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Publication numberUS3853177 A
Publication typeGrant
Publication dateDec 10, 1974
Filing dateApr 19, 1973
Priority dateFeb 19, 1970
Publication numberUS 3853177 A, US 3853177A, US-A-3853177, US3853177 A, US3853177A
InventorsMott J
Original AssigneeBreston M
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Automatic subsurface blowout prevention
US 3853177 A
Abstract
A tool and method for automatic subsurface closure of a well to prevent the uncontrolled flow of high-pressure formation fluids upward to the atmosphere while a well is being drilled or completed. The tool includes at least two main parts: A movable sealing means and a fluid flow control means positioned above the sealing means. The movable sealing means is used to shut in the well in response to a subsurface pressure condition. The fluid flow control means automatically provides an opening between the interior and exterior walls of the tool, when the pressure below the sealed off area is greater than the pressure above the sealed off area. The tool's functions are automatic, reversible and repetitive.
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Description  (OCR text may contain errors)

United States Patent 1191 Mott Dec. 10, 1974 AUTOMATIC SUBSURFACE BLOWOUT 3,283,823 8/1966 Warrington 175/243 PREVENTION 3,322,215 5/1967 Warrington 175/317 Inventor: James D. Mott, Houston, Tex.

[73] Assignee: Michael P. Breston, Houston, Tex. Primary Examiner-James Lepplnk Fl d A 19 3 1 Attorney, Agent, or FirmMichael P. Breston 1e pr.

[21] Appl. No.: 352,808 [57] ABSTRACT Related Application Data A tool and method for automatic subsurface closure [63] Continuation of Ser NO 12 823 Feb 1970 of a well to prevent the uncontrolled flow of highabandoned pressure formation fluids upward to the atmosphere v while a well is being drilled or completed. The tool in- [52] Us Cl 166/244 166/184 166/187 cludes at least two main parts: A movable sealing 175/243 175/317 means and a fluid flow control means positioned [51] Int Cl 23/06 Ezlb 33/127 above the sealing means. The movable sealing means [58] Field 166/121 184 187 is used to shut in the well in response to a subsurface v 3 pressure condition. The fluid flow control means automatically provides an opening between the interior [56] References Cited and exterior walls of the tool, when the pressure below the sealed off area is greater than the pressure above UNITED STATES PATENTS the sealed off area. The tools functions are automatic, 2,74l,3 Bagnell reversible and repetitive 2,742,968 4/1956 Hildebrandt... 166/100 3,032,116 5/1962 Barry 166/187 21 Claims, 8 Drawing Figures i 38 ,/25 i F 30 1 2] I l 3/ ,1/2 I 116 RAM 1 1 I' r106 1' 3 as 82., I76 I C q 3' L v- Tsl' e4 PATENTEU DEC 1 01974 Hill-3 ATTORNEY PATENTED DEC! 0|974 MEI 20f 3 FIG. 26

James D. Mott INVENTOR BY Michael PBreston A T TORNE Y A FIG. 2a

PATENTEB DEC 1 01974 FIG. 3 C

James D. Mott IN VENTOR BY Michael F. Breston A T TORNE Y AUTOMATIC SUBSURFACE BLOWOUT PREVENTION REFERENCE TO PRIOR APPLICATION This application is a continuation of application Ser. No. 12,823 filed Feb. 19, 1970, and now abandoned.

BACKGROUND OF THE INVENTION 1. Field of the Invention This invention generally relates to the field of pressure control in the drilling of oil and gas wells or other type wells. More particularly it relates to the automatic subsurface closure of a drilled hole to prevent the upward flow of high-pressure formation fluids when the pressure of the formations fluid exceeds the hydrostatic pressure of the drilling fluid adjacent to the formation. It also provides an automatic fluid flow control means to allow for the circulation of higher weight drilling fluid, thereby containing the formations pressure.

2. Description of the Prior Art .A well blowout condition refers to the uncontrolled flow of fluids from a well to the atmosphere. The out-' ward manifestations of a blowout condition can be very damaging both to property and life. Great efforts have been made to solve the blowout problem.

One common method involves the use of a surface blowout preventer around the drill string. Such a surface preventer can cause a subsurface blowout condition. More recently, a subsurface blowout preventer was proposed which consists of a fluid-operated packer to shut in the well, and a valve means to allow for the circulation of drilling fluid above the sealed off area. Such an apparatus is described in US. Pat. No. 3,427,651. In the patented apparatus, (using the reference characters of the patent) when a high-pressure formation 12 is penetrated by a drill bit 11 and it is desired to inflate the packer l6, drilling is halted and the hydraulic pressure of the drilling fluid is increased to a predetermined pressure above the normal circulation pressure. Then the hydraulic pressure is further increased to shear pin 33 and to move plug 30. Fluid pressure then expands packer l6 and seals the annulus 45 between tubular member 15 and the wall of borehole 10. Hydraulic pressure within the drill string is then decreased to prevent fluid pressure from escaping from packer 16. A circulation port 17 is opened by a means of a wire line. The weight of the drilling fluid is increased to compensate for the high-pressure formation fluid. To-deflate packer l6, circulation port 17 is closed by means of a wire line and the hydraulic pres- .sure in the drill string is increased to a predetermined pressure level above the pressure required to inflate packer 16. This increased hydraulic pressure causes shear pin 39 to shear and the packer to deflate.

Among the main shortcomings encountered with known devices are: the parts forming the subsurface blowout preventer require human effort to become operative; precious time is wasted in manually carrying out the required manipulations; educated guesses must be made concerning the relation between the subsurface pressure conditions existing inside and outside the portion of the drill string adjacent the high-pressure formation; the fluid-inflatable packer can carry out only one cycle of operation; and after one cycle of operation the apparatus must be reconditioned and at least the shear pins restored.

Accordingly, it is a main object of this invention to overcome the above and other shortcomings of known devices. In accordance with this invention, a well can be controlled automatically in response to the occurrence of a sudden change in the pressure of a subsurface formation. A sealing wall will automatically expand in response to such changed pressure condition, and automatically contract after the pressure of the drilling fluid is properly compensated. The operation is therefore automatic, reversible, and repetitive.

SUMMARY OF THE INVENTION flow channel for the circulation of drilling fluid. When the pressure of the drilling fluid above the sealed off area exceeds the pressure below the sealed off area, the packer will automatically deflate and return to its deactivated condition. Thereafter, normal drilling operations can be resumed. When another high-pressure formation is encountered, the packer will again inflate to shut in the well.

BRIEF DESCRIPTION OF THE DRAWINGS FIG. 1 is a view in perspective of a preferred embodimentof the present invention;

FIGS. 2A, 2B, and 2C are more detailed views partly in section of the embodiment shown in FIG. 1;

FIGS. 3A, 3B, and 3C are similar to FIGS. 2A, 2B, and 2C but with the movable parts arranged in activated positions, and

FIG. 4 is a cross-section on line 4'4 in FIG. 2C.

Referring to the drawings there is shown a subsurface apparatus 10 for controlling wells during drilling operations. Apparatus 10 is herein, generally, called a tool and, particularly, a subsurface blowout preventer. Normally, tool 10 forms part of and is positioned at a selected, desired elevation along a drill string assembly, generally designated as 11. String 11 includes drill pipes 12, collars l4, and a bit 16.

Experience indicates that if one tool is used, the preferred location is near the top drill collar 14. Several vertically-spaced tools 10 can be inserted within string 11 for greater protection. Drill string 11 has an inner wall 15 and an outer wall 17 and extends into a borehole 13 which may or may not have a casing. Borehole l3 traverses a formation 18 whose wall 19 is typically made up of distinct, vertically-spaced zones, each zone being characterized by an internal fluid (water, oil, or gas) pressure P,

Under normal drilling operations, a drilling fluid (liquid or gas) is pumped from the surface down string 11, through restricted orifices (not shown) in bit 16, and up through an annular area or annulus 20 between walls 17 and 19. After circulation of the drilling fluid is established, for the same elevation, the hydraulic pressure inside string 11 on the inner wall 15 is greater than the pressure on the outer wall 17. Conversely,

with no fluid circulation, the interior and exterior hydrostatic fluid pressure, at any level, is substantially the same.

As bit 16 continues to drill, a formation may be encountered whose pressure P, is greater than the pressure of the circulating fluid in the adjacent annulus 20. This condition may cause the well to blowout unless preventive measures are immediately taken, preferably automatically. The outward manifestations of a blowout condition are well-known and need not be described. A check valve 21 positioned at the lowermost end of tool will prevent the formations pressure P; from fluidly communicating with the interior of drill string 11.

Referring more specifically to the construction of tool 10, it includes a preferably tubular member or mandrel'34 which extends throughout the entire length of tool 10. The mandrels lower end is threadedly connected to a bottom connector 22, and its upper end is threadedly connected to a top connector 23. Mandrel 34 has an inner wall 24 and an outer wall 25. Mounted on wall 25 are fixed and movable members which can be grouped into two main parts: a valve 26, and a fluidinflatable sealing means or packer 28 which includes a packer setting mechanism 30.

THE PACKER SETTING MECHANISM 30 Guide pins 36 of mechanism 30 extend into spaced,

longitudinal slots 38 to allow for the up-and down' movement of mechanism 30. A locking sleeve 40 is threadedly connected to a cylinder 42, which in turn is threadedly'connected to a packer piston 44. Sleeve 40 is releasably secured by a snap ring 46 and a fixed, splined, retainer ring 48. Ring 48 defines several (six) openings 50. Through each opening 50 vertically extends a finger 52 of a movable expander ring 54. The tip 56 of each finger 52 is in contact with a power piston 58. Piston 58 is slidably mounted between wall 25 and the cylindrical inner wall 60 of cylinder 42. Piston 58 can move between a shoulder 62 of sleeve 40 and a shoulder 64 of cylinder 42. Between the internal wall 60 .of cylinder 42 and the external wall 25 of mandrel 34 is formed a long chamber 66 which communicates with the internal pressure in mandrel 34, through a port 68. Below piston 58 is a chamber 70 which fluidly communicates with the pressure in the annular area 20, through ports 71. Above piston 58 is the chamber 66.

A sleeve is fixedly secured on wall 25 by rings 82 and 84. Wall 60 of cylinder 42 slides on a seal 86 in the outer wall of sleeve 80. A port 88 communicates the annulus pressure to a chamber 90. This pressure is exerted on the lower surface 92 of the packer piston 44. The outer cylindrical wall portion 94 of cylinder 44 defines the previously-mentioned, vertically-extending,

spaced slots 38. The top surface 96 of packer piston 44 is exposed to the pressure of an enclosed fluid within packer chamber 98. The packer fluid is typically heavy oil having a low vapor pressure. 1

THE PACKER 28 Chamber 98 is formed between the outer wall 25 of mandrel 34 and the inner wall 100 of a cylinder 102. Pins 36 of cylinder 102 extend into slots 38. Cylinder 102 forms integral part with a movable flexible member, or fluid-expandable packer wall 104. Wall 104, in turn, forms integral part with a sleeve 106 which is threadedly connected to a sleeve 108. Sleeve 108 defines a stop shoulder 110 for arresting the further movement of the bottom surface 112 of a piston 114. A fluid passageway 116 establishes fluid communication between chambers 98 and 118.

THE VALVE 26 A valve cylinder 120 is threadedly connected to piston 114. The top surface 122 of cylinder 120, when in its raised position, will abuttingly engage the bottom surface 124 of top connector 23. When valve 26 is open, a chamber 126 is in fluid communication with the mandrels interior pressure through openings .128 and with the annulus pressure through ports 130. A cylinder 132 is fixedly mounted on the outer wall 25 by two retaining rings 134 and 136. Cylinder 132 defines an inclined valve surface 138 which snugly engages surface 140 of cylinder 120. A sea] 139 is provided on surface 138. A floating piston 142 provides a shoulder 144 for engaging a coiled spring 146 which also rests on the top surface 148 of piston 114. Ports 150 fluidly communicate with a chamber 152 formed between 'wall 25 and the inner wall 154 of cylinder 120.

GENERAL DESCRIPTION OF OPERATION To facilitate the understanding of the operation of tool 10, and with particular reference to FIGS. 3A, 3B and 3C, let

P, pressure inside mandrel 34, P pressure outside tool 10 and below packer seal P pressure outside tool 10 and above packer seal P pressure inside packer seal and in chamber 98,

A, cross-sectional area of chamber 66,

A cross-sectional area of piston surface 96 A,

A, cross-sectional area of piston surface 112 A, cross-sectional area of sliding piston 142 A,

A,, cross-sectional area from seal 139 to wall 25 For simplicity assume that,

A, =-A A =1 (unit area), and

In operation, tool 10 is connected to a drill collar 14 and to a drill pipe 12 by connectors 22 and-23, respectively. As the drill string 11 is being lowered into the annular area 20, tool 10 is in its deactivated and locked condition. Check valve 21 prevents the drilling fluid which is in borehole 13 from entering into mandrel 34. Accordingly, before fluid circulation begins, the exterior hydrostatic pressure is greater than the interior pressure and an upward force becomes exerted on the power piston 58. The movement of piston 58 is arrested by shoulder 64 of cylinder 42. Snap ring 46 locks sleeve 40 and hence cylinder 42.

Thereafter, in conventional manner, the drill pipe 12 is filled with a drilling fluid and circulation is established through the drill string 11, bit 16, and up the annular area .20. The interior pressure then becomes greater than the exterior pressure. A downwardly directed force now becomes exerted on power piston 58. Piston 58 pushes against the tips 56 of fingers S2,'causing ring 54 to move downwardly against connector 22. Snap ring 46 reduces its diameter and frees sleeve 40,

and hence cylinder 42, for upward movement. The

OPERATION OF PACKER SETTING MECHANISM 30 When the drill bit 16'encounters a high-pressure formation sufficient to cause a blowout condition, the formations fluid pressure P; will communicate through ports 71 with chamber 70. The check valve 21 will prevent the formations pressure from lifting the drilling fluid inside mandrel 34. P is then greater than F, P

' is applied against the top surface and P against the bottom surface of power piston 58, and power piston 58 will move upwardly. An upward force also becomes exerted by P on the lower surface 92 of packer piston 44. Since piston 58 pushes cylinder 42 upwardly and an upward force isalso exerted on the packer piston 44, the packer 28 will now become inflated.

. OPERATION OF PACKER 28 As the packer piston 44 moves up into chamber 98, the constant volume fluid in chamber 98 moves up through passageway 116 and causes the flexible wall 104 to move radially outwardly. If possible, a seal-will be established between packer wall 104 and wall 19 of borehole 13. If packer wall 104 does not effectuate a seal, cylinder 120 will not move up and valve 26 will remain closed. Conversely, if a wall is encountered and a seal established, valve 2.6 can open.

OPERATION OF THE CIRCULATING VALVE 26 Surface 112 of piston 114 is exposed to the pressure P,. Therefore, when P is greater than P,, the upward force F on threadedly connected members 114 and 120 is,

F P 14 P,A P 4 and Thus for all conditions when P, is greater than Q valve 26 will be closed, and for all conditions where P;,

is less than 0,, valve 26 will be open.

It follows then that for valve 26 to open P must be less than P This condition is met only when packer 28 has sealingly engaged wall 19 of borehole 13, and a differential pressure is established across the packer 28.

Under normal drilling operations when the interior pressure P, is greater than the exterior pressure P the floating piston 142 is at its'upper position and engages stop ring. 136. The forces involved are P,A, acting downwardly through port 150 against piston 114 and 120. Since EA, is greater than P A cylinder 120 is forced downwardly and its shoulder 140 tightly engages seal 139 to prevent fluid from communicating between the valves internal port 128 and its external port 130.

Upon the occurrence of a blowout condition, P becomes greater than P and an upward force is exerted on cylinder 42 and hence on packer piston 44, as previously described. The packers fluid in chamber 98 becomes compressed and its wall 104 inflated. For valve 26 to open, P must be less than P hence either P must increase or P must decrease. P may become greater than P when an effective seal is established between wall 104 and wall 19 of borehole 13. It may be possible from thesurface to decrease P In any event, when P is greater than P P exerts a downward force P A through port 130 on the top surface of floating piston 142 moving it downwardly, compressing spring 146, and pushing against surface 148 of piston 114. A downward force is thus exerted on cylinder 120. On cylinder 120 are also exerted a downward force P A and an upward force P A The net force is however a downward force. Valve 26 will remain effectively closedand will not accidentally open.

Now, under all conditions the packer fluid in chamber 98 fluidly communicates with chamber 118 through passageway 116. Hence, either a low or relatively high upwardly directed force P A is exerted on surface 112 of piston 114. When pressure conditions in and around tool 10 are such that P is less than Or (see Equation I), valve 26 will open.

To open valve 26, piston 114 and cylinder 120 must move upwardlyv until surface 122 of cylinder 120 is stopped by surface 124 of top connector 23. Fluid communication is now established between the valves internal port 128 and external port 130, i.e., between the inside and outside of drill string 11 abovethe sealed off area. Moving up with piston 114 is piston 142 thereby carrying compressed spring 146.

After valve 26 opens, the circulation of drilling fluid can be re-established and the weightof the fluid increased so that the internal pressure P, is greater than the external pressure P, below packer 28. Again a downwardly directed force is exerted on piston 58 P A acting upwardly through port 128 on cylinder. 1

through port 68. Piston 58 pushes locking sleeve 40 and piston 44 downwardly to their lowermost deactivated position. The fluid pressure in chambers 98 and 118 becomes reduced and' wall 104 deflated. Valve 26 closes thereby breaking fluid communication between the valve's ports 128 and 130.

Tool 10 has now completed a full cycle: Packer 28 was activated and reversibly deactivated. Tool 10 is now ready to repeat another full cycle in response to another high-pressure formation fluid.

Thus, it will be evident from the above description that the various movable parts of tool 10 become automatically actuated without human intervention. Also, the function of each part is executed without having to guess at the subsurface pressure values in and around tool 10. Since no human effort is required, little precious time is wasted and serious damage to both life and property can be averted.

It will be appreciatedthat while a preferred embodiment of this invention has been described in great detail and with'reference to certain illustrative values, the invention is not limited thereto and modifications will readily suggest themselves to those skilled in the art,

and all such modifications are intended to fall within the scope of the following claims.

What is claimed is:

l. A well tool for controlling a well having a borehole filled with a drilling fluid, said borehole extending through a geological structure which is susceptible of containing a formation fluid, the tool being adapted for insertion within a very long drill string which is lowered into the well bore, said tool comprising:

a tubular member having an inner and an outer wall;

'a fluid-inflatable sleeve means mounted on said outer wall and being adapted to radially expand and to close off the annular area between the drill string and the borehole wall;

fluid pressure control means mounted on said tubular member for controlling the expansion and contraction of said sleeve means, said control means defining: l a first fluid chamber fluidly communicating with said sleeve means, said first chamber being filled with a constant volume fluid, and (2) a second chamber fluidly communicating with the interior of said sleeve means and with said first chamber, said second chamber being positioned on said outer wall above said sleeve means;

said control means including: a first piston movably mounted in said first chamber and a second piston mounted on said outer wall for moving said first piston in and out of said first chamber; and

said sleeve means radially expanding when said first piston moves intosaid first chamber and radially contracting when said first piston moves out of said first chamber.

2. The tool of claim 1 and further including:

locking means mounted on said outer wall for releasably securing said first piston to said tubular member; and

said second piston unlocking said locking means when the pressure of the fluid inside said tubular member is greater than the pressure of the fluid within said annular area. I

3. The tool of claim 2 and further including;

a first fluid passageway between said inner wall and said annular area above said sleeve means; and valve means for automatically controlling fluid flow through said first passageway.

4. The tool of claim 3 and further including:

a third piston movably mounted in said second chamber, one surface of said third piston being responsive to the pressure inside said sleeve means and another surface being responsive to the pressure inside said tubular member; and

said third piston moving out of said second chamber after said annular area below said sleeve means becomes effectively sealed off.

5; The tool of claim 4 and further including:

second sleeve means connected to said third piston;

and

said second sleeve means defining a valve surface which controls the fluid flow through said first passageway.

6. The tool of claim 5 and further including:

a spring-biased floating piston mounted on said outer wall; and

said floating piston assisting in moving said third piston downwardly into said second chamber when 8 fluid communication through said passageway becomes cut off.

7. The tool of claim 6 and further defining:

a second fluid passageway between said annular area and a surface of said second piston;

a third fluid passageway between said annular area and said first piston;

a fourth fluid passageway between said tubular member and a surface of said floating piston; and

an opposite face of said floating piston being responsive to the fluid pressure in said annular area above said inflatable sleeve means.

8. The tool of claim 7 and further including:

a shoulder securely mounted on said outer wall;

a seal on said shoulder; and

said seal snugly engaging said valve surface when said valve means is closed. 9. A method for controlling a well having a borehole filled with a drilling fluid, said borehole extending through a geological structure which is susceptible of containing a formation of high-pressure fluid, and a very long drill string extending through said borehole, said method comprising: Y

sealing off a portion of the annular area between said drill string and the borehole wall in response to subsurface differential pressures existing between the interior and exterior of said drill string;

opening a fluid passageway between the interior of said drill string and said annular area above said sealed off portion in response to said differential pressures; v

circulating drilling fluid down said drill string through said passageway and up said annular area above said sealed off portion;

increasing the weight of said drilling fluid;

closing said fluid passageway in response to said differential pressures; and unsealing said previously sealed off portion when the weight of said drilling fluid reaches a sufficient level, thereby allowing drilling fluid to circulate down said drill string and up through said annular area. 10. An elongated tool connectable to a string of liquid conducting hollow members for insertion into a well bore, said tool comprising:

a hollow mandrel; radially expandable sealing means carried by said mandrel, said sealing means defining a first chamber and a liquid filling said chamber;

pressure-responsive control means operatively coupled to said sealing means for normally maintaining said sealing means contracted, and

said control means controlling the pressure of the liquid in said first chamber and including a differential-pressure sensing element responsive to a change in the well bore pressure external to said tool relative to the pressure in said hollow mandrel.

11. The tool of claim 10 including, 1 disabling means coupled to said pressure contro means adapted to disable said control means when said tool is initially inserted into said well bore and said disabling means changing to enabling means after said tool becomes functional in said well bore.

12. The tool of claim 10 including,

normally-closed first fluid communication means disposed above said sealing means, and said communication means being adapted to open for establishing fluid communication between the inside and outside of said tool. 13. The tool of claim 10 wherein, .said first sensing element is a piston mounted on said mandrel for longitudinal movement. 14. The tool of claim 13 wherein, said control means include a movable mechanism controlled by said first sensing element; and said mechanism pressurizing or depressurizing the liquid in said first chamber. 15. The tool of claim 14 including, locking means for initially securing said mechanism to said mandrel, and I said locking means releasing said mechanism after said tool becomes functional in said well bore. 16. The tool of claim 15 wherein the movement of said first sensing element exerts a downward force against said locking means to release said locking means.

17. The tool of claim 16 wherein said mechanism includes a piston adapted to move in or out of said first chamber.

18. The tool of claim 17 wherein said first communication means includes a circulating valve having a body portion coupled to said sealing means.

19. The tool of claim 18 wherein the first communication means includes a second differential-pressure sensing element movably mounted on said mandrel, and

said second sensing element assisting in maintaining said circulating valve normally closed.

20. The tool of claim 19 wherein:

said second sensing element is a piston movably mounted on said mandrel; and

said sealing means includes an expandable element adapted to seal off said well bore when said first chamber becomes pressurized.

21. The tool of claim 20 including a check valve positioned near the bottom end of said mandrel to prevent fluid from entering said mandrel.

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Referenced by
Citing PatentFiling datePublication dateApplicantTitle
US3908769 *Dec 6, 1973Sep 30, 1975Shell Oil CoMethod and means for controlling kicks during operations in a borehole penetrating subsurface formations
US3935903 *Apr 2, 1975Feb 3, 1976Otis Engineering CorporationWell tubing protective fluid injection system
US4300636 *Mar 7, 1980Nov 17, 1981Dailey Oil Tools, Inc.Constant bottom contact tool
US4877086 *Sep 20, 1988Oct 31, 1989Halliburton CompanyPressure limiter for a downhole pump and testing apparatus
US4941534 *Apr 28, 1989Jul 17, 1990Baker Hughes IncorporatedMethod and apparatus for sealing a casing in a subterranean well bore
US5058684 *Jan 30, 1991Oct 22, 1991Halliburton CompanyDrill pipe bridge plug
US5404953 *Oct 14, 1993Apr 11, 1995Norsk Hydro A.S.Blow-out prevention device for shutting off an annulus between a drill column and a well wall when drilling for oil or gas
US5443124 *Apr 11, 1994Aug 22, 1995Ctc InternationalHydraulic port collar
US5730222 *Dec 20, 1995Mar 24, 1998Dowell, A Division Of Schlumberger Technology CorporationDownhole activated circulating sub
US6966373Feb 27, 2004Nov 22, 2005Ashmin LcInflatable sealing assembly and method for sealing off an inside of a flow carrier
US7836962 *Mar 28, 2008Nov 23, 2010Weatherford/Lamb, Inc.Methods and apparatus for a downhole tool
US8316943Oct 20, 2010Nov 27, 2012Weatherford/Lamb, Inc.Methods and apparatus for a downhole tool
EP0205297A2 *Jun 2, 1986Dec 17, 1986Peder Smedvig AksjeselskapImprovements in down-hole blow-out preventers
WO2007060449A2 *Nov 24, 2006May 31, 2007Churchill Drilling Tools LtdDownhole tool
Classifications
U.S. Classification166/244.1, 175/317, 166/187, 166/184, 175/243
International ClassificationE21B34/00, E21B21/10, E21B33/12, E21B33/127, E21B21/00, E21B34/08
Cooperative ClassificationE21B34/08, E21B33/127, E21B21/10
European ClassificationE21B21/10, E21B34/08, E21B33/127