Patent Grant
10180059
This disclosure relates generally to a telemetry tool with a fluid pressure pulse generator, such as a mud pulse telemetry measurement-while-drilling (“MWD”) tool.
The recovery of hydrocarbons from subterranean zones relies on the process of drilling wellbores. The process includes drilling equipment situated at surface, and a drill string extending from the surface equipment to a below-surface formation or subterranean zone of interest. The terminal end of the drill string includes a drill bit for drilling (or extending) the wellbore. The process also involves a drilling fluid system, which in most cases uses a drilling “mud” that is pumped through the inside of piping of the drill string to cool and lubricate the drill bit. The mud exits the drill string via the drill bit and returns to surface carrying rock cuttings produced by the drilling operation. The mud also helps control bottom hole pressure and prevent hydrocarbon influx from the formation into the wellbore, which can potentially cause a blow out at surface.
Directional drilling is the process of steering a well from vertical to intersect a target endpoint or follow a prescribed path. At the terminal end of the drill string is a bottom-hole-assembly (“BHA”) which generally comprises: 1) the drill bit; 2) a steerable downhole mud motor of a rotary steerable system; 3) sensors of survey equipment used in logging-while-drilling (“LWD”) and/or measurement-while-drilling (“MWD”) to evaluate downhole conditions as drilling progresses; 4) means for telemetering data to surface; and 5) other control equipment such as stabilizers or heavy weight drill collars. The BHA is conveyed into the wellbore by a string of metallic tubulars (i.e. drill pipe). MWD equipment is used to provide downhole sensor and status information to surface while drilling in a near real-time mode. This information is used by a rig crew to make decisions about controlling and steering the well to optimize the drilling speed and trajectory based on numerous factors, including lease boundaries, existing wells, formation properties, and hydrocarbon size and location. The rig crew can make intentional deviations from the planned wellbore path as necessary based on the information gathered from the downhole sensors during the drilling process. The ability to obtain real-time MWD data allows for a relatively more economical and more efficient drilling operation.
One type of downhole MWD telemetry known as mud pulse telemetry involves creating pressure waves (“pulses”) in the drilling mud circulating through the drill string. Mud is circulated from surface to downhole using positive displacement pumps. The resulting flow rate of mud is typically constant. The pressure pulses are achieved by changing the flow area and/or path of the drilling fluid as it passes the MWD tool in a timed, coded sequence, thereby creating pressure differentials in the drilling fluid. The pressure differentials or pulses may be either negative pulses or positive pulses. Valves that open and close a bypass stream from inside the drill pipe to the wellbore annulus create a negative pressure pulse. All negative pulsing valves need a high differential pressure below the valve to create a sufficient pressure drop when the valve is open, but this results in the negative valves being more prone to washing. With each actuation, the valve hits against the valve seat and needs to ensure it completely closes the bypass; the impact can lead to mechanical and abrasive wear and failure. Valves that use a controlled restriction within the circulating mud stream create a positive pressure pulse. Pulse frequency is typically governed by pulse generator motor speed changes. The pulse generator motor requires electrical connectivity with the other elements of the MWD probe.
One type of valve mechanism used to create mud pulses is a rotor and stator combination where a rotor can be rotated relative to the fixed stator between an open flow position where there is no restriction of mud flowing through the valve and no pulse is generated, and a restricted flow position where there is restriction of mud flowing through the valve and a pressure pulse is generated.
According to a first aspect, there is provided a telemetry tool comprising: (a) a pulser assembly comprising a housing and a driveshaft extending out of an opening in the housing; (b) a primary seal surrounding and sealing against the driveshaft to seal the opening in the housing; (c) a fluid pressure pulse generator comprising a stator with a bore therethrough configured to fixedly attach to the housing or to a drill collar surrounding the fluid pressure pulse generator, and a rotor fixedly attached to the driveshaft, wherein the driveshaft and rotor are rotatable relative to the fixed stator; and (d) a secondary seal seated in the stator bore, the secondary seal surrounding and sealing against a portion of the driveshaft extended out of the housing or a portion of the rotor.
An internal surface of the stator may comprise an annular shoulder against which the secondary seal abuts. The secondary seal may be a wiper seal. The wiper seal may be a comb wiper seal.
The telemetry tool may further comprise a retainer configured to retain the secondary seal within the stator bore. The retainer may releasably retain the secondary seal within the stator bore.
The rotor may comprise a rotor body fixedly attached to the driveshaft and at least a portion of the rotor body may be received within the stator bore. The secondary seal may surround and seal against the rotor body or the secondary seal may surround and seal against the driveshaft.
There may be a fluid flow channel between adjacent longitudinal surfaces of the rotor body and the stator and the fluid flow channel may define at least a portion of a tortuous flow path for drilling fluid which flows from external the fluid pressure pulse generator, past the secondary seal to the primary seal when the telemetry tool is positioned downhole. The tortuous flow path may include at least one change in direction. The tortuous flow path may comprise at least one restricted point and at least one expansion zone, whereby the cross sectional area of the restricted point may be less than the cross sectional area of the expansion zone. An entrance to the fluid flow channel may be downhole relative to the primary seal or an entrance to the fluid flow channel may be uphole relative to the primary seal.
The stator may comprise a stator body with the stator bore therethrough and a plurality of radially extending stator projections spaced around the stator body whereby spaced stator projections define stator flow channels therebetween. A plurality of radially extending rotor projections may be spaced around the rotor body. The stator projections may be positioned between the rotor projections and the housing. The rotor projections may be axially adjacent and rotatable relative to the stator projections such that the rotor projections move in and out of fluid communication with the stator flow channels to create fluid pressure pulses in drilling fluid flowing through the stator flow channels.
According to another aspect, there is provided a telemetry tool comprising: (a) a pulser assembly comprising a housing and a driveshaft extending out of an opening in the housing; (b) a seal surrounding and sealing against the driveshaft to seal the opening in the housing; and (c) a fluid pressure pulse generator comprising a stator with a bore therethrough fixedly attached to the housing and a rotor comprising a rotor body fixedly attached to the driveshaft. At least a portion of the rotor body is received within the stator bore, and the driveshaft and rotor are rotatable relative to the fixed stator. A fluid flow channel extends between adjacent longitudinal surfaces of the rotor body and the stator and the fluid flow channel defines at least a portion of a tortuous flow path for drilling fluid which flows from external the fluid pressure pulse generator to the seal when the telemetry tool is positioned downhole.
The tortuous flow path may include at least one change in direction. The tortuous flow path may comprise at least one restricted point and at least one expansion zone, whereby the cross sectional area of the restricted point may be less than the cross sectional area of the expansion zone.
An entrance to the fluid flow channel may be downhole relative to the seal or an entrance to the fluid flow channel may be uphole relative to the seal.
The stator may comprise a stator body with the stator bore therethrough and a plurality of radially extending stator projections spaced around the stator body whereby spaced stator projections define stator flow channels therebetween. A plurality of radially extending rotor projections may be spaced around the rotor body. The stator projections may be positioned between the rotor projections and the housing. The rotor projections may be axially adjacent and rotatable relative to the stator projections such that the rotor projections move in and out of fluid communication with the stator flow channels to create fluid pressure pulses in the drilling fluid flowing through the stator flow channels.
This summary does not necessarily describe the entire scope of all aspects. Other aspects, features and advantages will be apparent to those of ordinary skill in the art upon review of the following description of specific embodiments.
Like numerals refer to like parts throughout the several views of the drawings.
The following description and drawings are illustrative and are not to be construed as limiting. Numerous specific details are described to provide a thorough understanding of the disclosure. However, in certain instances, well-known or conventional details are not described in order to avoid obscuring the description. References to one or an embodiment in the present disclosure can be, but are not necessarily, references to the same embodiment; and, such references are intended to refer to at least one of the embodiments.
Reference in this specification to “one embodiment” or “an embodiment” means that a particular feature, structure, or characteristic described in connection with the embodiment is included in at least one embodiment of the-disclosure. The appearances of the phrase “in one embodiment” in various places in the specification are not necessarily all referring to the same embodiment, nor are separate or alternative embodiments mutually exclusive of other embodiments. Moreover, various features are described which may be exhibited by some embodiments and not by others. Similarly, various requirements are described which may be requirements for some embodiments but not for other embodiments.
The terms used in this specification generally have their ordinary meanings in the art, within the context of the disclosure, and in the specific context where each term is used. Certain terms that are used to describe the disclosure are discussed below, or elsewhere in the specification, to provide additional guidance to one of skill in the art regarding the description of the disclosure. For convenience, certain terms may be highlighted, for example using italics and/or quotation marks. The use of any such highlighting has no influence on the scope and meaning of a term; the scope and meaning of a term is the same, in the same context, whether or not it is highlighted.
It will be appreciated that the same thing can be said in more than one way. Consequently, alternative language and synonyms may be used for any one or more of the terms discussed herein. No special significance is to be placed upon whether or not a term is elaborated or discussed herein. Synonyms for certain terms are provided. A recital of one or more synonyms does not exclude the use of other synonyms. The use of examples anywhere in this specification including examples of any terms discussed herein is illustrative only, and is not intended to further limit the scope and meaning of the disclosure or of any exemplified term. Likewise, the disclosure is not limited to various embodiments given in this specification.
Without intent to further limit the scope of the disclosure, examples of instruments, apparatus, methods and their related results according to the embodiments of the present disclosure are given below. Note that titles or subtitles may be used in the examples for convenience of a reader, which in no way should limit the scope of the disclosure. Unless otherwise defined, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this disclosure pertains. In the case of conflict, the present document, including definitions, will control.
It will be appreciated that terms such as “front,” “back,” “top,” “bottom,” “side,” “short,” “long,” “up,” “down,” “aft,” “forward,” “inboard,” “outboard” and “below” used herein are merely for ease of description and refer to the orientation of the components as shown in the figures. It should be understood that any orientation of the components described herein is within the scope of the present invention.
Directional terms such as “uphole” and “downhole” are used in the following description for the purpose of providing relative reference only, and are not intended to suggest any limitations on how any apparatus is to be positioned during use, or to be mounted in an assembly or relative to an environment.
The embodiments described herein generally relate to a telemetry tool with a fluid pressure pulse generator that can generate fluid pressure pulses. The telemetry tool may be used for mud pulse (“MP”) telemetry used in downhole drilling, wherein a drilling fluid or mud (herein referred to as “mud”) is used to transmit telemetry pulses to surface. The telemetry tool may alternatively be used in other methods where it is necessary to generate a fluid pressure pulse. The fluid pressure pulse generator comprises a stator and a rotor. The stator may be fixed to a pulser assembly of the telemetry tool or to a drill collar housing the telemetry tool, and the rotor is fixed to a driveshaft extending from the pulser assembly. The driveshaft and rotor rotate relative to the fixed stator to generate pressure pulses in mud flowing through the fluid pressure pulse generator.
Referring to the drawings and specifically to
Referring to
The pulser assembly 26 is fixed to the drill collar 27 with an annular channel 55 therebetween and mud flows along the annular channel 55 when the MWD tool 20 is downhole. The pulser assembly 26 comprises pulser assembly housing 49 enclosing a motor subassembly and an electronics subassembly 28 electronically coupled together but fluidly separated by a feed-through connector (not shown). The motor subassembly includes a motor and gearbox subassembly 23, a driveshaft 24 coupled to the motor and gearbox subassembly 23, and a pressure compensation device 48. The fluid pressure pulse generator 30 comprises a stator and a rotor. The stator comprises a stator body 41 with a bore therethrough and stator projections 42 radially extending around the downhole end of the stator body 41. The rotor comprises a generally cylindrical rotor body 69 with a central bore therethrough and a plurality of radially extending projections 62 at the downhole end thereof.
The stator body 41 comprises a cylindrical section at the uphole end and a generally frusto-conical section at the downhole end which tapers longitudinally in the downhole direction. The cylindrical section of stator body 41 is coupled with the pulser assembly housing 49. More specifically, a jam ring 58 threaded on stator body 41 is threaded onto pulser assembly housing 49. Once the stator is positioned correctly, the stator is held in place and the jam ring 58 is backed off and torqued against the stator body 41 holding it in place.
The rotor body 69 is received in the downhole end of the bore through the stator body 41 and a downhole portion 24a of the driveshaft 24 is received in the uphole end of the bore through the rotor body 69. A coupling key 35 extends through downhole driveshaft portion 24a and is received in a coupling key receptacle (not shown) at the uphole end of the rotor body 69 to couple the driveshaft 24 with the rotor body 69. In alternative embodiments the rotor body 69 may not have a bore therethrough which receives the driveshaft portion 24a, and alternative means of coupling the rotor body 69 to the driveshaft 24 may be used as would be known to a person skilled in the art.
A rotor cap comprising a cap body 91 and a cap shaft 92 is positioned at the downhole end of the fluid pressure pulse generator 30. The cap shaft 92 is received in the downhole end of the bore through the rotor body 69 and threads onto downhole driveshaft portion 24a to lock (torque) the rotor to the driveshaft 24. The cap body 91 includes a hexagonal shaped opening 93 dimensioned to receive a hexagonal Allen key which is used to torque the rotor to the driveshaft 24. The rotor cap therefore releasably couples the rotor to the driveshaft 24 so that the rotor can be easily removed and repaired or replaced if necessary using the Allen key. In alternative embodiments, the rotor cap may not be present.
Rotation of the driveshaft 24 by the motor and gearbox subassembly 23 rotates the rotor relative to the fixed stator. The electronics subassembly 28 includes downhole sensors, control electronics, and other components required by the MWD tool 20 to determine direction and inclination information and to take measurements of drilling conditions, to encode this telemetry data using one or more known modulation techniques into a carrier wave, and to send motor control signals to the motor and gearbox subassembly 23 to rotate the driveshaft 24 and rotor in a controlled pattern to generate pressure pulses 6 representing the carrier wave for transmission to surface as described above with reference to
The driveshaft 24 extends out of pulser assembly housing 49 through an opening in the pulser assembly housing 49. The motor subassembly is filled with a lubricating liquid such as hydraulic oil or silicon oil and this lubricating liquid is fluidly separated from mud flowing along the annular channel 55 by an annular primary seal 54. Primary seal 54 surrounds and seals against the driveshaft 24 or a sealing cylinder 25 (shown in
Mud pumped from the surface by pump 2 flows along annular channel 55 between the outer surface of pulser assembly housing 49 and the inner surface of drill collar 27. When the mud reaches the fluid pressure pulse generator 30 it flows along an annular channel 56 provided between the external surface of the stator body 41 and the internal surface of the flow bypass sleeve 70 and hits the stator projections 42 where the mud is channeled through stator flow channels defined by adjacently positioned stator projections 42. Some mud also flows along bypass channels provided by the flow bypass sleeve 70. The rotor projections 62 are axially adjacent and downhole relative to the stator projections 42 and rotate in and out of fluid communication with the stator flow channels to generate pressure pulses 6 in mud flowing through the fluid pressure pulse generator 30.
The external dimensions of flow bypass sleeve 70 may be adapted to fit any sized drill collar 27. It is therefore possible to use a one size fits all fluid pressure pulse generator 30 with multiple sized flow bypass sleeves 70 with various different external circumferences that are dimensioned to fit different sized drill collars 27. Each of the multiple sized flow bypass sleeves 70 may have the same internal dimensions to receive the one size fits all fluid pressure pulse generator 30 but different external dimensions to fit the different sized drill collars 27. In larger diameter drill collars 27 the volume of mud flowing through the drill collar 27 will generally be greater than the volume of mud flowing through smaller diameter drill collars 27, however the bypass channels of the flow bypass sleeve 70 may be dimensioned to accommodate this greater volume of mud. The bypass channels of the different sized flow bypass sleeves 70 may therefore be dimensioned such that the volume of mud flowing through the one size fits all fluid pressure pulse generator 30 fitted within any sized drill collar 27 is within an optimal range for generation of pressure pulses 6 which can be detected at the surface without excessive pressure build up. It may therefore be possible to control the flow rate of mud through the fluid pressure pulse generator 30 using different flow bypass sleeves 70 rather than having to fit different sized fluid pressure pulse generators 30 to the pulser assembly 26.
In alternative embodiments (not shown), the fluid pressure pulse generator 30 may be present in the drill collar 27 without the flow bypass sleeve 70. In these alternative embodiments, the stator projections 42 and rotor projections 62 may radially extend to have an external diameter that is greater than the external diameter of the cylindrical section of the stator body 41, such that mud following along annular channel 55 impinges on the stator projections 42 and is directed through the stator flow channels. The stator projections 42 and rotor projections 62 may radially extend to meet the internal surface of the drill collar 27. There may be a small gap between the rotor projections 62 and the internal surface of the drill collar 27 to allow rotation of the rotor projections 62. The innovative aspects apply equally in embodiments such as these.
Referring to
The driveshaft 24 is received in the uphole end of the bore through the stator body 141. The downhole end of pulser assembly housing 49 is received in cavities 146 and 147 in the stator body 141 and jam ring 58 is backed off and torqued against the stator body 141 holding it in place as described above in more detail with reference to
As shown in
When the MWD tool 20 is downhole, mud flows through the stator flow channels 143 and a small amount of mud may enter the fluid pressure pulse generator 30 between the downhole end of the stator body 141 and the rotor body 69. The mud flows along a mud flow path represented by arrows A in
Referring now to
In both embodiments of the stator 140, 240, the secondary seal 150 may reduce the amount of mud, grit and debris impinging on the primary seal 54 which could otherwise cause wear or damage to primary seal 54. Secondary seal 150 may therefore beneficially extend the life of primary seal 54 and reduce the likelihood of mud entering the pulser assembly 26 and lubrication liquid leaving the pulser assembly 26. As the mud impinges on the secondary seal 150 before it reaches the primary seal 54, the secondary seal 150 may become worn or damaged over time through exposure to mud, however, the secondary seal 150 may be removed and replaced if needed as described above in more detail.
The fluid pressure pulse generator 30 may be configured to provide a tortuous flow path for mud which flows between adjacent longitudinal surfaces of the stator and the rotor to the primary seal 54. The tortuous flow path may change direction one or more times and may include one or more restriction points and expansion zones which may reduce the momentum of mud flow and may therefore reduce the velocity of mud reaching the primary seal 54.
An exemplary tortuous flow path is represented by arrows A in
Frictional losses, known as Moody-type friction losses, occur as the mud flows along the flow path reducing the energy of mud flow. In addition, the tortuous nature of the flow path may provide additional minor energy losses to the mud flowing through the flow path. The energy losses resulting from the tortuous flow path can be quantified by a dimensionless loss coefficient K which is usually given as a ratio of the head loss
to the velocity
through the area of concern:
The total head loss Δhtot of a system can be determined by separately summing all losses, namely frictional hf and minor hm losses as follows:
Δhtot=hf+Σhm
Calculation of these energy losses is generally known in the art.
The energy losses from frictional losses and from the tortuous nature of the mud flow path typically result in essentially stagnant or slow moving mud reaching the primary seal 54, which may beneficially reduce wear of the primary seal 54. The sealing cylinder 25, primary seal 54 and other parts of the primary seal assembly (for example, the seal retention washer 155 and washer retaining ring 156) are strategically positioned near the end of the tortuous flow path where the velocity of flow of mud is reduced instead of being positioned in the fast flowing mud at the beginning of the tortuous flow path. The sealing cylinder 25, primary seal 54 and other parts of the seal assembly are also positioned uphole of the entry point of mud into the MWD tool 20, therefore the mud must flow uphole against gravity and in the opposite direction of the general mud flow in order to reach these components. In alternative embodiments the entry point of mud into the MWD tool 20 may be downhole relative to the sealing cylinder 25, primary seal 54 and other parts of the seal assembly, however, as mud flows past the entry point venturi forces may be created that suck mud out of the tortuous flow path. As a result wear of the primary sealing cylinder 25, primary seal 54 and other parts of the primary seal assembly may be reduced, thereby increasing their life.
In alternative embodiments (not shown) the fluid pressure pulse generator may be any rotor/stator type fluid pressure pulse generator where the stator includes flow channels or orifices through which mud flows and the rotor rotates relative to the fixed stator to move in and out of fluid communication with the flow channels or orifices to generate pressure pulses 6. The fluid pressure pulse generator may be positioned at either the downhole or uphole end of the MWD tool 20.
Referring now to
During assembly of the first and second embodiments of the flow bypass sleeve 170, 270, the uphole and downhole body portions 171a,b and 271a,b are axially aligned and a lock down sleeve 81 is slid over the downhole end of the downhole body portion 171b, 271b and moved towards the uphole body portion 171a, 271b until the uphole edge of the lock down sleeve 81 abuts an annular shoulder on the external surface of uphole body portion 171a, 271a. The assembled flow bypass sleeve 170, 270 can then be inserted into the downhole end of drill collar 27. The external surface of uphole body portion 171a, 271a includes an annular shoulder 180, 280 near the uphole end of uphole body portion 171a, 271a which abuts a downhole shoulder of a keying ring (not shown) that is press fitted into the drill collar 27. A threaded ring (not shown) fixes the flow bypass sleeve 170, 270 within the drill collar 27. A groove 185, 285 on the external surface of the uphole body portion 171a, 271a receives an o-ring (not shown) and a rubber back-up ring (not shown) such as a parbak to help seat the flow bypass sleeve 170, 270 and reduce fluid leakage between the flow bypass sleeve 170, 270 and the drill collar 27. In alternative embodiments the flow bypass sleeve 170, 270 may be assembled or fitted within the drill collar 27 using alternative fittings as would be known to a person of skill in the art.
In the first embodiment of the flow bypass sleeve 170, the internal surface of the uphole body portion 171a includes a plurality of longitudinal extending grooves 173. Grooves 173 are equidistantly spaced around the internal surface of the uphole body portion 171a. Internal walls 174 in-between each groove 173 align with the stator projections 42 of the fluid pressure pulse generator 30, and the grooves 173 align with the stator flow channels. The flow bypass sleeve 170 may be precisely located with respect to the drill collar 27 using a keying notch (not shown) to ensure correct alignment of the stator projections 42 with the internal walls 174. The rotor projections 62 rotate relative to the flow bypass sleeve 170 as the rotor moves between the open flow position and the restricted flow position as described above in more detail.
In the second embodiment of the flow bypass sleeve 270 a plurality of apertures 275 extend longitudinally through the uphole body portion 271a. The apertures 275 are circular and equidistantly spaced around uphole body portion 271a. The internal surface of the downhole body portion 271b includes a plurality of spaced grooves 278 which align with the apertures 275 in the assembled flow bypass sleeve 270 (shown in
While particular embodiments have been described in the foregoing, it is to be understood that other embodiments are possible and are intended to be included herein. It will be clear to any person skilled in the art that modifications of and adjustments to the foregoing embodiments, not shown, are possible.
Unless the context clearly requires otherwise, throughout the description and the claims, the words “comprise,” “comprising,” and the like are to be construed in an inclusive sense, as opposed to an exclusive or exhaustive sense; that is to say, in the sense of “including, but not limited to.” As used herein, the terms “connected,” “coupled,” or any variant thereof, means any connection or coupling, either direct or indirect, between two or more elements; the coupling of connection between the elements can be physical, logical, or a combination thereof. Additionally, the words “herein,” “above,” “below,” and words of similar import, when used in this application, shall refer to this application as a whole and not to any particular portions of this application. Where the context permits, words in the above Detailed Description of the Preferred Embodiments using the singular or plural number may also include the plural or singular number respectively. The word “or” in reference to a list of two or more items, covers all of the following interpretations of the word: any of the items in the list, all of the items in the list, and any combination of the items in the list.
The above-detailed description of embodiments of the disclosure is not intended to be exhaustive or to limit the teachings to the precise form disclosed above. While specific embodiments of and examples for the disclosure are described above for illustrative purposes, various equivalent modifications are possible within the scope of the disclosure, as those skilled in the relevant art will recognize. Further, any specific numbers noted herein are only examples: alternative implementations may employ differing values, measurements or ranges.
The teachings of the disclosure provided herein can be applied to other systems, not necessarily the system described above. The elements and acts of the various embodiments described above can be combined to provide further embodiments. Any measurements described or used herein are merely exemplary and not a limitation on the present invention. Other measurements can be used.
Any patents and applications and other references noted above, including any that may be listed in accompanying filing papers, are incorporated herein by reference in their entirety. Aspects of the disclosure can be modified, if necessary, to employ the systems, functions, and concepts of the various references described above to provide yet further embodiments of the disclosure.
These and other changes can be made to the disclosure in light of the above Detailed Description of the Preferred Embodiments. While the above description describes certain embodiments of the disclosure, and describes the best mode contemplated, no matter how detailed the above appears in text, the teachings can be practiced in many ways. Details of the system may vary considerably in its implementation details, while still being encompassed by the subject matter disclosed herein. As noted above, particular terminology used when describing certain features or aspects of the disclosure should not be taken to imply that the terminology is being redefined herein to be restricted to any specific characteristics, features or aspects of the disclosure with which that terminology is associated. In general, the terms used in the following claims should not be construed to limit the disclosures to the specific embodiments disclosed in the specification unless the above Detailed Description of the Preferred Embodiments section explicitly defines such terms. Accordingly, the actual scope of the disclosure encompasses not only the disclosed embodiments, but also all equivalent ways of practicing or implementing the disclosure under the claims.
While certain aspects of the disclosure are presented below in certain claim forms, the inventors contemplate the various aspects of the disclosure in any number of claim forms. For example, while only one aspect of the disclosure is recited as a means-plus-function claim under 35 U.S.C. § 112, ¶6, other aspects may likewise be embodied as a means-plus-function claim, or in other forms, such as being embodied in a computer-readable medium. (Any claims intended to be treated under 35 U.S.C. § 112, ¶6 will include the words “means for.”) Accordingly, the applicant reserves the right to add additional claims after filing the application to pursue such additional claim forms for other aspects of the disclosure.
Although exemplary embodiments of the invention have been shown and described, it is to be understood that all the terms used herein are descriptive rather than limiting, and that many changes, modifications, and substitutions may be made by one having ordinary skill in the art without departing from the spirit and scope of the invention.
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