The present disclosure is generally related to controlling fluid flow in a wellbore and, more particularly, to annular flow control devices and their methods of use.
Recovery of valuable hydrocarbons in some subterranean formations can sometimes be difficult due to a relatively high viscosity of the hydrocarbons and/or the presence of viscous tar sands in the formations. In particular, when a production well is drilled into a subterranean formation to recover oil residing therein, often little or no oil flows into the production well even if a natural or artificially induced pressure differential exists between the formation and the well. To overcome this problem, various thermal recovery techniques have been used to decrease the viscosity of the oil and/or the tar sands, thereby making the recovery of the oil easier.
Steam assisted gravity drainage (SAGD) is one such thermal recovery technique and utilizes steam to thermally stimulate viscous hydrocarbon production by injecting steam into the subterranean formation to the hydrocarbons residing therein. As the temperature of the hydrocarbons increases, they are able to more easily flow to a production well to be produced to the surface. During injection of the steam, however, the steam is often not evenly distributed throughout the length of the wellbore such that a temperature gradient or energy gradient along the wellbore is generated and consists of some areas that are hotter or have more potential energy than other areas. As a result, hydrocarbons are often only efficiently produced across a narrow window of the wellbore where the temperature is able to increase to an effective point.
A number of devices are available for regulating the flow of steam into subterranean formations. Some of these devices are non-discriminating for different types of fluids and simply function as a “gatekeeper” for regulating injection rates of the steam into the formation. Such gatekeeper devices can be simple on/off valves or they can be metered to regulate fluid flow over a continuum of flow rates. Other types of devices that may be used to regulate the flow of steam into subterranean formations include tubular flow restrictors, nozzle-type flow restrictors, ports, tortuous paths, and other flow control devices. Such standard flow control devices, however, tend to expel steam at one point in the wellbore and water at another point. This is partially due to the effects of gravity on the steam, but also due to the fact that the steam can more easily exit through a flow control device as opposed to water flowing with the steam.
It would prove advantageous to have a system that uses flow control devices that are able to deliver a consistent heat flow along the entire length of a wellbore. It would similarly prove advantageous to have a system that uses flow control devices that are able to deliver a similar quantity of water and steam (assuming wet steam) into each section of the wellbore and otherwise deliver a consistent pressure drop along such lengths of the wellbore.
The present disclosure is generally related to controlling fluid flow in a wellbore and, more particularly, to annular flow control devices and their methods of use.
In some embodiments, a flow control device may be disclosed and may include an annular inner shroud coupled to a work string that defines one or more flow ports therein, and an annular outer shroud also coupled to the work string and radially offset from the inner shroud such that a channel is defined between at least a portion of the inner and outer shrouds, the channel being in fluid communication with at least one of the one or more flow ports and configured to restrict a flow rate of a fluid.
In some embodiments, a method of regulating a flow of a fluid may be disclosed. The method may include conveying the fluid in a work string defining one or more flow ports therein, receiving a portion of the fluid in an annular flow control device coupled to the work string and including an inner shroud and an outer shroud radially offset from the inner shroud and defining a channel therebetween to receive the portion of the fluid, the channel being in fluid communication with at least one of the one or more flow ports, and conducting the portion of the fluid through the channel and the at least one of the one or more flow ports, and thereby creating a flow restriction on the fluid through the annular flow control device.
In some embodiments, another method of regulating a flow of a fluid may be disclosed and may include drawing the fluid into a work string defining one or more flow ports therein, receiving the fluid in an annular flow control device coupled to the work string and including an inner shroud and an outer shroud radially offset from the inner shroud such that a channel is defined therebetween to receive the fluid, the channel being in fluid communication with at least one of the one or more flow ports, and conducting the fluid through the channel and the at least one of the one or more flow ports, and thereby creating a flow restriction on the fluid through the annular flow control device.
The features of the present disclosure will be readily apparent to those skilled in the art upon a reading of the description of the embodiments that follows.
The following figures are included to illustrate certain aspects of the present disclosure, and should not be viewed as exclusive embodiments. The subject matter disclosed is capable of considerable modifications, alterations, combinations, and equivalents in form and function, as will occur to those skilled in the art and having the benefit of this disclosure.
The present disclosure is generally related to controlling fluid flow in a wellbore and, more particularly, to annular flow control devices and their methods of use.
Disclosed are various embodiments of flow control devices that may be used for injection or production operations in oil and gas wells. The disclosed flow control devices may be well suited and otherwise prove advantageous for steam assisted gravity drainage (SAGD) operations. For instance, the exemplary flow control devices described herein provide an annular structure that is able to deliver a consistent heat flow (or thermal energy) along the entire length of a horizontal injection well. Moreover, because of the annular structural design, the disclosed flow control devices may be able to deliver a consistent pressure drop along the length of the injection well, thereby being able to deliver a similar quantity of water and steam (assuming wet steam) into each section.
The exemplary flow control devices may also include various fluidic features, such as dimples, fluidic diodes, a porous medium, and tortuous flow paths, all of which increase the flow path length and promote increase pressure drop. As a result, the disclosed flow control devices may be effective and otherwise advantageous in controlling the injection of a mixed fluid, such as an injected steam that includes both gaseous and aqueous components. For instance, the gaseous and aqueous components may be trapped by the annular structure and otherwise contained in a section of lower velocity and by a cross-section that is parallel to their flow direction.
Referring to
The depicted system 100 may include an injection service rig 102 that is positioned on the earth's surface 104 and extends over and around an injection wellbore 106 that penetrates a subterranean formation 108. The injection service rig 102 may include a drilling rig, a completion rig, a workover rig, or the like. The injection wellbore 106 may be drilled into the subterranean formation 108 using any suitable drilling technique and may extend in a substantially vertical direction away from the earth's surface 104 over a vertical injection wellbore portion 110. At some point in the injection wellbore 106, the vertical injection wellbore portion 110 may deviate from vertical relative to the earth's surface 104 over a deviated injection wellbore portion 112 and may further transition to a horizontal injection wellbore portion 114, as illustrated. In some embodiments, for example, the wellbore 106 may be angled past 90° or otherwise angled up toward the surface 104, without departing from the scope of the disclosure.
The system 100 may further include an extraction service rig 116 (e.g., a drilling rig, completion rig, workover rig, and the like) that may also be positioned on the earth's surface 104. The service rig 116 may extend over and around an extraction wellbore 118 that also penetrates the subterranean formation 108. Similar to the injection wellbore 106, the extraction wellbore 118 may be drilled into the subterranean formation 108 using any suitable drilling technique and may extend in a substantially vertical direction away from the earth's surface 104 over a vertical extraction wellbore portion 120. At some point in the extraction wellbore 118, the vertical extraction wellbore portion 120 may deviate from vertical relative to the earth's surface 104 over a deviated extraction wellbore portion 122, and transition to a horizontal extraction wellbore portion 124. As illustrated, at least a portion of horizontal extraction wellbore portion 124 may be vertically offset from and otherwise disposed below the horizontal injection wellbore portion 114.
While the injection and extraction service rigs 102, 116 are depicted in
The system 100 may further include an injection work string 126 (e.g., production string/tubing) that extends into the injection wellbore 106. The injection work string 126 may include a plurality of injection tools 128, each injection tool 128 being configured for an outflow control configuration such that a fluid (e.g., steam) may be effectively injected into the surrounding subterranean formation 108. Similarly, the system 100 may include an extraction work string 130 (e.g., production string/tubing) that extends into the extraction wellbore 118. The extraction work string 130 may include a plurality of production tools 132, each production tool being configured for an inflow control configuration such that a flow of hydrocarbons may be drawn into the extraction work string 130 from the surrounding subterranean formation 108.
One or more wellbore isolation devices 134 (e.g., packers, gravel pack, collapsed formation, or the like) may be used to isolate annular spaces of both the injection and extraction wellbores 106, 118. As illustrated, the isolation devices 134 may be configured to substantially isolate separate injection and production tools 128, 132 from each other within their corresponding injection and extraction wellbore 106, 118, respectively. As a result, fluids may be injected into the formation 108 at discrete and separated intervals via the injection tools 128 and fluids may subsequently be produced from multiple intervals or “pay zones” of the formation 108 via isolated production tools 132 arranged along the extraction work string 130.
While the system 100 is described above as comprising two separate wellbores 106, 118, other embodiments may be configured differently, without departing from the scope of the disclosure. For example, in some embodiments the work strings 126, 130 may both be located in a single wellbore. In other embodiments, vertical portions of the work strings 126, 130 may both be located in a common wellbore but may each extend into different deviated and/or horizontal wellbore portions from the common vertical portion. In yet other embodiments, the vertical portions of the work strings 126, 130 may be located in separate vertical wellbore portions but may both be located in a shared horizontal wellbore portion.
In each of the above described embodiments, the injection and production tools 128, 132 may be used in combination and/or separately to deliver fluids to the wellbore with an outflow control configuration and/or to recover fluids from the wellbore with an inflow control configuration. Still further, in other embodiments, any combination of injection and production tools 128, 132 may be located within a shared wellbore and/or amongst a plurality of wellbores and the injection and production tools 128, 132 may be associated with different and/or shared isolated annular spaces of the wellbores, the annular spaces, in some embodiments, being at least partially defined by one or more zonal isolation devices 134.
In exemplary operation of the well system 100, a fluid (e.g., steam) may be conveyed into the injection work string 126 and ejected therefrom via the injection tools 128 and into the surrounding formation 108. Introducing steam into the formation 108 may reduce the viscosity of some hydrocarbons affected by the injected steam, thereby allowing gravity to draw the affected hydrocarbons downward and into the extraction wellbore 118. The extraction work string 130 may be caused to maintain an internal bore pressure (e.g., a pressure differential) that tends to draw the affected hydrocarbons into the extraction work string 130 through the production tools 132. The hydrocarbons may thereafter be pumped out or flowed out of the extraction wellbore 118 and into a hydrocarbon storage device and/or into a hydrocarbon delivery system (i.e., a pipeline).
While
Each of the injection and production tools 128, 132 may include at least one flow control device (not shown) configured to restrict or otherwise regulate the flow of fluids out of the injection work string 126 and/or into the extraction work string 130, respectively. One challenge presented to well operators is injecting or producing uniform or substantially uniform amounts of fluid through traditional flow control devices along the length of the injection and extraction work strings 126, 130 where the injection and production tools 128, 132 are located. For example, when steam is being injected into the formation 108, the gaseous component of the steam is more readily injected near the heel of a well through traditional flow control devices, while a good portion of the aqueous component of the steam (i.e., water) is more likely to congregate and be injected near the toe of the well.
In vertical injection wells, the water typically passes the injection ports of a typical flow control device and falls to the toe. This drastically decreases the injection of steam at the toe and rather favors water injection at the toe. In horizontal injection wells, on the other hand, there are usually limited flow ports for traditional flow control devices and, in some applications, there is only one flow port per section of tubing. The location of the flow ports often have a random orientation and thus some flow ports will be filled with water and some will be out of the water. The result is that the heat flow into the subterranean formation 108 may not be uniform along the length of the injection work strings 126 where the injection tools 128 are located.
Referring now to
The flow control device 200, as depicted in
In some embodiments, the fluid 202 may be steam flowing in the downhole direction as indicated by the arrows 204. The steam may be a dry steam and entirely composed of a gas. In other embodiments, however, the steam may include both gaseous and aqueous components. In at least one embodiment, the fluid 202 may be injected into the surrounding formation 108 for the purposes of steam assisted gravity drainage (SAGD) operations. In other embodiments, the fluid 202 may be any other type of fluid that may be injected into the formation 108 for other wellbore operations, without departing from the scope of the disclosure.
In some embodiments, the flow control device 200 may include an inner shroud 206a and an outer shroud 206b arranged within the work string 126. The inner shroud 206a may be radially offset from the outer shroud 206b toward a central axis 208 of the work string 126, and the outer shroud 206b may be radially offset from the inner surface of the work string 126 toward the central axis 208. In other embodiments, however, the outer shroud 206b may be omitted or otherwise replaced functionally by the work string 126 itself. In other words, the work string 126 may functionally serve as the outer shroud 206b in at least some embodiments, without departing from the scope of the disclosure.
The inner and outer shrouds 206a,b may be radially offset from each other a short distance 210 so as to define a narrow channel 212 therebetween. The channel 212 may create or otherwise define an annular area that generates a flow restriction for the fluid 202 and simultaneously create back pressure on the fluid 202 as it enters the channel 212. Accordingly, the channel 212 may prove advantageous in maximizing the sensitivity to viscosity of the fluid 202 and simultaneously minimizing the sensitivity to density of the fluid 202, especially when the fluid 202 is a steam that contains an aqueous component (i.e., liquid water).
For instance, the density of saturated water is 12.78 times the density of saturated steam (690 kg/m3 versus 54 kg/m3). On the other hand, the viscosity of saturated water is only 4.1 times the viscosity of saturated steam (0.082 cP versus 0.02 cP). Accordingly, the flow control device 200 may be designed or otherwise able to achieve a flow within the channel 212 that is less sensitive to the steam saturation if the restriction caused by the distance 210 of the channel 212 is dominated by viscosity rather than by density. As a result, more uniform amounts of both gaseous steam and water may be introduced into the channel 212 and expelled into the formation 108, as opposed to expelling uneven amounts of either gaseous steam or water and thereby not providing an equal injection rate along the work string 126.
For laminar flow, the pressure restriction of the channel 212 may be approximately given by the following equation:
where μ is the absolute viscosity of the fluid 202, L is the length of the channel 212, V is the bulk flow velocity of the fluid 202 within the channel 212, and h is the distance 210 between the inner and outer shrouds 206a,b.
For turbulent flow, the pressure restriction provided by the channel 212 may be approximately given by the following equation:
where ρ is the mass density of the fluid 202, and f is the friction factor of the channel 212. Whether laminar or turbulent flow is desired will depend on the application from well to well, such as how much pressure drop is desired along the work string 126 for the particular well and the costs required to obtain such a pressure drop. As will be appreciated by those skilled in the art, a pressure drop along the work string 126 may prove advantageous in balancing the flow of the fluid 202 out of the work string 126 such that a change in the permeability of the surrounding formation 108 does not dominate SAGD injection operations.
If the flow control device 200, or otherwise the channel 212, is designed to operate in laminar flow, then the pressure drop along the length of the work string 126 will be dominated by the viscous effects of the fluid 202. If, however, the flow control device 200, or otherwise the channel 212, is designed to operate in turbulent flow, then the density of the fluid 202 will dominate. With rare exception, turbulent flow of the fluid 202 will result in a larger pressure drop along the length of the work string 126.
The work string 126 may have one or more flow ports 214 defined therein and the channel 212 may be fluidly coupled to the one or more flow ports 214 such that the fluid 202 may be conveyed to the flow ports 214 via the channel 212. While two flow ports 214 are illustrated in
The inner and outer shrouds 206a,b may be coupled to the work string 126 and extend longitudinally in the uphole direction (i.e., to the left in
Referring briefly to
Referring again to
In some embodiments, the inner shroud 206a may be longer than the outer shroud 206b such that the inner shroud 206a may include or otherwise define an axial extension 220 (shown in dotted lines). The axial extension 220 may prove advantageous in embodiments where the fluid 202 includes aqueous and gaseous fluid components. For instance, the axial extension 220 creates an area of lower fluid velocity where the outer shroud 206b fails to extend longitudinally. Such an area of lower fluid velocity near the inner wall of the work string 126 may help draw the aqueous and gaseous fluid components into the channel 212 at substantially the same flow rate. Once the fluid 202 begins to proceed within the channel 212, the aqueous component becomes trapped within the channel 212 as a result of the back pressure generated within the work string 126. As a result, the aqueous component is forced to flow within the channel 212 and eventually exits at the flow port(s) 214. Accordingly, the axial extension 220 may be configured to balance the injection of aqueous and gaseous components of the fluid 202 during injection operations.
In some embodiments, the axial extension 220 may extend substantially parallel with the remaining portions of the inner and outer shrouds 206a,b, as indicated by the axial extension 220a. In other embodiments, the axial extension 220 may scoop or otherwise bend inward toward the central axis 208, as indicated by the axial extension 220b. In such embodiments, the axial extension 220b may be configured to funnel a greater amount of aqueous component of the fluid 202 into the channel 212. In yet other embodiments, the axial extension 220 may bend away from the central axis 208, as indicated by the axial extension 220c. In such embodiments, the axial extension 220c may be configured to funnel a lesser amount of aqueous component of the fluid 202 into the channel 212. As will be appreciated, the flow of the fluid 202 (and its fluid components) into the channel 212 may be regulated by manipulating the angle of the axial extension 220 (i.e., either toward or away from the central axis 208).
In some embodiments, the flow control device 200 may be arranged on or otherwise attached to the outer diameter of the work string 126, as indicated by the dashed lines 222 (shown only on the top side of the work string 126). In such an embodiment, the inner and outer shrouds 206a,b, shown as dashed lines 224a and 224b, may be coupled to the work string 126 or the coupling 216 and similarly provide a channel 226 for the fluid 202 to be injected into the surrounding subterranean formation 108. The channel 226 may again provide fluid resistance to the flow of the fluid 202 such that injection of the fluid 202 into the formation 108 is slowed or otherwise regulated.
Referring now to
In other embodiments, however, as depicted in
In some embodiments, as depicted in
Referring now to
The flow control device 500 may further include a plurality of dimples 502 being defined on one or both of the inner and outer shrouds 206a,b and otherwise extending into the channel 212. In the illustrated embodiment of
Referring briefly to
The flow path provided in
The flow path provided in
The flow path provided in
The flow path designs shown in
Referring again to
Those skilled in the art will readily recognize the additional structural advantages that the dimples 502 may provide to the flow control device 500. For instance, the dimples 502 may help with manufacturing tolerances by maintaining the inner and outer shrouds 206a,b separated by a fixed distance and otherwise help maintain the shrouds 206a,b in a generally concentric relationship with respect to each other. The dimples 502 may also prove advantageous in preventing collapse of the channel 212.
Referring now to
Unlike the flow control devices 200 and 500, however, the flow control device 700 may include a third and innermost shroud 702 radially offset from the inner shroud 206a toward the central axis 208. A second or inner channel 704 may be defined between the innermost shroud 702 and the inner shroud 206a and otherwise configured to receive the fluid 202 and fluidly communicate with the first or outer channel 212.
The flow control device 700 may further include a plurality of dimples 502 defined or otherwise formed on one, two, or all of the shrouds 206a,b, 702. In the illustrated embodiment, the dimples 502 are defined on the innermost shroud 702 and the outer shroud 206b, and the inner shroud 206a may define a plurality of flow exits 706 that provide fluid communication between the channels 212, 704. It will be appreciated, however, that in some embodiments the inner shroud 206a may also provide or otherwise define dimples 502 in addition to or otherwise in place of the dimples 502 defined by the innermost shroud 702 and the outer shroud 206b.
In some embodiments, the dimples 502 may form fluidic diodes, similar to the vortex diodes 606 described above with reference to
Referring briefly to
The fluid 202 may initially enter the flow control device 700 via the inner channel 704, as depicted in
Referring to
Referring again to
Referring now to
As illustrated, the flow control device 900 may include the inner and outer shrouds 206a,b and a channel 212 may be formed between the two for conveying the fluid 202 to the flow ports 214. Portions of the inner and outer shrouds 206a,b, however, may be nested within each other such that the channel 212 directs the fluid 202 within the channel 212 in a generally downhole direction over a first section 902a, in a generally uphole direction over a second section 902b, and in a generally downhole direction again over a second section 902c. As depicted, each of the inner and outer shrouds 206a,b may be folded or otherwise configured to define the first, second, and third sections 902a,b,c of the channel 212. As a result, the flow control device 900 may be configured to convey the fluid 202 within a narrow channel that lengthens the flow path that the fluid 202 is required to traverse before exiting the work string 126 at the flow ports 214, and thereby advantageously creating a pressure drop.
Referring now to
Unlike the flow control device 200 of
In operation, the porous medium 1002 may be configured to increase the pressure drop of the fluid 202 in the flow control device 1000. By including the porous medium 1002, the fluid 202 may be conveyed through the porous medium 1002 and otherwise required to traverse crenellations and/or a more tortuous flow path before exiting via the flow ports 214. As the fluid 202 courses through the porous medium 1002, the fluid may start to behave like a Darcy flow that exhibits a pressure drop roughly approximated by the following equation:
where k is the permeability of the porous medium 1002.
As will be appreciated, the porous medium 1002 may be included in any of the embodiments described herein, without departing from the scope of the disclosure. For example, the porous medium 1002 may be added to the flow control devices 500 and 700 of
Referring now to
As depicted, the flow control device 1100 may be arranged about the exterior of the extraction work string 130. In other embodiments, however, the flow control device 1100 may be equally arranged on the interior of the work string 130, without departing from the scope of the disclosure. Moreover, it will be appreciated that any of the flow control devices generally described herein may also be arranged about the exterior or interior of either the injection work string 126 or the extraction work string 130, without departing from the scope of the disclosure.
The flow control device 1100 may be operatively coupled to a screen filter 1108 also arranged about the exterior of the work string 130. The screen filter 1108 may be configured to filter or otherwise strain the fluid 1104 prior to being introduced into the flow control device 1100. In particular, the fluid 1104 may be introduced into the flow control device 1100 via a channel 1110 defined between the inner and outer shrouds 1102a,b. Similar to the channel 212 described above, the channel 1110 may create or otherwise define an annular area that generates a flow restriction for the incoming fluid 1104, thereby regulating the fluid flow into the work string 130.
In at least one embodiment, the inner shroud 1102a may be omitted or otherwise replaced functionally by the work string 130 itself. In other words, the work string 130 may functionally serve as the inner shroud 1102a in at least some embodiments, without departing from the scope of the disclosure. Moreover, any of the features or components described herein with respect to any of the flow control devices may equally be applied or otherwise employed in the flow control device 1100 of
Referring now to
The flow control device 1200 may be generally arranged about the exterior of the work string 126 and may include one or more fluid conduits 1204 (two shown) fluidly coupled to the flow ports 214 defined in the work string 126 (or a coupling forming part of the work string 126). In particular, the fluid conduit 1204 may be a tubular length coupled to, attached to, or otherwise inserted at least partially within a corresponding flow port 214 and extending radially a short distance into the interior of the work string 126. The fluid conduits 1204 may be configured to convey the fluid 202 within the work string 126 to the flow port 214 which ejects the fluid 202 into a channel 1206 defined between the inner and outer shrouds 1202a,b. After circulating through the channel 2106, the fluid 202 may exit the flow control device 1200 via one or more flow exits 1208 defined in the outer shroud 2102b and otherwise providing fluid communication between the flow control device 1200 and the surrounding subterranean formation 108.
Referring briefly to
The work string 126 depicted in
Those skilled in the art will readily appreciate the advantages that the flow control device 1200 may provide. For instance, in horizontal steam injection wells, increased amounts of water are typically injected into the surrounding formation 108 near the heel of the well as opposed to the toe such that the toe of the well receives an increased amount of gaseous steam and the surrounding formation 108 is not heat treated efficiently. The exemplary flow control device 1200 may help convey an amount of the aqueous component 1304 (i.e., water) of the fluid 202 toward the toe of the well such that both the aqueous component 1304 and the gaseous component 1302 may be distributed substantially evenly along the length of the work string 126.
As will be appreciated, the depth or height of the fluid conduits 1204 (i.e., the distance the fluid conduit 1204 extends into the interior of the work string 126) may be varied or otherwise configured such that a predetermined amount of the aqueous component 1304 is able to be injected into the formation 108 at the flow control device 1200. In some embodiments, where the work string 126 may have several flow control devices 1200 axially aligned along a length of the work string 126, the depth or height of the fluid conduits 1304 in successive flow control devices 1200 may progressively decrease such that increased amounts of the aqueous component 1304 may be able to be injected into the formation 108 as the flow of the fluid 202 progresses in the downhole direction 204 (
Referring now to
Similar to the flow control device 1200 of
Therefore, the disclosed systems and methods are 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 teachings of the present disclosure may 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 may be altered, combined, or modified and all such variations are considered within the scope and spirit of the present disclosure. The systems and methods illustratively disclosed herein may suitably be practiced in the absence of any element that is not specifically disclosed herein and/or any optional element disclosed herein. While compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. All numbers and ranges disclosed above may vary by some amount. 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,” or, equivalently, “from approximately a-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 or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.
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Number | Date | Country | |
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Parent | 14234161 | US | |
Child | 15040392 | US |