STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OF DEVELOPMENT
Not applicable.
BACKGROUND
1. Field of Inventions
The field of this application and any resulting patent is an improved valve, and in particular, but not exclusively, to improvements in and relating to a downhole shutoff valve.
2. Description of Related Art
Various systems and methods have been proposed and utilized for preventing fluids from flowing back into a formation once production is stopped, including some of the systems and methods in the references appearing on the face of this patent. However, those systems and methods lack all the steps or features of the systems and methods covered by any patent claims below. As will be apparent to a person of ordinary skill in the art, any systems and methods covered by claims of the issued patent solve many of the problems that prior art systems and methods have failed to solve. Also, the systems and methods covered by at least some of the claims of this patent have benefits that could be surprising and unexpected to a person of ordinary skill in the art based on the prior art existing at the time of invention.
SUMMARY
One or more specific embodiments disclosed herein includes a shutoff valve device that may comprise a top sub, a bottom sub, and a flow tube, wherein the bottom sub may comprise a flapper valve and a valve seat, and further wherein the flow tube may comprise drag features designed to move the flow tube back and forth from a first position (holding the flapper valve in a completely open position) to a second position (allowing the flapper valve to a closed, sealed position), depending on the direction of fluid flow in the wellbore.
One or more specific embodiments disclosed herein includes a shutoff valve device for permitting and preventing fluid flow in a production string, comprising: a body comprising a borehole, wherein the body is a top sub coupled to a bottom sub via a threaded fastener; a flow tube disposed within the body's borehole and capable of axial movement within the body's borehole, comprising a flow tube borehole; a bi-directional actuator attached to a bottom opening of the flow tube, comprising flexible flaps; and a flapper valve disposed within the body's borehole, wherein the flapper valve is hingedly coupled to a top surface of the bottom sub and capable of moving between a fully opened and fully closed position.
One or more specific embodiments disclosed herein includes a shutoff valve device for permitting and preventing fluid flow in a production string, comprising: a body comprising a borehole, wherein the body is a top sub coupled to a bottom sub via a threaded fastener; a flow tube disposed within the body's borehole and capable of axial movement within the body's borehole, comprising a flow tube borehole; a compression spring disposed radially between the flow tube and the body, wherein the compression spring biases the flow tube in an axially upward position; a bi-directional actuator attached to a bottom opening of the flow tube, comprising flexible flaps; and a flapper valve disposed within the body's borehole, wherein the flapper valve is hingedly coupled to a top surface of the bottom sub and capable of moving between a fully opened and fully closed position.
One or more specific embodiments disclosed herein includes a method for permitting and preventing fluid flow in a production string, comprising: outfitting a production string with a shutoff valve device comprising: a body comprising a borehole, wherein the body is a top sub coupled to a bottom sub via a threaded fastener; a flow tube disposed within the body's borehole and capable of axial movement within the body's borehole, comprising a flow tube borehole; a bi-directional actuator attached to a bottom opening of the flow tube, comprising flexible flaps; and a flapper valve disposed within the body's borehole, wherein the flapper valve is hingedly coupled to a top surface of the bottom sub and capable of moving between a fully opened and fully closed position.
The foregoing has outlined rather broadly the features and technical advantages of the present invention in order that the detailed description of the invention that follows may be better understood. Additional features and advantages of the invention will be described hereinafter that form the subject of the claims of the invention. It should be appreciated by those skilled in the art that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other embodiments for carrying out the same purposes of the present invention. It should also be realized by those skilled in the art that such equivalent embodiments do not depart from the spirit and scope of the invention as set forth in the appended claims.
BRIEF DESCRIPTION OF THE DRAWINGS
For a detailed description of the preferred embodiments of the invention, reference will now be made to the accompanying drawings in which:
FIG. 1A-1C each illustrate a portion of a production string configured with a shutoff valve in accordance with embodiments of the present invention;
FIG. 2 illustrates an internal side view of a shutoff valve in accordance with embodiments of the present invention;
FIG. 3 illustrates a perspective view of a portion of a bottom sub of a shutoff valve in accordance with embodiments of the present invention;
FIGS. 4A-4D each illustrate an orifice disk in accordance with embodiments of the present invention;
FIGS. 5A and 5B each illustrate an internal side view of an alternative flapper valve in accordance with embodiments of the present invention;
FIG. 6A-6C each illustrate an internal side view of a shutoff valve in accordance with embodiments of the present invention in different operating positions;
FIG. 7A-7C each illustrate an internal side view of an alternative shutoff valve in accordance with embodiments of the present invention in different operating positions;
FIGS. 8A and 8B each illustrate an internal side view of an alternative shutoff valve in accordance with embodiments of the present invention in different operating positions;
FIGS. 9A and 9B each illustrate an internal side view of an alternative shutoff valve in accordance with embodiments of the present invention in different operating positions;
FIGS. 10A-10G illustrate a progression of debris removal from a shutoff valve 100 in accordance with embodiments of the present invention.
DETAILED DESCRIPTION
1. Introduction
A detailed description will now be provided. The purpose of this detailed description, which includes the drawings, is to satisfy the statutory requirements of 35 U.S.C. § 112. For example, the detailed description includes a description of the inventions defined by the claims and sufficient information that would enable a person having ordinary skill in the art to make and use the inventions. In the figures, like elements are generally indicated by like reference numerals regardless of the view or figure in which the elements appear. The figures are intended to assist the description and to provide a visual representation of certain aspects of the subject matter described herein. The figures are not all necessarily drawn to scale, nor do they show all the structural details of the systems, nor do they limit the scope of the claims.
Each of the appended claims defines a separate invention which, for infringement purposes, is recognized as including equivalents of the various elements or limitations specified in the claims. Depending on the context, all references below to the “invention” may in some cases refer to certain specific embodiments only. In other cases, it will be recognized that references to the “invention” will refer to the subject matter recited in one or more, but not necessarily all, of the claims. Each of the inventions will now be described in greater detail below, including specific embodiments, versions, and examples, but the inventions are not limited to these specific embodiments, versions, or examples, which are included to enable a person having ordinary skill in the art to make and use the inventions when the information in this patent is combined with available information and technology.
2. Specific Embodiments in the Figures
The drawings presented herein are for illustrative purposes only and are not intended to limit the scope of the claims. Rather, the drawings are intended to help enable one having ordinary skill in the art to make and use the claimed inventions.
Referring to FIGS. 1A-10G, specific embodiments, e.g., versions or examples, of a shutoff valve are illustrated. These figures may show features which may be found in various specific embodiments, including the embodiments shown in this specification and those not shown.
FIGS. 1A-1C each illustrate a portion of a production string 2, a primary conduit through which reservoir fluids are produced to surface. Depending on wellbore conditions and desired production method, production string 2 may be configured and/or assembled with various tubing and completion components. As illustrated in FIG. 1A, production string 2 may be configured for gas lift application and comprise, without limitation, tubing 4, an artificial lift completion such as a gas lift mandrel 6, an on-off tool 8, a retrievable production packer 10, or any combinations thereof. Alternatively, as illustrated in FIG. 1B, production string 2 may be configured for electric submersible pump (ESP) application and comprise, without limitation, tubing 4, an artificial lift completion such as an ESP 12, retrievable production packer 10, or any combinations thereof. In addition to the various completion components, production string 2 may comprise a shutoff valve 100, a flow actuated device that creates a down hole barrier to prevent loss of kill fluid into a reservoir or formation when downhole flow may be reversed, for instance when production may be stopped. Loss of said kill fluid could damage the reservoir and/or formation. In embodiments, shutoff valve 100 may be installed at any suitable location on production string 2. As illustrated in both FIGS. 1A and 1B, shutoff valve 100 may be installed below (further downhole) gas lift mandrel 6 or ESP 12 as well as below retrievable production packer 10. Alternatively, although not illustrated, shutoff valve 100 may be installed above (further uphole) gas lift mandrel 6 or ESP 12 as well as above retrievable production packer 10. Further alternatively, shutoff valve 100 may be installed below gas lift mandrel 6 or ESP 12 and above retrievable production packer 10, as illustrated in FIG. 1C. In such an embodiment, shutoff valve 100 may comprise a fish neck 3 and flow ports 5.
In embodiments, shutoff valve 100 may be installed on new or existing completion strings of various tubing sizes, which in turn may govern the size of shutoff valve 100. Standard tubing size (measured from an outer diameter) may range from about 2⅜ inches to about 4½ inches. In embodiments, the tubing size may be 2⅞ inches, 3½ inches, or 4½ inches. Depending on the tubing size, shutoff valve 100 may be manufactured in a range of suitable sizes, comprising an outer diameter between about 4 inches and about 8 inches and an inner diameter between about 2 inches and about 4 inches. Note that the outer diameter may be measure from the point of greatest outer diameter of shutoff valve 100 and the inner diameter may be measured from the point of smallest inner diameter of shutoff valve 100, particularly in embodiments in which the outer and inner diameters of shutoff valve 100 may be variable along the axial length. In embodiments, shutoff valve 100, when employed on a completion string using tubing sized to 2% inches, may comprise an outer diameter measuring about 4.65 inches and an inner diameter measuring about 2.31 inches. Alternatively, shutoff valve 100, when employed on a completion string using tubing sized to 3½ inches, may comprise an outer diameter measuring about 5.20 inches and an inner diameter measuring about 2.75 inches. Further alternatively, shutoff valve 100, when employed on a completion string with tubing sized to 4½ inches, may comprise an outer diameter measuring about 7.20 inches and an inner diameter measuring about 3.75 inches. Depending on tubing size, shutoff valve 100 may be rated for high pressures between about 5,000 psi to about 15,000 psi. In embodiments, shutoff valve 100 may be rated for pressures up to 10,000 psi. Further, shutoff valve 100 may be rated for standard and high temperatures between about 300° F. and about 700° F. In embodiments, shutoff valve may be rated for a standard temperature of about 350° F., or alternatively for a high temperature of about 600° F. Regardless of the tubing size, shutoff valve 100 may be manufactured to any suitable axial length, ranging from about 25 inches to about 45 inches. In embodiments, the overall axial length of shutoff valve 100 may be about 35 inches.
FIG. 2 illustrates an internal side view of an embodiment of shutoff valve 100. Shutoff valve 100 may comprise a top sub 102, a bottom sub 104, a flow tube 106, and a flapper valve 126. In embodiments, top sub 102 and bottom sub 104 may be hollow-bodied metal components coupled together via any suitable fastening mechanisms, thereby forming a borehole 118 through which fluid may flow. Top sub 102 and/or bottom sub 104 may be manufactured from any oil field steel. For example, top sub 102 and/or bottom sub 104 may be manufactured from L-80 Steel, P-110 Steel, 9 Chrome, 13 Chrome, etc. In embodiments, suitable fastening mechanisms may comprise, without limitation, a threaded fastener 122, shear screws 124, or any combinations thereof. Threaded fastener 122 may comprise female/internal threading disposed on a portion of the interior surface of top sub 102 as well as corresponding male/external threading disposed on a portion of the exterior surface of bottom sub 104, thus providing a means by which bottom sub 104 may be screwed into top sub 102. The male/external threading of threaded fastener 122 as well as some other components may be further depicted in FIG. 3, illustrating a perspective view of a portion of bottom sub 104. In some embodiments, threaded fastener 122 may comprise a 4- 5/16-inch diameter, 8 thread per inch, ACME thread with a class 2G. In other embodiments, other thread types may be employed. Referring once again to FIG. 2, a top portion of bottom sub 104 may be screwed into a bottom portion of top sub 102 via threaded fastener 122 until the bottom portion of top sub 102 engages a flange 116 of bottom sub 104. In conjunction with or independent of threaded fastener 122, shear screws 124 may be employed to connect top sub 102 to bottom sub 104. In embodiments, shear screws 124 may be threaded through top sub 102 and bottom sub 104 in a radial direction at a point at which the bottom portion of top sub 102 overlaps with the top portion of bottom sub 104. Shear screws 124 may allow for shearing between top sub 102 and bottom sub 104 in the event of emergency or malfunction of shutoff valve 100, such as an inadvertent obstruction of fluid flow through borehole 118. Shearing may be performed by applying a pressure to shutoff valve 100 that exceeds its overall pressure rating. In some embodiments, shutoff valve 100 may further comprise a sealing element 132 disposed radially between top sub 102 and bottom sub 104 at the point at which the bottom portion of top sub 102 overlaps with the top portion of bottom sub 104. Sealing element 132 may be any suitable sealing mechanism such as, without limitation, an O-ring or the like, which may be capable of preventing fluid leakage from borehole 118. In embodiments, borehole 118 may comprise upper and lower portions 119 and 121, each having a diameter corresponding to that of the tubing utilized in the completion string on which shutoff valve 100 may be installed (i.e., the inner diameter of shutoff valve 100). Further, borehole 118 may comprise a middle portion 123 having a variable diameter greater than that of upper and lower portions 119 and 121.
As illustrated in FIG. 2, middle portion 123 may contain flow tube 106, a hollow-bodied metal cylinder comprising a flow tube borehole through which fluid flowing through borehole 118 may pass. In embodiments, flow tube 106 may be sized to fit within middle portion 123, such that the flow tube borehole may be in-line with upper and lower portions 119 and 121, as well as correspond in diameter to that of upper and lower portions 119 and 121. Further, flow tube 106 may be sized, particularly in length, to be capable of axial movement within middle portion 123. To aid in facilitating this axial movement, embodiments of flow tube 106 may be outfitted with an orifice disk 146 by any suitable means. Orifice disk 146 may be a bi-directional actuator of a single, circular component attached over a bottom opening of flow tube 106 via screws 148, thus providing a partial covering of the bottom opening. In embodiments, orifice disk 146 may be mad up of proprietary fiber-infused, erosion-resistant material such as, without limitation, rubber materials.
FIGS. 4A-4D illustrate different embodiments of orifice disk 146 with one or more holes 149 to receive screws 148. In embodiments, orifice disk 146, on addition to holes 149, may comprise an opening 147 and any suitable number of flexible flaps 152. FIG. 4A illustrates an embodiment of orifice disk 146 comprising opening 147 and six flexible flaps 152, FIG. 4B illustrates an embodiment of orifice disk 146 comprising opening 147 and three flexible flaps 152, and FIG. 4C illustrates an embodiment of orifice disk 146 comprising opening 147 and four flexible flaps 152. FIG. 4D, as opposed to FIGS. 4A-4C, may not initially comprise opening 147, but rather may only initially comprise three flexible flaps 152, in addition to holes 149. For such an embodiment, it may not be until orifice disk 146 experiences fluid flow that opening 147 may be revealed through spacing in flexible flaps 152 caused by the fluid flow. Orifice disk 146, having flexibility by nature of material, may allow for fluid to flow through opening 147 and flexible flaps 152 at the bottom opening of flow tube 106 and manipulate the axial movement of flow tube 106. Further, orifice disk 146, having durability by nature of material, may experience minimal erosion that could otherwise be caused by the flowing fluid.
Referring to FIG. 2, middle portion 123 may further contain flapper valve 126, a circular metal flapper capable of obstructing fluid flow within borehole 118. In embodiments, flapper valve 126 may be sized, particularly in area, to be seated on a valve seat 136 comprising a sealing element 134, and further may be disposed on a top surface of bottom sub 104. As such, flapper valve 126 may be capable of fully covering a top opening of flow tube 106. Further, flapper valve 126 may be connected to the top surface of bottom sub 104 via a hinge pin connection 141 comprising a hinge pin 140 and a spring 138 (e.g., a torsion spring, a compression spring, a tension spring, or the like) to allow for hinged movement of flapper valve 126 within middle portion 123. In embodiments, flapper valve 126 may be capable of moving between a fully opened position and a fully closed position. The fully opened position may comprise flapper valve 126 being positioned at about a 90° angle relative to the top surface of bottom sub 104 within a flapper valve recess 125 of middle portion 123, while the fully closed position may comprise flapper valve 126 being positioned at about a 0° angle relative to the top surface of bottom sub 104, in complete contact with valve seat 136. Alternate embodiments of flapper valve 126 and valve seat 136 may be illustrated in FIGS. 5A and 5B. FIG. 5A illustrates an angled flapper valve 126 comprising an angled edge 127 to correspondingly mate with angled valve seat 136. FIG. 5B illustrates a flapper valve 126 capable of mating with a ridged valve seat 136 comprising a ridge 137. Although not exhaustively illustrated, flapper valve 126 may be any shape suitable for properly mating with valve seat 136 such as, without limitation, straight, convex, and/or concaved, as it relates to fluid flow in the downhole direction.
In embodiments, flow tube 106 and flapper valve 126 may operate in conjunction to permit or prevent flow through borehole 118 of shutoff valve 100. FIGS. 6A-6C illustrate various positions in which shutoff valve 100 may operate. FIG. 6A, which is the same as FIG. 2 described above, illustrates shutoff valve 100 in an initial resting position during operation. In this position, flow tube 106, through the assistance of gravity, may be disposed below flapper valve 126 such that the bottom of flow tube 106 may be resting on a lower ledge 130. Lower ledge 130 may provide a means in which to prevent any further downward axial movement of flow tube 106 during operation. Further, flapper valve 126, through the assistance of spring 138, may be biased in a partially opened position at about a 45° angle relative to the top surface of bottom sub 104. In this position, there may be minimal or no fluid flowing through borehole 118.
FIG. 6B illustrates shutoff valve 100 in a fully opened position during operation. In this position, flow tube 106 may be disposed such that the top opening may be in contact with an upper ledge 120 and an outer portion of orifice disk 146 disposed at the bottom opening of flow tube 106 may be in contact with a middle ledge 131. In embodiments, the contact between the outer portion of orifice disk 146 and middle ledge 131 may aid in preventing fluid from leaking into an annulus between flow tube 106 and top and bottom subs 102 and 104. Upper ledge 120 and middle ledge 131 may provide a means in which to prevent any further upward axial movement of flow tube 106 during operation. Further, flapper valve 126 may be in the fully opened position. This positioning of flow tube 106 and flapper valve 126 may be caused by fluid flowing upward through borehole 118, toward the surface of the well. The upward flowing fluid may engage with flexible flaps 152 of orifice disk 146, pushing flexible flaps 152 toward the surface of the well, thereby forcing flow tube 106 to move axially upward until reaching upper ledge 120 and middle ledge 131. In this position, fluid may continuously flow through borehole 118, passing through opening 147 of orifice disk 146, which includes any space created by the displacement of flexible flaps 152, as well as through the flow tube borehole. This may occur with a minimal pressure drop of less than 3 psi. Further in this position, flapper valve 126 may be isolated from the upward flowing fluid, thus preventing any erosion to flapper valve 126 that may otherwise be caused by the upward flowing fluid.
FIG. 6C illustrates shutoff valve 100 in a fully closed position. In this position, similarly to the initial resting position, flow tube 106 may be disposed below flapper valve 126 such that the bottom of flow tube 106 may be resting on lower ledge 130. However, flapper valve 126 may be in the fully closed position, thus preventing any fluid flow within borehole 118. This positioning of flow tube 106 and flapper valve 126 may be caused by fluid flowing downward through borehole 118, in a downhole direction. The downward flowing fluid may engage with flexible flaps 152 of orifice disk 146, pushing flexible flaps 152 downward, thereby forcing flow tube 106 to move axially downward until reaching lower ledge 130. Further, the downward flowing fluid may engage with a top side of flapper valve 126, pushing flapper valve 126 into valve seat 136. In embodiments, sealing element 134 may provide an initial seal for flapper valve 126 until load from the pressure differential of the downward flowing fluid creates a metal-to-metal seal between flapper valve 126 and valve seat 136. In this position, fluid flow within borehole 118 may be halted, thus preventing any kill fluid from flowing back into the formation, particularly when production has stopped. This may reduce potential reservoir damage due to fluid loss.
FIGS. 7A-7C illustrate an alternative embodiment of shutoff valve 100. In this embodiment, shutoff valve 100 may comprise an alternative flow tube 111, which may be similar to that of flow tube 106, but comprises a drag section 154 rather than orifice disk 146. Drag section 154 may be a section of flow tube 111 of smaller inner diameter or smaller inner and outer diameter comprising one or more surface-facing drags 156 and one or more downhole-facing drags 158. In such embodiments, drag section 154 may provide similar functionality for shutoff valve 100 as that of orifice disk 146. FIG. 7A, illustrates shutoff valve 100 in an initial resting position during operation. In this position, flow tube 111, through the assistance of gravity, may be disposed below flapper valve 126 such that the bottom of flow tube 111 may be resting on lower ledge 130. Lower ledge 130 may provide a means in which to prevent any further downward axial movement of flow tube 111 during operation. Further, flapper valve 126, through the assistance of spring 138, may be biased in a partially opened position at about a 45° angle relative to the top surface of bottom sub 104. In this position, there may be minimal or no fluid flowing through borehole 118.
FIG. 7B illustrates shutoff valve 100 in a fully opened position during operation. In this position, flow tube 111 may be disposed such that the top opening may be in contact with upper ledge 120. Upper ledge 120 may provide a means in which to prevent any further upward axial movement of flow tube 111 during operation. Further, flapper valve 126 may be in the fully opened position. This positioning of flow tube 111 and flapper valve 126 may be caused by fluid flowing upward through borehole 118, toward the surface of the well. The upward flowing fluid may engage with downhole-facing drag 158, thereby forcing flow tube 111 to move axially upward until reaching upper ledge 120. In this position, fluid may continuously flow through borehole 118, passing through the flow tube borehole. This may occur with a minimal pressure drop of less than 3 psi. Further in this position, flapper valve 126 may be isolated from the upward flowing fluid, thus preventing any erosion to flapper valve 126 that may otherwise be caused by the upward flowing fluid.
FIG. 7C illustrates shutoff valve 100 in a fully closed position. In this position, similarly to the initial resting position, flow tube 111 may be disposed below flapper valve 126 such that the bottom of flow tube 111 may be resting on lower ledge 130. However, flapper valve 126 may be in the fully closed position, thus preventing any fluid flow within borehole 118. This positioning of flow tube 111 and flapper valve 126 may be caused by fluid flowing downward through borehole 118, in a downhole direction. The downward flowing fluid may engage with surface-facing drag 156, thereby forcing flow tube 111 to move axially downward until reaching lower ledge 130. Further, the downward flowing fluid may engage with a top side of flapper valve 126, pushing flapper valve 126 into valve seat 136. In embodiments, sealing element 134 may provide an initial seal for flapper valve 126 until load from the pressure differential of the downward flowing fluid creates a metal-to-metal seal between flapper valve 126 and valve seat 136. In this position, fluid flow within borehole 118 may be halted, thus preventing any kill fluid from flowing back into the formation, particularly when production has stopped. This may reduce potential reservoir damage due to fluid loss.
FIGS. 8A and 8B illustrate an alternative embodiment of shutoff valve 100. In this embodiment, shutoff valve 100 may comprise an alternative flow tube 107, which may be similar to that of flow tube 106, but further comprise flow tube notch 166. Further in this embodiment, shutoff valve 100 may comprise a flow tube spring 160, a compression spring disposed radially between flow tube 107 and bottom sub 104 and axially between movable spring guard 162 and stationary spring guard 164. In some embodiments, bottom sub 104 may consist of two parts 103 and 105 coupled together by any suitable fastening mechanisms as previously described. In such embodiments, flow tube spring 160 may be radially disposed between flow tube 107 and bottom sub part 103. FIG. 8A illustrates alternative shutoff valve 100 in an initial resting position/fully opened position during operation. In this position, spring 160 may bias flow tube 107 such that the top opening may be in contact with upper ledge 120, an outer portion of orifice disk 146 may be in contact with middle ledge 131, and a connection point 143 between orifice disk 146 and flow tube 107 may be in contact with stationary spring guard 164. In embodiments, the contact between the outer portion of orifice disk 146 and middle ledge 131 may aid in preventing fluid from leaking into an annulus between flow tube 107 and top and bottom subs 102 and 104. Upper ledge 120 and middle ledge 131 may provide a means in which to prevent any further upward axial movement of flow tube 107 during operation. Further, flapper valve 126 may be in the fully opened position. This positioning of flow tube 107 and flapper valve 126 may be caused or assisted by decompression of flow tube spring 160, which may be capable of applying an upward force through movable spring guard 132 to flow tube notch 166, particularly when there may be minimal or no fluid flowing through borehole 118, or rather when fluid may be flowing upward through borehole 118, toward the surface of the well. Similar to previous embodiments, in this position, fluid may continuously flow through borehole 118, passing through opening 147 of orifice disk 146, which includes any space created by the displacement of flexible flaps 152, as well as through the flow tube borehole. This may occur with a minimal pressure drop of less than 3 psi. Further in this position, flapper valve 126 may be isolated from the upward flowing fluid, thus preventing any erosion to flapper valve 126 that may otherwise be caused by the upward flowing fluid.
FIG. 8B illustrates alternative shutoff valve 100 in a fully closed position during operation. In this position, downward flowing fluid may bias flow tube 107 below flapper valve 126 such that the bottom of flow tube 107 may be resting on lower ledge 130. Further, flapper valve 126 may be in the fully closed position. This positioning of flow tube 107 and flapper valve 126 may be caused or assisted by fluid flowing downward through borehole 118, in a downhole direction. The downward flowing fluid may engage with flexible flaps 152 of orifice disk 146, pushing flexible flaps 152 downward, thereby forcing flow tube 107 to move axially downward until reaching lower ledge 130. As such, flow tube notch 166 may apply a downward force to movable spring guard 162 thereby axially displacing movable spring guard 162 in the downward direction and compressing spring 160 between movable spring guard 162 and stationary spring guard 164. Further, the downward flowing fluid may engage with a top side of flapper valve 126, pushing flapper valve 126 into valve seat 136. Similar to previous embodiments, sealing element 134 may provide an initial seal for flapper valve 126 until load from the pressure differential of the downward flowing fluid creates a metal-to-metal seal between flapper valve 126 and valve seat 136. In this position, fluid flow within borehole 118 may be halted, thus preventing any kill fluid from flowing back into the formation, particularly when production has stopped. This may reduce potential reservoir damage due to fluid loss.
FIGS. 9A and 9B illustrate an alternative embodiment of shutoff valve 100. In this embodiment, shutoff valve 100 may comprise an alternative flow tube 109, which may be similar to that of flow tube 107, but further comprise an orifice disk extension piece 145. In such embodiments, orifice disk 146 may be attached to a bottom opening of orifice disk extension piece 145 via screws 148, while orifice disk extension piece 145 may in turn be attached to flow tube 109 by any suitable means, such as screws 129. In embodiments, flow tube 109 may function similarly to that of flow tube 107, as is illustrated in FIGS. 9A and 9B. FIG. 9A illustrates alternative shutoff valve 100 in an initial resting position/fully opened position during operation. In this position, spring 160 may bias flow tube 109 such that the top opening may be in contact with upper ledge 120 and a connection point 171 between orifice disk extension piece 145 and flow tube 109 may be in contact with stationary spring guard 164. Upper ledge 120 and stationary spring guard 164 may provide a means in which to prevent any further upward axial movement of flow tube 109 during operation. Further, flapper valve 126 may be in the fully opened position. Similar to previous embodiments, this positioning of flow tube 109 and flapper valve 126 may be caused or assisted by decompression of flow tube spring 160, which may be capable of applying an upward force through movable spring guard 132 to flow tube notch 166, particularly when there may be minimal or no fluid flowing through borehole 118, or rather when fluid may be flowing upward through borehole 118, toward the surface of the well. In this position, fluid may continuously flow through borehole 118, passing through opening 147 of orifice disk 146, which includes any space created by the displacement of flexible flaps 152, as well as through the flow tube borehole. This may occur with a minimal pressure drop of less than 3 psi. Further in this position, flapper valve 126 may be isolated from the upward flowing fluid, thus preventing any erosion to flapper valve 126 that may otherwise be caused by the upward flowing fluid.
FIG. 9B illustrates alternative shutoff valve 100 in a fully closed position during operation. In this position, downward flowing fluid may bias flow tube 109 below flapper valve 126. Further, flapper valve 126 may be in the fully closed position. Similar to previous embodiments, this positioning of flow tube 109 and flapper valve 126 may be caused or assisted by fluid flowing downward through borehole 118, in a downhole direction. The downward flowing fluid may engage with flexible flaps 152 of orifice disk 146, pushing flexible flaps 152 downward, thereby forcing flow tube 109 to move axially downward until below closed flapper valve 126. As such, flow tube notch 166 may apply a downward force to movable spring guard 162 thereby axially displacing movable spring guard 162 in the downward direction and compressing spring 160 between movable spring guard 162 and stationary spring guard 164. Further, the downward flowing fluid may engage with a top side of flapper valve 126, pushing flapper valve 126 into valve seat 136. Sealing element 134 may provide an initial seal for flapper valve 126 until load from the pressure differential of the downward flowing fluid creates a metal-to-metal seal between flapper valve 126 and valve seat 136. In this position, fluid flow within borehole 118 may be halted, thus preventing any kill fluid from flowing back into the formation, particularly when production has stopped. This may reduce potential reservoir damage due to fluid loss. Although only depicted in FIGS. 9A and 9B thus far, orifice disk extension piece 145 may be implemented on any one of the previous flow tube embodiments.
In addition to alternative flow tube 109, the alternative embodiment of shutoff valve 100 illustrated in FIGS. 9A and 9B may further comprise a pump-open sleeve 170. Pump-open sleeve 170 may be a sleeve disposed about an outer surface of top sub 102 covering openings 172, which may lead from borehole 118 to outside shutoff valve 100. In embodiments, pump-open sleeve 170 may be attached to top sub 102 via shear screws 176. Further, sealing elements 174 may be disposed radially between top sub 102 and pump-open sleeve 170 to aid in sealing off openings 172. These openings 172 may be disposed through top sub 102 in any suitable size, shape, and number, and may provide a means by which to clean out any built-up debris from above a fully closed flapper valve 126. Debris buildup may prevent shutoff valve 100 from moving to the fully open position after having been previously closed, thus may inadvertently restrict fluid flow within borehole 118.
FIGS. 10A-10G illustrate a progression of debris removal from an embodiment of shutoff valve 100 comprising pump-open sleeve 170 and experiencing a buildup of debris 180. FIG. 10A illustrates an initial state of shutoff valve 100 experiencing a buildup of debris 180 in a fully closed position. In order to remove debris 180, referring now to FIGS. 10B-10D an operator may apply a differential pressure (depicted by arrows 182) to shutoff valve 100 in the downhole direction. This applied differential pressure may be capable actuating pump-open sleeve 170 by shearing shear screws 176, thereby permanently uncovering openings 172. By actuating pump-open sleeve 170, at least a portion of debris 180 may be displaced from inside borehole 118 through openings 172. This displacement of debris 180, referring now to FIGS. 10E-10G, may allow at least some fluid flow (depicted by arrows 184) to be restored through openings 172. In embodiments, as the at least some fluid flow continues, the removal of debris 180 from above flapper valve 126 may also continue. Eventually, enough debris 180 may be removed so as to allow shutoff valve 100 to move to the fully open position and thereby allow, once again, upward fluid flow through borehole 118, as well as through openings 172. However, once pump-open sleeve 170 has been actuated, shutoff valve 100 may no longer be capable of moving to the fully closed position. In order to recover this functionality, an operator may need to retrieve shutoff valve 100 and redress the tool. Although only depicted in FIGS. 8A-9G, pump-open sleeve 170 may be implemented on any one of the previous shutoff valve embodiments.
The benefit of the embodiments of shutoff valve 100 may be that it deals with some common problems in wellbore production. In the absence of a shutoff valve in a producing well, the unobstructed downward flow of fluid may allow the pumping mechanism (e.g., an ESP or gas lift) to move in reverse, which could lead to damage of the pump. This may be especially true if an operator attempts to restart the pump while the pumping mechanism may already be moving in reverse. Another problem may be that unobstructed downward flow of fluid would be permitted to uncontrollably move back into the formation, which could cause serious issues with the productivity of the well. Alternatively, in the absence of a shutoff valve, unwanted upward fluid flow may be allowed to flow freely toward the surface of a well. To avoid this, particularly in injection wells, the embodiments of shutoff valve 100 may be reciprocally installed, thus capable of preventing unwanted upward fluid flow. Regardless of orientation, the advantages of the embodiments of shutoff valve 100 may be that it self-operates without the need for control lines or external actuation signals, as well as reduces rig time by maintaining static fluid level created by the downhole barrier.
Although the present invention and its advantages have been described in detail, it should be understood that various changes, substitutions and alterations may be made herein without departing from the spirit and scope of the invention as defined by the appended claims.
Patent Application
20220049575
