US20030094285A1 - Valve assembly - Google Patents
Valve assembly Download PDFInfo
- Publication number
- US20030094285A1 US20030094285A1 US10/331,274 US33127402A US2003094285A1 US 20030094285 A1 US20030094285 A1 US 20030094285A1 US 33127402 A US33127402 A US 33127402A US 2003094285 A1 US2003094285 A1 US 2003094285A1
- Authority
- US
- United States
- Prior art keywords
- valve
- bore
- fluid
- tubing string
- tubing
- 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.)
- Abandoned
Links
- 239000012530 fluid Substances 0.000 claims abstract description 74
- 238000004891 communication Methods 0.000 claims abstract description 15
- 230000015572 biosynthetic process Effects 0.000 claims description 22
- 238000004519 manufacturing process Methods 0.000 claims description 12
- 238000000034 method Methods 0.000 claims description 12
- 238000005553 drilling Methods 0.000 claims description 11
- 238000007789 sealing Methods 0.000 claims description 10
- 238000012544 monitoring process Methods 0.000 claims description 5
- 230000008878 coupling Effects 0.000 claims description 3
- 238000010168 coupling process Methods 0.000 claims description 3
- 238000005859 coupling reaction Methods 0.000 claims description 3
- 238000011017 operating method Methods 0.000 claims description 2
- 230000007246 mechanism Effects 0.000 abstract description 13
- 238000005755 formation reaction Methods 0.000 description 21
- 230000004888 barrier function Effects 0.000 description 4
- 230000004941 influx Effects 0.000 description 4
- 230000003628 erosive effect Effects 0.000 description 3
- 230000004044 response Effects 0.000 description 3
- 238000012360 testing method Methods 0.000 description 2
- 230000003466 anti-cipated effect Effects 0.000 description 1
- 230000006835 compression Effects 0.000 description 1
- 238000007906 compression Methods 0.000 description 1
- 230000007797 corrosion Effects 0.000 description 1
- 238000005260 corrosion Methods 0.000 description 1
- 230000001351 cycling effect Effects 0.000 description 1
- 238000004868 gas analysis Methods 0.000 description 1
- 230000036541 health Effects 0.000 description 1
- 230000002706 hydrostatic effect Effects 0.000 description 1
- 230000003116 impacting effect Effects 0.000 description 1
- 238000002955 isolation Methods 0.000 description 1
- 238000012986 modification Methods 0.000 description 1
- 230000004048 modification Effects 0.000 description 1
- 238000009419 refurbishment Methods 0.000 description 1
- 230000008439 repair process Effects 0.000 description 1
- 230000005236 sound signal Effects 0.000 description 1
Images
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
- E21B34/00—Valve arrangements for boreholes or wells
- E21B34/06—Valve arrangements for boreholes or wells in wells
-
- 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
- E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
- E21B21/10—Valve arrangements in drilling-fluid circulation systems
- E21B21/103—Down-hole by-pass valve arrangements, i.e. between the inside of the drill string and the annulus
-
- 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
- E21B34/00—Valve arrangements for boreholes or wells
- E21B34/06—Valve arrangements for boreholes or wells in wells
- E21B34/10—Valve arrangements for boreholes or wells in wells operated by control fluid supplied from outside the borehole
-
- 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
- E21B34/00—Valve arrangements for boreholes or wells
- E21B34/06—Valve arrangements for boreholes or wells in wells
- E21B34/10—Valve arrangements for boreholes or wells in wells operated by control fluid supplied from outside the borehole
- E21B34/101—Valve arrangements for boreholes or wells in wells operated by control fluid supplied from outside the borehole with means for equalizing fluid pressure above and below the valve
-
- 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
- E21B2200/00—Special features related to earth drilling for obtaining oil, gas or water
- E21B2200/05—Flapper valves
Definitions
- the present invention relates to a valve assembly.
- the present invention relates to a valve assembly for location in a borehole of a well.
- each string of casing that is run into a bore reduces the available bore diameter, and running casing earlier than predicted will restrict the available bore diameter, possibly to the extent that the well cannot be completed, and also limits the possibilities for running subsequent casing strings in the event of further problem formations being encountered.
- a well operating method comprising:
- the invention thus permits well work over and the like without the requirement to run a plug or kill the well.
- the valve may also be utilised to assist in the running of the tubing, in the setting of packers, in testing of the tubing, and to allow circulation of a fluid cushion. The valve may then be opened, until it becomes necessary to isolate the lower portion of the bore.
- the tubing string is a production tubing string.
- the valve is located towards the lower end of the tubing string.
- the tubing string is sealed in the cased bore by a packer, which is preferably located adjacent the valve.
- the packer may be located above or below the valve.
- a bore-drilling method comprising:
- the method further comprises the step of monitoring the bore for conditions indicative the bore encountering a problem formation.
- monitoring may include pressure monitoring, mud gas analysis, or any known monitoring method.
- valve assembly for location in a borehole of a well, the assembly comprising:
- a valve comprising a valve member and a fluid actuated valve control mechanism adapted to be selectively actuated to move the valve member between an open and a closed configuration, for selectively allowing fluid flow through the hollow member;
- a first hydraulic control conduit in fluid communication with the valve control mechanism for permitting actuation of the control mechanism to move the valve member to the open configuration, by application of a first control fluid
- a second hydraulic control conduit in fluid communication with the valve control mechanism to move the valve member to the closed configuration, by application of a second control fluid.
- valve assembly is adapted to form part of or to be mounted to a string of tubular members.
- the tubular members may be bore-lining casing or liner, production tubing, drill tubing or drill pipe, or the like.
- One or both of the first and second control fluids may be a hydraulic fluid.
- the control fluids may be well fluids.
- the hollow elongate member is tubular.
- the valve is adapted to contain pressure from both above and below.
- the valve member may comprise a plate, generally circular in plan and arcuate in profile.
- the plate may be disposed in an annular or part annular cavity in a wall of the hollow member when the valve is in the open configuration, and is preferably isolated in the cavity, to protect the plate from well fluids and debris.
- the wall of the hollow member may define an aperture to receive the open valve member, increasing the available internal diameter.
- the plate In the closed configuration, the plate may be disposed substantially perpendicularly to the wall of the hollow member.
- the valve control mechanism comprises a plurality of fluid actuated movable elements, and most preferably the elements are adapted to move in a predetermined sequence in response to exposure to a common fluid pressure. Conveniently, this is achieved by the elements defining different, staggered piston areas, such that the pressure forces experienced by the elements are different.
- the valve control mechanism comprises one or more elements each defining oppositely acting piston areas in communication with respective control conduits, a differential fluid pressure force in one direction tending to move the element in that direction.
- the pistons may be located in respective chambers and the flow of fluid from the chambers may be controlled to control piston movement; if the chamber contains an incompressible fluid, the piston will not move unless fluid can flow from the chamber.
- the valve may be actuated between the open and closed configurations by the selective application of control fluid through a selected one of the first and second control conduits, whilst simultaneously removing fluid via the other one of said first and second control conduits.
- first and second control conduits may be adapted to extend out of the borehole, with the fluid control and supply apparatus being located at surface.
- supply of fluid to the conduits may be controlled by downhole valves, which may form part of a control unit.
- the valves may provide selective communication with tubing fluid, or annulus fluid, or fluid supplied from surface.
- the valves may be controlled by any appropriate means, for example by signals communicated via control lines from surface or remotely from surface, such as by radio or audio signals, pressure pulses or pressure cycling, or in response to sensed downhole conditions, for example a sudden loss or increase in tubing pressure.
- the control unit may be located above or below a packer positioned between tubing and casing or liner.
- the valve assembly further comprises a bypass vent which is selectively openable to permit flow between the interior and exterior of the hollow member on opening and closing of the valve member to provide a fluid path around the valve member.
- a bypass vent which is selectively openable to permit flow between the interior and exterior of the hollow member on opening and closing of the valve member to provide a fluid path around the valve member.
- fluid pressure or flow may bypass the valve member.
- the valve member and valve seat thus do not experience the wear and erosion that would otherwise occur when the valve member was only partially open and impair the ability of the valve member to create an effective seal.
- valve assembly for location in a borehole of a well, the assembly comprising:
- a valve comprising a valve member and a fluid actuated valve control mechanism adapted to be selectively actuated to move the valve member between an open and a closed configuration, for selectively allowing fluid flow through the hollow member, the valve control mechanism comprising a plurality of fluid actuated movable elements adapted to move in a predetermined sequence in response to exposure to a common fluid pressure.
- This aspect of the invention provides for an additional degree of control of downhole valves, and may equally be applied to other downhole devices.
- the sequential movement of the elements is achieved by the elements defining different piston areas, such that the pressure forces experienced by the elements are different.
- valve assembly for location in a borehole of a well, the assembly comprising:
- a hollow elongate member for location in the borehole
- a valve comprising a valve member and a fluid actuated valve control mechanism adapted to be selectively actuated to move the valve member between an open and a closed configuration
- a bypass vent being selectively openable to permit an alternative flow path around the valve member on closing of the valve member to provide a fluid path around the valve member.
- FIG. 1 is a longitudinal cross-sectional view of a valve assembly, in accordance with an embodiment of the present invention, shown with a valve member of the valve assembly in an open configuration;
- FIG. 2 is a view of the valve assembly of FIG. 1, shown with the valve member in a closed, sealed configuration
- FIG. 3 is a longitudinal cross-sectional view of part of the valve assembly of FIG. 1, drawn to an alternative scale;
- FIG. 4 is a longitudinal cross-sectional view of part of the valve assembly of FIG. 2, shown immediately prior to actuation to the closed sealed configuration of FIG. 2, and drawn to an alternative scale;
- FIG. 5 is a view of the part of the valve assembly shown in FIG. 4, with the valve of the valve assembly shown in the closed, sealed configuration of FIG. 2.
- FIG. 1 there is shown a longitudinal cross-sectional view of a valve assembly in accordance with an embodiment of the present invention, shown in an open configuration, and indicated generally by reference numeral 10 .
- the valve assembly 10 comprises a tubular housing 12 , an annular piston member, indicated generally by reference numeral 14 , a sleeve assembly 16 and a hinged valve flap 18 .
- the housing 12 is shaped to define, together with the sleeve assembly 16 , an annular cavity 20 which extends axially along the housing 12 .
- the piston member 14 comprises a leading end 22 to which the valve flap 18 is pivotally coupled, a tubular body portion 24 extending through the cavity 20 , and a tail portion 26 uppermost in the housing 12 .
- Shoulders 28 and 30 extend radially inwardly and outwardly respectively from the body portion 24 , and a seal 32 is disposed in the shoulder 30 , to seal the piston member 14 to the housing 12 .
- the sleeve assembly 16 comprises upper and lower sleeves 34 and 36 , each having respective opposed seals 38 and 40 .
- Hydraulic control lines 41 are coupled to the housing 12 and supply hydraulic fluid to actuate the assembly 10 through inlet ports 42 , 44 and 46 , and to selectively inject or withdraw fluid from the assembly 10 , as will be described in more detail below.
- the control lines 41 may extend to surface, or may extend to a remotely controllable downhole control unit, where selectively actuatable valves may permit fluid communication between the conduits 41 and the tubing bore or the annulus.
- the valve assembly 10 is located in a production tubing string and run into a casing-lined borehole, to selectively isolate the lower end of the borehole, particularly when it is desired to carry out well work over operations above the assembly.
- the assembly 10 may be run into the casing-lined borehole in the open configuration shown in FIG. 1, or in the closed configuration shown in FIG. 2.
- valve flap 18 In the closed configuration, the valve flap 18 is disposed substantially perpendicularly to a longitudinal axis of the housing 12 , and is in sealing contact with the sleeves 34 and 36 , as shown in FIG. 2.
- the upper and lower sleeves 34 and 36 are themselves sealed to the housing 12 , via seals 37 in the portion of the housing 12 adjacent to the upper sleeve 34 , and seals 39 in the portion of the housing 12 adjacent to the sleeve 36 , thus fluidly isolating the tubing bore 48 .
- fluid pressure in the tubing bore 48 acting upon the upper sleeve 34 assists in maintaining the sealing arrangement of the valve assembly 10 .
- FIGS. 3 to 5 are longitudinal cross-sectional views of parts of the valve assembly 10 shown in FIGS. 1 and 2, which illustrate the various steps involved in actuating the valve assembly 10 between the open and closed configurations of FIGS. 1 and 2 respectively.
- FIG. 3 there is shown the lower sleeve 36 of the assembly 10 in a retracted configuration.
- the lower sleeve 36 includes a seal 50 for sealing the sleeve 36 to the housing 12 , the seal being mounted in a shoulder 52 extending radially outwardly from the sleeve 36 .
- a lower face of the shoulder 52 abuts a compression spring 54 , which, in the absence of fluid pressure, maintains the sleeve 36 in an upper position, as shown in FIG. 1.
- the sleeve 36 may be actuated to the retracted configuration to allow the valve flap 18 to move to the closed configuration, as shown in FIG. 2.
- FIG. 4 there is shown the housing 12 excluding the sleeve 36 of FIG. 3, before the closed valve flap 18 comes into sealing contact with the seals 38 and 40 of the upper and lower sleeves 34 and 36 .
- One of the control lines 41 is coupled to the housing 12 such that fluid is supplied simultaneously to the ports 42 and 46 .
- the lower sleeve 36 is actuated to the retracted configuration shown in FIG. 3 at a lower applied pressure than the piston member 14 , due to the different effective areas of the sleeve and piston member.
- the lower sleeve 36 can be actuated to the retracted configuration before the piston member 14 moves down to move the valve flap 18 to the closed configuration shown in FIG. 2.
- control fluid is withdrawn through, or bled off from, the port 44 , via a respective control line 41 , whilst supplying control fluid to the port 42 to move the piston member 14 axially downwardly to the position shown in FIG. 4.
- the valve flap 18 pivots about the leading end 22 of the piston member 14 , and extends across the bore 48 .
- a bevelled face 58 is provided on the valve flap 18 , which face moves over a similar bevelled face 60 of the housing 12 (not shown in FIG. 4).
- valve flap 18 When the valve flap 18 has extended to the closed position, the valve flap 18 resides with a lower face 70 of the flap 18 adjacent to and in contact with the seals 40 of the lower sleeve 36 .
- the upper sleeve 34 then moves down into contact with an upper face 62 of the valve flap 18 , as shown in FIG. 2.
- the movement of the upper sleeve 34 is achieved by moving the piston member 14 axially downwardly, until the shoulder 28 of the piston member 14 comes into contact with a radially outwardly extending shoulder 64 of the sleeve 34 . Further downward movement of the piston member 14 thus causes the sleeve 34 to be driven co-axially downwardly, towards the valve flap 18 .
- the valve flap 18 includes an axially extending slot, and is mounted to the end 22 of the piston member 14 via a pin 23 . This allows the valve flap 18 to remain axially stationary while the upper sleeve 34 is being moved downwardly by the piston member 14 .
- the sleeve 34 is carried down until the seals 38 come into contact with the face 62 of the valve flap 18 .
- the housing 12 includes flow ports 66 extending radially through the housing 12 , the valve assembly being adapted to allow fluid communication between the tubing bore 48 and the annulus while the valve is opening and closing of the valve flap 18 .
- the sleeve 34 also includes flow ports 68 , which align with the housing flow ports 66 as the sleeve 34 descends, and before the seals 38 are brought into contact with the face 62 of the valve flap 18 . This ensures that there is little or no pressure differential across the valve flap 18 during closure (and opening), as there is fluid communication between the tubing bore 48 and the annulus, as shown in FIG. 4. It will be apparent to those of skill in the art that this bypass feature will only function if there is a fluid communication route between the annulus and the lower, open end of the housing. In other words, the valve assembly is likely to be located below the tubing packer.
- valve flap 18 When the valve flap 18 is in the closed, sealed configuration of FIG. 2, the flow ports 66 and 68 of the housing 12 and the upper sleeve 34 respectively are misaligned, preventing fluid communication between the tubing bore 48 and the annulus.
- the valve assembly 10 is now closed and sealed, and the tubing bore 48 is isolated from the annulus. This allows the production tubing to be uncoupled from the valve assembly, above the tubing packer, and the lower end of the bore, which intersects the production formation, to be isolated from the rest of the bore. Thus, any required well operations may be carried out above the valve assembly without impacting on the production zone.
- valve assembly 10 When the well operations have been completed, for work over of the well, followed by running in and testing of replacement tubing, and coupling of the tubing to the assembly, the valve assembly 10 is returned to the open configuration shown in FIG. 1 by withdrawing fluid from the ports 42 and 46 and injecting fluid in at port 44 . This allows the piston member 14 to move axially upwardly, carrying the upper sleeve 34 co-axially therewith when the shoulder 28 of the piston member 14 comes into contact with a radially outwardly extending shoulder 35 of the sleeve 34 . This causes the valve flap 18 to retract into the annular recess 20 in the wall of the housing 12 .
Abstract
A downhole valve assembly (10) comprises a tubular body (12), and a valve comprising a valve member (18) and a fluid actuated valve control mechanism (14) adapted to be selectively actuated to move the valve member between an open and a closed configuration, for selectively allowing fluid flow through the body (12). A first hydraulic control conduit (41) is in fluid communication with the valve control mechanism (14) for permitting actuation of the control mechanism to move the valve member (18) to the open configuration, by application of a first control fluid. A second hydraulic control conduit (41) is in fluid communication with the valve control mechanism (14) to move the valve member (18) to the closed configuration, by application of a second control fluid.
Description
- This application is a continuation of U.S. patent application Ser. No. 09/575,325 filed May 19, 2000, which claims priority of United Kingdom Patent Application No. 9911648.3 filed May 19, 1999.
- The present invention relates to a valve assembly. In particular, but not exclusively, the present invention relates to a valve assembly for location in a borehole of a well.
- When it is desired to carry out work on a partially or fully cased borehole of an oil or gas well there is a requirement for provision of an isolation barrier in the bore, which barrier may take the form of a valve, or a dense or “weighted” fluid. Also, when tubing is installed on a production well, and the well is “completed”, health and safety regulations require that a barrier, typically referred to a “safety” valve, is installed as part of the completion.
- In the course of drilling a well, the bore will pass through formations of different porosities and containing fluids at different pressures. Surveys will have been carried out with the aim of predicting the properties of the different formations, and the density of the column of drilling fluid or mud being circulated in the bore during the drilling operation is typically selected such that the fluid pressure in the bore is slightly higher than the formation fluid which is expected to be encountered. However, there is always a risk that a formation will be at a higher or lower pressure than anticipated, or that different formations intersected by a single bore will be at significantly different pressures. If the bore intersects an unexpectedly low pressure formation, there may be a significant loss of drilling mud into the formation, at great expense to the drilling operator, and if the formation is gas or oil-bearing such an influx of mud may result in significant damage to the production capabilities of the formation. On the other hand, encountering an unexpectedly high pressure formation, creating a “kick” in the bore, may result in a sudden influx of formation fluid to the bore, with potentially disastrous consequences.
- There are various established steps and operations which may be implemented to control such situations. In some cases, it may be possible to chemically treat or plug a porous or low pressure formation, or to circulate higher density drilling fluid to prevent or limit influx of fluids from a high pressure formation. However, these procedures tend to be time consuming and expensive, and in some cases the condition may be such, for example a sudden high pressure or high volume influx, that the well must be capped and abandoned. If time and conditions permit, it may be possible to isolate a problem formation by running casing into the bore. However, each string of casing that is run into a bore reduces the available bore diameter, and running casing earlier than predicted will restrict the available bore diameter, possibly to the extent that the well cannot be completed, and also limits the possibilities for running subsequent casing strings in the event of further problem formations being encountered.
- In a completed well that has been producing for some time, it is not unusual for corrosion or erosion of well components to occur, such that the tubing must be retrieved to permit refurbishment and repair, or “work over” of the well. Clearly, the flow of production fluid from the well must be halted during work over. Generally, it is preferred to do this by isolating the lower end of the bore, which intersects the producing formation, by installing a plug in the lower end of the tubing; the tubing above the plug may then be removed. However, erosion and the build up of scale and other deposits in the tubing may make it impossible to set a plug in the tubing. Accordingly, it may then be necessary to “kill” the well, by filling the bore with relatively dense fluid, the hydrostatic pressure produced by the column of fluid preventing the production fluid from flowing into the bore. However, killing a well often contaminates or damages the producing formation, and may even reduce the production capabilities of the formation to the extend that the well is no longer commercially viable.
- It is amongst the objects of the present invention to obviate or mitigate at least one of the foregoing disadvantages.
- According to a first aspect of the present invention there is provided a well operating method comprising:
- providing a valve in a tubing string;
- running the tubing string into a cased bore;
- sealing the tubing string in the cased bore;
- closing the valve to isolate the lower end of the bore;
- uncoupling the tubing string from the valve;
- retrieving the tubing string;
- running a replacement tubing string into the bore;
- coupling the replacement tubing string to the valve; and
- opening the valve to permit fluid communication between the lower end of the bore and the tubing string.
- The invention thus permits well work over and the like without the requirement to run a plug or kill the well. The references to a cased bore and intended to encompass a drilled bore which has been lined or partially lined with casing, liner or other form of bore wall support or sealing arrangement.
- The valve may also be utilised to assist in the running of the tubing, in the setting of packers, in testing of the tubing, and to allow circulation of a fluid cushion. The valve may then be opened, until it becomes necessary to isolate the lower portion of the bore.
- Preferably, the tubing string is a production tubing string.
- Preferably, the valve is located towards the lower end of the tubing string.
- Preferably, the tubing string is sealed in the cased bore by a packer, which is preferably located adjacent the valve. The packer may be located above or below the valve.
- According to another aspect of the present invention there is provided a bore-drilling method comprising:
- providing a valve in bore-lining casing;
- advancing the bore by drilling using a drill string passing through the valve;
- retrieving the drill string through the valve;
- closing the valve to isolate the lower end of the bore; and
- opening the valve to re-establish fluid communication with the lower end of the bore.
- This aspect if the invention is useful in dealing with “kicks” or other problems encountered while drilling. In the event of a kick, the drill string may be pulled back to above the valve and the valve closed. Thus, the problem formation may be isolated relatively quickly. With the protection of the valve in place the well may be circulated to the required mud weight, the valve then opened and the well returned to a controlled situation.
- Preferably, the method further comprises the step of monitoring the bore for conditions indicative the bore encountering a problem formation. Such monitoring may include pressure monitoring, mud gas analysis, or any known monitoring method.
- According to a still further aspect of the present invention provides a valve assembly for location in a borehole of a well, the assembly comprising:
- a hollow elongate member for location in the borehole;
- a valve comprising a valve member and a fluid actuated valve control mechanism adapted to be selectively actuated to move the valve member between an open and a closed configuration, for selectively allowing fluid flow through the hollow member;
- a first hydraulic control conduit in fluid communication with the valve control mechanism for permitting actuation of the control mechanism to move the valve member to the open configuration, by application of a first control fluid; and
- a second hydraulic control conduit in fluid communication with the valve control mechanism to move the valve member to the closed configuration, by application of a second control fluid.
- Preferably the valve assembly is adapted to form part of or to be mounted to a string of tubular members. The tubular members may be bore-lining casing or liner, production tubing, drill tubing or drill pipe, or the like.
- One or both of the first and second control fluids may be a hydraulic fluid. Alternatively, the control fluids may be well fluids.
- Preferably, the hollow elongate member is tubular.
- Preferably, the valve is adapted to contain pressure from both above and below.
- The valve member may comprise a plate, generally circular in plan and arcuate in profile. The plate may be disposed in an annular or part annular cavity in a wall of the hollow member when the valve is in the open configuration, and is preferably isolated in the cavity, to protect the plate from well fluids and debris. Alternatively, where the hollow member does not have to serve as a pressure barrier to one side of the closed valve member, the wall of the hollow member may define an aperture to receive the open valve member, increasing the available internal diameter. In the closed configuration, the plate may be disposed substantially perpendicularly to the wall of the hollow member.
- Preferably, the valve control mechanism comprises a plurality of fluid actuated movable elements, and most preferably the elements are adapted to move in a predetermined sequence in response to exposure to a common fluid pressure. Conveniently, this is achieved by the elements defining different, staggered piston areas, such that the pressure forces experienced by the elements are different.
- Preferably, the valve control mechanism comprises one or more elements each defining oppositely acting piston areas in communication with respective control conduits, a differential fluid pressure force in one direction tending to move the element in that direction. The pistons may be located in respective chambers and the flow of fluid from the chambers may be controlled to control piston movement; if the chamber contains an incompressible fluid, the piston will not move unless fluid can flow from the chamber.
- The valve may be actuated between the open and closed configurations by the selective application of control fluid through a selected one of the first and second control conduits, whilst simultaneously removing fluid via the other one of said first and second control conduits.
- One or both of the first and second control conduits may be adapted to extend out of the borehole, with the fluid control and supply apparatus being located at surface. Alternatively, supply of fluid to the conduits may be controlled by downhole valves, which may form part of a control unit. The valves may provide selective communication with tubing fluid, or annulus fluid, or fluid supplied from surface. The valves may be controlled by any appropriate means, for example by signals communicated via control lines from surface or remotely from surface, such as by radio or audio signals, pressure pulses or pressure cycling, or in response to sensed downhole conditions, for example a sudden loss or increase in tubing pressure. The control unit may be located above or below a packer positioned between tubing and casing or liner.
- Preferably, the valve assembly further comprises a bypass vent which is selectively openable to permit flow between the interior and exterior of the hollow member on opening and closing of the valve member to provide a fluid path around the valve member. Thus, as the valve member is opened or closed, fluid pressure or flow may bypass the valve member. The valve member and valve seat thus do not experience the wear and erosion that would otherwise occur when the valve member was only partially open and impair the ability of the valve member to create an effective seal.
- According to a yet further aspect of the present invention provides a valve assembly for location in a borehole of a well, the assembly comprising:
- a hollow elongate member for location in the borehole;
- a valve comprising a valve member and a fluid actuated valve control mechanism adapted to be selectively actuated to move the valve member between an open and a closed configuration, for selectively allowing fluid flow through the hollow member, the valve control mechanism comprising a plurality of fluid actuated movable elements adapted to move in a predetermined sequence in response to exposure to a common fluid pressure.
- This aspect of the invention provides for an additional degree of control of downhole valves, and may equally be applied to other downhole devices.
- Conveniently, the sequential movement of the elements is achieved by the elements defining different piston areas, such that the pressure forces experienced by the elements are different.
- According to a yet further aspect of the present invention provides a valve assembly for location in a borehole of a well, the assembly comprising:
- a hollow elongate member for location in the borehole;
- a valve comprising a valve member and a fluid actuated valve control mechanism adapted to be selectively actuated to move the valve member between an open and a closed configuration;
- a bypass vent being selectively openable to permit an alternative flow path around the valve member on closing of the valve member to provide a fluid path around the valve member.
- Embodiments of the present invention will now be described, by way of example, with reference to the accompanying drawings, in which:
- FIG. 1 is a longitudinal cross-sectional view of a valve assembly, in accordance with an embodiment of the present invention, shown with a valve member of the valve assembly in an open configuration;
- FIG. 2 is a view of the valve assembly of FIG. 1, shown with the valve member in a closed, sealed configuration;
- FIG. 3 is a longitudinal cross-sectional view of part of the valve assembly of FIG. 1, drawn to an alternative scale;
- FIG. 4 is a longitudinal cross-sectional view of part of the valve assembly of FIG. 2, shown immediately prior to actuation to the closed sealed configuration of FIG. 2, and drawn to an alternative scale; and
- FIG. 5 is a view of the part of the valve assembly shown in FIG. 4, with the valve of the valve assembly shown in the closed, sealed configuration of FIG. 2.
- Referring firstly to FIG. 1, there is shown a longitudinal cross-sectional view of a valve assembly in accordance with an embodiment of the present invention, shown in an open configuration, and indicated generally by
reference numeral 10. - The
valve assembly 10 comprises atubular housing 12, an annular piston member, indicated generally byreference numeral 14, asleeve assembly 16 and a hingedvalve flap 18. - The
housing 12 is shaped to define, together with thesleeve assembly 16, anannular cavity 20 which extends axially along thehousing 12. Thepiston member 14 comprises aleading end 22 to which thevalve flap 18 is pivotally coupled, atubular body portion 24 extending through thecavity 20, and atail portion 26 uppermost in thehousing 12.Shoulders body portion 24, and aseal 32 is disposed in theshoulder 30, to seal thepiston member 14 to thehousing 12. - The
sleeve assembly 16 comprises upper andlower sleeves seals housing 12 and supply hydraulic fluid to actuate theassembly 10 throughinlet ports assembly 10, as will be described in more detail below. The control lines 41 may extend to surface, or may extend to a remotely controllable downhole control unit, where selectively actuatable valves may permit fluid communication between the conduits 41 and the tubing bore or the annulus. - The
valve assembly 10 is located in a production tubing string and run into a casing-lined borehole, to selectively isolate the lower end of the borehole, particularly when it is desired to carry out well work over operations above the assembly. Theassembly 10 may be run into the casing-lined borehole in the open configuration shown in FIG. 1, or in the closed configuration shown in FIG. 2. - In the closed configuration, the
valve flap 18 is disposed substantially perpendicularly to a longitudinal axis of thehousing 12, and is in sealing contact with thesleeves lower sleeves housing 12, viaseals 37 in the portion of thehousing 12 adjacent to theupper sleeve 34, and seals 39 in the portion of thehousing 12 adjacent to thesleeve 36, thus fluidly isolating the tubing bore 48. Also, when theassembly 10 is in the closed, sealed, configuration shown in FIG. 2, fluid pressure in the tubing bore 48 acting upon theupper sleeve 34 assists in maintaining the sealing arrangement of thevalve assembly 10. This is due to the fact that theseal 37 is of a larger diameter than theseal 38 at the lower end of theupper sleeve 34, creating a differential pressure force on thesleeve 34, forcing it downwards to maintain sealing with thevalve flap 18. Similarly, fluid pressure in thehousing 12 below thevalve flap 18 forces thelower sleeve 36 upwardly to maintain sealing with thevalve flap 18, due to the difference in diameter between theseal 40 and the inside of thehousing 12 below thesleeve 36. - FIGS.3 to 5 are longitudinal cross-sectional views of parts of the
valve assembly 10 shown in FIGS. 1 and 2, which illustrate the various steps involved in actuating thevalve assembly 10 between the open and closed configurations of FIGS. 1 and 2 respectively. - Referring firstly to FIG. 3, there is shown the
lower sleeve 36 of theassembly 10 in a retracted configuration. Thelower sleeve 36 includes aseal 50 for sealing thesleeve 36 to thehousing 12, the seal being mounted in ashoulder 52 extending radially outwardly from thesleeve 36. A lower face of theshoulder 52 abuts acompression spring 54, which, in the absence of fluid pressure, maintains thesleeve 36 in an upper position, as shown in FIG. 1. Thesleeve 36 may be actuated to the retracted configuration to allow thevalve flap 18 to move to the closed configuration, as shown in FIG. 2. This is achieved by supplying control fluid to theport 46 and into thecavity 56, causing thesleeve 36 to move axially downwardly, compressing thespring 54, and moving to the position shown in FIG. 3. This enables thevalve flap 18 to move to the closed configuration, as will be described below. - Referring now to FIG. 4, there is shown the
housing 12 excluding thesleeve 36 of FIG. 3, before theclosed valve flap 18 comes into sealing contact with theseals lower sleeves housing 12 such that fluid is supplied simultaneously to theports lower sleeve 36 is actuated to the retracted configuration shown in FIG. 3 at a lower applied pressure than thepiston member 14, due to the different effective areas of the sleeve and piston member. Thus by gradually increasing the pressure of the actuating fluid, thelower sleeve 36 can be actuated to the retracted configuration before thepiston member 14 moves down to move thevalve flap 18 to the closed configuration shown in FIG. 2. - To allow the piston member (and thus the upper sleeve36) to move to the closed configuration shown in FIG. 2, control fluid is withdrawn through, or bled off from, the
port 44, via a respective control line 41, whilst supplying control fluid to theport 42 to move thepiston member 14 axially downwardly to the position shown in FIG. 4. Meanwhile, thevalve flap 18 pivots about the leadingend 22 of thepiston member 14, and extends across thebore 48. To facilitate the desired pivoting movement of theflap 18, abevelled face 58 is provided on thevalve flap 18, which face moves over a similarbevelled face 60 of the housing 12 (not shown in FIG. 4). When thevalve flap 18 has extended to the closed position, thevalve flap 18 resides with alower face 70 of theflap 18 adjacent to and in contact with theseals 40 of thelower sleeve 36. Theupper sleeve 34 then moves down into contact with anupper face 62 of thevalve flap 18, as shown in FIG. 2. - The movement of the
upper sleeve 34 is achieved by moving thepiston member 14 axially downwardly, until theshoulder 28 of thepiston member 14 comes into contact with a radially outwardly extendingshoulder 64 of thesleeve 34. Further downward movement of thepiston member 14 thus causes thesleeve 34 to be driven co-axially downwardly, towards thevalve flap 18. Thevalve flap 18 includes an axially extending slot, and is mounted to theend 22 of thepiston member 14 via apin 23. This allows thevalve flap 18 to remain axially stationary while theupper sleeve 34 is being moved downwardly by thepiston member 14. Thesleeve 34 is carried down until theseals 38 come into contact with theface 62 of thevalve flap 18. - The
housing 12 includesflow ports 66 extending radially through thehousing 12, the valve assembly being adapted to allow fluid communication between the tubing bore 48 and the annulus while the valve is opening and closing of thevalve flap 18. Thesleeve 34 also includesflow ports 68, which align with thehousing flow ports 66 as thesleeve 34 descends, and before theseals 38 are brought into contact with theface 62 of thevalve flap 18. This ensures that there is little or no pressure differential across thevalve flap 18 during closure (and opening), as there is fluid communication between the tubing bore 48 and the annulus, as shown in FIG. 4. It will be apparent to those of skill in the art that this bypass feature will only function if there is a fluid communication route between the annulus and the lower, open end of the housing. In other words, the valve assembly is likely to be located below the tubing packer. - When the
valve flap 18 is in the closed, sealed configuration of FIG. 2, theflow ports housing 12 and theupper sleeve 34 respectively are misaligned, preventing fluid communication between the tubing bore 48 and the annulus. Thus thevalve assembly 10 is now closed and sealed, and the tubing bore 48 is isolated from the annulus. This allows the production tubing to be uncoupled from the valve assembly, above the tubing packer, and the lower end of the bore, which intersects the production formation, to be isolated from the rest of the bore. Thus, any required well operations may be carried out above the valve assembly without impacting on the production zone. - When the well operations have been completed, for work over of the well, followed by running in and testing of replacement tubing, and coupling of the tubing to the assembly, the
valve assembly 10 is returned to the open configuration shown in FIG. 1 by withdrawing fluid from theports port 44. This allows thepiston member 14 to move axially upwardly, carrying theupper sleeve 34 co-axially therewith when theshoulder 28 of thepiston member 14 comes into contact with a radially outwardly extendingshoulder 35 of thesleeve 34. This causes thevalve flap 18 to retract into theannular recess 20 in the wall of thehousing 12. As the control fluid is withdrawn from theports port 44, the pressure of the control fluid reduces, and thelower sleeve 34 subsequently returns to its extended position under the force of thespring 54, with thevalve assembly 10 in the open configuration. - Various modifications may be made to the foregoing within the scope of the present invention. For example, the above described embodiment relates to a tubing-mounted assembly, while other embodiments of the assembly may incorporated or mounted in casing or liner.
Claims (9)
1. A well operating method comprising:
providing a valve in a tubing string;
running the tubing string into a cased bore;
sealing the tubing string in the cased bore;
closing the valve to isolate a lower end of the bore;
uncoupling the tubing string from the valve;
retrieving the tubing string above the valve;
running a replacement tubing string into the bore;
coupling the replacement tubing string to the valve; and
opening the valve to permit fluid communication between the lower end of the bore and the tubing string.
2. The method of claim 1 , further comprising running the valve into the bore with the tubing.
3. The method of claim 1 , wherein the tubing string is a production tubing string.
4. The method of claim 1 , further comprising locating the valve towards the lower end of the tubing string.
5. The method of claim 1 , further comprising sealing the tubing string in the cased bore using a packer.
6. The method of claim 5 , further comprising locating the valve in the bore above a packer.
7. The method of claim 5 , further comprising locating the valve in the bore below a packer.
8. A bore-drilling method comprising:
mounting a valve in casing lined with a bore;
advancing the bore by drilling using a drill string passing through the valve;
retrieving the drill string through the valve;
closing the valve to isolate a lower end of the bore; and
opening the valve to re-establish fluid communication with the lower end of the bore.
9. The method of claim 10, further comprising the step of monitoring the bore for conditions indicative of the formation of a problem the bore is about to encounter.
Priority Applications (1)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US10/331,274 US20030094285A1 (en) | 1999-05-19 | 2002-12-30 | Valve assembly |
Applications Claiming Priority (4)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
GBGB9911545.3A GB9911545D0 (en) | 1999-05-19 | 1999-05-19 | Valve assembly |
GB9911648.3 | 1999-05-19 | ||
US09/575,325 US6508309B1 (en) | 1999-05-19 | 2000-05-19 | Valve assembly |
US10/331,274 US20030094285A1 (en) | 1999-05-19 | 2002-12-30 | Valve assembly |
Related Parent Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
US09/575,325 Continuation US6508309B1 (en) | 1999-05-19 | 2000-05-19 | Valve assembly |
Publications (1)
Publication Number | Publication Date |
---|---|
US20030094285A1 true US20030094285A1 (en) | 2003-05-22 |
Family
ID=10853684
Family Applications (2)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
US09/575,325 Expired - Fee Related US6508309B1 (en) | 1999-05-19 | 2000-05-19 | Valve assembly |
US10/331,274 Abandoned US20030094285A1 (en) | 1999-05-19 | 2002-12-30 | Valve assembly |
Family Applications Before (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
US09/575,325 Expired - Fee Related US6508309B1 (en) | 1999-05-19 | 2000-05-19 | Valve assembly |
Country Status (2)
Country | Link |
---|---|
US (2) | US6508309B1 (en) |
GB (2) | GB9911545D0 (en) |
Cited By (8)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US20050279506A1 (en) * | 2004-06-18 | 2005-12-22 | Mckee L M | Flow-biased sequencing valve |
US20090188662A1 (en) * | 2008-01-24 | 2009-07-30 | Dario Casciaro | Pressure Balanced Piston for Subsurface Safety Valves |
US20100051284A1 (en) * | 2008-08-28 | 2010-03-04 | Stewart Alex C | Valve trigger for downhole tools |
US20130068476A1 (en) * | 2010-03-11 | 2013-03-21 | Jeffrey Edwards | Well barrier |
US8522887B1 (en) * | 2010-05-18 | 2013-09-03 | Kent R. Madison | Aquifier flow controlling valve assembly and method |
US9068411B2 (en) | 2012-05-25 | 2015-06-30 | Baker Hughes Incorporated | Thermal release mechanism for downhole tools |
US20200095843A1 (en) * | 2018-09-20 | 2020-03-26 | Halliburton Energy Services, Inc. | Electric safety valve with annulus/section pressure activation |
CN112943165A (en) * | 2021-02-05 | 2021-06-11 | 东营市昌瑞石油机械配件有限责任公司 | Linkage type hydraulic layer-changing switch |
Families Citing this family (19)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US6691785B2 (en) * | 2000-08-29 | 2004-02-17 | Schlumberger Technology Corporation | Isolation valve |
US6808020B2 (en) * | 2000-12-08 | 2004-10-26 | Schlumberger Technology Corporation | Debris-free valve apparatus and method of use |
CA2445870C (en) * | 2001-04-30 | 2009-04-07 | Weatherford/Lamb, Inc. | Automatic tubing filler |
US6904975B2 (en) * | 2001-12-19 | 2005-06-14 | Baker Hughes Incorporated | Interventionless bi-directional barrier |
US7255173B2 (en) * | 2002-11-05 | 2007-08-14 | Weatherford/Lamb, Inc. | Instrumentation for a downhole deployment valve |
GB0401440D0 (en) * | 2004-01-23 | 2004-02-25 | Enovate Systems Ltd | Completion suspension valve system |
GB2443109B (en) * | 2004-01-23 | 2008-08-20 | Enovate Systems Ltd | Suspension valve system |
GB0414128D0 (en) * | 2004-06-24 | 2004-07-28 | Renovus Ltd | Valve |
US7789156B2 (en) * | 2004-06-24 | 2010-09-07 | Renovus Limited | Flapper valve for use in downhole applications |
US7434625B2 (en) * | 2005-06-01 | 2008-10-14 | Tiw Corporation | Downhole flapper circulation tool |
US7762336B2 (en) * | 2006-06-12 | 2010-07-27 | Weatherford/Lamb, Inc. | Flapper latch |
US7673689B2 (en) * | 2006-06-12 | 2010-03-09 | Weatherford/Lamb, Inc. | Dual flapper barrier valve |
GB0721746D0 (en) | 2007-11-06 | 2007-12-19 | Petrowell Ltd | Device |
US9784057B2 (en) * | 2008-04-30 | 2017-10-10 | Weatherford Technology Holdings, Llc | Mechanical bi-directional isolation valve |
US8733449B2 (en) * | 2011-04-15 | 2014-05-27 | Hilliburton Energy Services, Inc. | Selectively activatable and deactivatable wellbore pressure isolation device |
US20140202713A1 (en) | 2013-01-18 | 2014-07-24 | Halliburton Energy Services, Inc. | Well Intervention Pressure Control Valve |
US9518445B2 (en) | 2013-01-18 | 2016-12-13 | Weatherford Technology Holdings, Llc | Bidirectional downhole isolation valve |
US10132137B2 (en) | 2013-06-26 | 2018-11-20 | Weatherford Technology Holdings, Llc | Bidirectional downhole isolation valve |
GB201612508D0 (en) * | 2016-07-19 | 2016-08-31 | Black Diamond Holding Pte Ltd | Isolation apparatus and isolation methods |
Citations (9)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
USRE30070E (en) * | 1971-12-22 | 1979-08-14 | Otis Engineering Corporation | Apparatus for treating wells |
US4967844A (en) * | 1989-03-30 | 1990-11-06 | Elder Oil Tools | Selectively operable ball valve and production packer system |
US5251702A (en) * | 1991-07-16 | 1993-10-12 | Ava International Corporation | Surface controlled subsurface safety valve |
US5320178A (en) * | 1992-12-08 | 1994-06-14 | Atlantic Richfield Company | Sand control screen and installation method for wells |
US5372193A (en) * | 1992-11-13 | 1994-12-13 | French; Clive J. | Completion test tool |
US5484022A (en) * | 1991-08-08 | 1996-01-16 | Exploration & Production Services (North Sea) Ltd. | Tubing test valve |
US6079497A (en) * | 1997-06-03 | 2000-06-27 | Camco International Inc. | Pressure equalizing safety valve for subterranean wells |
US6209663B1 (en) * | 1998-05-18 | 2001-04-03 | David G. Hosie | Underbalanced drill string deployment valve method and apparatus |
US6230808B1 (en) * | 1996-02-03 | 2001-05-15 | Ocre (Scotland) Limited | Downhole apparatus |
Family Cites Families (4)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US5810087A (en) | 1996-01-24 | 1998-09-22 | Schlumberger Technology Corporation | Formation isolation valve adapted for building a tool string of any desired length prior to lowering the tool string downhole for performing a wellbore operation |
GB9709007D0 (en) | 1997-05-03 | 1997-06-25 | Ocre Scotland Ltd | Casing perforating system |
CA2269876C (en) | 1998-05-18 | 2005-12-27 | Gulf Technologies International, L.C. | Underbalanced drill string deployment valve method and apparatus |
US6167974B1 (en) * | 1998-09-08 | 2001-01-02 | Halliburton Energy Services, Inc. | Method of underbalanced drilling |
-
1999
- 1999-05-19 GB GBGB9911545.3A patent/GB9911545D0/en not_active Ceased
-
2000
- 2000-05-19 GB GB0012206A patent/GB2350852B/en not_active Expired - Fee Related
- 2000-05-19 US US09/575,325 patent/US6508309B1/en not_active Expired - Fee Related
-
2002
- 2002-12-30 US US10/331,274 patent/US20030094285A1/en not_active Abandoned
Patent Citations (9)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
USRE30070E (en) * | 1971-12-22 | 1979-08-14 | Otis Engineering Corporation | Apparatus for treating wells |
US4967844A (en) * | 1989-03-30 | 1990-11-06 | Elder Oil Tools | Selectively operable ball valve and production packer system |
US5251702A (en) * | 1991-07-16 | 1993-10-12 | Ava International Corporation | Surface controlled subsurface safety valve |
US5484022A (en) * | 1991-08-08 | 1996-01-16 | Exploration & Production Services (North Sea) Ltd. | Tubing test valve |
US5372193A (en) * | 1992-11-13 | 1994-12-13 | French; Clive J. | Completion test tool |
US5320178A (en) * | 1992-12-08 | 1994-06-14 | Atlantic Richfield Company | Sand control screen and installation method for wells |
US6230808B1 (en) * | 1996-02-03 | 2001-05-15 | Ocre (Scotland) Limited | Downhole apparatus |
US6079497A (en) * | 1997-06-03 | 2000-06-27 | Camco International Inc. | Pressure equalizing safety valve for subterranean wells |
US6209663B1 (en) * | 1998-05-18 | 2001-04-03 | David G. Hosie | Underbalanced drill string deployment valve method and apparatus |
Cited By (18)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US20050279506A1 (en) * | 2004-06-18 | 2005-12-22 | Mckee L M | Flow-biased sequencing valve |
US7311153B2 (en) * | 2004-06-18 | 2007-12-25 | Schlumberger Technology Corporation | Flow-biased sequencing valve |
GB2485315B (en) * | 2008-01-24 | 2012-07-11 | Baker Hughes Inc | Pressure balanced piston for subsurface safety valves |
NO344691B1 (en) * | 2008-01-24 | 2020-03-09 | Baker Hughes A Ge Co Llc | Pressure balanced piston for underground safety valves |
US7743833B2 (en) * | 2008-01-24 | 2010-06-29 | Baker Hughes Incorporated | Pressure balanced piston for subsurface safety valves |
GB2468984B (en) * | 2008-01-24 | 2012-05-02 | Baker Hughes Inc | Pressure balanced piston for subsurface safety valves |
GB2485315A (en) * | 2008-01-24 | 2012-05-09 | Baker Hughes Inc | Pressure balanced piston for subsurface safety valves |
US20090188662A1 (en) * | 2008-01-24 | 2009-07-30 | Dario Casciaro | Pressure Balanced Piston for Subsurface Safety Valves |
US7793733B2 (en) * | 2008-08-28 | 2010-09-14 | Baker Hughes Incorporated | Valve trigger for downhole tools |
US20100051284A1 (en) * | 2008-08-28 | 2010-03-04 | Stewart Alex C | Valve trigger for downhole tools |
US20130068476A1 (en) * | 2010-03-11 | 2013-03-21 | Jeffrey Edwards | Well barrier |
US9297233B2 (en) * | 2010-03-11 | 2016-03-29 | Enovate Systems Limited | Well barrier |
US10024139B2 (en) | 2010-03-11 | 2018-07-17 | Enovate Systems Limited | Well barrier |
US8522887B1 (en) * | 2010-05-18 | 2013-09-03 | Kent R. Madison | Aquifier flow controlling valve assembly and method |
US9068411B2 (en) | 2012-05-25 | 2015-06-30 | Baker Hughes Incorporated | Thermal release mechanism for downhole tools |
US20200095843A1 (en) * | 2018-09-20 | 2020-03-26 | Halliburton Energy Services, Inc. | Electric safety valve with annulus/section pressure activation |
US11643905B2 (en) * | 2018-09-20 | 2023-05-09 | Halliburton Energy Services, Inc. | Electric safety valve with annulus/section pressure activation |
CN112943165A (en) * | 2021-02-05 | 2021-06-11 | 东营市昌瑞石油机械配件有限责任公司 | Linkage type hydraulic layer-changing switch |
Also Published As
Publication number | Publication date |
---|---|
GB2350852A (en) | 2000-12-13 |
US6508309B1 (en) | 2003-01-21 |
GB9911545D0 (en) | 1999-07-21 |
GB2350852B (en) | 2003-10-08 |
GB0012206D0 (en) | 2000-07-12 |
Similar Documents
Publication | Publication Date | Title |
---|---|---|
US6508309B1 (en) | Valve assembly | |
AU2003234673B2 (en) | Method and apparatus to reduce downhole surge pressure using hydrostatic valve | |
US6302216B1 (en) | Flow control and isolation in a wellbore | |
EP1264076B1 (en) | Multi-purpose float equipment and method | |
US7721805B2 (en) | Method and apparatus to hydraulically bypass a well tool | |
US6866100B2 (en) | Mechanically opened ball seat and expandable ball seat | |
EP1794411B1 (en) | Downhole safety valve apparatus and method | |
EP1771639B1 (en) | Downhole valve | |
CA2445870C (en) | Automatic tubing filler | |
EP2261457A2 (en) | Method and apparatus for drilling a borehole into a subsea abnormal pore pressure environment | |
EP2053196A1 (en) | System and method for controlling the pressure in a wellbore | |
US6109353A (en) | Single bore riser system | |
EP1828537B1 (en) | Method and apparatus to hydraulically bypass a well tool | |
GB2388139A (en) | Wellbore isolation valve | |
CA2269876C (en) | Underbalanced drill string deployment valve method and apparatus | |
EP4077870B1 (en) | Valve assembly for controlling fluid communication along a well tubular | |
CA2487012C (en) | Method and apparatus to reduce downhole surge pressure using hydrostatic valve | |
CA2560828C (en) | Actuation system for an oilfield tubular handling system |
Legal Events
Date | Code | Title | Description |
---|---|---|---|
STCB | Information on status: application discontinuation |
Free format text: ABANDONED -- FAILURE TO RESPOND TO AN OFFICE ACTION |