Patent Grant
10161214
Systems and methods for isolating multiple wellbore intervals are provided which can be similar to ball and seat isolation systems. An isolation well tool can include an isolation device and an isolation mandrel, where the isolation mandrel is interconnected in a tubing string in a wellbore and selectively allows the isolation device to pass through the isolation mandrel as the isolation device is displaced along an internal flow passage of the tubing string. The length of the isolation device determines whether the isolation mandrel will permit the isolation device to pass or prevent the isolation device from passing through the isolation mandrel. According to an embodiment, the isolation well tool can be used in an oil or gas well operation.
The features and advantages of certain embodiments will be more readily appreciated when considered in conjunction with the accompanying figures. The figures are not to be construed as limiting any of the preferred embodiments.
As used herein, the words “comprise,” “have,” “include,” and all grammatical variations thereof are each intended to have an open, non-limiting meaning that does not exclude additional elements or steps.
It should be understood that, as used herein, “first,” “second,” “third,” etc., are arbitrarily assigned and are merely intended to differentiate between two or more materials, layers, isolation tools, isolation devices, isolation mandrels, wellbore intervals, etc., as the case can be, and does not indicate any particular orientation or sequence. Furthermore, it is to be understood that the mere use of the term “first” does not require that there be any “second,” and the mere use of the term “second” does not require that there be any “third,” etc.
As used herein, a “fluid” is a substance having a continuous phase that tends to flow and to conform to the outline of its container when the substance is tested at a temperature of 71° F. (22° C.) and a pressure of one atmosphere “atm” (0.1 megapascals “MPa”). A fluid can be a liquid or gas.
Oil and gas hydrocarbons are naturally occurring in some subterranean formations. In the oil and gas industry, a subterranean formation containing oil and/or gas is referred to as a reservoir. A reservoir can be located under land or off shore. Reservoirs are typically located in the range of a few hundred feet (shallow reservoirs) to a few tens of thousands of feet (ultra-deep reservoirs). In order to produce oil or gas, a wellbore is drilled into a reservoir or adjacent to a reservoir. The oil, gas, or water produced from a reservoir is called a reservoir fluid.
A well can include, without limitation, an oil, gas, or water production well, or an injection well. As used herein, a “well” includes at least one wellbore. A wellbore can include vertical, inclined, and horizontal portions, and it can be straight, curved, or branched. As used herein, the term “wellbore” includes any cased, and any uncased, open-hole portion of the wellbore. A near-wellbore region is the subterranean material and rock of the subterranean formation surrounding the wellbore. As used herein, a “well” also includes the near-wellbore region. The near-wellbore region is generally considered to be the region within approximately 100 feet radially of the wellbore. As used herein, “into a well” means and includes into any portion of the well, including into the wellbore or into the near-wellbore region via the wellbore.
A portion of a wellbore can be an open hole or cased hole. In an open-hole wellbore portion, a tubing string can be placed into the wellbore. The tubing string allows fluids to be introduced into or flowed from a remote portion of the wellbore. In a cased-hole wellbore portion, a casing is placed into the wellbore that can also contain a tubing string. A wellbore can contain an annulus. Examples of an annulus include, but are not limited to: the space between the wellbore and the outside of a tubing string in an open-hole wellbore; the space between the wellbore and the outside of a casing in a cased-hole wellbore; and the space between the inside of a casing and the outside of a tubing string in a cased-hole wellbore.
It is not uncommon for a wellbore to extend several hundreds of feet or several thousands of feet into a subterranean formation. The subterranean formation can have different zones. A zone is an interval of rock differentiated from surrounding rocks on the basis of its fossil content or other features, such as faults or fractures. For example, one zone can have a higher permeability compared to another zone. It is often desirable to treat one or more locations within multiples zones of a formation. One or more zones of the formation can be isolated within the wellbore via the use of an isolation device, in conjunction with an isolation mandrel, to create multiple wellbore intervals. At least one wellbore interval can correspond to a particular subterranean formation zone. The isolation device can be used for zonal isolation and functions to block fluid flow within a tubular, such as a tubing string, or within an annulus. The blockage of fluid flow prevents the fluid from flowing across the isolation device in any direction and isolates the zone of interest. In this manner, completion operations, such as well treatments, fracturing, injecting, production, etc., can be performed within the zone of interest.
Common isolation devices include, but are not limited to, a ball and a seat, a bridge plug, a frac plug, a packer, a plug, and wiper plug. It is to be understood that reference to a “ball” is not meant to limit the geometric shape of the ball to spherical, but rather is meant to include any device that is capable of engaging with a seat. A “ball” can be spherical in shape, but can also be a dart, a bar, or any other shape. Zonal isolation can be accomplished via a ball and seat by dropping or flowing the ball from the wellhead onto the seat that is located within the wellbore. The ball engages with the seat, and the seal created by this engagement prevents fluid communication into other wellbore intervals downstream of the ball and seat. As used herein, the relative term “downstream” means at a location further away from a wellhead.
In order to treat more than one zone using a ball and seat, the wellbore can contain more than one ball seat. For example, a seat can be located within each wellbore interval. Generally, the inner diameter (I.D.) of the ball seats can be different for each zone. For example, the I.D. of the ball seats sequentially decreases at each zone, moving from the wellhead to the bottom of the well. In this manner, a smaller ball is first dropped into a first wellbore interval that is the farthest downstream; the corresponding zone is treated, tested, injected and/or produced; a slightly larger ball is then dropped into another wellbore interval that is located upstream of the first wellbore interval; that corresponding zone is then treated, tested, injected and/or produced; and the process continues in this fashion—moving upstream along the wellbore—until all the desired zones have been treated, tested, injected and/or produced. As used herein, the relative term “upstream” means at a location closer to the wellhead. Also, the current disclosure does not require that the multiple “seats” be a different diameter as typical ball and seat systems generally require.
The tubing string has a limited inner diameter. Moreover, the difference in the inner diameter of each seat must be sufficiently different to allow for the different sized balls to fall through the tubing string to its desired seat. Therefore, being able to create a multitude of wellbore intervals has been quite challenging. There is a need for improved systems that allow for a multitude of wellbore intervals to be created. It has been discovered that multiple wellbore intervals can be created without any regard to the inner diameter of the tubing string.
According to an embodiment, a system for selective isolation of multiple wellbore intervals comprises: an isolation mandrel interconnected in a tubing string, where the tubing string has a flow passage that extends through the isolation mandrel. The isolation mandrel can include, an entry bore (or channel), a transition chamber, and an exit bore (or channel), with the transition chamber positioned between the entry and exit bores (or channels), and the transition chamber being radially enlarged relative to the entry and exit bores (or channels). The isolation device having a predetermined length can be displaced through the tubing string to the isolation mandrel where it selectively permits and prevents fluid flow through the isolation mandrel.
According to another embodiment, a method of selectively performing a wellbore operation on multiple wellbore intervals comprises: interconnecting an isolation mandrel in a tubing string. The isolation mandrel can include: an entry bore (or channel), a transition chamber, and an exit bore (or channel), with the transition chamber located between the entry and exit bores (or channels), and the transition chamber being radially enlarged relative to the entry and exit bores (or channels). Displacing an isolation device through the tubing string to the isolation mandrel, the isolation device having a predetermined length, and selectively permitting and preventing displacement of the isolation device through the isolation mandrel in response to the length of the isolation device.
According to yet another embodiment, a wellbore isolation tool for selectively isolating multiple wellbore intervals comprises: an isolation mandrel that can include, an entry bore (or channel), a transition chamber, and an exit bore (or channel), with the transition chamber being positioned between the entry and exit bores (or channels), and where an inner diameter of the transition chamber is greater than a minimum inner diameter of the entry and exit bores (or channels). An isolation device that is displaced through the entry bore (or channel) and at least partially into the transition chamber, with the isolation device selectively permitting and preventing fluid flow through the isolation mandrel in response to a length of the isolation device.
Any discussion of the embodiments regarding the isolation device or the isolation mandrel, or any component related to the isolation device or the isolation mandrel is intended to apply to all of the apparatus, system, and method embodiments.
Turning to the Figures,
The well system 10 can contain multiple packers 26, multiple flow control devices 30 and multiple wellbore isolation tools 40 located within multiple zones 16, 17, 18, 19 of the well system 10. The methods include selectively permitting and preventing fluid flow through the wellbore isolation tools 40, thereby selectively isolating wellbore intervals 35, 36, 37, 38, 39 for performing completion operations, such as well treatment, injecting, fracturing, well testing, and fluid production, on one or more wellbore intervals while isolating one or more downstream wellbore intervals 35, 36, 37, 38, 39 from the completion operations.
When fluid flow is prevented between one or more wellbore intervals 35, 36, 37, 38, 39, respective flow control devices 30 can be used in completion operations within one or more of the wellbore intervals 35, 36, 37, 38, 39 or formation zones upstream of the blocked wellbore isolation tool 40. For example, an injection fluid can be flowed into any of the zones 16, 17, 18, 19, and/or fracturing fluid can be flowed into the formation 20 to initiate fractures 22, as shown by arrows 32. Additionally, fluid and/or gas can be flowed, as shown by arrows 34, into the tubing string 24 from the zones 16, 17, 18, 19 and/or fractures 22 during production operations.
The wellbore 11 can have a generally vertical uncased section 14 extending downwardly from a casing 15, as well as a generally horizontal uncased section extending through the subterranean formation 20. The wellbore 11 can alternatively include only a generally vertical wellbore section or can alternatively include only a generally horizontal wellbore section. The wellbore 11 can include a heel 12 and a toe 13.
The wellbore isolation tools 40 can be used to selectively permit and prevent fluid flow between various wellbore intervals. Each wellbore isolation tool 40 includes an isolation mandrel 44 and an isolation device 42. The isolation mandrels 44 can be interconnected in the tubing string 24 as seen in
In general, a particular isolation tool 40 interconnected in the tubing string 24 has an isolation mandrel 44 with a longitudinal length that is longer than isolation mandrel(s) 44 that are downstream from the particular isolation tool 40. Also, the particular isolation tool 40 can have an isolation mandrel 44 with a longitudinal length that is shorter than isolation mandrel(s) 44 that are upstream from the particular isolation tool 40. The end isolation mandrels 44 (i.e., the ones located the farthest downhole or nearest to the wellhead) cannot have one of the upstream or downstream isolation mandrels.
In operation, the isolation devices 42 can be separately (or simultaneously) displaced through the tubing string 24 into respective isolation mandrels 44. The isolation devices 42 can be displaced through the tubing string by gravity, tethered to an end of a wire line or coiled tubing, pumped through a flow passage of the tubing string via fluid pressure, and/or any other suitable method for displacing the devices 42 through the tubing string 24 to the respective isolation mandrels 44.
The isolation devices 42 have different predetermined lengths, and when they are displaced through the flow passage, their lengths determine which of the isolation mandrels 44 that the individual isolation devices 42 will land in and engage a no-go feature, which causes the isolation device 42 to block (or prevent) flow through the respective isolation mandrel 44 in which the device 42 has landed. An isolation device 42 can be landed in the isolation mandrel 44 that is closest to the toe 13 of the wellbore (i.e., farthest downhole). This isolates all wellbore intervals downstream of this isolation mandrel 44 from all other wellbore intervals 35, 36, 37, 38, 39 that are upstream of the farthest downhole isolation mandrel 44. Therefore, wellbore completion operations can be performed on any of these wellbore intervals 35, 36, 37, 38, 39 without impacting the downstream wellbore intervals.
Please note that
The individual isolation mandrels 44 are “associated” with a particular isolation device 42 because they are pre-selected to be matched pairs with a device 42 and mandrel 44 per pair. When the “associated” isolation device is displaced through the tubing string 24 to the “associated” (or paired) isolation mandrel 44, the “associated” isolation device 42 will land in the “associated” isolation mandrel 44 and prevent flow through the “associated” isolation mandrel 44. The isolation mandrels 44 are interconnected in the tubing string 24 prior to or during installation of the tubing string 24 in the wellbore 11. Then their associated or paired isolation devices 42 are displaced through the tubing string 24 to their associated or paired isolation mandrel 44.
Once the tubing string in positioned in the well (e.g., cemented in the wellbore, packers set, etc.), then the isolation devices 42 are individually introduced into the tubing string 24 at the surface and/or above a wellhead. There can be a significant time delay between introducing the first isolation device 42 in the tubing string 24, or the time delay can be quiet small, such that the isolation devices are traveling (i.e., displacing) through the tubing string simultaneously. However, it is preferred that the time delay between introductions of the isolation devices 42 into the tubing string 24 is long enough that the wellbore operations for a particular wellbore interval are complete before introducing the next isolation device 42.
The first isolation mandrel 44 with a longitudinal length 71 is shown in
The second isolation tool 40 is shown as a partial cross-sectional view with portions of the second isolation mandrel 44 removed for clarity. The second isolation mandrel 44 is shown as the being interconnected in the tubing string 24 farther downstream (e.g., longitudinally spaced apart) from the first isolation mandrel 44. The second isolation mandrel 44 is also indicated as having a length 71. However, the lengths 71 of the first and second isolation mandrels 44 are preferably different. The farthest downhole mandrel 44 (e.g., second mandrel 44) is preferably shorter than the upstream mandrel 44 (e.g., first mandrel 44).
However, it is not a requirement that the farthest downhole be the shortest of the first and second isolation mandrels 44. The isolation devices 42 can be retrieved from the wellbore, dissolved in the wellbore, or otherwise degraded in the wellbore to remove the isolation device from the isolation mandrel 44 in which it landed. For example, the isolation device can be made of a frangible material that will breakup at a predetermined pressure differential. Once the device 42 is broken, the well fluids can then dissolve and/or degrade the pieces. The isolation devices 42 can also be dissolved or otherwise degraded to remove them from the isolation mandrels 44. Therefore, the isolation devices can be introduced into the tubing string 24 in any order in keeping with the principles of this disclosure.
The length 71 of the second isolation mandrel 44 is also selected prior to interconnection of the second isolation mandrel 44 in the tubing string and installation of the tubing string 24 in the wellbore. The length 71 generally determines which of the multiple isolation devices 42 is associated (or paired) with the second isolation tool 40, and thereby indicates which of the multiple isolation devices 42 will displace through the first isolation mandrel, and land in the second isolation mandrel 44, thereby blocking flow through the second isolation tool 40. When the isolation device 42 is a lock mandrel 100, as seen in
The cross-sectional view of the second isolation tool 40 reveals the second isolation device 42 as being a lock mandrel 100. The lock mandrel 100 is shown engaging a no-go surface 58 of the isolation mandrel 44, thereby landing (or preventing further displacement of) the lock mandrel 100 in the second isolation mandrel 44. Flow between intervals 36 and 37 is prevented due to the landing of the lock mandrel 100 (or isolation device 42) in the second isolation mandrel 44. Please note that the lock mandrel 100 is shown as including two modules 102, 104, with the standard length module 102 being substantially the same length for various lock mandrels 100 with various longitudinal lengths. The variable length module 104 allows convenient configuration of the lock mandrel 100 (or isolation device 42) into any number of length configurations by connecting various modules 104 of various lengths to standard length modules 102. This can allow simpler manufacturing of the more expensive standard length module 102 and can also allow reuse of the standard length modules 102. The module 102 can include various downhole tools, such as sensors, electronics, controllers, telemetry devices, power sources, etc. Of course, the variable length module 104 can also include sensors, electronics, etc., but it is preferred that these are contained within the module 102.
Please note that the configuration of the well system 10 shown in
It should also be clear that the terms “first” and “second” in these discussions in no way implies a connection to items in the appended claims that can be phrased similarly.
In this case, the second isolation device 42, which is associated with the second isolation mandrel 44, is being displaced through the tubing string 24 (which is also the casing string 15). Three separate points in time are indicated by the separate locations of the second isolation device 42 along the tubing string 24. The first two locations are indicated by dashed lines outlining the second isolation device 42. The first location of the isolation device 42 is shown as the device enters a portion of the wellbore included in
The second isolation device 42 travels through the tubing string 24, the tubing string having a longitudinal axis 80. Each of the first and second isolation mandrels 44 includes an entry bore 52, and exit bore 56, and a transition chamber 50 having a chamber bore 54, where the transition chamber 50 is positioned between the entry and exit bores 52, 56, as shown in
The inner diameter of portions of the tubing string 24 that are outside of the isolation mandrels 44 is preferably larger than the entry bores 52 and the exit bores 56 of the isolation mandrels 44. This larger diameter allows the isolation devices 42 to more freely travel through the tubing string prior to and after traveling through an isolation mandrels 44. As seen in
A central longitudinal axis 81 of the entry bore 52 can be radially offset from the central longitudinal axis 80 of the tubing string by an offset 88. When the second isolation device 42 is displaced into the entry bore 52 of the first isolation mandrel 44, the second isolation device 42 can be radially shifted to align its longitudinal axis 82 with the longitudinal axis 81 of the entry bore 52. Please note, however, that it is not necessary that the entry bore be eccentrically arranged (i.e., a longitudinal axis 81 of the entry bore 52 is radially offset by offset 88 from the tubing string axis 80). Instead, the longitudinal axis 81 of the entry bore 52 can be coaxially aligned (i.e., the longitudinal axis 81 is in line with the longitudinal axis 80 of the tubing string 24).
The second isolation device 42 has a longitudinal length 70, which can include multiple modules, such as the standard length module 102 and the variable length module 104, such as for the lock mandrel 100, or can include a single variable module such as a dart, plug, etc. As the second isolation device 42 displaces into the transition chamber 50 it is allowed to completely exit the entry bore 52 before entering the exit bore 56, if the length 70 is less than a no-go length of the isolation mandrel 44. Since the second isolation device 42 is fully contained within the transition chamber 50 of the first isolation mandrel 44, it is allowed to move or displace radially (as shown by arrow 46) to align with the longitudinal axis 84 of the exit bore 56 (axis 84 not shown in the first isolation mandrel, see second isolation mandrel for reference).
This realignment within the transition chamber 50 of the first isolation mandrel 44 allows the second isolation device 42 to enter the exit bore 56 and continue moving through the tubular string to the second isolation mandrel 44. The first isolation mandrel 44 has a no-go surface 58 that is used to no-go the second isolation device 42 (i.e., prevent further longitudinal displacement of the second isolation device 42 in a downhole direction) if the length 70 of the second isolation device 42 is greater than or equal to the no-go length 74 of the isolation mandrel 44 (as is the case with the second isolation mandrel 44), the second isolation device 42 will engage the no-go surface 58 preventing the second isolation device 42 from fully exiting the isolation mandrel 44 and will not be allowed to enter the exit bore 56. In this manner, the length of a particular isolation device can be used to either allow the passage of the isolation device through the isolation mandrel or no-go within the isolation mandrel based on the length of the transition chamber.
However, the no-go length 74 of the first isolation mandrel 44 is longer than the length 70 of the second isolation device 42, so the second isolation device 42 is allowed to pass through the first isolation mandrel 44 without landing in the mandrel. It can be clearly understood that the second isolation device 42 can indeed temporarily engage the no-go surface 58, but it will not remain engaged with the surface 58 since the second isolation device 42 is allowed to radially displace in the transition chamber 50 to align with the exit bore 56 and thereby bypass the no-go surface 58 of the first isolation mandrel 44. The no-go surface 58 is shown a being a linear inclined shape. However, the no-go surface 58 can be any surface that will urge the isolation device 42 into alignment with the exit bore axis 84.
Each of the multiple isolation mandrels includes the no-go length 74, which can include a longitudinal length 72 of the chamber bore 54 and a longitudinal length 73 of a portion of an end of the entry bore 52 that is near the transition chamber 50. This portion of the entry bore 52 can be any length including “zero” depending on the design of bore transitions between the entry, exit and chamber bores 52, 56, 54, as well as a design of the ends of the isolation devices 42.
The second isolation device 42 then continues its journey through the tubing string 24 and into the entry bore 52 of the second isolation mandrel 44. As seen in
Since a portion of the second isolation device 42 remains in the entry bore 52, the second isolation device 42 is prevented from radially displacing in the transition chamber 50 to align with the exit bore 56, the exit bore 56 being radially offset from the entry bore axis 82 (and in this case tubing string axis 80) by offset 86. It can be said that the second isolation device 42 is “landed” in the second isolation mandrel 44, where “landed” (or no-go) indicates that the second isolation device 42 is prevented from further longitudinal displacement in a downstream direction.
The portion of the second isolation device 42 that remains in the entry bore 52 can include a seal 90 (e.g., an annular seal or seals, such as O-rings, chevron seals, cup seals, etc.) that sealing engages the entry bore 52 and prevents fluid flow through the second isolation mandrel 44. With the second isolation device 42 landed in second isolation mandrel 44, completion operations can be performed on wellbore intervals 35 and/or 36, which are upstream from the second isolation mandrel 44, without affecting the wellbore interval 37, which is downstream from the second isolation mandrel 44.
As seen in
It should be understood that the lengths of the transition chambers along with the lengths of the isolation devices can be selected to create a multitude of wellbore intervals within the wellbore. The lengths can vary and be selected in order to create the desired number of wellbore intervals and the number will not be limited by the inner diameter of the tubing string. Therefore, the possibilities and exact configurations are virtually endless.
A method for selective isolation of multiple wellbore intervals can include determining the desired lengths 71 of the multiple isolation mandrels 44 to be interconnected in the tubing string 24, and determining the lengths 70 of the associated isolation devices 42, such that the appropriate isolation device 42 will land in its associated (or paired) isolation mandrel 44 when the isolation devices 42 are displaced through the tubing string 24, thereby providing isolation of multiple wellbore intervals in a desired sequence.
The method can include installing the tubing string 24 in the wellbore 11, with the multiple isolation mandrels positioned at their respective desired locations in the wellbore 11. The tubing string 24 can be secured in the wellbore 11 by setting packers against a casing string or an open hole section of the wellbore 11, or by cementing the tubing string 24 in the wellbore, or etc.
The method can include displacing a first isolation device 42 with a length 70 through the tubing string to it associated isolation mandrel 44 with a no-go length 74 that is shorter than its length 70, where the isolation device will land (or no-go) in the associated isolation mandrel 44. The landed isolation device 42 will prevent fluid flow through the associated isolation mandrel 44, thereby isolating the wellbore intervals that are downstream of the associated isolation mandrel 44 from the wellbore intervals that are upstream of the associated isolation mandrel 44.
The method can include performing various completions operations on one or more of the upstream wellbore intervals, without affecting the downstream wellbore intervals.
The method can include removing the isolation device 42 by retrieval and/or removal (such as breaking, dissolving, degrading, etc.). However, it is not required to remove the isolation device 42. If the desired sequence is to land isolation devices 42 in the farthest downhole isolation mandrel 44 first and then successively land isolation devices 42 in successive upstream isolation mandrels 44, the isolation devices 42 will not need to be removed and can remain in the tubing string 24.
The method can include moving the next isolation device 42 through the tubing string 24 to its associated isolation mandrel 44, and landing the next isolation device 42 in its associated isolation mandrel 44 to isolate wellbore intervals upstream and downstream of the associated isolation mandrel.
The method can include repeating the performing completion operations, removing the isolation device, and moving the next isolation device through the tubing string until all wellbore intervals operations are complete.
It should be noted that the well system 10 is illustrated in the drawings and is described herein as merely one example of a wide variety of well systems in which the principles of this disclosure can be utilized. It should be clearly understood that the principles of this disclosure are not limited to any of the details of the well system 10, or components thereof, depicted in the drawings or described herein. Furthermore, the well system 10 can include other components not depicted in the drawing. For example, the well system 10 can further include a well screen. By way of another example, cement can be used instead of packers 26 to aid the isolation device in providing zonal isolation.
Therefore, the present system is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the principles of the present disclosure can be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is, therefore, evident that the particular illustrative embodiments disclosed above can be altered or modified and all such variations are considered within the scope and spirit of the principles of the present disclosure.
While compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods also can “consist essentially of” or “consist of” the various components and steps. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the element that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent(s) or other documents that can be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/US2014/058293 | 9/30/2014 | WO | 00 |
| Publishing Document | Publishing Date | Country | Kind |
|---|---|---|---|
| WO2016/053297 | 4/7/2016 | WO | A |
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| 20160251929 A1 | Sep 2016 | US |
