packer 34 is provided with at least one expandable elastomer1c ring 37 extending circumferentially about the tubular member 30 of packer 34 and which has been sub~ected to compression in a direction parallel to the longitudinal axis of borehole 10 by sultable actuating means to cause the annular ring 37 to expand radially outwardly inlo sealing engagement with the interior surface of the bore of the laterally ad;acent portion of pipe string 16. Packer 34 is also provided with slip mechanisms 38 and 39 extending -:
circumferentially about tubular member 30 and which have been moved radially outwardly into frictional engagement with the interior surface of the bore of pipe string 16 to immobilize the packer 34 in pipe string 16. :
A conventional hydraullc setting tool 41 is in threaded engagement with the upper end of packer 34 and is secured to the lower end of drill pipe or tubing 42 by a crossover section 43 and extension 44. Packer 34 and seal unl~t 31 can be lowered into borehole 10 by :
drill pipe or tubing 42 and setting tool 41 until seal ~ .
unit 31 has entered and sealingly engaged the polished bore 24 of PBR 23. Setting tool 41 can then be utilized to cause elastomeric rlng 37 to sealingly engage the lnterior surface of the bore of pipe strlng 16 and to ll 202~ 518 cause slips 3a and 39 to mechanically grlp the interior pipe surface of the bore of string 16. Such engagement by slips 38 and 39 prevents movement of pac~er 34 upwardly or downwardly ln pipe string 16. After the packer 34 has been activated, the drlll pipe ~2 can be rotated to unscrew setting tool 41 from packer 34, and the drlll plpe 42 and setting tool 41 can be withdrawn from the borehole 10. The packer 34, crossover 33, tubular extension 32 and seal unit 31 isolate the annulus between the exterior surface of PBR 23 and the interior surface of the bore of pipe string 16 from the interlor of pipe string 18 and from the interior of pipe string 16 above pac~er 34, while permitting fluid communlcatlon between the interior of pipe string 18 and the lnterior of pipe string 16 above packer 34 via their axial bores.
Referring to FIGURE 3, the se'ting tool 41 has been removed from the well bore 10 and the downhole production completion assembly has been positioned in place. A latch seal assembly 51 has a latch seal nipple 52, a seal unit 53, and a crossover unit 54. The latching elements of the latch seal nipple 52 snap into engagement with the threads on the female collar at the top of the tubular member 30 of packer 34 when the latch seal assembly is lowered into the packer 34. The latch seal assembly Sl can be rotated to unscrew it from the packer 34, permitting the latch seal assembly to be removed from the well bore lf that becomes necessary. A
tubular tailpipe 55, havlng profile collars 56 and 57 therein, is secured to the lower portlon of crossover unit 54.
An on-off tool 5a ls connected between the lower end of production tubing 59 and the upper end of latch seal assembly 51. The on-off tool 5a has an outer A
.. . .. .. . . . .
, ;; ~, ~ . . .
12 202~ ~18 tubular skirt 61 secured to the lower end of production tubing 59 by suitable means, e.g. threaded engagement.
Tool 58 has an inner tubular skirt 62 secured to the upper end of latch seal assembly 51 by suitable means.
The on-off tool 58 has a bore 60 therethrough whlch is approximately coaxial with the bore of production tubing string 59, the bore latch seal assembly 51, and the bore of tailpipe 55 to provide fluid communication between the bore of liner 18 and the bore of production tubing string 59. Skirt 61 has an upside-down J-shaped groove 63 cut in its interior surface, while sklrt 62 is provided with a pin 64 which pro~ects outwardly therefrom into groove 63. A plurality of annular seals 66 are positioned on the exterior of tubular element 62 in sealing engagement with the interior surface of outer tubular element 61 in a region axially spaced from the slot 63. Thus, outer tubular elem-nt 61 is movable axially with respect to inner tubular element 62, from a first position with sleeves 61 and 62 being releasably secured to each other to a second position wherein sleeves 61 and 62 are separated from each other. This ~ls accomplished by pln 64 sliding in the long leg of the slot 63, and seals 66 providing a fluid seal between the exter1or of inner element 62 and the interior of outer element 61 during engagement of sleeves 61 and 62.
Alternately, the production tubing 59 and outer tubular element 61 can be lowered to place the pin 64 at the curved arc of the slot 63 and then the tubing 59 and element 61 can be rotated a quarter-turn, thereby permltting tubing 59 to be raised, separating outer sleeve 61 from the inner sleeve 62.
Slot 63 can ~e a groove having a depth less than the thickness of sleeve 61, or it can extend through the sleeve 61. while the slot 63 and pin 64 have been .-..~
13 20215~8 illustrated on sleeves 61 and 62, respectively, they can be reversed ~f desired.
The downhole completion assembly, comprising on-off tool 58, latch seal assembly 51 and tailpipe 55, can be attached to the lower end of production tubing string 59 and lowered lnto the w~llbore until the latch seal assembly 51 is positioned within tubular element 30 and tailpipe 55 extends at least partially below the bore of the packer. The latch seal assembly can then be activated to engage the threaded portion of packer 34 to releasably secure the latch seal assembly to packer 34.
Production fluid from the producing formation can be passed from the bore of liner 18 through tailpipe 55, latch seal assembly 51, on-off tool 58 and production tubing 59 to the above ground production facillties.
If it is desirable to removing the tubing string 59 while the production is still viable, a plug can be lowered through the production tubing 59 and inserted -into one of the profile nipples 56, 57 in tailpipe 55 to seal off the producing formation. Then the on-off tool 58 can be rotated to disconnect the production tubing 59 from latch seal assembly 51, and the production tubing 59 can be withdrawn from the well. If for any reason it ls desired to retrieve the latch seal assembly 51 and tailpipe 55, the tubing string 59 can be rotated to unscrew the latch seal assembly from the packer 34, and then the tubing 59, on-off tool 59, latch seal assembly 51 and tailpipe 55 can be withdrawn ln a slngle trip of the tubing.
Each of liner hanger 21, PBR 23, packer 34, seal unlt 31, latch seal assembly 51, tallplpe 55 and on-off tool 58 can be any suitable device whlch is commercially available for the intended purpose. While the devices selected can vary according to the size and other .
environmental limitations, one suitable combination for isolating and completing a 4-1/2" liner hung from a 7~
casing, with a 2-7/8~ productlon tublng, is as follows:
Device ComrnerclallY Available Equipment On-off tool S8 7" x 2-7/8" Gulberson XL on-off tool with 3 bonded seals (10,000 psi pressure rating), model #89207, with a 2.313n type X proflle nipple Latch seal 51 4" x 2-7/8" latch seal assembly containing a Guiberson model #83089 latch seal nipple, a one foot seal unit model i~83082, and a crossover to 2-7/8" tublng thread Packer 34 7" x 4.00" Guiberson bore magnum "GT" drillable packer, model #82063 Tailpipe 55 One 10' x 2-7/8" N-80 tubing pup, one 2.313" type "XN~ profile nipple with 2.205" no-go, and one wireline re-entry collar.
The on-off tool can be released by slacking off on the tension on tubing 59, rotating tubing 59 1/4 turn to the left and then raising tubing 59. The on-off tool 58 can -;~
be automatically reset by slacking off on the tubing s9 with the two sleeves of the on-off tool contacting each ~ -other, and then pulling tenslon to insure that the tubing is latched. The latch seal 51 can be released by pulling 500 pounds tension and then rotating tubing 59 eight turns to the right. The latch seal automatically reseats upon being lowered lnto contact with the threads of packer 34 and slacking off of the tension of tubing 59. This system can be used for stimulation, production ~ -or workover operations. Reasonable variations and modifications are possible withln the scope of the foregoing description and the appended claims to the lnvention. -~
A `
,,,"~,",~ "~ ";,~",,~
The drilling of an oil well generally involves drilling the borehole in successive stages with each stage having a borehole diameter which is less than the borehole diameter of the preceding stage. As each of the upper stages of the borehole ls drllled, a string of tubular casing plpe is inserted lnto the borehole, extending from the earth's surface to a location adjacent the current bottom of the borehole. This string of casing pipe is generally cemented in place.
The column of cement, in the annulus forme~ by outer surface of the casing pipe and the borehole wall, supports the casing pipe and at least substantlally prevents fluid migratlon along the annulus. Then a smaller dlameter drill is lowered through the caslng and the next stage of the borehole ls drilled. Eventually ~-extending the new caslng all the wav from the earth surface becomes undeslrable, and then the newest borehole stage is cased by lowerlng a strlng of liner plpe lnto the borehole and hanglng thls llner from the lower end of the lowermost strlng of plpe already ln the borehole, followed by cementlng the llner in place. The drilllng, lining and cementlng operatlons can contlnue untll the deslred depth is achleved.
To position and cement a llner ln a string of caslng, the llner ls made up wlth the usual bottom hsle equipment whlch includes a caslng shoe, float collar and plug catchers and ls connected up to the desired length.
At the top of the llner is a llner hanger which is an assembly having slip elements whlch are normally retracted whlle going into the borehole and whlch are released downhole when setting of the liner hanger is desired. The liner hanger is lowered into the borehole by a settlng tool which attaches to the llner hanger and ~ 0 ~ 8 a string of pipe attached to the setting tool. At the desired location where the casing shoe ls preferably located above the bottom of the open borehole, the liner hanger is set ln the next above casing by actuating the settlng tool to set the sllps on the liner hanger. Upon settlng the liner hanger, the welght of the liner ls suspended by the llner hanger on the next above casing.
The setting tool ls released and the liner hanger ls then cemented by pumplng cement through the strlng of plpe and through the liner and lnto the annulus between the llner and borehole. After the cement ~s set up, any remalnlng cement ln the llner can be removed by drllllng through the llner and destructible cement equipment at the lower end of the liner. When the open borehole reaches the pro~ected well depth and traverses the formatlons to be completed, the llner lncludes a llner hanger and oftentlmes a pollshed bore receptacle ~PBR).
The pollshed bore receptacle attaches either above or below the liner hanger and provides a bore to recelve a seallng member on a productlon tublng string.
The productlon strlng of tublng, which has a seallng element adapted to be slldlngly and seallngly recelved ln the pollshed bore receptacle, extends from the earth's surface. When the well ls completed, flulds from the earth formatlon being produced flow through the tublng strlng to the productlon equlpment at the earth's surface. The seallng element on the strlng of tublng is sub~ected to downhole hydraullc pressure forces, and the tublng strlng ls sub~ected to expanslon and contractlon forces due to changes ln the temperature of the fluld in the tubing strlng. The purpose of a slldlng seal on a strlng of tublng ln a pollshed bore receptacle generally ls to permlt movement of the seal and the string of tublng relative to the polished bore receptacle.
,. " .. , ,.. . . .. . ;-When the produclng formation ls at high pressure conditions, it is possible for high pressure fluld to sePp through the annular sleeve of concrete which exists between the outside of the liner and the surrounding earth formation. Such seepage can rise and enter the annular gap between the overlap of the top of the liner in the producing formation and the bottom of the next higher cemented string of pipe. In the absence of any sealing mechanism for the annular gap, the high pressure fluid can fill the annulus between the production tubing and the casing. The production tubing can have a higher pressure rating for a lower cost than the casing pipe because of the relatively small diameter of the production tubing compared to the diameter of the casing pipe. Accordingly, it is generally desirable to reduce costs by using casing pipe with a substantially lower pressure rating than the productior tubing. Thus, leakage of the high pressure fluid into the annulus between the production tubing and the casing can cause damage to the lower pressure rated casing.
One solution for the leakage problem is to install a packer to seal the annular gap between the liner and the casing, in combination with a second polished bore receptacle ~PBR) posltioned wlthin the packer to seal -off the annulus between the productlon tubing and the llner. Each PBR can be as much as thirty feet long and ls very expensive due to the manufacturing requirements for its polished interior surface. In many downhole completlons using a permanent packer, the tailpipe is run as part of the packer assembly and becomes a permanent part of the well, unless the permanent packer is also removed. The presence of the tailpipe in the wellbore restricts access to the llner because of the small size of the tailpipe. Some downhole completions ,,, ~ . , . .. .. , . ., . . . ~ , .... ... . . .
2~21~ 8 utillze a landed seal assembly, but thls requlres two trips to retrleve.
Accordlngly, lt ls an ob~ect of the present invention to provlde new and lmproved method and apparatus for isolatlng a llner and provldlng a seal between productlon tubing and the llner. Another ob~ect of the inventlon ls to permlt the downhole productlon completlon assembly to be dlsconnected from the llner lsolation seal and be removed from the borehole ln a single trlp. A further ob~ect of the lnvention is to permit the removal of the productlon tubing from the borehole whlle maintalning a high pressure seal between the producing formatlon and the borehole caslng above the produclng formatlon. Other ob~ects, aspects and advantages of the lnventlon wlll be apparent from the following description, the drawings and the appended claims to the lnventlon.
6 202~ 51~
The annulus around a wellbore liner can be isolated by positioning a tubular member within the liner with the tubular member extending upwardly from a first position within the axial bore of the liner to a second position within the axial bore of the next higher string of pipe above the upper end of the liner. The tubular member can be provided with a first annular seal between the tubular member and the liner, and a second annular seal between the tubular member and the next higher string of pipe.
The downhole completion can be achieved by lowering a string of production pipe, having on the lower end thereof an on-off tool, a latch and a seal assembly connected to the lower end of the on-off tool, and a tailpipe extending downwardly from the latch and seal assembly, until the latch and seal assembly is positioned within the tubular member and said tailpipe extends at least partially below the bore of the packer. The latch -and seal assembly can then be activated to releasably secure the latch and seal assembly to the tubular member and to provide a fluid seal for the annulus between the -interior surface of tubular member and the exterior surface of said latch and seal assembly.
Production fluid from the producing formation can be withdrawn via the tailpipe, the latch and seal assembly, the on-off tool, and the string of production pipe. When it is desirable to pull the production tubing, a plug can be inserted into the tailpipe to seal off the producing formation, the on-off tool can be activated for separation of the production tubing from the downhole completion assembly, and the production tubing can then be withdrawn from the borehole while leaving the producing formation at high pressure :
2~2~8 . . .
:
condltion. If access to the wellbore below the tailplpe is desired, the downhole completlon assembly can be withdrawn by activatlng the latch and seal assembly to release from the tubular member, and retrieving the downhole completlon equlpment ln a slngle trip.
BRIEF DESCRIP~ION OF THE DRAWINGS
FIGURE 1 is a vertlcal sectlonal vlew of a well bore whlch has been lined by successively smaller diameter plpe strings cemented in place, wlth at least the lowermost pipe string being a liner which has been hung from a lower portlon of the next hlgher plpe string;
FIGURE 2 corresponds to the lower portlon of FIGURE
1 with an lsolation packer and seal unit, shown partially ln cross sectlon, having been lowered into place by a drill plpe string and hydraulic settlng tool;
and FIGURE 3 corresponds to FIGURE 2 after the packer has been set ln place, the hydraulic settlng tool has been removed and productlon completlon assembly has been lowered lnto place by the productlon tublng.
- - , . ... .. . .
2~2~8 DETAILED DESCRIPTION
Referring now to PIGUR~ 1, a borehole 10 extends vertically downwardly lnto the earth traversing varlous fonmations, lncluding at least one producing formation.
The borehole 10 has been drilled ln a plurallty of stages 11, 12 and 13 wlth each stage havlng a smaller borehole diameter than the lmmedlately preceding stage.
A string of casing plpe 14 was inserted lnto upper borehole stage 11 and secured ln place by the formatlon of cement sleeve 15 filling the annular space between the exterior surface of casing 14 and the ad~acent exposed earthen surface of the borehole. Similarly, a strlng of caslng plpe 16 was lnserted lnto lntermedlate ;
borehole stage 12 and secured ln place by the formatlon ::
of cement sleeve 17, with the lower end of string 16 being substantially above the ultimate bottom of borehole 10. Thus, plpe string 14 serves as a liner or casing for the vertical portion of wellbore 10 represented by flrst stage 11, whlle plpe strlng 16 serves as a liner or caslng for the vertlcal portlon of wellbore 10 represented.by lntermedlate stage 12.
A string of liner pipe 18 has been positioned in --the lower borehole section 13. Unlike casings 14 and 16, which extend to the earth surface and are dlrectly connected to the wellhead 19, llner 18 extends upwardly ..
only lnto the lowermost portlon of the next hlgher plpe string 16. Each of pipe strings 14, 16 and 18 has an axlal bore therethrough at least generally parallel to -the axis of borehole 10. The external diameter of plpe ~ :
string 18 is less than the lnternal dlameter of the bore of pipe strlng 16. Similarly, the external diameter of pipe strlng 16 ls less than the lnternal diameter of the bore of pipe string 14. Liner strlng 18 is initially ~.
suspended from the lowermost portion of plpe strlng 16 .
2 ~ 8 by means of a conventlonal llner hanger assembly 21 positloned within the bore of strlng 16. Assembly 21 achieves a mechanical engagement with the lnner surface of the bore of plpe strlng 16 and the outer surface of llner string 18. The llner strlng 18 can then be cemented in place by the formatlon of cement sleeve 22, in the same manner as the caslng strlngs 14 and 16 were cemented ln place. Thus, pipe string 18 serves as a llner for the vertical portlon of wellbore 10 whlch extends downwardly from the lower end of pipe strlng 16.
In additlon to the liner hanger assembly 21, the strlng 18 of llner pipe ls also provlded wlth a relatlvely short polished bore receptacle (PBR) 23. In contrast to the approxlmately 30 foot length of many P8R's lntended for use as a telescoplng ~olnt, the PBR
23 can be on the order of only slx feet ln length. PBR
23 has an upper bore section 24 whlch is hlghly pollshed and a lower bore sectlon 25 whlch has a smaller internal dlameter than upper bore section 24. A normal llner plpe 26 ls attached to the lower end of PBR 23. The llner strlng 18 can be made up with the PBR 23 above the liner hanger assembly 21, as lIlustrated, or wlth the llner hanger assembly 21 above the PBR 23. Whlle the cement sleeve 22 ls shown as extendlng upwardly only to .
the bottom of caslng strlng 16 for slmpllclty of lllustratlon, lt ls generally customary for the cement 22 to contlnue upwardly to the top of the llner strlng 18, lncludlng the PBR 23 and llner hanger assembly 21.
As the cement sleeve 22 ls not completely lmpermeable to well flulds, it ls posslble for flulds under sufflciently hlgh pressure at the bottom of the borehole 10 to seep upwardly through cement sleeve 22 and lnto the lnterlor of caslng 16. ~ -202~ 51~
Referrlng now to FIGURE 2, a seal unit 31 is connected by extension sleeve 32 and crossover 33 to the bottom of tubular isolation pac~er 34. The tubular member 35 of seal unit 31 has an external diameter which ls slightly smaller than the internal diameter of the upper bore section 24 of PBR 23, and is provided with a plurality of circumferentially extending seals 36 to contact the interior surface of bore section 24 and thereby seal the annular space between the exterior of seal unit 31 and the interior surface of bore section 24. Isolation packer 34 is provided with at least one expandable elastomer1c ring 37 extending circumferentially about the tubular member 30 of packer 34 and which has been sub~ected to compression in a direction parallel to the longitudinal axis of borehole 10 by sultable actuating means to cause the annular ring 37 to expand radially outwardly inlo sealing engagement with the interior surface of the bore of the laterally ad;acent portion of pipe string 16. Packer 34 is also provided with slip mechanisms 38 and 39 extending -:
circumferentially about tubular member 30 and which have been moved radially outwardly into frictional engagement with the interior surface of the bore of pipe string 16 to immobilize the packer 34 in pipe string 16. :
A conventional hydraullc setting tool 41 is in threaded engagement with the upper end of packer 34 and is secured to the lower end of drill pipe or tubing 42 by a crossover section 43 and extension 44. Packer 34 and seal unl~t 31 can be lowered into borehole 10 by :
drill pipe or tubing 42 and setting tool 41 until seal ~ .
unit 31 has entered and sealingly engaged the polished bore 24 of PBR 23. Setting tool 41 can then be utilized to cause elastomeric rlng 37 to sealingly engage the lnterior surface of the bore of pipe strlng 16 and to ll 202~ 518 cause slips 3a and 39 to mechanically grlp the interior pipe surface of the bore of string 16. Such engagement by slips 38 and 39 prevents movement of pac~er 34 upwardly or downwardly ln pipe string 16. After the packer 34 has been activated, the drlll pipe ~2 can be rotated to unscrew setting tool 41 from packer 34, and the drlll plpe 42 and setting tool 41 can be withdrawn from the borehole 10. The packer 34, crossover 33, tubular extension 32 and seal unit 31 isolate the annulus between the exterior surface of PBR 23 and the interior surface of the bore of pipe string 16 from the interlor of pipe string 18 and from the interior of pipe string 16 above pac~er 34, while permitting fluid communlcatlon between the interior of pipe string 18 and the lnterior of pipe string 16 above packer 34 via their axial bores.
Referring to FIGURE 3, the se'ting tool 41 has been removed from the well bore 10 and the downhole production completion assembly has been positioned in place. A latch seal assembly 51 has a latch seal nipple 52, a seal unit 53, and a crossover unit 54. The latching elements of the latch seal nipple 52 snap into engagement with the threads on the female collar at the top of the tubular member 30 of packer 34 when the latch seal assembly is lowered into the packer 34. The latch seal assembly Sl can be rotated to unscrew it from the packer 34, permitting the latch seal assembly to be removed from the well bore lf that becomes necessary. A
tubular tailpipe 55, havlng profile collars 56 and 57 therein, is secured to the lower portlon of crossover unit 54.
An on-off tool 5a ls connected between the lower end of production tubing 59 and the upper end of latch seal assembly 51. The on-off tool 5a has an outer A
.. . .. .. . . . .
, ;; ~, ~ . . .
12 202~ ~18 tubular skirt 61 secured to the lower end of production tubing 59 by suitable means, e.g. threaded engagement.
Tool 58 has an inner tubular skirt 62 secured to the upper end of latch seal assembly 51 by suitable means.
The on-off tool 58 has a bore 60 therethrough whlch is approximately coaxial with the bore of production tubing string 59, the bore latch seal assembly 51, and the bore of tailpipe 55 to provide fluid communication between the bore of liner 18 and the bore of production tubing string 59. Skirt 61 has an upside-down J-shaped groove 63 cut in its interior surface, while sklrt 62 is provided with a pin 64 which pro~ects outwardly therefrom into groove 63. A plurality of annular seals 66 are positioned on the exterior of tubular element 62 in sealing engagement with the interior surface of outer tubular element 61 in a region axially spaced from the slot 63. Thus, outer tubular elem-nt 61 is movable axially with respect to inner tubular element 62, from a first position with sleeves 61 and 62 being releasably secured to each other to a second position wherein sleeves 61 and 62 are separated from each other. This ~ls accomplished by pln 64 sliding in the long leg of the slot 63, and seals 66 providing a fluid seal between the exter1or of inner element 62 and the interior of outer element 61 during engagement of sleeves 61 and 62.
Alternately, the production tubing 59 and outer tubular element 61 can be lowered to place the pin 64 at the curved arc of the slot 63 and then the tubing 59 and element 61 can be rotated a quarter-turn, thereby permltting tubing 59 to be raised, separating outer sleeve 61 from the inner sleeve 62.
Slot 63 can ~e a groove having a depth less than the thickness of sleeve 61, or it can extend through the sleeve 61. while the slot 63 and pin 64 have been .-..~
13 20215~8 illustrated on sleeves 61 and 62, respectively, they can be reversed ~f desired.
The downhole completion assembly, comprising on-off tool 58, latch seal assembly 51 and tailpipe 55, can be attached to the lower end of production tubing string 59 and lowered lnto the w~llbore until the latch seal assembly 51 is positioned within tubular element 30 and tailpipe 55 extends at least partially below the bore of the packer. The latch seal assembly can then be activated to engage the threaded portion of packer 34 to releasably secure the latch seal assembly to packer 34.
Production fluid from the producing formation can be passed from the bore of liner 18 through tailpipe 55, latch seal assembly 51, on-off tool 58 and production tubing 59 to the above ground production facillties.
If it is desirable to removing the tubing string 59 while the production is still viable, a plug can be lowered through the production tubing 59 and inserted -into one of the profile nipples 56, 57 in tailpipe 55 to seal off the producing formation. Then the on-off tool 58 can be rotated to disconnect the production tubing 59 from latch seal assembly 51, and the production tubing 59 can be withdrawn from the well. If for any reason it ls desired to retrieve the latch seal assembly 51 and tailpipe 55, the tubing string 59 can be rotated to unscrew the latch seal assembly from the packer 34, and then the tubing 59, on-off tool 59, latch seal assembly 51 and tailpipe 55 can be withdrawn ln a slngle trip of the tubing.
Each of liner hanger 21, PBR 23, packer 34, seal unlt 31, latch seal assembly 51, tallplpe 55 and on-off tool 58 can be any suitable device whlch is commercially available for the intended purpose. While the devices selected can vary according to the size and other .
environmental limitations, one suitable combination for isolating and completing a 4-1/2" liner hung from a 7~
casing, with a 2-7/8~ productlon tublng, is as follows:
Device ComrnerclallY Available Equipment On-off tool S8 7" x 2-7/8" Gulberson XL on-off tool with 3 bonded seals (10,000 psi pressure rating), model #89207, with a 2.313n type X proflle nipple Latch seal 51 4" x 2-7/8" latch seal assembly containing a Guiberson model #83089 latch seal nipple, a one foot seal unit model i~83082, and a crossover to 2-7/8" tublng thread Packer 34 7" x 4.00" Guiberson bore magnum "GT" drillable packer, model #82063 Tailpipe 55 One 10' x 2-7/8" N-80 tubing pup, one 2.313" type "XN~ profile nipple with 2.205" no-go, and one wireline re-entry collar.
The on-off tool can be released by slacking off on the tension on tubing 59, rotating tubing 59 1/4 turn to the left and then raising tubing 59. The on-off tool 58 can -;~
be automatically reset by slacking off on the tubing s9 with the two sleeves of the on-off tool contacting each ~ -other, and then pulling tenslon to insure that the tubing is latched. The latch seal 51 can be released by pulling 500 pounds tension and then rotating tubing 59 eight turns to the right. The latch seal automatically reseats upon being lowered lnto contact with the threads of packer 34 and slacking off of the tension of tubing 59. This system can be used for stimulation, production ~ -or workover operations. Reasonable variations and modifications are possible withln the scope of the foregoing description and the appended claims to the lnvention. -~
A `
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Claims (16)
1. In a wellbore which transverses various earth formations, a first string of pipe for lining a first vertical portion of said wellbore, said first string of pipe having a lower end which is above the bottom of said wellbore, a second string of pipe for lining a second vertical portion of said wellbore, said second vertical portion extending downwardly from said lower end of said first string of pipe, each of said first and second strings of pipe having an axial bore therethrough, the outer diameter of said second string of pipe being smaller than the inner diameter of said first string of pipe, a polished bore receptacle and liner hanger assembly connected to the upper end of said second string of pipe and having a fluid passageway therethrough, said assembly having a liner hanger positioned within the bore of said first string of pipe and in mechanical engagement with the interior surface of the bore of a lower portion of said first string of pipe to suspend said second string of pipe from said lower portion of said first string of pipe, said assembly having a polished bore receptacle with a polished interior bore forming at least a portion of said passageway, the improvement comprising a tubular packer positioned within the bore of said first string of pipe at a location above said assembly, said packer having at least one gripping means in frictional engagement with the interior surface of the bore of said first string of pipe to immobilize said packer in said first string of pipe, said packer having a tubular element with an internal bore extending axially therethrough, at least one annular packer seal extending circumferentially about said tubular element and in contact with the interior surface of the bore of said first string of pipe to provide a fluid seal between the exterior surface of said tubular element and the interior surface of the bore of said first string of pipe, a seal unit having a tubular member and at least one annular seal extending circumferentially about said tubular member, said seal unit being positioned in said polished interior bore with said at least one annular seal of said seal unit being in contact with said polished interior bore to form a fluid seal between said tubular member and said polished bore receptacle, means for connecting the upper portion of said tubular member of said seal unit to the lower portion of said tubular element of said packer, a string of tubing positioned within the bore of said first string of pipe, an on-off tool having a first sleeve and a second sleeve, means for connecting said first sleeve to the lower end of said string of tubing, means for releasably securing said first sleeve to said second sleeve, a latch and seal assembly having latching means in engagement with the upper portion of said tubular element of said packer, and having a tubular section extending downwardly from said latching means within said tubular element of said packer, at least one annular seal extending circumferentially about said tubular section and in contact with the interior surface of the internal bore of said tubular element of said packer to provide a fluid seal between the exterior surface of said latch and seal assembly and the interior surface of said internal bore of said packer, means for connecting said latch and seal assembly to said second sleeve of said on-off tool, a tailpipe, and means for connecting said tailpipe to the lower portion of said tubular section, whereby the only fluid communication between the interior of said second string of pipe and the interior of said string of tubing is through said tailpipe, said latch and seal assembly and said on-off tool.
2. Apparatus in accordance with claim 1 wherein said means for releasably securing said first sleeve to said second sleeve comprises:
one of said first and second sleeves having a J
shaped slot therein and the other of said first and second sleeves having a projection thereon which is adapted to project into and slide within said slot between a first position wherein said first and second sleeves are thereby secured together and a second position wherein said first and second sleeves are separated from each other.
one of said first and second sleeves having a J
shaped slot therein and the other of said first and second sleeves having a projection thereon which is adapted to project into and slide within said slot between a first position wherein said first and second sleeves are thereby secured together and a second position wherein said first and second sleeves are separated from each other.
3. Apparatus in accordance with claim 2 further comprising at least one profile nipple in said tailpipe, whereby a plug can be lowered through said string of tubing into said tailpipe to engage said profile nipple and thereby seal the interior of said second string of pipe from the interior of said tailpipe above the thus plugged profile nipple.
4. Apparatus in accordance with claim 3 wherein, in said polished bore receptacle and liner hanger assembly, said polished bore receptacle extends above said liner hanger.
5. Apparatus for isolating the annulus around a wellbore liner and for achieving downhole completion in a wellbore which transverses various earth formations, which comprises:
a first string of pipe positioned in said wellbore to serve as a liner for a first portion of said wellbore, said first string of pipe having an axial bore therethrough, the lower end of said first string of pipe being above the bottom of said wellbore, a second string of pipe, means for hanging said second string of pipe from within the bore of the lower portion of said first string of pipe to serve as a liner for a second portion of said wellbore, said second portion extending downwardly from the lower end of said first string of pipe, said second string of pipe having an axial bore therethrough, the outer diameter of said second string of pipe being less then the inner diameter of the bore of said first string of pipe, a tubular member extending upwardly from a first position within the bore of said second string of pipe to a second position within the bore of said first string of pipe above the upper end of said second string of pipe, one first annular seal between a lower portion of said tubular member, located within said second string of pipe, and the interior surface of the bore of the laterally adjacent portion of said second string of pipe, at least one second annular seal between an upper portion of said tubular member, located above said second string of pipe, and the interior surface of the bore of the laterally adjacent portion of said first string of pipe, a third string of pipe positioned within the bore of said first string of pipe, said third string of pipe having on the lower end thereof an on-off tool, a latch and seal assembly connected to the lower end of said on-off tool, and a tailpipe extending downwardly from said latch and seal assembly, said latch and seal assembly being positioned within said tubular member, and said tailpipe extending at least partially into the bore of said second string of pipe, said latch and seal assembly releasably securing said latch and seal assembly to said tubular member and providing a fluid seal for the annulus between the interior surface of tubular member and the exterior surface of said latch and seal assembly.
a first string of pipe positioned in said wellbore to serve as a liner for a first portion of said wellbore, said first string of pipe having an axial bore therethrough, the lower end of said first string of pipe being above the bottom of said wellbore, a second string of pipe, means for hanging said second string of pipe from within the bore of the lower portion of said first string of pipe to serve as a liner for a second portion of said wellbore, said second portion extending downwardly from the lower end of said first string of pipe, said second string of pipe having an axial bore therethrough, the outer diameter of said second string of pipe being less then the inner diameter of the bore of said first string of pipe, a tubular member extending upwardly from a first position within the bore of said second string of pipe to a second position within the bore of said first string of pipe above the upper end of said second string of pipe, one first annular seal between a lower portion of said tubular member, located within said second string of pipe, and the interior surface of the bore of the laterally adjacent portion of said second string of pipe, at least one second annular seal between an upper portion of said tubular member, located above said second string of pipe, and the interior surface of the bore of the laterally adjacent portion of said first string of pipe, a third string of pipe positioned within the bore of said first string of pipe, said third string of pipe having on the lower end thereof an on-off tool, a latch and seal assembly connected to the lower end of said on-off tool, and a tailpipe extending downwardly from said latch and seal assembly, said latch and seal assembly being positioned within said tubular member, and said tailpipe extending at least partially into the bore of said second string of pipe, said latch and seal assembly releasably securing said latch and seal assembly to said tubular member and providing a fluid seal for the annulus between the interior surface of tubular member and the exterior surface of said latch and seal assembly.
6. Apparatus in accordance with claim 5 wherein said on-off tool comprises a first sleeve and a second sleeve, one of said first and second sleeves having a J
shaped slot therein and the other of said first and second sleeves having a projection thereon which is adapted to project into and slide within said slot between a first position wherein said first and second sleeves are thereby secured together and a second position wherein said first and second sleeves are separated from each other, means for connecting said first sleeve to the lower end of said third string of pipe, and means for securing said second sleeve to said latch and seal assembly.
shaped slot therein and the other of said first and second sleeves having a projection thereon which is adapted to project into and slide within said slot between a first position wherein said first and second sleeves are thereby secured together and a second position wherein said first and second sleeves are separated from each other, means for connecting said first sleeve to the lower end of said third string of pipe, and means for securing said second sleeve to said latch and seal assembly.
7. Apparatus in accordance with claim 6 wherein said tubular member and said at least one second annular seal constitute a packer.
8. Apparatus in accordance with claim 7 further comprising at least one profile nipple in said tailpipe.
9. A method of isolating the annulus around a wellbore liner and for achieving downhole completion in a wellbore which transverses various earth formations, which comprises:
installing a first string of pipe in said wellbore to serve as a liner for a first portion of said wellbore, said first string of pipe having an axial bore therethrough, the lower end of said first string of pipe being above the bottom of said wellbore, hanging, from within the lower portion of said first string of pipe, a second string of pipe to serve as a liner for a second portion of said wellbore, said second portion extending downwardly from the lower end of said first string of pipe, said second string of pipe having an axial bore therethrough, the outer diameter of said second string of pipe being less than the inner diameter of the bore of said first string of pipe, positioning a tubular member so that it extends upwardly from a first position within the bore of said second string of pipe to a second position within the bore of said first string of pipe above the upper end of said second string of pipe, providing an annular seal between a lower portion of said tubular member, located within said second string of pipe, and the interior surface of the bore of the laterally adjacent portion of said second string of pipe, providing an annular seal between an upper portion of said tubular member, located above said second string of pipe, and the interior surface of the laterally adjacent portion of said first string of pipe, lowering through the axial bore of said first string of pipe a third string of pipe, having on the lower end thereof an on-off tool, a latch and seal assembly connected to the lower end of said on-off tool, and a tailpipe extending downwardly from said latch and seal assembly, until said latch and seal assembly is positioned within said tubular member and said tailpipe extends at least partially below the bore of said tubular member, and activating said latch and seal assembly to releasably secure said latch and seal assembly to said tubular member and to provide a fluid seal for the annulus between the interior surface of tubular member and the exterior surface of said latch and seal assembly.
installing a first string of pipe in said wellbore to serve as a liner for a first portion of said wellbore, said first string of pipe having an axial bore therethrough, the lower end of said first string of pipe being above the bottom of said wellbore, hanging, from within the lower portion of said first string of pipe, a second string of pipe to serve as a liner for a second portion of said wellbore, said second portion extending downwardly from the lower end of said first string of pipe, said second string of pipe having an axial bore therethrough, the outer diameter of said second string of pipe being less than the inner diameter of the bore of said first string of pipe, positioning a tubular member so that it extends upwardly from a first position within the bore of said second string of pipe to a second position within the bore of said first string of pipe above the upper end of said second string of pipe, providing an annular seal between a lower portion of said tubular member, located within said second string of pipe, and the interior surface of the bore of the laterally adjacent portion of said second string of pipe, providing an annular seal between an upper portion of said tubular member, located above said second string of pipe, and the interior surface of the laterally adjacent portion of said first string of pipe, lowering through the axial bore of said first string of pipe a third string of pipe, having on the lower end thereof an on-off tool, a latch and seal assembly connected to the lower end of said on-off tool, and a tailpipe extending downwardly from said latch and seal assembly, until said latch and seal assembly is positioned within said tubular member and said tailpipe extends at least partially below the bore of said tubular member, and activating said latch and seal assembly to releasably secure said latch and seal assembly to said tubular member and to provide a fluid seal for the annulus between the interior surface of tubular member and the exterior surface of said latch and seal assembly.
10. A method in accordance with claim 9 further comprising producing fluid from at least one of said earth formations by passing fluid from the bore of said second string of pipe through said tailpipe, said latch and seal assembly, said on-off tool and said third string of pipe to above ground production facilities.
11. A method in accordance with claim 9 further comprising inserting a plug in said tailpipe, activating said on-off tool to disconnect said third string of pipe from said latch and seal assembly, and withdrawing said third string of pipe from the wellbore while the interior of the bore of said second string of pipe below said tailpipe is isolated from the interior of the bore of said first string of pipe.
12. A method in accordance with claim 9 further comprising causing said latch and seal assembly to become released from said tubular member, and, thereafter simultaneously withdrawing said third string of pipe, said on-off tool, said latch and seal assembly and said tailpipe from said wellbore.
13. A method of achieving downhole completion in a wellbore which transverses various earth formations, a first string of pipe having been installed in said wellbore to serve as a liner for a first portion of said wellbore, said first string of pipe having an axial bore therethrough, the lower end of said first string of pipe being above the bottom of said wellbore, a second string of pipe having been hung from within the lower portion of said first string of pipe, to serve as a liner for a second portion of said wellbore, said second portion extending downwardly from the lower end of said first string of pipe, said second string of pipe having an axial bore therethrough, the outer diameter of said second string of pipe being less than the inner diameter of the axial bore of said first string of pipe, a tubular member having been positioned in said wellbore extending upwardly from a first position within the axial bore of said second string of pipe to a second position within the axial bore of said first string of pipe above the upper end of said second string of pipe, said tubular member having an annular seal between a lower portion of said tubular member, located within said second string of pipe, and the interior surface of the laterally adjacent portion of said second string of pipe, said tubular member having an annular seal between an upper portion of said tubular member, located above said second string of pipe, and the interiro surface of the laterally adjacent portion of said first string of pipe, which comprises the steps of:
lowering through the axial bore of said first string of pipe a third string of pipe, having on the lower end thereof an on-off tool, a latch and seal assembly connected to the lower end of said on-off tool, and a tailpipe extending downwardly from said latch and seal assembly, until said latch and seal assembly is positioned with said tubular member and said tailpipe extends at least partially below the bore of said tubular member, and activating said latch and seal assembly to releasably secure said latch and seal assembly to said tubular member and to provide a fluid seal for the annulus between the interior surface of tubular member and the exterior surface of said latch and seal assembly.
lowering through the axial bore of said first string of pipe a third string of pipe, having on the lower end thereof an on-off tool, a latch and seal assembly connected to the lower end of said on-off tool, and a tailpipe extending downwardly from said latch and seal assembly, until said latch and seal assembly is positioned with said tubular member and said tailpipe extends at least partially below the bore of said tubular member, and activating said latch and seal assembly to releasably secure said latch and seal assembly to said tubular member and to provide a fluid seal for the annulus between the interior surface of tubular member and the exterior surface of said latch and seal assembly.
14. A method in accordance with claim 13 further comprising producing fluid from at least one of said earth formations by passing fluid from the bore of said second string of pipe through said tailpipe, said latch and seal assembly, said on-off tool and said third string of pipe to above ground production facilities.
15. A method in accordance with claim 13 comprising inserting a plug in said tailpipe, activating said on-off tool to disconnect said third string of pipe from said latch and seal assembly, and withdrawing said third string of pipe from the wellbore while the interior of the bore of said second string of pipe below said tailpipe is isolated from the interior of the bore of said first string of pipe.
16. A method in accordance with claim 13 further comprising causing said latch and seal assembly to become released from said tubular member, and thereafter simultaneously withdrawing said third string of pipe, said on-off tool, said latch and seal assembly and said tailpipe from said wellbore.
Applications Claiming Priority (2)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US07/396,563 US4942925A (en) | 1989-08-21 | 1989-08-21 | Liner isolation and well completion system |
| US396,563 | 1989-08-21 |
Publications (2)
| Publication Number | Publication Date |
|---|---|
| CA2021518A1 CA2021518A1 (en) | 1991-02-22 |
| CA2021518C true CA2021518C (en) | 1994-04-05 |
Family
ID=23567736
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA002021518A Expired - Fee Related CA2021518C (en) | 1989-08-21 | 1990-07-19 | Liner isolation and well completion system |
Country Status (4)
| Country | Link |
|---|---|
| US (1) | US4942925A (en) |
| CA (1) | CA2021518C (en) |
| GB (1) | GB2235939B (en) |
| NO (1) | NO903659L (en) |
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| CA2163946C (en) * | 1995-11-28 | 1997-10-14 | Integrated Production Services Ltd. | Dizzy dognut anchoring system |
| US5642782A (en) * | 1995-12-28 | 1997-07-01 | Dynamic Oil Tools Inc. | Downhole clutch assembly |
| CA2216668C (en) * | 1997-09-23 | 2000-12-26 | Michael Jonathon Haynes | Telescoping joint for use in a conduit connected to a wellhead and zone isolating tool for use therewith |
| US6557640B1 (en) | 1998-12-07 | 2003-05-06 | Shell Oil Company | Lubrication and self-cleaning system for expansion mandrel |
| US7357188B1 (en) | 1998-12-07 | 2008-04-15 | Shell Oil Company | Mono-diameter wellbore casing |
| AU770359B2 (en) * | 1999-02-26 | 2004-02-19 | Shell Internationale Research Maatschappij B.V. | Liner hanger |
| US6302203B1 (en) * | 2000-03-17 | 2001-10-16 | Schlumberger Technology Corporation | Apparatus and method for communicating with devices positioned outside a liner in a wellbore |
| US6382324B1 (en) * | 2000-06-20 | 2002-05-07 | Schlumberger Technology Corp. | One trip seal latch system |
| GB2409217B (en) | 2001-08-20 | 2005-12-28 | Enventure Global Technology | Apparatus for radially expanding tubular members including an adjustable expansion device |
| WO2004081346A2 (en) | 2003-03-11 | 2004-09-23 | Enventure Global Technology | Apparatus for radially expanding and plastically deforming a tubular member |
| CA2471875A1 (en) * | 2001-12-27 | 2003-07-17 | Enventure Global Technology | Seal receptacle using expandable liner hanger |
| US20030201102A1 (en) * | 2002-02-07 | 2003-10-30 | Baker Hughes Incorporated | Liner top test packer |
| CA2482743C (en) | 2002-04-12 | 2011-05-24 | Enventure Global Technology | Protective sleeve for threaded connections for expandable liner hanger |
| EP1501645A4 (en) | 2002-04-15 | 2006-04-26 | Enventure Global Technology | Protective sleeve for threaded connections for expandable liner hanger |
| AU2003265452A1 (en) | 2002-09-20 | 2004-04-08 | Enventure Global Technology | Pipe formability evaluation for expandable tubulars |
| US7886831B2 (en) | 2003-01-22 | 2011-02-15 | Enventure Global Technology, L.L.C. | Apparatus for radially expanding and plastically deforming a tubular member |
| GB2415988B (en) | 2003-04-17 | 2007-10-17 | Enventure Global Technology | Apparatus for radially expanding and plastically deforming a tubular member |
| US7195073B2 (en) * | 2003-05-01 | 2007-03-27 | Baker Hughes Incorporated | Expandable tieback |
| US7712522B2 (en) | 2003-09-05 | 2010-05-11 | Enventure Global Technology, Llc | Expansion cone and system |
| WO2006020960A2 (en) | 2004-08-13 | 2006-02-23 | Enventure Global Technology, Llc | Expandable tubular |
| WO2008032112A1 (en) * | 2006-09-11 | 2008-03-20 | Philip Head | Well construction and completion |
| US8985221B2 (en) * | 2007-12-10 | 2015-03-24 | Ngsip, Llc | System and method for production of reservoir fluids |
| US20110094755A1 (en) * | 2009-10-28 | 2011-04-28 | Chevron U.S.A. Inc. | Systems and methods for initiating annular obstruction in a subsurface well |
| US8297368B2 (en) * | 2009-10-28 | 2012-10-30 | Chevron U.S.A. Inc. | Systems and methods for initiating annular obstruction in a subsurface well |
| FR2937076B1 (en) * | 2010-01-07 | 2011-03-11 | Saltel Ind | PROCESS FOR REPAIRING A LOST COLUMN SUSPENSION, DEVICE AND BRAKE FOR ITS IMPLEMENTATION |
| US9016364B2 (en) | 2010-11-23 | 2015-04-28 | Wireline Solutions, Llc | Convertible multi-function downhole isolation tool and related methods |
| US9151127B1 (en) * | 2011-12-27 | 2015-10-06 | Christopher A. Branton | On/off tool running and well completion method and assembly |
| US9260926B2 (en) | 2012-05-03 | 2016-02-16 | Weatherford Technology Holdings, Llc | Seal stem |
| US20140202241A1 (en) * | 2013-01-18 | 2014-07-24 | Group 42, Inc. | Liner Top Test Tool and Method of Use |
| EP3088655A1 (en) * | 2015-04-29 | 2016-11-02 | Welltec A/S | Downhole tubular assembly of a well tubular structure |
| US10087695B1 (en) | 2018-02-21 | 2018-10-02 | Texas Oilwell Partners | Downhole safety valve and method of application |
| US10837245B2 (en) | 2018-06-28 | 2020-11-17 | Saudi Arabian Oil Company | Liner hanger system |
| CN109386247A (en) * | 2018-11-27 | 2019-02-26 | 中国石油天然气股份有限公司 | A kind of expandable casing patching time is slotting every tool of adopting and application method |
| US20230003097A1 (en) * | 2021-06-30 | 2023-01-05 | Welltec Oilfield Solutions Ag | Annular barrier |
| EP4112874A1 (en) * | 2021-06-30 | 2023-01-04 | Welltec Oilfield Solutions AG | Annular barrier |
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| US3993128A (en) * | 1976-02-18 | 1976-11-23 | Texas Iron Works, Inc. | Well tool for setting and supporting liners |
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| US4482014A (en) * | 1982-07-12 | 1984-11-13 | Mwl Tool & Supply Company | Barrier tool for polished bore receptacle |
| US4646842A (en) * | 1984-04-20 | 1987-03-03 | Texas Iron Works, Inc. | Retrievable well bore assembly |
| US4688642A (en) * | 1984-10-09 | 1987-08-25 | Texas Iron Works, Inc. | Rotatable liner with multiple simultaneously set liner hanger arrangement and method |
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| US4601343A (en) * | 1985-02-04 | 1986-07-22 | Mwl Tool And Supply Company | PBR with latching system for tubing |
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| CA1262233A (en) * | 1985-12-16 | 1989-10-10 | Hughes Tool Company | Combination landing unit and seal assembly |
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| US4671358A (en) * | 1985-12-18 | 1987-06-09 | Mwl Tool Company | Wiper plug cementing system and method of use thereof |
| US4712615A (en) * | 1986-07-01 | 1987-12-15 | Lindsey Completion Systems | Liner hanger assembly with setting tool |
| US4712614A (en) * | 1986-08-29 | 1987-12-15 | Lindsey Completion Systems | Liner hanger assembly with combination setting tool |
| US4825954A (en) * | 1988-02-12 | 1989-05-02 | Baker Hughes Incorporated | Liner hanger with improved bite and method |
| US4823872A (en) * | 1988-04-22 | 1989-04-25 | Baker Hughes Incorporated | Downhole locking apparatus |
| US4828037A (en) * | 1988-05-09 | 1989-05-09 | Lindsey Completion Systems, Inc. | Liner hanger with retrievable ball valve seat |
-
1989
- 1989-08-21 US US07/396,563 patent/US4942925A/en not_active Expired - Lifetime
-
1990
- 1990-07-19 CA CA002021518A patent/CA2021518C/en not_active Expired - Fee Related
- 1990-08-17 GB GB9018115A patent/GB2235939B/en not_active Expired - Fee Related
- 1990-08-20 NO NO90903659A patent/NO903659L/en unknown
Also Published As
| Publication number | Publication date |
|---|---|
| NO903659D0 (en) | 1990-08-20 |
| GB2235939A (en) | 1991-03-20 |
| GB9018115D0 (en) | 1990-10-03 |
| NO903659L (en) | 1991-02-22 |
| US4942925A (en) | 1990-07-24 |
| CA2021518A1 (en) | 1991-02-22 |
| GB2235939B (en) | 1993-02-03 |
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Legal Events
| Date | Code | Title | Description |
|---|---|---|---|
| EEER | Examination request | ||
| MKLA | Lapsed |