BAKER HUGHES INCORPORATED AND
`BAKER HUGHES OILFIELD
`OPERATIONS, INC.
`Exhibit 1010
`BAKER HUGHES INCORPORATED AND
`BAKER HUGHES OILFIELD
`OPERATIONS, INC. v. PACKERS PLUS
`ENERGY SERVICES, INC.
`IPR2016-00598
`
`Page 1 of 21
`
`

`
`(12) Ulllted States Patent
`Kilgore
`
`(10) Patent N0.:
`(45) Date of Patent:
`
`US 6,257,338 B1
`Jul. 10, 2001
`
`USO(l6257338B1
`
`3/1994 Loughlin ............................ .. 166/387
`5,297,634 *
`4/1994 George et 91-
`-
`5,301,755
`
`9/1994 Screm et al.
`5,350,018 :
`.................. .. 166/187 X
`22:21:? 41:13:: 15:21:65:
`842711;
`£2;/1332
`;&::.ts)c())ne::ta;1a.1...
`166/250.07X
`5,555,945 *
`9/1996 S‘h lt
`t
`l.
`..... ..
`........ 166/387
`5,577,560 * 11/1996 C:)r1dn:d:):tal.
`5,692,564 * 12/1997 Brooks ................ .. 166/185X
`5,767,400 *
`6/1998 Nakano etal.
`..
`. 166/254.1X
`5,803,135 *
`9/1998 Berger et a1.
`155/254 X
`5,941,307 *
`8/1999 Tubel
`. . . . . . . . . . .
`.. . .. 166/313
`6,056,059 *
`5/2000 Ohmer
`............................... .. 166/313
`* cited by examiner
`.
`.
`.
`Primary Exammer—David Bagiiell
`Assistant Examiner—.long-Suk Lee
`S[4)1.*"fi”’;9".m*‘ge”” 0’ F’""—W1“‘am M" “Wane;
`at 1“
`' ml
`(57)
`
`
`
`ABSTRACT
`
`Apparatus and corresponding methods are disclosed for
`controlling fluid flow Within a subterranean Well.
`In a
`described embodiment, a longitudinally spaced apart series
`of selectively set and unset inflatable packers is utilized to
`substantially isolate desired portions of a formation inter-
`t d b
`1 11. S tt'
`d
`tt'
`f th
`k
`Sec 6
`y a.“
`e lug.” “"56 .mg 0
`3 P“ 5“ may
`e accomplished by a variety of devices, some of which may
`b
`1
`11 bl
`dd. .
`11
`.
`f fl
`.d
`3 remote Y Comm *1
`9- A mo“ Y’ a SW95 0
`“1
`e0HtF01deVieeS mayee alternated With the Paekers as Part Of
`a tubular string positioned Witlini the Well.
`
`31 Claims, 10 Drawing Sheets
`
`(54) METHOD AND APPARATUS FOR
`CONTROLLING FLUID FLOW WITHIN
`WELLBORE WITH SELECTIVELY SET AND
`
`Inventor: Marion D. Kilgore, Dallas, TX (US)
`(75)
`.
`.
`,
`(73) Asslgnee‘ Ha"‘b“”°“ Energy S°rV‘°°5’ I“°'>
`D‘<t11aS>TX(US)
`.
`.
`.
`.
`SLll)_]CCt to any disclaimer, the term of this
`patent is extended or adjusted under 35
`U.S.C. i54(b) by0 days.
`
`.
`( * ) Notice:
`
`(21) Appl. N0.: 09/184,770
`
`Filedi
`NOV- 2, 1993
`(22)
`Int. Cl.7 ............................. E21B 33/12, E21B 43/12
`(51)
`(52) U.s. Cl.
`........................... 166/387; 166/50; 166/651;
`166/187; 166/313
`(58) Field of Search ............................ .. 166/313, 50, 387,
`166/651’ 187’ 106
`
`(56)
`'
`
`References Cited
`
`U.S. PATENT DOCUMENTS
`
`4,378,850
`*
`4,535,843
`4,756,364 *
`4,942,926 *
`5,002,485
`5,070,941
`5,127,477
`
`4/1983 Barrington .
`8/1985 Jageler ........................... .. 166/187 X
`
`7/1988 Christensen eta].
`166/187X
`7/1990 Lessi
`...........................
`166/50 X
`11/1991 Wesson et a1.
`.
`12/1991 Kilgore.
`7/1992 Schult7 .
`
`16
`
`18
`
`10
`’/
`
`“2"EllIEll8
`
`
`,,I1§"C¥=:-.-.'.;.‘.-.::'.1..
`
`‘IV-
`
`
`
`
`
`38e
`
`34°
`
`409
`
`14e
`
`
`
`
`
` 42e
`
`,, «=4;e.w;.i:-ai%ae%i.EE1%e
`
`-—IuI—IuI—Iu»
`-"-'i.'..:i’f-‘nu-‘u1v;i'-ii?-:1‘
` ml‘?
`
`
`'
` mEmE
`
`
`Page 1 of 21
`Page 1 of 21
`
`

`
`U.S. Patent
`
`Jul. 10,2001
`
`Sheet 1 of 10
`
`US 6,257,338 B1
`
`
`
`16
`
`
`
`G
`
`18
`
`
`38
`32
`36
`so
` ElnmEm@EmraW
`%’%»s\..%e:.;-'51:.--E--—-H’
`ZIAVZQZ
`u(¢‘=‘ El!!!’-=1’! ax '2!!!‘-=| é
`
`/
`
`
`
`Page 2 of 21
`Page 2 of 21
`
`

`
`U.S. Patent
`
`Jul. 10, 2001
`
`Sheet 2 of 10
`
`US 6,257,338 B1
`
`
`
`233
`52
`30a 36a
`32a 38a
`34a
`40a
`
`"'I€mEW§mEfllEmEflEIm@I1|§lIlE
`ll-—.!"Q-.
`§i-_iII|:1I—II:Il$luo
`
`
`
`
`423
`
`
`
`
`«vréitaaanliawxamansgaaieauayeameaxm
`\‘5='L!.U.I..—._..!§.I_—__!_TQI_.C_I
`~§Ell—IuIgluI=lub
`'
`
`
`
`
`
`
`
`
`
`Page 3 of 21
`Page 3 of 21
`
`

`
`U.S. Patent
`
`Jul. 10, 2001
`
`Sheet 3 of 10
`
`US 6,257,338 B1
`
`
`
`:a‘13".E«‘v_"E£:%i‘uEv.Ev'§'7-iv§§.¥rE’
`
`
`
`l|I=luI—IuIgIup
`
`12d 30d
`
`
`
`«new
`
`14d
`
`
`'!9}}'.'.‘.".-'L';'£%'.EE'.'.'£'.'l
`
`
`
`alnamsmannanr
`
`1
`
`42d
`
`26d
`
`Page 4 of 21
`Page 4 of 21
`
` n _
`
`86
`
`

`
`U.S. Patent
`
`Jul. 10, 2001
`
`Sheet 4 of 10
`
`US 6,257,338 B1
`
`
`
`
`‘\a:v'2-awfia-+'aw%?
`
`«-3,,
`_u_—;::_|_g—nul—luo
`5,-",;,;‘g:.n1nnuvs-rung‘
`
`
`-.
`
`
`
`
`
`
`
`
`
`E
`\—'_‘ml
`EE E 42f
`
`-.9.-.-.1;-.'.e.-,-fig.-.-Le.-.-.:.*I
`
`
`‘ §1!IE]I(’é1Il!EllIEl!.'Ei|IlElIII‘-:5IIrl
`13122 12233‘22r
`24t38f‘22 122 4o:
`
`
`
`. 26,
`
`
`FIG. 8
`
`Page 5 of 21
`Page 5 of 21
`
`

`
`tnw3P&U
`
`0
`
`S
`
`1cl
`
`1B8
`
`
`
`.1l.‘\|l.llll.‘‘HIII-»fifl..vm@....fl
`
`Wm.m.m.mmm.
`
`460%80wmM3
`
`
`
`0wII..I.|I|l.|¢.I...../V‘IlaAHII,.
`
`hn
`
`GH
`
`mmWO2,6Mm.Um/P
`
`Page 6 of 21
`
`
`

`
`tnmaPS”U
`
`m
`
`1VFFmmm!)I1mml.m
`.,G.I
`
`
`
`iii.‘M\...\I:...NIW‘,m1e01A.M1O\11
`
`11V.04M...
`
`U6P
`6m...mMm11122
`
`mmEpm27
`
`Page 7 of 21
`
`
`
`

`
` U.S.Patent
`
`FIG. 12
`
`Jul. 10, 2001
`
`Sheet 7 of 10
`
`US 6,257,338 B1
`
`0
`
`1V‘23.
`
`/.
`
`2
`
`190
`
`‘ l N ' '
`
`FIG. 13
`
`Page 8 of 21
`Page 8 of 21
`
`

`
`U.S. Patent
`
`Jul. 10, 2001
`
`Sheet 8 of 10
`
`US 6,257,338 B1
`
`214
`
`/
`
`226
`
`216
`
`226
`
`218
`
`228
`
`226
`
`222
`
`220
`
`,
`
`224
`
`226
`
`230
`
`231
`
`
`
`Page 9 of 21
`Page 9 of 21
`
`

`
`U.S. Patent
`
`Jul. 10, 2001
`
`Sheet 9 of 10
`
`US 6,257,338 B1
`
`242
`
`/
`
`
`
`265
`
`284
`
`272
`
`290
`
`2
`
`78 WT
`
`*2
`.""-_—.'-—_.
`‘“*““""—§74 292
`,v.
`
`——..j._.._j—_..._._
`
`
`
`264
`
`X
`
`Page 10 of 21
`Page 10 of 21
`
`

`
`U.S. Patent
`
`Jul. 10, 2001
`
`Sheet 10 of 10
`
`US 6,257,338 B1
`
`296
`
`Page 11 of 21
`Page 11 of 21
`
`

`
`US 6,257,338 Bl
`
`1
`METHOD AND APPARATUS FOR
`CONTROLLING FLUID FLOW WITHIN
`WELLBORE WITH SELECTIVELY SET AND
`UNSET PACKER ASSEMBLY
`BACKGROUND OF THE INVENTION
`
`invention relates generally to operations
`The present
`performed within subterranean wells and, in an embodiment
`described herein, more particularly provides apparatus and
`methods for controlling fluid flow within a subterranean
`well.
`
`In horizontal well open hole completions, fluid migration
`has typically been controlled by positioning a production
`tubing string within the horizontal wellbore intersecting a
`formation. An annulus formed between the wellbore and the
`tubing string is then packed with gravel. A longitudinally
`spaced apart series of sliding sleeve valves in the tubing
`string provides fluid communication with selected portions
`of the formation in relatively close proximity to an open
`valve, while somewhat restricting fluid communication with
`portions of the formation at greater distances from an open
`valve. In this manner, water and gas coning may be reduced
`in some portions of the formation by closing selected ones
`of the valves, while not affecting production from other
`portions of the formation.
`Unfortunately,
`the above method has proved
`unsatisfactory, inconvenient and inefficient for a variety of
`reasons. First,
`the gravel pack in the annulus does not
`provide sullicient fluid restriction to significantly prevent
`fluid migration longitudinally through the wellbore. Thus, an
`open valve in the tubing string may produce a significant
`volume of fluid from a portion of the formation longitudi-
`nally remote from the valve. However, providing additional
`fluid restriction in the gravel pack in order to prevent fluid
`migration longitudinally therethrough would also deleteri-
`ously affect production of fluid from a portion of the
`formation opposite an open valve.
`Second, it is difficult to achieve a uniform gravel pack in
`horizontal well completions. In many cases the gravel pack
`will be less dense and/or contain voids in the upper portion
`of the annulus. This situation results in a substantially
`unrestricted longitudinal flow path for migration of fluids in
`the wellbore.
`
`Third, in those methods which utilize the spaced apart
`series of sliding sleeve valves, intervention into the well is
`typically required to open or close selected ones of the
`valves. Such intervention usually requires commissioning a
`slickline rig, wireline rig, coiled tubing rig, or other
`equipment, and is very time-consuming and expensive to
`perform. Furthermore, well conditions may prevent or
`hinder these operations.
`Therefore, it would be advantageous to provide a method
`of controlling fluid flow within a subterranean well, which
`method does not rely on a gravel pack for restricting fluid
`flow longitudinally through the wellbore. Additionally, it
`would be advantageous to provide associated apparatus
`which permits an operator to produce or inject fluid from or
`into a selected portion of a formation intersected by the well.
`These methods and apparatus would be useful in open hole,
`as well as cased hole, completions.
`It would also be advantageous to provide a method of
`controlling fluid flow within a well, which does not require
`intervention into the well for its performance. Such method
`would permit remote control of the operation, without the
`need to kill the well or pass equipment through the wellbore.
`SUMMARY OF TIIE INVENTION
`
`In carrying out the principles of the present invention, in
`accordance with an embodiment thereof, a method is pro-
`
`10
`
`15
`
`30
`
`35
`
`40
`
`45
`
`50
`
`55
`
`60
`
`65
`
`2
`vided which utilizes selectively set and unset packers to
`control fluid flow within a subterranean well. The packers
`may be set or unset with a variety of power sources which
`may be installed along with the packers, provided at a
`remote location, or conveyed into the well when it is desired
`to set or unset selected ones of the packers. Associated
`apparatus is provided as well.
`In broad terms, a method of controlling fluid flow within
`a subterranean well is provided which includes the step of
`providing a tubing string including a longitudinally spaced
`apart series of wellbore sealing devices. The sealing devices
`are selectively engaged with the wellbore to thereby restrict
`fluid flow between the tubing string and a corresponding
`selected portion of a formation intersected by the wellbore.
`In one aspect of the present invention, the sealing devices
`are inflatable packers. The packers may be alternately
`inflated and deflated to prevent and permit, respectively,
`fluid flow longitudinally through the wellbore.
`In another aspect of the present invention, flow control
`devices are alternated with the sealing devices along the
`tubing string to provide selective fluid communication
`between the tubing string and portions of the formation in
`relatively close proximity to the flow control devices. Thus,
`an open flow control device positioned between two sealing
`devices engaged with the wellbore provides unrestricted
`fluid communication between the tubing string and the
`portion of the formation longitudinally between the two
`sealing devices, but fluid flow from other portions of the
`formation is substantially restricted.
`In yet another aspect of the present invention, the sealing
`devices and/or flow control devices may be actuated by
`intervening into the well, or by remote control. If interven-
`tion is desired, a fluid source, battery pack, shifting tool,
`pump, or other equipment may be conveyed into the well by
`slickline, wireline, coiled tubing, or other conveyance, and
`utilized to selectively adjust the flow control devices and
`selectively set or unset the sealing devices. If remote control
`is desired, the flow control devices and/or sealing devices
`may be actuated via a form of telemetry, such as mud pulse
`telemetry, radio waves, other electromagnetic waves, acous-
`tic telemetry, etc. Additionally,
`the flow control devices
`and/or sealing devices may be actuated via hydraulic, elec-
`tric and/or data transmission lines extending to a remote
`location, such as the earth’s surface or another location
`within the well.
`
`These and other features, advantages, benefits and objects
`of the present invention will become apparent to one of
`ordinary skill in the art upon careful consideration of the
`detailed descriptions of representative embodiments of the
`invention hereinbelow and the accompanying drawings.
`BRIEF DESCRIPTION OF THE DRAWINGS
`
`FIG. 1 is a schematicized cross-sectional view of a
`subterranean well;
`FIG. 2 is a schematicized partially cross-sectional and
`partially elevational View of the well of FIG. I, in which
`steps of a first method embodying principles of the present
`invention have been performed;
`FIG. 3 is a schematicized partially cross-sectional and
`partially elevational view of the well of FIG. 1, in which
`steps of a second method embodying principles of the
`present invention have been performed;
`FIG. 4 is a schematicized partially cross-sectional and
`partially elevational view of the well of FIG. 1, in which
`steps of a third method embodying principles of the present
`invention have been performed;
`
`Page 12 of 21
`Page 12 of 21
`
`

`
`US 6,257,338 B1
`
`3
`FIG. 5 is a schematicized partially cross-sectional and
`partially elevational View of the well of FIG. 1, in which
`steps of a fourth method embodying principles of the present
`invention have been performed;
`FIG. 6 is a schematicized partially cross-sectional and
`partially elevational View of the well of FIG. 1, in which
`steps of a fifth method embodying principles of the present
`invention have been performed;
`FIG. 7 is a schematicized partially cross-sectional and
`partially elevational View of the well of FIG. 1, in which
`steps of a sixth method embodying principles of the present
`invention have been performed;
`FIG. 8 is a schematicized partially cross-sectional and
`partially elevational View of the well of FIG. 1, in which
`steps of a seventh method embodying principles of the
`present invention have been performed;
`FIG. 9 is a schematicized cross-sectional View of a first
`
`apparatus embodying principles of the present invention;
`FIG. 10 is a schematicized quarter-sectional View of a first
`release device embodying principles of the present invention
`which may be used with the first apparatus;
`FIG. 11 is a schematicized quarter-sectional View of a
`second release device embodying principles of the present
`invention which may be used with the first apparatus;
`FIG. 12 is a schematicized quarter-sectional View of a
`second apparatus embodying principles of the present inven-
`tion;
`FIG. 13 is a schematicized quarter-sectional View of a
`third apparatus embodying principles of the present inven-
`tion;
`FIG. 14 is a schcmaticizcd quartcr-scctional view of a
`fourth apparatus embodying principles of the present inven-
`tion;
`FIG. 15 is a cross-sectional View of an atmospheric
`chamber embodying principles of the present invention;
`FIG. 16 is a scheniaticized View of a fifth apparatus
`embodying principles of the present invention;
`FIG. 17 is a schematicized View of a sixth apparatus
`embodying principles of the present invention;
`FIG. 18 is a schematicized elevational View of a seventh
`
`apparatus embodying principles of the present invention;
`and
`
`FIG. 19 is a schematicized elevational View of an eighth
`apparatus embodying principles of the present invention.
`DETAILED DESCRIPTION
`
`Representatively and schematically illustrated in FIG. 1 is
`a method 10 which embodies principles of the present
`invention. In the following description of the method 10 and
`other apparatus and methods described herein, directional
`terms, such as “above”, “below”, “upper”, “lower”, etc., are
`used for convenience in referring to the accompanying
`drawings. Additionally, it is to be understood that the various
`embodiments of the present invention described herein may
`be utilized in various orientations, such as inclined, inverted,
`horizontal, vertical, etc., without departing from the prin-
`ciples of the present invention.
`The method 10 is described herein as it is practiced in an
`open hole completion of a generally horizontal wellbore
`portion 12 intersecting a formation 14. However, it is to be
`clearly understood that methods and apparatus embodying
`principles of the present invention may be utilized in other
`environments, such as vertical wellbore portions, cased
`wellbore portions, etc. Additionally, the method 10 may be
`
`4
`performed in wells including both cased and uncased
`portions, and vertical, inclined and horizontal portions, for
`example, including the generally vertical portion of the well
`lined with casing 16 and cement 18. Furthermore,
`the
`method 10 is described in terms of producing fluid from the
`well, but
`the method may also be utilized in injection
`operations. As used hcrcin, thc tcrm “wcllborc” is uscd to
`indicate an uncased wellbore (such as wellbore 12 shown in
`FIG. 1), or the interior bore ofthe casing or liner (such as the
`casing 16) if the wellbore has casing or liner installed
`therein.
`
`It will be readily appreciated by a person of ordinary skill
`in the art that if the well shown in FIG. 1 is completed in a
`conventional manner utilizing gravel surrounding a produc-
`tion tubing string including longitudinally spaced apart
`screens and/or sliding sleeve valves, Iluid from various
`longitudinal portions 20, 22, 24, 26 of the formation 14 will
`be permitted to migrate longitudinally through the gravel
`pack in the annular space between the tubing string and the
`wellbore 12. Of course, a sliding sleeve valve may be closed
`in an attempt to restrict fluid production from one of the
`formation portions 20, 22, 24, 26 opposite the valve, but this
`may have little actual effect, since the fluid may easily
`migrate longitudinally to another, open, valve in the pro-
`duction tubing string.
`Referring additionally now to FIG. 2, steps of the method
`10 have been performed which include positioning a tubing
`string 28 within the wellbore 12. The tubing string 28
`includes a longitudinally spaced apart series of sealing
`devices 30, 32, 34 and a longitudinally spaced apart series of
`flow control devices 36, 38, 40. The tubing string 28 extends
`to the earth’s surface, or to another location remote from the
`wellbore 12, and its distal end is closed by a bull plug 42.
`The sealing devices 30, 32, 34 are representatively and
`schematically illustrated in FIG. 2 as inflatable packers,
`which are capable of radially outwardly extending to seal-
`ingly engage the wellbore 12 upon application of fluid
`pressure to the packers. Of course, other types of packers,
`such as production packers settable by pressure, may be
`utilized for the packers 30, 32, 34, without departing from
`the principles of the present invention. The packers 30, 32,
`34 utilized in the method 10 have been modified somewhat,
`however, using techniques well within the capabilities of a
`person of ordinary skill in the art, so that each of the packers
`is independently inflatable. Thus, as shown in FIG. 2,
`packers 30 and 32 have been inflated, wl1ile packer 34
`remains deflated.
`
`In order to inflate a selected one of the packers 30, 32, 34,
`a fluid power source is conveyed into the tubing string 28,
`and fluid is flowed into the packer. For example, in FIG. 2
`a coiled tubing string 44 has been inserted into the tubing
`string 28, the coiled tubing string thereby forming a fluid
`conduit extending to the earth’s surface.
`At its distal end, the coiled tubing string 44 includes a
`latching device 46 and a fluid coupling 48. The latching
`device 46 is of conventional design and is used to positively
`position the fluid coupling 48 within the sclcctcd one of the
`packers 30, 32, 34. For this purpose, each of the packers 30,
`32, 34 includes a conventional internal latching profile (not
`shown in FIG. 2) formed therein.
`The coupling 48 provides fluid communication between
`the interior of the coiled tubing string 44 and the packer 30,
`32, 34 in which it is engaged. Thus, when the coupling 48
`is engaged within the packer 30 as shown in FIG. 2, fluid
`pressure may be applied to the coiled tubing string 44 and
`communicated to the packer via the coupling 48. Deflation
`
`10
`
`15
`
`30
`
`35
`
`40
`
`45
`
`50
`
`55
`
`60
`
`65
`
`Page 13 of 21
`Page 13 of 21
`
`

`
`US 6,257,338 Bl
`
`5
`of a previously inflated packer may be accomplished by
`relieving fluid pressure from within a selected one of the
`packers 30, 32, 34 via the coupling 48 to the coiled tubing
`string 44, or to the interior of the tubing string 28, etc.
`Therefore, it may be clearly seen that each of the packers 30,
`32, 34 may be individually and selectively set and unset
`within thc wcllborc 12.
`
`The flow control devices 36, 38, 40 are representatively
`illustrated as sliding sleeve—type valves. However, it is to be
`understood that other types of flow control devices may be
`used for the valves 36, 38, 40, without departing from the
`principles of the present invention. For example, the valves
`36, 38, 40 may instead be downhole chokes, pressure
`operated valves, remotely controllable valves, etc.
`Each of the valves 36, 38, 40 may be opened and closed
`independently and selectively to thereby permit or prevent
`fluid flow between the wellbore 12 external to the tubing
`string 28 and the interior of the tubing string. For example,
`the latching device 46 may be engaged with an internal
`profile of a selected one of the valves 36, 38, 40 to shift its
`sleeve to its open or closed position in a conventional
`manner.
`
`As representatively depicted in FIG. 2, packers 30 and 32
`have been inflated and the valve 36 has been closed, thereby
`preventing fluid migration through the wellbore 12 between
`the formation portion 22 and the other portions 20, 24, 26 of
`the formation 14. Note that fluid from the portion 22 may
`still migrate to the other portions 20, 24, 26 through the
`formation 14 itself, but such flow through the formation 14
`will typically be minimal compared to that which would
`otherwise be permitted through the wellbore 12. Thus, flow
`of fluids from the portion 22 to the interior of the tubing
`string 28 is substantially rcstrictcd by the mcthod 10. It will
`be readily appreciated that production of fluid from selected
`ones of the other portions 20, 24, 26 may also be substan-
`tially restricted by inflating other packers, such as packer 34,
`and closing other valves, such as valves 38 or 40.
`Additionally,
`inflation of the packer 30 may be used to
`substantially restrict production of fluid from the portion 20,
`without the need to close a valve.
`
`If, however, it is desired to produce fluid substantially
`only from the portion 22, the valve 36 may be opened and
`the other valves 38, 40 may be closed. Thus, the method 10
`permits each of the packers 30, 32, 34 to be selectively set
`or unsct, and permits cach of thc valves 36, 38, 40 to bc
`selectively opened or closed, which enables an operator to
`tailor production from the formation 14 as conditions war-
`rant. The use of variable chokes in place of the valves 36, 38,
`40 allows even further control over production from each of
`the portions 20, 22, 24, 26.
`As shown in FIG. 2, three packers 30, 32, 34 and three
`valves 36, 38, 40 are used in the method 10 to control
`production from four portions 20, 22, 24, 26 of the formation
`14. It will be readily appreciated that any other number of
`packers and any number of valves (the number of packers
`not necessarily being the same as the number of valves) may
`bc used to control production from any number of formation
`portions, as long as a sufficient number of packers is utilized
`to prevent flow through the wellbore between each adjacent
`pair of formation portions. Furthermore, production from
`additional formations intersected by the wellbore could be
`controlled by extending the tubing string 28 and providing
`additional sealing devices and flow control devices therein.
`Referring additionally now to FIG. 3, another method 50
`is schematically and representatively illustrated. Elements of
`the method 50 which are similar to those previously
`
`10
`
`15
`
`30
`
`35
`
`40
`
`45
`
`50
`
`55
`
`60
`
`65
`
`6
`described are indicated in FIG. 3 using the same reference
`numbers, with an added suflix “a”.
`The method 50 is in many respects similar to the method
`10. However, in the method 50, the power source used to
`inflate the packers 30a, 32a, 34a is a fluid pump 52 con-
`veyed into the tubing string 28a attached to a wireline or
`electric line 54 extending to the earth’s surface. The electric
`line 54 supplies electricity to operate the pump 52, as well
`as conveying the latching device 46a, pump, and coupling
`48a within the tubing string 28a. Other conveyances, such as
`slickline, coiled tubing, etc., may be used in place of the
`electric line 54, and electricity may be otherwise supplied to
`the pun1p 52, without departing from the principles of the
`present invention. For example, the pump 52 may include a
`battery, such as the Downhole Power Unit available from
`Halliburton Energy Services, Inc. of Duncan, Okla.
`As depicted in FIG. 3, the latching device 46a is engaged
`with the packer 30a, and the coupling 48a is providing fluid
`communication between the packer and the pump 52. Actua-
`tion of the pump 52 causes fluid to be pumped into the
`packer 30a, thereby inflating the packer, so that it sealingly
`engages the wellbore 12a. The packer 34a has been previ-
`ously inflated in a similar manner. Additionally, the valves
`36a, 38a have been closed to restrict fluid flow generally
`radially therethrough.
`Note that the packers 30a, 34a longitudinally straddle two
`of the formation portions 22a, 24a. Thus, it may be seen that
`fluid flow from multiple formation portions may be
`restricted in keeping with the principles of the present
`invention. If desired, another flow control device could be
`installed in the tubing string 28a above the packer 30a to
`selectively permit and prevent fluid flow into the tubing
`string directly from the formation portion 20a while the
`packer 30a is set within the wellbore 12a.
`Referring additionally now to FIG. 4, another method 60
`embodying principles of the present invention is represen-
`tatively illustrated. Elements shown in FIG. 4 which are
`similar to those previously described are indicated using the
`same reference numbers, with an added suffix “b”.
`The method 60 is similar in many respects to the method
`50, in that the power source used to set selected ones of the
`packers 30b, 32b, 34b includes the electric line 54b and a
`fluid pump 62. However,
`in this case the pump 62 is
`interconnected as a part of the tubing string 28b. Thus, the
`pump 62 is not separately conveyed into the tubing string
`28b, and is not separately engaged with the selected ones of
`the packers 30b, 32b, 34b by positioning it therein. Instead,
`fluid pressure developed by the pump 62 is delivered to
`selected ones of the packers 30b, 32b, 34b and valves 36b,
`38b, 40b Via lines 64.
`As used herein, the term “pump” includes any means for
`pressurizing a fluid. For example, the pump 62 could be a
`motorized rotary or axial pump, a hydraulic accumulator, a
`device which utilizes a pressure differential between hydro-
`static pressure and atmospheric pressure to produce hydrau-
`lic pressure, other types of fluid pressurizing devices, etc.
`Fluid pressure from the pump 62 is delivered to the lines
`64 as directed by a control module 66 interconnected
`between the pump and lines. Such control modules are well
`known in the art and may include a plurality of solenoid
`valves (not shown) for directing the pump fluid pressure to
`selected ones of the lines 64, in order to actuate correspond-
`ing ones of the packers 30b, 32b, 34b and valves 36]), 38b,
`40b. For example, if it is desired to inflate the packer 34b,
`the pump 62 is operated to provide fluid pressure to the
`control module 66, and the control module directs the fluid
`
`Page 14 of 21
`Page 14 of 21
`
`

`
`US 6,257,338 B1
`
`7
`pressure to an appropriate one of the lines 64 interconnect-
`ing the control module to the packer 34b by opening a
`corresponding solenoid valve in the control module.
`Electricity to operate the pump 62 is supplied by the
`electric line 54b extending to the earth’s surface. The
`electric line 54b is properly positioned by engaging the
`latching device 46b within the pump 62 or control module
`66. A wet connect head 68 of the type well known to those
`of ordinary skill in the art provides an electrical connection
`between the electric line 54b and the pump 62 and control
`module 66. Alternatively,
`the electric line 54b may be a
`slickline or coiled tubing, and electric power may be sup-
`plied by a battery installed as a part of the tubing string or
`conveyed separately therein. Of course, if the pump 62 is of
`a type which does not require electricity for its operation, an
`electric power source is not needed.
`The control module 66 directs the fluid pressure from the
`pump 62 to selected ones of the lines 64 in response to a
`signal transmitted thereto via the electric line 54b from a
`remote location, such as the earth’s surface. Thus,
`the
`clcctric line 54b performs scvcral functions in thc mcthod
`60: conveying the latching device 46b and wet connect head
`68 within the tubing string 28b, supplying electric power to
`operate the pump 62, and transmitting signals to the control
`module 66. Of course, it is not necessary for the electric line
`54b to perform all of these functions, and these functions
`may be performed by separate elements, without departing
`from the principles of the present invention.
`Note that the valves 36b, 38b, 40b utilized in the method
`60 differ from the valves in the previously described meth-
`ods 10, 50 in that
`they are pressure actuated. Pressure
`actuated valves are well known in the art. They may he of
`thc typc that is actuated to a closed or opcn position upon
`application of fluid pressure thereto and return to the alter-
`nate position upon release of the fluid pressure by a biasing
`member, such as a spring, they may be of the type that is
`actuated to a closed or open position only upon application
`of fluid pressure thereto, or they may be of any other type.
`Additionally, the valves 36b, 38b, 40b may be chokes in
`which a resistance to fluid flow generally radially there-
`through is varied by varying fluid pressure applied thereto,
`or by balancing fluid pressures applied thereto. Thus, any
`type of flow control device may be used for the valves 36b,
`38b, 40b, without departing from the principles of the
`present invention.
`In FIG. 4, the packer 34b has been set within the wellbore
`12b, and the valve 40b has been closed. The remainder of the
`valves 36b, 38b are open. Therefore, fluid flow from the
`formation portion 26b to the interior of the tubing string 28b
`is restricted.
`It may now be clearly seen that
`it
`is not
`necessary to set more than one of the packers 36b, 38b, 40b
`in order to restrict fluid flow from a formation portion.
`Referring additionally now to FIG. 5, another method 70
`embodying principles of the present invention is schemati-
`cally and representatively illustrated. In FIG. 5, elements
`which are similar to those previously described are indicated
`using thc samc rcfcrcncc numbcrs, with an addcd suffix “c”.
`The method 70 is substantially similar to the method 60
`described above, except that no intervention into the well is
`used to selectively set or unset the packers 30c, 32c, 34c or
`to operate the valves 36c, 38c, 40c. Instead, the pump 62c
`and control module 66c are operated by a receiver 72
`interconnected in the tubing string 28c. Power for operation
`of the receiver 72, pump 62c and control module 66c is
`supplied by a battery 74 also interconnected in the tubing
`string 28c. Of course, other types of power sources may be
`
`10
`
`15
`
`30
`
`35
`
`40
`
`45
`
`50
`
`55
`
`60
`
`65
`
`8
`utilized in place of the battery 74. For example, the power
`source may be an electro-hydraulic generator, wherein fluid
`flow is utilized to generate electrical power, etc.
`The receiver 72 may be any of a variety of receivers
`capable of operatively receiving signals transmitted from a
`remote location. The signals may be in the form of acoustic
`telemetry, radio waves, mud pulses, electromagnetic waves,
`or any other form of data transmission.
`The receiver 72 is connected to the pump 62c, so that
`when an appropriate signal is received by the receiver, the
`pump is operated to provide fluid pressure to the control
`module 66c. The receiver 72 is also connected to the control
`
`module 66c, so that when another appropriate signal is
`received by the receiver, the control module is operated to
`direct the fluid pressure via the lines 64c to a selected one of
`the packers 30c, 32c, 34c or valves 36c, 38c, 40c. As such,
`the combined receiver 72, battery 74, pump 62c and control
`module 66c may be referred to as a common actuator 76 for
`the sealing devices and flow control devices of the tubing
`string 28c.
`As shown in FIG. 5, the receiver 72 has received a signal
`to operate the pump 62c, and has received a signal for the
`control module 666 to direct the fluid pressure to the packer
`306. The packer 30c has, thus, been inflated and is prevent-
`ing fluid flow longitudinally through the wellbore 12c
`between the formation portions 20c and 22c.
`Referring additionally now to FIG. 6, another method 80
`embodying principles of the present invention is schemati-
`cally and representatively illustrated. Elements of the
`method 80 which are similar to those previously described
`are indicated in FIG. 6 with the same reference numbers,
`with an added suflix “d”.
`
`The method 80 is similar to the previously described
`method 70. However,
`instead of a common actuator 76
`utilized for selectively actuating the sealing devices and flow
`control dev