Patent Application
20250137350
Downhole pressure isolation tools for use in a tubing string, casing string, or other suitable assembly, the downhole isolation tool able to prevent the passage of high pressure fluids (i.e., liquid and/or gas).
There are a number of situations in the completion of oil and gas wells where it is desirable to isolate one section of a subterranean well from another. Bridge plugs (“plugs”) and packers are typically used to permanently or temporarily isolate two or more zones within a wellbore. Such isolation is often necessary to pressure test, perforate, frac, or stimulate a zone of the well without impacting or communicating with other zones within the wellbore. After completing the task requiring isolation, the plugs and/or packers may be removed or otherwise compromised to reopen the wellbore and restore fluid communication from all zones, both above and below the plug and/or packer.
Permanent (i.e., non-retrievable) plugs are typically drilled or milled to remove them. Most permanent plugs are constructed of a brittle material such as cast iron, cast aluminum, ceramics, or engineered composite materials that can be drilled or milled. However, problems sometimes occur during the removal of permanent plugs. For instance, without some sort of locking mechanism to hold the plug within the wellbore, the permanent plug components can bind upon the drill bit and rotate within the casing string. Such binding can result in extremely long drill-out times, excessive casing wear, or both. Long drill-out times are highly undesirable as rig time is typically charged by the hour.
Retrievable plugs typically have anchors and sealing elements to securely anchor the plug within the wellbore in addition to a retrieving mechanism to remove the plug from the wellbore. In operation, a retrieval tool is lowered into the wellbore to engage the retrieving mechanism on the plug. When the retrieving mechanism is actuated, the slips and sealing elements on the plug are retracted, permitting withdrawal of the plug from the wellbore.
A common problem with retrievable plugs is that accumulation of debris on the top of the plug may make it difficult or impossible to engage the retrieving mechanism. Debris within the well can also adversely affect the movement of the slips and/or sealing elements, thereby permitting only partial disengagement from the wellbore. Additionally, the jarring of the plug or friction between the plug and the wellbore can unexpectedly unlatch the retrieving tool or relock the anchoring components of the plug. Difficulties in removing a retrievable bridge plug sometimes require that a retrievable plug be drilled or milled to remove the plug from the wellbore.
Other plugs have employed sealing disks partially or wholly fabricated from brittle materials (e.g., ceramic) that can be physically fractured by dropping a weighted bar via wireline into the casing string to fracture the sealing disks. While permitting rapid and efficient removal within vertical wellbores, weighted bars are ineffective at removing sealing solutions in deviated or horizontal wellbores. Moreover, ceramic barriers tend to fracture as shards, leaving large chunks in the wellbore, which can clog ports and restrict flow.
A barrier valve having one or more frangible glass barriers may be configured to resist fluid flow in one or more specified directions. In particular embodiments, for example, a barrier valve may include a housing and a frangible glass barrier. The housing may include an outer wall and an inner wall, with the inner wall defining a passage through the housing. The frangible glass barrier may include a cylindrical base and a curved surface, with the cylindrical base having a bore therethrough and the curved surface having a convex outer face and a concave inner face. The inner face of the curved surface may close off the bore at one end of the cylindrical base. The frangible disk may be composed of glass having surface layers and an inner layer, the surface layers being in compression and the inner layer being in tension. In particular implementations, the compression in the surface layer may be at least 10,000 psi.
Various features will be evident to those skilled in the art in light of the following written description and the accompanying drawings. The features of any particular implementation are typically achievable in other implementations even if not described explicitly therein.
A barrier valve is provided. The term “barrier valve” refers to any downhole tool used to at least temporarily isolate one wellbore zone from another, including any tool with blind passages or plugged mandrels, as well as open passages extending completely therethrough and passages blocked with a check valve. Such tools can be a single assembly (i.e., one barrier valve) or comprise two or more assemblies disposed within a work string or otherwise connected and run into a wellbore on a wireline, slickline, production tubing, coiled tubing, or any technique known or yet to be discovered in the art. A barrier valve is to provide maintenance of fluid pressure in a tubular or casing string or provide for partial or total elimination of a borehole blockage to allow fluid communication through the barrier valve and the tubular or casing string.
So that the manner in which the above recited features of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, can be had by reference to various embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only example embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention can admit to other equally effective embodiments.
The valve section 160 can include one or more frangible disks 200 disposed therein. As illustrated, frangible disks 200 are disposed transversally to a longitudinal axis of barrier valve 100, preventing fluid communication through the passage in barrier valve 100. A first end of the one or more frangible disks 200 can be curved (e.g., domed). The curved configuration can provide greater pressure resistance than a comparable flat surface. In one or more embodiments, a first (“lower”) frangible disk 200 can be oriented with the curvature facing downward to provide greater pressure resistance to upward flow through barrier valve 100. In one or more embodiments, a second (“upper”) frangible disk 200 can be oriented with the curvature in a second direction (“upward”) to provide greater pressure resistance in a first direction (“downward”) through the barrier valve 100.
The terms “up” and “down”; “upper” and “lower”; “upwardly” and “downwardly”; “upstream” and “downstream”; “above” and “below”; and other like terms as used herein refer to relative positions to one another and are not intended to denote a particular direction or spatial orientation.
In particular implementations, frangible disk 200 may be made of a safety glass. As shown in the drawings, frangible disk 200 is monolithically formed from the glass material with the glass material extending from the top axial end to the bottom axial end.
The glass material may be based upon a fused quartz, borosilicate, soda lime, or any other appropriate material. After forming into its desired shape, the glass material may be treated (e.g., by heat and/or chemical treatment) so that the outer surfaces of the glass are put into compression and the interior is put into tension (e.g., even under zero load). In particular implementations, the compression may be above 10,000 psi, and in some implementations, the compression may be above 15,000 psi. The safety glass may, for example, be tempered glass or ultra-high compression, pre-tensioned glass. Tempered glass may, for instance be formed by dipping molten glass into cold water. While the outside of the glass quickly cools, the inside remains hot for a longer time. Allowances may have to be made for the different heat transfer rates between the outer surface and the inner surface (e.g., the inner surface may need more cooling due to its higher heat flux density). When the inside eventually cools, it shrinks, setting up very large compressive stresses on the surface.
The glass material may also be chemically strengthened. For example, the glass material may be immersed in an ion bath at an elevated temperature. The ion bath may result in an ion exchange at the surface of the glass creating a uniform surface compression layer. The surface compression layer may increase the strength of the glass material and make it more frangible.
Considering the valve section 160 in greater detail, a first end and a second end of the valve section 160 can define a threaded, annular, cross-section, which can permit threaded attachment of the valve section 160 to a lower sub-assembly (“bottom-sub”) 152, a casing string, and/or to other tubulars. As depicted in
In one or more embodiments, the first, downward facing, frangible disk 200 can be concentrically disposed transverse to the longitudinal axis of the barrier valve 100 with the end 205 proximate to the downward facing first surface 162 of the shoulder 164. A second, upwardly facing, frangible disk 200 can be similarly disposed with the end 205 proximate to the upward facing second surface 166 of the shoulder 164. A circumferential sealing device (“first crush seal”) 170 can be disposed about a circumference of the curved surface 260 of the first, downwardly facing, frangible disk 200. As a second (upper) end of the bottom-sub 152 is threadably engaged to a first (lower) end of the valve section 160, the first crush seal 170 can be compressed between the upper end of the bottom-sub 152, the valve section 160, and the frangible disk 200, forming a liquid-tight seal therebetween. The pressure exerted by the bottom-sub 152 on the frangible disk 200 causes the end 205 of the frangible disk 200 to seat against the first surface 162.
Similarly, a circumferential sealing device (“second crush seal”) 172 can be disposed about the curved surface 260 of the second, upwardly facing, frangible disk 200. As a first (lower) end of the plug section 110 is threadably engaged to a second (upper) end of the valve section 160, the second crush seal 172 can be compressed between the lower end of the plug section 110, the valve section 160 and the second frangible disk 200, forming a liquid-tight seal therebetween. The pressure exerted by the plug section 110 on the frangible disk 200 causes the end 205 of the frangible disk 200 to seat against the second surface 166.
In one or more embodiments, the first and second crush seals, 170 and 172 can be fabricated from any resilient material unaffected by downhole stimulation and/or production fluids. Such fluids can include, but are not limited to, frac fluids, proppant slurries, drilling muds, hydrocarbons, and the like. For example, the first and second crush seals 170, 172 can be fabricated from the same or different materials, including, but not limited to, buna rubber, polytetrafluoroethylene (“PTFE”), ethylene propylene diene monomer (“EPDM”), VITON®, or any combination thereof.
The plug section 110 can include a mandrel (“body”) 112, first and second back-up ring members 114, 116, first and second slip members 122, 126, element system 128, first and second lock rings 118, 134, and support rings 138. Each of the members, rings and elements 114, 116, 122, 126, 128, 130, and 134 can be disposed about the body 112. One or more of the body, members, rings, and elements 112, 114, 116, 122, 126, 128, 130, 134, 138 can be constructed of a non-metallic material, preferably a composite material, and more preferably a composite material described herein. In one or more embodiments, each of the members, rings and elements 114, 116, 122, 126, 128, and 138 are constructed of a non-metallic material. The plug section 110 can include a non-metallic sealing system 134 disposed about a metal or more preferably, a non-metallic mandrel or body 122.
The back-up ring members 114, 116 can be and are preferably constructed of one or more non-metallic materials. In one or more embodiments, the back-up ring members 114, 116 can be one or more annular members with a first section having a first diameter stepping up to a second section having a second diameter. A recessed groove or void can be disposed or defined between the first and second sections. The groove or void in the back-up ring members 114, 116 permits expansion of the ring member.
The back-up ring members 114, 116 can be one or more separate components. In one or more embodiments, at least one end of the ring member 114, 116 is conical shaped or otherwise sloped to provide a tapered surface thereon. In one or more embodiments, the tapered portion of the ring members 114, 116 can be a separate cone 118 disposed on the ring member 114, 116 having wedges disposed thereon. The cone 118 can be secured to the body 110 by a plurality of shearable members such as screws or pins (not shown) disposed through one or more receptacles 120.
In one or more embodiments, the cone 118 or tapered member can include a sloped surface adapted to rest underneath a complimentary sloped inner surface of the slip members 122, 126. As will be explained in more detail below, the slip members 122, 126 can travel about the surface of the cone 118 or ring member 116, thereby expanding radially outward from the body 110 to engage the inner surface of the surrounding tubular or borehole.
Each slip member 122, 126 can include a tapered inner surface conforming to the first end of the cone 118 or sloped section of the ring member 116. An outer surface of the slip member 122, 126 can include at least one outwardly extending serration or edged tooth, to engage an inner surface of a surrounding tubular (not shown) if the slip member 122, 126 moves radially outward from the body 112 due to the axial movement across the cone 118 or sloped section of the ring member 116.
The slip member 122, 126 can be designed to fracture with radial stress. In one or more embodiments, the slip member 122, 126 can include at least one recessed groove 124 milled therein to fracture under stress allowing the slip member 122, 126 to expand outwards to engage an inner surface of the surrounding tubular or borehole. For example, the slip member 122, 126 can include two or more, preferably four, sloped segments separated by equally spaced recessed longitudinal grooves 124 to contact the surrounding tubular or borehole, which become evenly distributed about the outer surface of the body 112.
The element system 128 can be one or more components. Three separate components are shown in
In one or more embodiments, the element system 128 can have any number of configurations to effectively seal the annulus. For example, the element system 128 can include one or more grooves, ridges, indentations, or protrusions designed to allow the element system 128 to conform to variations in the shape of the interior of a surrounding tubular or borehole.
The support ring 138 can be disposed about the body 112 adjacent a first end of the slip 122. The support ring 138 can be an annular member having a first end that is substantially flat. The first end serves as a shoulder adapted to abut a setting tool described below. The support ring 138 can include a second end adapted to abut the slip 122 and transmit axial forces therethrough. A plurality of pins can be inserted through receptacles 140 to secure the support ring 138 to the body 112.
In one or more embodiments, two or more lock rings 130, 134 can be disposed about the body 112. In one or more embodiments, the lock rings 130, 134 can be split or “C” shaped allowing axial forces to compress the rings 130, 134 against the outer diameter of the body 112 and hold the rings 130, 134 and surrounding components in place. In one or more embodiments, the lock rings 130, 134 can include one or more serrated members or teeth that are adapted to engage the outer diameter of the body 112. Preferably, the lock rings 130, 134 are constructed of a harder material relative to that of the body 110 so that the rings 130, 134 can bite into the outer diameter of the body 112. For example, the rings 130, 134 can be made of steel, and the body 112 made of aluminum.
In one or more embodiments, one or more of the first lock rings 130, 132 can be disposed within a lock ring housing 132. The first lock ring 130 is shown in
In operation, the barrier valve 100 can be installed in a wellbore using a non-rigid system, such as an electric wireline or coiled tubing. Any commercial setting tool adapted to engage the upper end of the barrier valve 100 can be used. Specifically, an outer movable portion of the setting tool can be disposed about the outer diameter of the support ring 138. An inner portion of the setting tool can be fastened about the outer diameter of the body 112. The setting tool and barrier valve 100 are then run into the wellbore to the desired depth where the barrier valve 100 is to be installed.
To set or activate the barrier valve 100, the body 112 can be held by the wireline, through the inner portion of the setting tool, while an axial force can be applied through a setting tool to the support ring 138. The axial force causes the outer portions of the barrier valve 100 to move axially relative to the body 112. The downward axial force asserted against the support ring 138 and the upward axial force on the body 112 translates the forces to the moveable disposed slip members 122, 126 and back-up ring members 114, 116. The slip members 122, 126 are displaced up and across the tapered surfaces of the back-up ring members 114, 116 or separate cone 118 and contact an inner surface of a surrounding tubular. The axial and radial forces are applied to the slip members 122, 126 causing the recessed grooves 124 in the slip members 122, 126 to fracture, permitting the serrations or teeth of the slip members 122, 126 to firmly engage the inner surface of the surrounding tubular.
The opposing forces cause the back-up ring members 114, 116 to move across the tapered sections of the element system 128. As the back-up ring members 114, 116 move axially, the element system 128 expands radially from the body 112 to engage the surrounding tubular. The compressive forces cause the wedges forming the back-up ring members 114, 116 to pivot and/or rotate to fill any gaps or voids therebetween, and the element system 128 is compressed and expanded radially to seal the annulus formed between the body 112 and the surrounding tubular. The axial movement of the components about the body 112 applies a collapse load on the lock rings 130, 134. The lock rings 130, 134 bite into the softer body 112 and help prevent slippage of the element system 128 once activated.
Where a wellbore penetrates two or more hydrocarbon bearing intervals, the setting of one or more barrier valves 100 between each of the intervals can prevent bi-directional fluid communication through the wellbore, permitting operations such as testing, perforating, and fracturing single or multiple intervals within the wellbore without adversely impacting or affecting the stability of other intervals within the wellbore. To restore full fluid communication throughout the wellbore, the one or more frangible disks 200 within the wellbore must be dissolved, fractured, or otherwise removed and/or breached.
Where one or more frangible disks 200 are disposed within the wellbore, a wireline breaker bar can be used to fracture, break, or otherwise remove the frangible disk(s) 200. In other modes of operation, a pressure differential (e.g., pumped down from the top) may be used to break one or more frangible disks 200. Other fracture methods are discussed below. Because the frangible disks are composed of safety glass, they should break into many small pieces, which may allow them to be pumped out of the wellbore or to remain therein. Any remaining pieces should have minimal effect on operations.
The size of the pieces may vary with the tempering. In particular implementations, a 7 inch disk may break into between about 500 to about 100,000 pieces. In certain implementations, a 7 inch disk may break into between about 1,000 to about 50,000 pieces. In some implementations a 7 inch disk may break into between about 2,500 to about 25,000 pieces.
The pieces of fractured disk themselves may generally (e.g., on the average or for the vast majority) be less than about 0.25 inches on major diameter. In some implementations, the pieces may generally be less than about 0.13 inches on major diameter. In certain implementations, the pieces may generally be less than about 0.06 inches on major diameter.
Barrier valve 100 provides a sealing solution that effectively seals the wellbore, withstands high differential pressures, and is quickly, easily, and reliably opened to the wellbore while only generating small pieces of debris. Previous barrier valves containing frangible disks, typically made of ceramic or traditional glass, suffered from the fact that the disks did not consistently restore the full diameter of the wellbore as fragments created by the impact of the weighted bar or high pressure fluid could remain lodged within the tool or the wellbore. The increased pressure drop and reduction in flow through the wellbore caused by the less than complete removal of the sealing disks can result in lost time and increased costs incurred in drilling or milling the entire barrier valve from the wellbore to restore full fluid communication. And even where physical fracturing of the previous frangible disks restored full fluid communication within the wellbore, the residual fragments generated by fracturing the disks could accumulate within the wellbore, potentially interfering with future downhole operations (e.g., jamming downhole tools, plugging ports, jamming mills, increasing milling, restricting production, etc.). Frangible disk 200 in barrier valve 100, however, may break into much smaller pieces.
Using safety glass for a frangible disk is not a straightforward proposition. Relative to a similarly-rated ceramic disk, for example, a disk made of safety glass will probably have to be thicker, as ceramic is typically stronger and tougher than safety glass. But thickening the disk militates against using safety glass because the fracture pieces will be thicker, which is contrary to achieving smaller pieces. The surface area of the pieces, however, should be significantly smaller versus ceramic pieces. Thus, the overall size of the pieces should be decreased.
Additionally, relative to traditional glass (e.g., annealed glass), safety glass is commonly viewed as being stronger (e.g., four times stronger), which makes it somewhat disadvantageous to use in a situation in which the ultimate aim is to break the disk. However, a disk made of safety glass may be made thinner relative to a disk made of traditional glass, which would weaken it somewhat but still allow it to withstand downhole pressures. Moreover, the thinned glass would produce even smaller fragments relative to traditional glass.
Thinning a disk made of safety glass will have to be balanced with the fact that safety glass is a brittle material (e.g., it is often viewed as having little to no yield strength). Thus, a significant safety factor (e.g., increased thickness) will have to be incorporated because any microscopic material imperfection risks getting magnified, which may cause a failure at a much lower load than expected. Brittle materials often fail according to a statistical scatter plot centered around their tensile/compressive strengths, with the more brittle materials producing the more random scatter. Using thickness as a counter can keep the material below the scatter (to guarantee against the glass cracking prematurely), but this is contrary to the perspective of minimizing debris (less thickness being better because that will leave less debris behind). In implementations where the disk will be broken by an impact (e.g., a drop bar), the disk may be made slightly thinner than a pressure application because safety glass is typically proportionally stronger against impact than pressure.
Although
In some implementations, the frangible disk may be solid (i.e., non-hollow). And in certain of these implementations, the height of the base may be reduced. In particular implementations, the radius of curvature of the dome may be increased, and the base may become negligible in height, the edge of the dome rolling back under the frangible disk to a flat bottom.
The barrier valve 400 can include a lower-sub 420 and an upper-sub 440. In one or more embodiments, one or more frangible disks 200 can be disposed within the lower-sub 420. The anchoring system 170 can be disposed about an outer surface of the upper-sub 440. The second (upper) end of the lower-sub 420 and the first (lower) end of the upper-sub 440 can be threadedly interconnected. In one or more embodiments, both the lower-sub 420 and the upper-sub 440 can be constructed from metallic materials including, but not limited to, carbon steel alloys, stainless steel alloys, cast iron, ductile iron and the like. In one or more embodiments, the lower-sub 420 and the upper-sub 440 can be constructed from non-metallic composite materials including, but not limited to, engineered plastics, carbon fiber, and the like. The barrier valve 400 can include one or more metallic and one or more non-metallic components. For example, the lower-sub 420 can be fabricated from a non-metallic, engineered, plastic material such as carbon fiber, while the upper-sub 440 can be fabricated from a metallic alloy such as carbon steel.
In one or more embodiments, the first, lower, end of the upper-sub 440 can include a seating surface 412 for the frangible disk 200. In one or more embodiments, a groove 496 with one or more circumferential sealing devices (“elastomeric sealing elements”) 497 disposed therein can be disposed about an inner circumference of the second, upper, end of the lower-sub 420. (A similar groove can be used in other embodiments.) The end 205 of the first, downwardly facing, frangible disk 200 can be disposed proximate to the seating surface 412. The second end of the lower-sub 420 can be threadably connected using threads 492 to the first end of the upper-sub 440, trapping the first frangible disk 200 therebetween. The one or more elastomeric sealing elements 497 with the lower-sub 420 can be disposed proximate to the base 230 of the first frangible disk 200, forming a liquid-tight seal therebetween and preventing fluid communication through the bore of the tool 400.
In one or more embodiments, the one or more elastomeric sealing elements 497 can be fabricated from any resilient material unaffected by downhole stimulation and/or production fluids. Such fluids can include, but are not limited to, frac fluids, proppant slurries, drilling muds, hydrocarbons, and the like. For example, the one or more elastomeric sealing elements 497 can be fabricated using one or more materials, including, but not limited to, buna rubber, PTFE, EPDM, VITON®, or any combination thereof. At areas where frangible disk 200 touches lower sub, a buffer material may be placed to prevent damaging (e.g., scratching) the disk.
In one or more embodiments, the upper-sub 440 can define a threaded, annular, cross-section permitting threaded attachment of the upper-sub 440 to a casing string (not shown) and/or to other tool sections, for example a lower-sub 420, as depicted in
Other embodiments may include fewer, additional, and/or a different arrangement of parts. For example, a barrier valve could include one or more sealing elements (e.g., O-ring(s)) between the curved section of the frangible disk and the inner wall of the housing (e.g., a crush seal). The radial seal shown may or may not be used with such an implementation. In some implementations, a ring, probably made of metal (e.g., aluminum), may be positioned between the base of the frangible disk and the inner wall of the housing, and one or more sealing elements may be positioned between the base and the ring to provide a seal therebetween. A similar sealing element may be positioned between the ring and the inner wall to provide a seal therebetween. A crush seal may or may not be used with such a ring. In additional implementations, a sealing element may be positioned between the bottom of the frangible disk and the sealing surface 412. This may be used in conjunction with the crush seal or a radial seal, with or without ring, around the base. Additionally, the curved surface of the frangible disk may generally have any ellipsoidal shape, including spherical. Moreover, the frangible disk may be made thinner than traditional disks due to the increased strength of the glass.
In one or more embodiments, a lower-sub 520 and an upper-sub 540 are threadably connected, trapping a frangible disk 200 therebetween. The lower-sub 520 can have a second (upper) end 524 and a shoulder 522 disposed about an inner circumference. The upper-sub 540 can have a shoulder 514 disposed about an inner diameter of the body 540 having a frangible disk seating surface (“first sealing surface”) 513 on a first, lower, side thereof. The end 205 of the first, downwardly facing, frangible disk 200 can be disposed proximate to the first sealing surface 513. At points where frangible disk 200 may contact one of the subs, a buffer material may be used in certain implementations.
A circumferential sealing device (“first elastomeric sealing element”) 535 can be disposed about the base 230 of the first frangible disk 200, proximate to the inner diameter of the body 540. (In some implementations, body 540 may include a groove for receiving sealing elements 535.) A circumferential sealing device (“second elastomeric sealing element”) 530 can be disposed about a circumference of the curved surface 260 of the first frangible disk 200. As the lower-sub 520 is threadably connected to the body 540 the second, upper, end 524 of the lower sub 520 compresses the first elastomeric sealing element 535, forming a liquid-tight seal between the frangible disk 200, the body 540 and the lower-sub 520. The shoulder 522 disposed about the inner circumference of the lower-sub 520 compresses the second elastomeric sealing element 530 between the surface 260 of the frangible disk 200 and the shoulder 522, forming a liquid-tight seal therebetween. The pressure exerted by the lower-sub 520 on the frangible disk 200 causes the end 205 of the frangible disk 200 to seat against the first sealing surface 513.
In one or more embodiments, the first and second elastomeric sealing elements, 530, 535 can be fabricated from any resilient material unaffected by downhole stimulation and/or production fluids. Such fluids can include, but are not limited to, frac fluids, proppant slurries, drilling muds, hydrocarbons, and the like. For example, the first and second elastomeric sealing elements, 530, 535 can be fabricated using the same or different materials, including, but not limited to, buna rubber, PTFE, EPDM, VITON®, or any combination thereof.
In operation, the barrier valve 400 can be set in the wellbore in similar fashion to the barrier valve 100. The removal of the one or more sealing elements 200 from the plugs 400, 500 can be accomplished in a manner similar to the barrier valve 100. Where one or more frangible disks are used within tools 400, 500 in the wellbore, fluid communication can be restored by fracturing the one or more sealing elements 200.
Other embodiments may include fewer, additional, and/or a different arrangement of parts. For example, the sealing element 535 may be between the upper end and the frangible disk 200. The sealing element could, for example, be mounted in a groove in the upper end. The crush seal may or may not be used with such a radial seal. In some implementations, a ring, probably made of metal (e.g., aluminum), may be positioned between the base of the frangible disk and the inner wall of the housing, and one or more sealing elements may be positioned between the base and the ring to provide a seal therebetween. A similar sealing element may be positioned between the ring and the inner wall to provide a seal therebetween. A crush seal may or may not be used with such a ring. In additional implementations, a sealing element may be positioned between the bottom of the frangible disk and the shoulder 514. This may be used in conjunction with a crush seal or a radial seal, with or without a ring, around the base. Additionally, the curved surface of the frangible disk may generally have any ellipsoidal shape, including spherical. Moreover, the frangible disk may be made thinner than traditional disks due to the increased strength of the glass.
In one or more embodiments, the barrier valve 600 can have a body 660 threadedly connected to an upper-sub 680 having one or more sliding sleeves 690 disposed concentrically therein, a valve housing 130 with one or more frangible disks 200 (two are shown) disposed therein, and a lower sub 120. Similar to
A first circumferential sealing device (“first crush seal”) 158 can be disposed about the curved surface 260 of the first frangible disk 200 to provide a fluid-tight seal between the first frangible disk 200, lower-sub 120 and valve housing 130 when the lower-sub 120 is threadedly connected to the valve housing 130. The pressure exerted by the lower-sub 120 on the frangible disk 200 causes the end 205 of the frangible disk 200 to seat against the first sealing surface 133.
Similarly, a second circumferential sealing device (“second crush seal”) 168 can be disposed about the curved surface 260 of the second frangible disk 200. As a first (lower) end of the body 660 is threadably engaged to a second (upper) end of the valve housing 130, the second crush seal 168 can be compressed between the lower end of the body 660, the valve housing 130 and the second frangible disk 200, forming a liquid-tight seal therebetween. The pressure exerted by the body 660 on the frangible disk 200 causes the end 205 of the frangible disk 200 to seat against the second sealing surface 135. A first (lower) end of the upper sub 680 can be threadedly connected to a second (upper) end of the body 660.
In one or more embodiments, the first and second crush seals, 158, 168 can be fabricated from any resilient material unaffected by downhole stimulation and/or production fluids. Such fluids can include, but are not limited to, frac fluids, proppant slurries, drilling muds, hydrocarbons, and the like. For example, the first and second crush seals 158, 168 can be fabricated from the same or different materials, including, but not limited to, buna rubber, PTFE, EPDM, VITON®, or any combination thereof.
In one or more embodiments, the sliding sleeve 690 can be an axially displaceable annular member having an inner surface 693, disposed within the tool body 600. In one or more embodiments, the inner surface 693 of the sliding sleeve 690 can include a first shoulder 697 to provide a profile for receiving an operating element of a conventional design setting tool, commonly known to those of ordinary skill in the art. The sliding sleeve 690 can be temporarily fixed in place within the upper-sub 680 using one or more shear pins 698, each disposed through an aperture on the upper-sub 680, and seated in a mating recess 699 on the outer surface of the sliding sleeve 690, thereby pinning the sliding sleeve 690 to the upper-sub 680. The tool body 660 can be disposed about and threadedly connected to the pinned upper-sub 680 and sliding sleeve 690 assembly, trapping the sliding sleeve 690 concentrically within the bore of the tool body 660 and the upper-sub 680 and providing an open flowpath therethrough.
A shoulder 694, having an outside diameter less than the inside diameter of the body 660, can be disposed about an outer circumference of the sliding sleeve 690. In one or more embodiments, the shoulder 694 can have an external, peripheral, circumferential groove and O-ring seal 696, providing a liquid-tight seal between the sliding sleeve 690 and the tool body 660. In one or more embodiments, the outside surface of the shoulder 694 proximate to the tool body 660 can have a roughness of about 0.1.mu.m to about 3.5.mu.m Ra. In one or more embodiments, one or more flame-hardened teeth 695 can be disposed about the first, lower, end of the sliding sleeve 690.
Other embodiments may include fewer, additional, and/or a different arrangement of parts. For example, a barrier valve could include one or more sealing elements (e.g., O-ring(s)) around the base of the frangible disk to seal to the inner wall of the housing. The sealing element could, for example, be mounted in a groove in the housing. A crush seal may or may not be used with such a sealing element. In some implementations, a ring, probably made of metal (e.g., aluminum), may be positioned between the base of the frangible disk and the inner wall of the housing, and one or more sealing elements may be positioned between the base and the ring to provide a seal therebetween. A similar sealing element may be positioned between the ring and the inner wall to provide a seal therebetween. A crush seal may or may not be used with such a ring. In additional implementations, a sealing element may be positioned between the bottom of the frangible disk and shoulder 134. This may be used in conjunction with a crush seal or a radial seal, with or without a ring, around the base. Additionally, the curved surface of the frangible disk may generally have any ellipsoidal shape, including spherical. Moreover, the frangible disk may be made thinner than traditional disks due to the increased strength of the glass.
Similar to the barrier valve depicted in
In operation of the barrier valves 600, 700, the sliding sleeve 690 within each tool 600, 700 can be fixed in a first position using the one or more shear pins 698 inserted into the one or more recesses 699 disposed about the outer circumference of the sliding sleeve 690. Fixing the sliding sleeve 690 in the first position prior to run-in of the casing string can prevent the one or more teeth 695 from accidentally damaging the frangible disks 200 disposed within the tool 600, 700 during run-in. While the sliding sleeve 690 remains fixed in the first position, the one or more frangible disks 200 disposed within the barrier valve 600 can prevent bi-directional fluid communication throughout the wellbore.
In one or more embodiments, fluid communication within the wellbore can be restored by axially displacing the sliding sleeve 690 to a second position. The axial displacement should be a sufficient distance to fracture the one or more frangible disks 200. In one or more embodiments, through the use of a conventional setting tool, a sufficient force can be exerted on the sliding sleeve 690 to shear the one or more shear pins 698, thereby axially displacing the sliding sleeve 690 from the first (“run-in”) position, to the second position wherein the one or more flame hardened teeth 695 (“protrusions”) on the first end of the sliding sleeve 690 can impact, penetrate, and fracture the one or more frangible disks 200 disposed within the barrier valve 600, 700. The process of axially displacing the sliding sleeve 690 and fracturing the one or more frangible disks 200 within each barrier valve 600, 700 disposed along the casing string can, in some implementations, be repeated to remove all of the frangible disks 200 from the wellbore, thereby restoring fluid communication throughout the wellbore.
Other embodiments may include fewer, additional, and/or a different arrangement of parts. For example, a barrier valve could include one or more sealing elements (e.g., O-ring(s)) around the base of the frangible disk to seal to the inner wall of the housing. The sealing element could, for example, be mounted in a groove in the housing. A crush seal may or may not be used with such a sealing element. In some implementations, a ring, probably made of metal (e.g., aluminum), may be positioned between the base of the frangible disk and the inner wall of the housing, and one or more sealing elements may be positioned between the base and the ring to provide a seal therebetween. A similar sealing element may be positioned between the ring and the inner wall to provide a seal therebetween. A crush seal may or may not be used with such a ring. In additional implementations, a sealing element may be positioned between the bottom of the frangible disk and the shoulder 746. This may be used in conjunction with the crush seal or a radial seal, with or without a ring, around the base. Additionally, the curved surface of the frangible disk may generally have any ellipsoidal shape, including spherical. Moreover, the frangible disk may be made thinner than traditional disks due to the increased strength of the glass.
Typically, at the outset and throughout the packer setting operation, there is hydrostatic pressure inside production string 810 and in the annulus between the production string and casing string 820, meaning there is hydrostatic pressure above upper disk 802 and below the lower frangible disk 804. Packer 830 is set by applying pressure downwardly through production string 810. So long as the packer is set by a pressure that is less than the strength of disk 802 against pressure applied on the convex side, the packer may be manipulated without fracturing the upper disk.
After packer 830 is set, pressure is applied from above. This applied pressure exceeds the ability of the convex side of upper disk 802 to withstand it. The upper disk then shatters or ruptures allowing tubing pressure to enter the area 806 between the disks. This pressure will also shatter lower disk 804, thereby placing production string 810, above and below the valve 800, in communication and allowing the well to produce. Thus, barrier valve 860 allows breaking of the disks 802, 804 to place the heretofore isolated parts of the well in communication by the application of pressure from above.
Frangible disks 14, 16 may be made from frangible glass in which the surface is in compression and the interior is in tension. As illustrated, the height of the upper frangible disk 14, the cylindrical base thereof, is between about 2.375″ and 4.325″. In some embodiments, the height of the upper frangible disk 14 is greater than the height of the lower frangible disk 16. This allows a greater pivoting torque, as well as greater distance for the piston to slide as it moves from the left to the right across distance D1.
Upper frangible disk 14 has cylindrical base 14a with a bore therethrough and a curved surface 14b. In the illustrated implementation, curved surface 14b is close to, but not quite, a hemisphere. Curved surface 14b may generally be an ellipsoidal shape. Curved surface 14b of upper disk 14 is typically convex when viewed from the top down. Lower disk 16 is typically concave when viewed from the top down and has a similar base portion and curved surface (unnumbered). Lower frangible disk 16 may be held in place by lower disk seal ring (or cartridge) 34 having O-rings with structure known in the art. At points where a frangible disk may contact another element, a buffer material may be used.
Seal ring 34, and similarly piston cartridge 28, has an inner surface and an outer surface. The inner surface and the outer surface each include two annular grooves, respectively. The inner surface and the outer surface may have a tolerance of 0.003 inches or less.
Inserted in each annular groove is an elastomeric member (e.g., an O-ring) that provides a seal between the outer surface of the cylindrical portion of frangible disk 14 and the inner surface of the seal ring. The elastomeric members may be sized so they compress between about 10%-25% of their width, depending on the gap achieved between the inner surface of the seal ring and the outer surface of cylindrical base 14a when the barrier valve is assembled. The elastomeric members may, for example, be approximately 0.095 inches-0.110 inches in width and be made of a fluoroelastomer (e.g., FFKM or AFLAS from Seals Eastern of Red Bank, N.J. (USA)).
Optionally inserted in each of the grooves is a backup ring. Backup rings prevent the elastomeric members from extruding into any gaps between the inner surface of the seal ring and the outer surface of the frangible disk, which may damage the elastomeric members. The backup rings may have flat or grooved surfaces for engaging the elastomeric members.
The backup rings may, for example, be made of a durable, stiff but springy material (e.g., a thermoplastic, such as, for example, polyaryletherketone (PAEK)). In particular implementations, the backup rings may be made of polyether ether ketone (PEEK) from Victrex, LLC of Thornton-Cleveleys, Lancashire (UK). The backup rings may also be made from polyetherketoneketone (PEKK), polyimide-imides (PAI), or polyphenylene sulfide (PPS).
In some implementations, the thermoplastic may be filled with a fiber (e.g., a carbon fiber of a glass fiber). The addition of fiber in the thermoplastics reduces shrinking of the backup ring after being exposed to a high temperature environment and then cooled, which can leave the elastomeric members unsupported. The fiber content is typically around 30%, but may range between about 5%-40%.
The backup rings may extend outside of the grooves slightly (e.g., about 0.002 inches in an uncompressed state). This helps prevent the elastomeric members from being extruded into the gap between the outer surface of the seal ring and the inner surface of the frangible disk. In some implementations, only one backup ring may be located in each groove because high fluid pressure to be resisted is only expected to penetrate from one side of the frangible disk. In other implementations, multiple backup rings (e.g., one on each side of an elastomeric member) may be used.
Inside housing 12 are a cylindrical piston 26 and a piston cartridge 28, the two cooperating together to form a piston assembly 42 (see
In
A few things may be readily appreciated with respect to the drawings. First, piston 26 is driven from the left in
A second feature that may be appreciated from reviewing the specification is that engagement of piston 26 with fingers 36/38/40 provides a force approximately normal to the outer walls of cylindrical section 14a (not on the dome) and near the lower end thereof (see
It is seen that access is provided to rupturable membrane assembly or fitting 30 through an access plug 32 provided through housing 12 directly adjacent rupturable membrane assembly or fitting 30. Moreover, it is seen that rupturable membrane assembly 30 may have threaded walls 30a and a tool receiving head 30c, so when access plug 32 is removed, a tool may be provided to thread out fitting 30 and replace it with another fitting 30, which may have a different rupturable membrane 30b. Rupturable membrane assembly 30 can be provided at the wellsite within a set of many rupturable membranes 30b, that differ in the ratings or pressure ratings at which rupturable membrane 30b will burst. This set and process may be used to provide a selected membrane 30d that will rupture at a selected pressure.
In one embodiment, a multiplicity of rupturable membranes assemblies 30 are provided that differ in their pressure ratings. They may be provided as a set in a kit, the sets' members sequentially increasing in their rupture pressure. The rupture membranes selected for the particular set provided to the particular well may be those most likely to be selected for use at the well or well site area. By providing such a set at the wellsite, an operator may selectively determine the pressure at which he wishes piston 26 to deploy, break disk 14, and open disk sub or isolation tool 10 to fluid flow. The operator may determine the vertical depth at which he wishes to place disk sub or isolation tool 10 and determine fluid or hydrostatic pressure above upper frangible disk 14. A typical frangible disk 14 can withstand a very high hydrostatic load, typically 15,000-20,000 psi. Then the operator selects a rupturable membrane assembly 30 that ruptures at a pressure greater than the hydrostatic pressure at the selected depth by a selected psi amount, for example, a psi in the range of about 400 to 4000 psi greater than the wellbore's hydrostatic psi at that depth. The operator may place the selected rupturable membrane assembly or fitting 30 in barrier valve 10, insert barrier valve 10 in a casing or tubing string, run barrier valve 10 in, and then run number of operations about barrier valve 10, using it to isolate the zones above and below it, some operations of which are set forth herein. The operator having used barrier valve 10 for its intended isolation purposes may then rupture membrane 30b by pumping additional pressure upon the wellbore fluid, which additional pressure plus the wellbore fluid's static hydrostatic pressure will cause rupturable membrane 30b to burst, activating piston 26, moving fingers 36/38/40 against frangible disk 14, breaking it, and opening barrier valve 10 to flow through its bore 19.
Turning to the multiple O-ring sealing sets, they may be used at 21/23/27/29/35 and other places. When used, they typically comprise an elastomeric cylindrical O-ring 27a and a stiff PEEK or other suitable material backup ring 27b on either side of O-ring 27a in ways known in the art.
Turning to
If gap 33 were sealed and isolated, then movement of piston 26 into gap 33 would, by compressing gap 33, compress the air in it and the compressed air would provide resistance to further downward or rightward movement of piston 26. However, because gap 33 is in gaseous communication with intermediate bore 19c, for practical purposes, there is no pressure material increase within gap 33 because the gas reservoir composed of intermediate bore 19c is substantially larger than gap 33. Accordingly, the downward gaseous force on piston 26 is not practicably resisted by an upward gaseous force on piston 26.
In some configurations and operations, barrier valve 10 may be operated without lower disk 16. In this event, the lower fluid pressure from below barrier valve 10 relative to the higher fluid pressure from above barrier valve 10 may provide sufficient differential downward pressure to push piston 26 downward.
Other embodiments may include fewer, additional, and/or a different arrangement of parts. For example, a barrier valve may not use a cartridge 28, which might be especially useful at high pressures (e.g., above 10,000 psi). As another example, a barrier valve could include a sealing element around the curved section of frangible disk (e.g., a crush seal). A ring may or may not be used with such a ring. In additional implementations, a sealing element may be positioned between the bottom of the frangible disk and the mounting shoulder. This may be used in conjunction with the crush seal or a radial seal around the base. Additionally, the curved surface of the frangible disk may generally have any ellipsoidal shape, including spherical. Moreover, the frangible disk may be made thinner than traditional disks due to the increased strength of the glass. As an additional example, some embodiments may not use piston cartridge 28. For instance, frangible disk 14 may be sealed to piston 26 (e.g., via a groove/sealing element combination in the piston).
Barrier 1110 is protected by a carrier 1120. Carrier 1120 has an inner surface 1121 that forms a passage 1122 through which a well fluid may flow when barrier 1110 is destroyed. Inner surface 1122 forms a shoulder 1122 against which barrier 1110 may be mounted.
As pictured, curved surface 1114b and periphery 1112 touch carrier 1120, but in particular embodiments a buffer material may exist between barrier 1110 and carrier 1120. The buffer material may, for example, be PEEK, PTFE, rubber, or any other appropriate material.
Carrier 1120 includes a groove 1123 that can contain a sealing member 1124 for sealing to the periphery 1112 of barrier 1110. Sealing member 1124 may, for example, be an O-ring (e.g., made of PEEK, PTFE, or rubber). In some implementations, backup rings may also be used in groove 1123.
Carrier 1120 also includes a mounting member 1126 (e.g., an annular ring) for securing barrier 1110 in carrier 1120. Mounting member 1126 is adapted to slide relative to inner surface 1121 to secure curved surfaced 1114b against shoulder 1122. A buffer material may be provided between the ends of mounting member 1126 and surface 1114a to prevent mounting member 1126 from damaging (e.g., scratching barrier 1110).
Mounting member 1126 includes a groove 1127 in which a sealing member 1128 may be received. Sealing member 1128 assists in holding mounting member 1126 in the correct position and also prevents fluid from getting between mounting member 1126 and inner surface 1121.
Carrier 1120 also a number (typically at least three) includes buttons 1124 that extend into passage 1122. Buttons 1124 function to disrupt the surface integrity of barrier 1110, causing it to shatter, when carrier 1120 slides along inner surface 1121 to allow barrier 1110 to come into contact with the buttons.
In other implementations, barrier 1110 may be sealed to carrier 1122 by other techniques. For example a crush seal could be used. As another example, a ball valve seal, possibly with grooves therein could be used. In some implementations, the ball valve seal may include a backup.
In other implementations, barrier 1110 may be ruptured by other techniques. For example, barrier 1110 may be ruptured by an excessive pressure thereon (e.g., a differential pressure of 15,000 psi or a surround pressure of 20,000 psi). As an additional example, a barrier may be ruptured by having a breaking device dropped onto it from the surface, prongs extend into it from carrier 1120, or fingers that press on the side of the barrier at a certain pressure, as demonstrated in
As a further example, a port with a fluid control device may be used to allow fluid into the space between mounting member 1126 and inner surface 1121, driving mounting member away from shoulder 1122. For instance, the wall of the carrier of the mounting member may include a rupturable membrane assembly or Fike fitting, which rupturable membrane assembly includes a rupturable membrane. The location of sealing member 1128 isolates the space between the mounting member and the inner surface 1121 from the downhole hydrostatic pressure. When a selected additional fluid pressure load is added to the downhole hydrostatic pressure outside carrier 1120 as with, for example, a pneumatic pump located at the surface, then the pressure in the bore exceeds the selected known rupture pressure of the rupturable membrane, which permits fluid to flow into the space and, acting as an unbalanced force against mounting member 1126 at sealing member 1128, force mounting member 1126 away from shoulder 1122. This, with possibly along pressure on curved surface 1114b, moves barrier 1110 into contact with buttons 1124, shattering it.
In some implementations, a multiplicity of rupturable membranes assemblies 30 is provided that differ in their pressure ratings. They may be provided as a set in a kit, the sets' members sequentially increasing in their rupture pressure. The rupture membranes selected for the particular set provided to the particular well may be those most likely to be selected for use at the well or well site area. By providing such a set at the wellsite, an operator may selectively determine the pressure at which he wishes mounting member 1126 to move, break barrier 1120, and open the disk sub or isolation tool to fluid flow.
The operator may, for example, determine the vertical depth at which he wishes to place the disk sub or isolation tool and determine fluid or hydrostatic pressure above barrier 1120. A typical barrier can withstand a very high hydrostatic load, typically 15,000-20,000 psi. Then, the operator selects a rupturable membrane assembly that ruptures at a pressure greater than the hydrostatic pressure at the selected depth by a selected psi amount, for example, a psi in the range of about 400 to 4000 psi greater than the wellbore' s hydrostatic psi at that depth. The operator may place the selected rupturable membrane assembly or fitting in the downhole tool, insert the tool in a casing or tubing string, run the tool in, and then run number of operations about the tool, using it to isolate the zones above and below it, some operations of which are set forth herein. Having used the tool for its intended isolation purposes, the operator may then rupture the membrane by pumping additional pressure upon the wellbore fluid, which additional pressure plus the wellbore fluid's static hydrostatic pressure will cause rupturable membrane to burst, activating mounting member 1126, moving barrier 1120, breaking it, and opening the disk or sub to flow through its passage.
Barrier 1210 is protected by a carrier 1220. Carrier 1220 has an inner surface 1221 that forms a passage 1222 through which a well fluid may flow when barrier 1210 is destroyed.
As pictured, barrier 1210 touches carrier 1220, but in particular embodiments barrier may not touch carrier 1220, but if the barrier does touch carrier 1210, a buffer material may exist between barrier 1210 and carrier 1220. The protective barrier may, for example, be PEEK, PTFE, rubber, or any other appropriate material.
Carrier 1220 also includes mounting members 1226 (e.g., annular rings) for securing barrier 1210 in carrier 1220. Mounting members 1226 are adapted to slide relative to inner surface 1221 to secure barrier 1210. Mounting members 1226 each include a sealing member 1227 for sealing to barrier 1210. Sealing members 1227 may, for example, be O-rings or ball valve seals.
Each mounting member 1226 also includes a groove 1228 in which a sealing member 1229 may be received. Sealing members 1229 assist in holding mounting members 1226 in the correct position and also prevent fluid from getting between mounting members 1226 and inner surface 1221.
Carrier 1220 also includes buttons 1224 that extend into passage 1222. Buttons 1224 function to disrupt the surface integrity of barrier 1210, causing it to shatter, when mounting member 1226b slides along inner surface 1122 (e.g., due to differential pressure on barrier 1210) to allow barrier 1210 to come into contact with the buttons.
In other implementations, barrier 1210 may be sealed to carrier 1220 by other techniques. For example a crush seal could be used. As another example, a ball valve seal, possibly with grooves therein could be used. In some implementations, the ball valve seal may include a backup.
In other implementations, barrier 1210 may be ruptured by other techniques. For example, barrier 1210 may be ruptured by an excessive pressure on the barrier (e.g., a differential pressure of 15,000 psi or a surrounding pressure of 20,000 psi). As an additional example, a barrier may be ruptured by having prongs extend into it from carrier 1220 or having fingers that press on the side of the barrier at a certain pressure, as demonstrated in
As a further example, a port with a fluid control device may be used to allow fluid into the space between mounting member 1226b and inside surface 1221, driving mounting member 1226b toward button 1224. For instance, the wall of the carrier or the mounting member may include a rupturable membrane assembly or Fike fitting, which rupturable membrane assembly includes a rupturable membrane. The location of sealing member 1229 in mounting member 1226b isolates the space between the mounting member and the inner surface 1221 from the downhole hydrostatic pressure. When a selected additional fluid pressure load is added to the downhole hydrostatic pressure outside carrier 1200 as with, for example, a pneumatic pump, then the pressure the bore exceeds the selected known rupture pressure of rupturable membrane, which permits fluid to flow into the space and, acting as an unbalanced force against mounting member 1226b at sealing member 1229, force mounting member 1126b away from shoulder button 1224. This, along with possibly pressure on barrier 1210, moves barrier 1210 into contact with buttons 1224, shattering it.
The use of the terms “a” and “an” and “the” and similar referents in the context of describing the invention (especially in the context of the following claims) are to be construed to cover both the singular and the plural, unless otherwise indicated herein or clearly contradicted by context. As used herein, the term “a” includes at least one of an element that “a” precedes, for example, “a device” includes “at least one device.” “Or” means “and/or.” Further, it should further be noted that the terms “first,” “second,” and the like herein do not denote any order, quantity (such that more than one, two, or more than two of an element can be present), or importance, but rather are used to distinguish one element from another. The modifier “about” used in connection with a quantity is inclusive of the stated value and has the meaning dictated by the context (e.g., it includes the degree of error associated with measurement of the particular quantity).
Certain embodiments and features have been described using a set of numerical upper limits and a set of numerical lower limits. It should be appreciated that ranges including the combination of any two values, e.g., the combination of any lower value with any upper value, the combination of any two lower values, and/or the combination of any two upper values are contemplated unless otherwise indicated. Certain lower limits, upper limits, and ranges may appear in one or more claims below. All numerical values are “about” or “approximately” the indicated value, and take into account experimental error and variations that would be expected by a person having ordinary skill in the art. Where such experimental error and expected variations are not determinable according to the person having ordinary skill in the art standard, then “about” or “approximately” numerical values are defined to include a plus or minus 10% of the stated absolute numerical value.
Where numerical ranges or limitations are expressly stated, such express ranges or limitations should be understood to include iterative ranges or limitations of like magnitude falling within the expressly stated ranges or limitations (e.g., from about 1 to about 10 includes, 2, 3, 4, etc.; greater than 0.10 includes 0.11, 0.12, 0.13, etc.). For example, whenever a numerical range with a lower limit, R.sub.1, and an upper limit, R.sub.u, is disclosed, any number falling within the range is specifically disclosed. In particular, the following numbers within the range are specifically disclosed: R=R.sub.1+k*(R.sub.u−R.sub.1), wherein k is a variable ranging from 1 percent to 100 percent with a 1 percent increment, i.e., k is 1 percent, 2 percent, 3 percent, 4 percent, 5 percent, . . . , 50 percent, 51 percent, 52 percent, . . . , 95 percent, 96 percent, 97 percent, 98 percent, 99 percent, or 100 percent. Moreover, any numerical range defined by two R numbers as defined in the above is also specifically disclosed.
Use of broader terms such as comprises, includes, and having should be understood to provide support for narrower terms such as consisting of, consisting essentially of, and composed substantially of.
Various terms have been defined above. To the extent a term used in a claim is not defined above, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent. Furthermore, all patents, test procedures, and other documents cited in this application are fully incorporated by reference to the extent such disclosure is not inconsistent with this application and for all jurisdictions in which such incorporation is permitted.
The invention has been described with reference to various particular implementations, and several others have been mentioned or suggested. Moreover, those skilled in the art will readily recognize that a variety of additions, deletions, substitutions, and transformations may be made to the disclosed implementations while still achieving a frangible glass barrier valve. Thus, the scope of protection should be judged based on the claims below, which may encompass one or more concepts of one or more embodiments. Each and every claim is incorporated as further disclosure into the specification, and the claims are embodiment(s) of the present invention.
| Number | Date | Country | |
|---|---|---|---|
| 63546750 | Oct 2023 | US |
