CA2873541A1 - Fracturing valve and fracturing tool string - Google Patents
Fracturing valve and fracturing tool string Download PDFInfo
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- CA2873541A1 CA2873541A1 CA2873541A CA2873541A CA2873541A1 CA 2873541 A1 CA2873541 A1 CA 2873541A1 CA 2873541 A CA2873541 A CA 2873541A CA 2873541 A CA2873541 A CA 2873541A CA 2873541 A1 CA2873541 A1 CA 2873541A1
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- valve
- tubing string
- fracturing
- tubular
- tool
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- 230000007246 mechanism Effects 0.000 claims description 11
- 230000004044 response Effects 0.000 claims description 3
- 238000004891 communication Methods 0.000 abstract description 9
- 206010017076 Fracture Diseases 0.000 description 8
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- 230000003628 erosive effect Effects 0.000 description 1
- 229930195733 hydrocarbon Natural products 0.000 description 1
- 150000002430 hydrocarbons Chemical class 0.000 description 1
- 238000002347 injection Methods 0.000 description 1
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Abstract
Description
Customer No. 112685 FRACTURING VALVE AND FRACTURING TOOL STRING
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR
DEVELOPMENT
[0001] Not Applicable.
BACKGROUND OF THE INVENTION
Following perforation, the perforated zone may be hydraulically isolated.
Fracturing operations may be performed to increase the size of the initially formed openings in the formation. During fracturing, proppant materials are introduced into enlarged openings in an effort to prevent the openings from closing.
Customer No. 112685 downhole and uphole, which in turn allows for fluid conservation and time-savings. It may also be useful to carry out operations such as fracturing by pumping treatment fluid down a coiled tubing string. One reason for this is that the coiled tubing string has a smaller cross-sectional area than the wellbore annulus (the annulus being defined as the region between the coiled tubing and the wellbore or, for cased wellbores, the annulus is defined as the annular space between the casing and the coiled tubing). Because of the smaller cross-sectional area of coiled tubing, smaller volumes of fluids (displacement and treatment fluids, for example) may be used.
However, many of these valves employ ball-seat arrangements. In ball-seat valves, the ball must be reverse-circulated to the surface after one operation is completed, resulting in a corresponding increase in fluid use and time. Because downhole treatment operations utilize large quantities of fluids, methods or tools that result in fluid savings are desirable.
There are often issues associated with moving proppant-laden treatment from the inside of the coiled tubing to the formation. The proppant may become wedged inside the nozzles, preventing its exit into the formation.
Page 2 of 38 Atty. Dkt. No. 1218-0034US
Customer No. 112685
The sliding sleeves or valves are installed on the inner diameter of the casing, sometimes being held in place by shear pins. Often the bottom-most sleeve is capable of being opened hydraulically by applying a pressure differential to the sleeve assembly. Fracturing fluid may be pumped into the formation through the open ports in the first zone. A ball may then be dropped. The ball hits the next sleeve up, thereby opening ports for fracturing the second zone.
BRIEF SUMMARY OF THE INVENTION
Customer No. 112685 valve is installed). This mechanical manipulation results in the opening and closing of the valve. More particularly, the valve may be moved from an open position wherein fracturing fluid pumped from the surface through the tubing string may exit the tool through a passageway formed in the tool to a closed position where fracturing fluid pumped down the tubing string cannot exit the tool.
The valve may be installed in a tool having a perforation device. In such a tool, perforation may be carried out when the valve is closed. The valve may be opened by manipulation of the tubing string, allowing fluid flow through a passageway in the tool to the exterior of the tool. Fracturing fluid may be pumped through this passageway.
Page 4 of 38 Atty. Dkt. No. 1218-0034US
Customer No. 112685
Page 5 of 38 Atty. Dkt. No. 1218-0034US
Customer No. 112685
BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS
Customer No. 112685 shown in the open position.
6 in FIG. 5
in FIG. 7A.
Page 7 of 38 Atty. Dkt. No. 1218-0034US
Customer No. 112685
DETAILED DESCRIPTION OF THE INVENTION
Page 8 of 38 Atty. Dkt. No. 1218-0034US
Customer No. 112685
= fracturing valve 10 = nozzles 12 = alignment pin 13 = tubular mandrel 15 = throughbore 20 = flow path 21 = tubing string 25 = outer sleeve 30 = upper end 31 of outer sleeve 30 = lower end 32 of outer sleeve 30 = equalization plug 35 = back-up ring 44 = circulation ports 45 = 0-ring 46 = 0-ring 47 = wiper 48 = perforation device 49 = frac window 60 = sleeve port 65 (in sidewall of sleeve 30) = wedge member 70 = apex 75 = base 80 = equalization housing 91 = lower mandrel 91' = sealing surfaces 92 = bottom sub 93 = mechanical collar locator 94 Page 9 of 38 Atty. Dkt. No. 1218-0034US
Customer No. 112685 = cap 95 (connected to lower mandrel 91) = perforations 99 = casing collar 100 = casing 101 = annulus 102 = formation 103 = threaded bore 112 (for lock screw 113) = lock screw 113 = radial opening 114 = slot 115 (in sleeve 30) = tool engagement grooves 116 = shoulder 117 = cross bore 118 (for alignment pin 13) = sealing element (annular packer) 121 = anchor 122 = J-slot 123 (grooved into lower mandrel 91) = ports 130 (in bottom sub 93 in the region of collar locator 94) = bullnose centralizer 135 = pins 140 = lands 142 = seal retainer (housing) 151 = downhole tool 200 = Hydraulic Hold Down 172 = Hydraulic Buttons 170
Page 10 of 38 Atty. Dkt. No. 1218-0034US
Customer No. 112685
"lower" or "downstream" mean toward the bottom of the wellbore along the longitudinal axis of the workstring. The terms "workstring" or "tubing string"
refer to any tubular arrangement for conveying fluids and/or tools from the surface into a wellbore.
= a fracturing valve;
= an equalization valve;
= a mechanical anchoring mechanism (slips); and, = an annular packer.
Referring first to Figure 1A, a frac valve 10 according to the invention is shown together with a jet perforating sub 49 equipped with a plurality of jet perforating nozzles 12 for creating openings in a surrounding well casing or liner and into cement filling the annulus between the casing or liner and the wellbore and even into the formation itself. Such openings may be created by pumping an abrasive-laden fluid at relatively high velocity down the tubing string and out the nozzles. As indicated in Figure 1A, jet perforating sub 49 may be coupled to the upper end of frac valve 10 to form tubing string 25. Thus, in order to preferentially direct fluid out of nozzles 12, frac valve 10 would ordinarily be placed in the closed position during a perforating operation.
Customer No. 112685 of fluids conveyed by the tubing string. Outer sleeve 30 has one or more ports (or "windows") 65 in its side wall. Mandrel 15 has corresponding openings 60 (see Figure 5). When ports 65 and openings 60 are aligned (as illustrated in Figure 1A), frac valve 10 is in the "open" condition and fluid pumped down bore 20 may exit the device in a radial direction after impinging on wedge 70 as indicated by flow arrows 21.
Customer No. 112685 sleeve 30. Downward travel of mandrel 15 relative to outer sleeve 30 (which may be effected by applying weight to the tubing string) is limited by shoulder (Figure 3) contacting the upper end of equalization housing 91. As shown in Figure 2, equalization valve plug 35 may be provided with circumferential seals 92 which may sealingly engage the inner bore of sealing ring 36 in equalization housing 91. In certain embodiments, seals 92 may be bonded seals.
To facilitate the assembly and/or disassembly of the device, longitudinal grooves 116 may be provided at selected locations on the outer surfaces of the component pieces for tool engagement.
Page 13 of 38 Atty. Dkt. No. 1218-0034US
Customer No. 112685
Bullnose centralizer 135 is connected to the downhole end of bottom sub 93.
This assembly is shown in casing 101 with annular packer 121 and anchor 122 unset. Annulus 102 is defined between the outer diameter of tool 200 and the inner diameter of casing 101.
94' has a profile that is sized and configured to fit in the space between the ends of casing segments 101.
In Figure 7A, tool 200 is in the run-in state. This state is obtained by applying weight (downhole force) to a tubing string attached to the upper end of the tool.
Page 14 of 38 Atty. Dkt. No. 1218-0034US
Customer No. 112685 The frac valve is open; the equalization valve is closed; and, the annular packer 121 and anchor 122 are unset.
Fracking fluids pumped down the tubing string impinge on wedge 70 and are forced to exit via windows 65. Downhole flow of fracking fluids is prevented by annular packer 121.
Page 15 of 38 Atty. Dkt. No. 1218-0034US
Customer No. 112685
The tool is in the state shown in Figure 8 ¨ i.e., the frac valve is closed;
the equalization valve is open; and, the annular packer 121 and anchor 122 are unset. Perforations 99 through the casing 101 and into the formation adjacent nozzles 12 may be formed by sand jet perforating.
i.e., the frac valve is open; the equalization valve is closed; and, the annular packer 121 and anchor 122 are set. Fracking fluids pumped down the tubing string impinge on wedge 70 and are forced to exit via windows 65. Downhole flow of fracking fluids is prevented by annular packer 121. The upward flow of fracking fluids may be prevented by applying fluid pressure in annulus 102 from the surface. Thus, the fracking fluids are forced into formation 103 via perforations 99.
Customer No. 112685 15 may be joined at either end to lengths of tubing string 25. Throughbore 20 of tubular mandrel 15 may be fluidically continuous with tubing string 25 in which frac valve 10 may be connected. Tubing string 25 may be connected to a string of coiled tubing (not shown) extending to the surface of the wellbore. The coiled tubing has a bore for the passage of fluids, the bore being continuous with throughbore 20 of tubular mandrel 15.
Page 17 of 38 Atty. Dkt. No. 1218-0034US
Customer No. 112685
Other seals may be employed. Cup seal 47 may be disposed within a seal housing 151 (as seen in FIG. 7A). In the illustrated embodiment, seal housing 151 (see FIG. 7A) acts at least in part as a connecting means to place (space) tubular mandrel 15 relative to equalization plug 35. In the illustrated embodiment, equalization plug 35, continuous with tubular mandrel 15, may be disposed with sealing ring 36. Also, seal housing 48 assists in holding cup seal 47 in place, and in holding alignment pin 13. Alignment pin 13 assists in controlling movement between outer sleeve 30 and tubular mandrel 15, helping to prevent rotational movement of outer sleeve 30 relative to tubular mandrel 15, and ensuring axial movement of tubular mandrel 15 relative to sleeve 30. Because cup seal 47 may be disposed within seal housing 48 surrounding tubular mandrel 15, movement of tubular mandrel 15 corresponds with sealing and unsealing of cup seal 47 against outer sleeve 30.
Page 18 of 38 Atty. Dkt. No. 1218-0034US
Customer No. 112685
In this position, wedge 70 may be exposed to the exterior of the valve through window 60 (see Figure 4). As used herein, a "closed" valve position means that substantially no fluid communication from the tubing string to the formation through frac window 60 is possible. In this position, wedge 70 is obscured by outer sleeve 30 (see Figure 3), and seal 47 seals between the tubular 15 and sleeve 30, preventing fluid flow down the tubing string below seal 47.
Customer No. 112685 tubular mandrel 15 is attached to coiled tubing, the tubing string may be compressed or pushed downward to slide tubular mandrel 15 relative to sleeve 30, resulting in wedge 70 being exposed through frac window 60 so that fluid flow out frac window 60 may be possible. In this position, the tubing string below the wedge may be sealed (e.g. by a slidable plug as one example which will be discussed below). Conversely, the tubing string may be pulled up, sliding tubular mandrel 15 upward relative to the sleeve 30, resulting in wedge 70 being obscured by sleeve 30, and seal 47 sealing between the tubular and the sleeve.
No fluid may then flow from the tubing string out of window 60. As will be described in more detail below, in practice, sleeve 30 may be held stationary by virtue of its connection to a stationary portion of the tubing string, while tubular mandrel 15 may be moveable axially, upwards (when pulling up on coiled tubing) and downwards (when pushing down on coiled tubing) relative to sleeve 30.
Customer No. 112685 valve 10, and the setting and unsetting of a sealing assembly or packer element disposed on a lower mandrel.
While an alignment pin is shown in the embodiment, another suitable member (such as a lug) may be provided in either the tubular mandrel 15 or sleeve 30 for preventing rotation of sleeve 30 relative to tubular mandrel 15, ensuring that when set down weight is applied to or released from the tubing string, the movement of tubular mandrel 15 is axial. Alternative configurations and alignment means are possible. For example, a groove or other profile may be defined in the tubular mandrel, and a pin or other member capable of traveling within the profile may be defined in the sleeve for engaging the groove in the tubular.
Customer No. 112685 length of the valve may be about 13 inches, frac window 60 may be about 11 inches in length, wedge 70 may be about 5.4 inches from base to apex, and the sloped surface of wedge 70 may be inclined at an angle of about 30 degrees.
Therefore, frac window 60 may be almost the same length as the valve stroke.
[0080] The sloped surface of wedge 70 provides a large distribution surface for treatment fluid (e.g. proppant) pumped through the tubing string and impinging on the surface of wedge 70. Also, the shape of the wedge may assist in decreasing the velocity of fracturing fluid exiting the tubing string to the formation.
Decreasing the velocity may prolong the life of the valve and tool in which the valve may be deployed. When valve 10 is used in a tool having a perforation plug, the fracturing rate may be decreased so as to be similar to the perforation rate. For example, Applicant has employed fracturing rates of 0.8 m3/minute and perforation rates of 0.6 m3/minute. However, the fracturing and perforation rates need not be the same ¨ a valve according to the invention enables an operator to change fracturing rates as needed. The rates needed are dependent on the formation, and a valve according to the invention enables an operator to rapidly adjust the rate of fracturing according to the formation. When using higher velocities for fracturing, proppant may be less likely to settle out and remain in the coiled tubing.
Typically, a high pressure differential is required for fracturing through nozzles, for example.
The present valve allows a lower pressure differential to be used for fracturing.
The lower pressure differential assists in maintaining seal integrity and in maintaining the integrity of the tool itself. The high velocity of the proppant particles encountered in fracturing treatment may erode the steel of the tool.
Accordingly, it may be desirable to use lower pressure during fracturing Page 22 of 38 Atty. Dkt. No. 1218-0034US
Customer No. 112685 operations. The valve may be useful in reducing costs and time associated with fracturing, and may be used in many types of completion systems, including:
open hole, deviated cased hole, multi-zone, multiple fractures in a cased vertical or horizontal wellbore and in wellbores having a horizontal slotted liner.
Using this tool, perforation may be carried out when valve 10 is in the closed position since there is no fluid delivery out of frac window 65 in this position. Once perforation is complete, valve 10 may be opened by pushing down on the tubing string, causing the sealing of the tubing string by equalization plug 35 and causing wedge 70 to be exposed in fracturing window 65. Fracturing treatment may be delivered down the tubing string, out of window 65 and port 60 (see FIG.
1A) into the formation. Thus, perforation and fracturing may be accomplished with the same tool by circulating appropriate treatment fluids down the coiled tubing string, without the need to reverse circulate any balls, without the need to trip uphole, and without the need to utilize the large amounts of fluids generally required when treatment fluids are pumped down the annulus. When using a valve according to the invention, no fracturing sleeves are required.
Fluid may be circulated from the annulus to the tubing string through these ports to help with debris relief.
Equalization plug 35 is sized and shaped to sealingly engage a portion of the Page 23 of 38 Atty. Dkt. No. 1218-0034US
Customer No. 112685 tubing string below frac valve 10. This lower portion will be referred to as equalization housing 91. In the illustrated embodiment, plug 35 and wedge 70 are made as different parts, but it will be appreciated that they may be made as one part, provided that wedge and plug are coupled to each other so as to be able to slide together. As tubular mandrel 15 may be continuous with the tubing string, plug 35 may be similarly actuable by application and release of weight applied to the tubing string. In an open position shown in FIG. 2, plug 35 is not sealed within lower mandrel 91' (and therefore, fluid may pass down the tubing string through lower mandrel 91'). In a closed position shown in FIG. 1A, plug may be sealingly engaged in lower mandrel 91' (and therefore, fluid may be prevented from traveling down the tubing string through lower mandrel 91').
For example, the plug may directly engage a tubular member (without a cap being present), or the sealing ring 36 may be part of the same tubular as lower mandrel 91' (e.g., the parts need not be manufactured as separate parts provided plug 35 may slide within it).
Customer No. 112685 assist in debris removal and in equalization. Removing debris by reverse circulation may be useful. Because the coiled tubing has a flow bore of smaller cross sectional area than the annulus cross section, the flow rates required to keep the debris in suspension may be reduced. Lower flow rates are desirable to prevent erosion within the coiled tubing.
Page 25 of 38 Atty. Dkt. No. 1218-0034US
Customer No. 112685
Operation
The fracturing pressure may be very high and may be generated at the surface.
As noted above, it may be desirable to reduce the fracturing pressure and velocity of the fracturing fluid pumped down coiled tubing. Also, it may also be desirable to change from a perforating operation to a fracturing operation on the fly. Finally, it may be desirable to have flexibility in the pressure used for fracturing and perforating. For example, in some cases, it may be desirable to use the same pressure for each operation, whereas in other cases, it may be desirable to use a different pressure for fracturing than that for perforating. The present frac valve may be useful in the process of running a tubing string a long distance into the wellbore, then fracturing by pumping fluid(s) down the tubing.
Downhole proppant concentration may be changed readily by increasing or decreasing the flow rate down the tubing string.
Annulus 102 may be formed between casing 101 and the tubing string containing tool 200. Once the desired position for perforation is identified, tool 200 may be run past that position, and then, the operator may start pulling up on the tubing string, and tool 200 may be pulled upwards towards the surface of the wellbore.
Mechanical collar locator 94 may be profiled to engage casing 101. While tool 200 is being pulled upwards, frac valve 10 may be moved from the open to closed position. In this closed valve position, perforating fluid may be pumped Page 26 of 38 Atty. Dkt. No. 1218-0034US
Customer No. 112685 down the tubing string to exit the perforation nozzles 12 on perforation device 49.
Perforation may be carried out for around 5 - 10 minutes, for example. This creates perforations 99. Because the tubing string is in the tensile or extended position during perforation, plug 35 is not seated within equalization housing 91.
Also, sealing element 121 and anchor 122 are not engaged against casing 101.
Customer No. 112685 wellbore toward the surface once the first interval is treated. Tool 200 may then be moved to the next region or interval of the formation to be perforated. To accomplish this, an upward pull on the coiled tubing causes sealing element to unset, plug 35 to move to an unseated position within housing 30, and frac valve 10 to close. Tool 200 may then be moved to the next zone to be perforated.
In multi-zone wells, this fracturing process may be repeated for each zone of the well. Thus, tool 200 may be moved to successive zones to be treated, and the process repeated.
FIGS 12A and 12B show the tool string of another embodiment used for pinpoint treatments. The figures are laid out so the portion of the tool that is furthest uphole is in the top left, and the lowest most portion of the tool string is in the bottom right. So the section on the left stacks on top of the middle section and those two stack on top of the right section to show the full tool string. As shown in FIG 12A, a lower sealing element 120B, which in a preferred embodiment would be sealing element 121 and anchor element 122, and an upper sealing element 120A is shown. In a preferred embodiment, the upper sealing element 120A is a cup sealing element. This creates a treatment zone 132 between the sealing elements.
Customer No. 112685 embodiment, the present invention uses a hydraulic hold down 172 above the upper sealing element 120A. The hydraulic hold down 172, has hydraulic hold down buttons 170 that as the pressure reaches a certain point inside the hydraulic hold down 172, the hydraulic hold down buttons are forced out against the casing and bite into the tubular enough to prevent any upward movement while the pressure exists in the hydraulic hold down and conveyance tubing string, i.e., during the treatment. In FIG 12A the hydraulic hold down buttons are shown engaged, pressed into the casing 101 and holding down the tubing string and tool. Once the pressure is relieved or lowered, the hydraulic hold down buttons are released and can be disengaged from the casing to allow for ease of movement. In FIG 12B the hydraulic hold down buttons 170 are shown as released or disengaged, such that the tool string can move up or down without being impeded by the hydraulic hold down 172. All other numbering in FIGs 12A
and 12B are consistent with the numbering ion the other figures
Thereafter, proppant may be pumped down the coiled tubing. As there is no ball-seat valve employed, there may be no need for reverse circulation. This results in additional cost and fluid savings (in addition to the fluid savings resulting from the difference in volume of the coiled tubing versus the annulus).
Page 29 of 38 Atty. Dkt. No. 1218-0034US
Customer No. 112685
One skilled in the art will understand that various changes and modifications may be made without departing from the scope of the present invention as literally and equivalently covered by the following claims.
Page 30 of 38
Claims (32)
-a tubular having a throughbore, the tubular being adapted to be connected in a tubing string, the tubular having window formed through the tubular;
-an outer sleeve disposed around the tubular, the outer sleeve having a port formed in a sidewall of the sleeve, the valve being arranged such that the tubular and the sleeve are axially moveable relative to one another from a first position in which the window and port are aligned such that fluid can exit the valve through the aligned window and port and a second position in which fluid cannot exit the valve and the valve being further arranged such that movement from the first position to the second position can be effectuated by applying a mechanical force to the tubular.
-a fracturing valve for a downhole tool, the valve comprising: a tubular having a through bore, the tubular being adapted to be connected in a tubing string, and the tubular having a window formed through the tubular, an outer sleeve disposed around the tubular, the outer sleeve having a port formed in a sidewall of the sleeve, the valve being arranged such that the tubular and the sleeve are axially moveable relative to one another from a first position in which the window and port are aligned such that fluid can exit the valve through the aligned window and port and a second position in which fluid cannot exit the valve and the valve being further arranged such that movement from the first position to the second position can be effectuated by applying a mechanical force to the tubular;
-a tubing string that can be manipulated from surface into which valve can be connected such that the throughbore of the tubular is fluidically continuous with a flow path of the tubing string;
-an equalization plug disposed on the tubing string below the window, the equalization plug being actuable between an open position in which fluid flow to the tubing string below the fracturing valve is enabled to a closed position in which fluid flow to the tubing string below the fracturing valve is prevented, wherein the actuation of the equalization plug from the open to closed position can be effectuated by applying a mechanical force to the plug.
-a jet perforation device disposed on a tubing string;
-a fracturing valve on the tubing string below the jet perforation device, the fracturing valve comprising: a tubular having a throughbore, the tubular being adapted to be connected in a tubing string, the tubular having window formed through the tubular, an outer sleeve disposed around the tubular, the outer sleeve having a port formed in a sidewall of the sleeve, the valve being arranged such that the tubular and the sleeve are axially moveable relative to one another from a first position in which the window and port are aligned such that fluid can exit the valve through the aligned window and port and a second position in which fluid cannot exit the valve and the valve being further arranged such that movement from the first position to the second position can be effectuated by applying a mechanical force to the tubular.
-running into the wellbore to the required depth, a tool on a tubing string, the tool including a fracturing valve, the fracturing valve being actuable from a first position in which fluid can exit the valve to an annulus formed between the tubing string and a casing in which the tool is deployed, to a second position in which fluid cannot exit the valve to the annulus;
-perforating the casing while the valve is in the second position;
-pulling up on the tubing string to actuate the valve to the first position;
and -circulating treatment fluid down the tubing string through a passageway leading from the tubing string through the valve, and into the formation through perforations created by the perforating step.
Priority Applications (1)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
CA2873541A CA2873541A1 (en) | 2013-12-04 | 2014-12-04 | Fracturing valve and fracturing tool string |
Applications Claiming Priority (7)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US201361911841P | 2013-12-04 | 2013-12-04 | |
US61/911,841 | 2013-12-04 | ||
US14/321,558 | 2014-07-01 | ||
US14/321,558 US20150013982A1 (en) | 2013-07-10 | 2014-07-01 | Fracturing valve |
CA2856184A CA2856184A1 (en) | 2013-07-10 | 2014-07-09 | Fracturing valve |
CA2856184 | 2014-07-09 | ||
CA2873541A CA2873541A1 (en) | 2013-12-04 | 2014-12-04 | Fracturing valve and fracturing tool string |
Publications (1)
Publication Number | Publication Date |
---|---|
CA2873541A1 true CA2873541A1 (en) | 2015-06-04 |
Family
ID=53366348
Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
---|---|---|---|
CA2873541A Pending CA2873541A1 (en) | 2013-12-04 | 2014-12-04 | Fracturing valve and fracturing tool string |
Country Status (1)
Country | Link |
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CA (1) | CA2873541A1 (en) |
Cited By (5)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US9528353B1 (en) | 2015-08-27 | 2016-12-27 | William Jani | Wellbore perforating tool |
US10961819B2 (en) | 2018-04-13 | 2021-03-30 | Oracle Downhole Services Ltd. | Downhole valve for production or injection |
CN114482957A (en) * | 2020-10-26 | 2022-05-13 | 中国石油化工股份有限公司 | Open hole full-bore infinite staged fracturing well completion device and fracturing well completion method thereof |
US11591886B2 (en) | 2019-11-13 | 2023-02-28 | Oracle Downhole Services Ltd. | Gullet mandrel |
US11702905B2 (en) | 2019-11-13 | 2023-07-18 | Oracle Downhole Services Ltd. | Method for fluid flow optimization in a wellbore |
-
2014
- 2014-12-04 CA CA2873541A patent/CA2873541A1/en active Pending
Cited By (8)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
US9528353B1 (en) | 2015-08-27 | 2016-12-27 | William Jani | Wellbore perforating tool |
US10961819B2 (en) | 2018-04-13 | 2021-03-30 | Oracle Downhole Services Ltd. | Downhole valve for production or injection |
US11486224B2 (en) | 2018-04-13 | 2022-11-01 | Oracle Downhole Services Ltd. | Sensor controlled downhole valve |
US11486225B2 (en) | 2018-04-13 | 2022-11-01 | Oracle Downhole Services Ltd. | Bi-directional downhole valve |
US11725476B2 (en) | 2018-04-13 | 2023-08-15 | Oracle Downhole Services Ltd. | Method and system for electrical control of downhole well tool |
US11591886B2 (en) | 2019-11-13 | 2023-02-28 | Oracle Downhole Services Ltd. | Gullet mandrel |
US11702905B2 (en) | 2019-11-13 | 2023-07-18 | Oracle Downhole Services Ltd. | Method for fluid flow optimization in a wellbore |
CN114482957A (en) * | 2020-10-26 | 2022-05-13 | 中国石油化工股份有限公司 | Open hole full-bore infinite staged fracturing well completion device and fracturing well completion method thereof |
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