Not applicable.
Not applicable.
1. Field Of The Invention
The inventions described herein relate generally to hydrocarbon well completion systems, and more particularly to a system for completing multiple production zones in a single trip.
2. Description of the Related Art
One of the single biggest costs associated with completing a subterranean hydrocarbon well, such as a sub sea well, is the time that it takes to remove a tool or other well equipment from the well bore. Depending on well depth, tripping time may account for the majority of well completion costs. For a well having multiple production zones, tripping time is compounded if each zone must be completed separately from the other zones. It is desirable, therefore, to reduce the number of trips necessary to complete the two or more production zones in a multi-zone well.
U.S. Pat. No. 6,464,006 is entitled Single Trip, Multiple Zone Isolation, Well Fracturing System and discloses a device and method for “the completion of multiple production zones in a single well bore with a single downhole trip.”
U.S. Pat. No. 4,401,158 is entitled One Trip Multi-Zone Gravel Packing Apparatus and discloses a device and method for “gravel packing a plurality of zones within a subterranean well . . . whereby each successive zone may be gravel packed by successively moving the” equipment.
The inventions disclosed and taught herein are directed to improved systems and methods for completing one or more production zones in a subterranean well during a single trip.
In one implementation of the invention, a method of completing two or more production zones with an improved well completion system in a single downhole trip is provided and may comprise assembling a plurality of production zone assemblies so that each assembly comprises a production screen assembly having at least one production screen valve. Locating a completion tool assembly in a lowermost production zone assembly, wherein the tool assembly may have a deactivated opening tool that is activated after the tool has passed below a last production screen valve. Assembling a production packer assembly comprising a setting tool to the production zone assemblies to form a completion assembly. Running the completion assembly and tool assembly into position established by a sump packer. Cycling the tool assembly within a production zone assembly to index the completion system to a formation treatment condition and treating the production zone.
In another implementation of the invention, a single trip well completion system is provided that may comprise: a completion assembly comprising a plurality of production zone assemblies corresponding to formation zones in the well. A completion tool system adapted to operate within the completion assembly. An automatic completion system locating assembly operable between a production assembly and the tool system to cycle the completion system between a plurality of operating conditions and a tool activation assembly disposed in a lowermost production zone assembly to activate a deactivated opening or closing tool on the tool system.
a illustrates a cross-sectional side view of a first inverted seal system for use with the improved well completion system
b illustrates a cross-sectional side view of a safety shear out system for use with the improved well completion system.
a and 6b illustrate a cross-sectional side view of alternate crossover subassembly in a service tool assembly and a formation access valve in a production zone assembly for use with the improved well completion system.
a illustrates a cross-sectional side view of a closing tool assembly having a circulation valve, associated with a service tool assembly for use with the improved well completion system.
b illustrates a cross-sectional side view of an alternate closing tool assembly associated with a service tool assembly for use with the improved well completion system.
a and 11b illustrate cross-sectional side views of alternate secondary indexing collet associated with a service tool assembly for use with the improved well completion system.
c illustrates cross-sectional side view of a deactivated opening tool associated with a service tool assembly for use with the improved well completion system.
The Figures described above and the written description of specific structures and processes below are not intended to limit the scope of what Applicants have invented or the scope of protection for those inventions. The Figures and written description are provided to teach any person skilled in the art to make and use the inventions for which patent protection is sought. Those skilled in the art will appreciate that not all features of a commercial implementation of the inventions are described or shown for the sake of clarity and understanding. Persons of skill in this art also appreciate that the development of an actual commercial embodiment incorporating aspects of the present inventions will require numerous implementation-specific decisions to achieve the developer's ultimate goal for the commercial embodiment. Such implementation-specific decisions may include, and likely are not limited to, compliance with system-related, business-related, government-related and other constraints, which may vary by specific implementation, location and from time to time. While a developer's efforts might be complex and time-consuming in an absolute sense, such efforts would be, nevertheless, a routine undertaking for those of skill this art having benefit of this disclosure. The inventions disclosed and taught herein are susceptible to numerous and various modifications and alternative forms.
The use of a singular term is not intended as limiting of the number of items. Also, the use of relative terms, such as, but not limited to, “top,” “bottom,” “left,” “right,” “upper,” “lower,” “down,” “up,” “side,” and the like are used herein for clarity in reference to the Figures and are not intended to limit the invention or the embodiments that come within the scope of the appended claims. “Uphole” generally refers to the direction in which equipment is tripped out the well. “Downhole” generally refers to the direction that is the opposite of uphole for a particular well. The improved well completion systems disclosed and taught herein may be used in vertical wells, deviated wells and/or horizontal wells.
Applicants have created an improved system for completing in a single downhole trip one or more hydrocarbon bearing formations (production zones) traversed by a well bore. The improved well completion system accomplishes multiple tasks in a single downhole trip and provides for well bore operations, such as, but not limited to, formation fracturing and gravel packing operations, squeeze and circulating conditions, and real time annulus pressure monitoring, all with no production zone length restriction. The improved well completion system may comprise a completion assembly comprising two or more production zone assemblies and a production packer, and a service tool assembly.
The improved well completion system may be pressure tested before pumping operations begin. Preferably, a wash pipe is not required during formation treatments, such as, but not limited to, fracturing or gravel packing operations. Positive, selective production zone isolation is provided during completion, stimulation, and production operations and the improved well completion system provides for fresh isolation seals for each zone. The improved well completion system provides physical indications of some or all system positions or conditions, with optional hydraulic verification as well.
Conventional mechanical sleeve valves may access hydrocarbon production from one or more selected production zones. Additionally, multi-zone production control systems, such as, but not limited to, those disclosed in commonly owned U.S. Pat. No. 6,397,949, U.S. Pat. No. 6,722,440, and pending application Ser. Nos. 10/364,941 and 10/788,833, may be incorporated with the improved completion system to allow non-commingled production from two or more zones that were completed in a single downhole trip.
In general, once the well bore has been established and is ready for completion, a conventional or proprietary sump packer may be run into the well bore to a predetermined depth and set in place. Typically, the sump packer will be used to provide a reference point for subsequent well operations, such as, but not limited to, zone perforation and completion. If desired, conventional or proprietary perforating operations may be employed to sequentially or simultaneously perforate one or more of the production zones of interest traversed by the well bore. The improved well completion system imposes no restrictions on the length of a production zone or on the spacing between zones. If necessary, fluid loss control systems, such as, but not limited to, but not limited to pills, may be used to control the perforated zones. Once the production zones of interest have been established, an improved completion system utilizing one or more aspects of the present inventions may be assembled.
An improved completion system may comprise a completion assembly, which may comprise a bottom assembly, two or more production zone assemblies and a production packer. The completion assembly may be assembled and hung off the rig floor. A bottom assembly may comprise a indicating collet assembly for indicating position off of the sump packer; a pressure test assembly allowing internal pressurization for integrity testing purposes, and a tool activating assembly to activate a deactivated tool assembly, if used. The two or more production zone assemblies may comprise a production screen assembly with internal production valves, such as, but not limited to, mechanical sleeves for sealing and unsealing production screen ports, a circulation valve closing profile, formation access valve assembly, a seal system, an isolation packer assembly and an automatic system locator assembly. The bottom assembly may be coupled to a first or lower production zone assembly, both of which may be hung off the rig floor and pressure tested during make up.
Each successive production zone assembly, if used, may comprise substantially the same components as the first or lower production zone assembly, or the successive production zone assemblies may comprise components different that than the first production zone assembly or other production zone assemblies, as required by the particulars of the well and production zones. Preferably, each production zone assembly comprises a seal system and an automatic system locating assembly. As each successive production zone assembly is made up, the completion assembly is hung off the rig floor and pressure tested for integrity. All system valves, such as, but not limited to, production valves, may be, and preferably are, run in the closed position to provide positive, pre-treatment zonal isolation. Once the desired number of production zone assemblies are made up and hung off the rig floor, a service tool assembly may be run into the completion assembly.
A service tool assembly for use with the improved well completion system may comprise a nosepiece, an opening tool assembly, a secondary indexing collet assembly, a closing tool assembly including a circulation valve, a cross-over assembly with hardened seal surfaces and a primary indexing shoulder, an automatic system locating profile and a hydraulic setting tool. For completion assemblies that utilize the typical down-to-open convention for production valves, the opening tool preferably will be located distally of the closing tool. The service tool assembly may comprise hardened seal surfaces, such as slick joints, that cooperate with the seal systems in each production zone assembly to provide a positive sealing system for each zone to be completed.
Prior to final improved completion system make-up, the service tool assembly may be run into the completion assembly and positioned such that the opening tool is located below the lowermost production sleeve in the first or lowermost production zone assembly. Once the tool assembly has been positioned within the lowermost production assembly, a completion system pressure test may be run to verify overall system integrity, including that all system valves are closed. To ensure that running the service tool assembly through the production zone assemblies has not unintentionally opened one or more down-to-open valves, the opening tool may be initially deactivated, such as during run in. In a preferred embodiment, once the service tool assembly has been positioned with the completion assembly, the opening tool may be activated by hydraulic pressure. Alternately, positioning the service tool with the completion assembly may mechanically activate the opening tool. If desired, a device may be provided to allow for verification that the opening tool has been activated, such as, but not limited to, a mock mechanical sleeve. After pressure integrity testing has been completed, the pressure test sub in the lowermost assembly may be deactivated, such as, but not limited to, by using the nose piece of the tool assembly to removing a sealing device.
An improved well completion system (e.g., comprising two or more production zone assemblies and a service tool assembly) may be run into to the well bore and located in position relative to the sump packer or other well bore artifact. In a preferred embodiment, the lowermost production zone assembly comprises a position indicating system, such as, but not limited to, an indicating collet assembly. For example, once the improved completion system is believed to be correctly positioned relative to the sump packer, the indicating system may provide positive placement identification, such as, but not limited to, by a repeatable lifting or “snap through” load. Once the improved completion system is properly located, with or without the aid of a position indicating system, a production packer may be set according to its design. For example, the production packer may comprise a BJ Services CompSet II HP packer, which may be hydraulically set, such as by dropping a ball or other pressurization device into the completion system and pressuring up against the device. This pressurization may be used to activate the hydraulic setting tool to set the packer, and thereafter release the service tool assembly and work string from the completion assembly (e.g., the production packer).
Once the service tool assembly has been separated from the completion assembly, any pressure-blocking device used to activate the setting tool may be disabled. In the case of the CompSet II HP production packer, additional pressurization against a ball will move the ball out of setting tool activating position and simultaneously uncover the crossover ports in the service tool assembly and trap the ball against unwanted upward travel. Alternately, the ball may comprise polymer glass-filled lightweight ball that may be reversed out of the system, thereby eliminating the need for a “mouse trap” to capture and hold the setting ball.
The service tool assembly may then be moved relative to the completion assembly to position the opening tool above a production valve, such as, but not limited to, a down-to-open production sleeve in the first or lowermost production zone assembly. Once the opening tool is positioned above the production valve, downward movement of the service tool assembly will cause the opening tool to engage a corresponding opening profile on the production valve and open the associated production ports, such as, but not limited to, by moving a production sleeve. Opening of the production ports may be verified hydraulically by pumping down the well bore and into the formation.
The service tool assembly also may be moved adjacent the isolation packer assembly for the lowermost production zone to engage the production assembly's seals with tool assembly's hardened seal surface. Once the seal surface or slick joint is positioned in sealing arrangement, the isolation packer may be set, such as, but not limited to, by pressuring down the work string. Once the pressure integrity of the lowermost isolation packer is established, the tool assembly may be re-positioned so that the opening tool is in position to open (e.g., above) a formation access valve or frac valve in the production zone assembly. The service tool assembly may be repositioned to open the formation access valve and to position the tool assembly for well treatment operations. In a preferred embodiment, each production zone assembly comprises an automatic locating assembly or “autolocator” that may be cycled by the service tool assembly among a plurality of well completion system conditions, such as, but not limited to, “Run-In,” “Set-down” and “Pick-Up.”
In a preferred embodiment, once the service tool assembly cycles the autolocator to the “Set-down” or frac condition, set down weight may be applied to the well completion system to maintain relative position between the service tool assembly and the completion assembly (e.g., to maintain port alignment) during pumping treatments. The improved well completion system may also provide for real time pumping pressures to be monitored through the annulus during pumping operations. The well completion system may be placed in a squeeze position at any time during the pumping operation by simply repositioning the well tool assembly.
A formation fracturing and/or gravel packing operation may be applied by pumping down the work string and into the annulus adjacent the production screen assembly. Once the treatment is completed, the service tool assembly may be repositioned to a reverse position by locating the crossover assembly relative to the reversing seal in the production zone assemblies. Debris from the gravel packing treatment may be reversed out of the completion system by pumping down the tool assembly annulus and taking returns up through the work string. The pressures developed during reversing will not affect formation zones above the zone being completed because such upper zones are fully isolated and their production ports are closed. The tool assembly is once again repositioned so that the end of the tool assembly is above the formation access seal to clear any remaining debris. The formation may be monitored thereafter for pressure build up or fall off.
The tool assembly may be repositioned so that the closing tool is located distal or below the lowermost opened production valve. Upward movement of the tool assembly through the zone causes the closing profile on the closing tool to engage a corresponding profile on the production valve, (e.g., a production sleeve) and causes all production valves to seal off or close their associated production ports, thereby isolating the completed zone. Zone isolation may be verified by surface pressurization.
The service tool assembly may then be repositioned into the zone above the zone just completed. The opening tool may be positioned above or proximal a production sleeve in this zone. The process described above may be repeated for each successive production zone. Once all production zones have been completed, the service tool assembly and work string may be removed from the well bore leaving a completed, fully isolated, multi-zone well. Production of hydrocarbons from any zone may be accomplished by mechanically opening the desired production valves using wire line, coiled tubing or other conventional or proprietary methods. Commingled production from multiple zones may be accomplished by opening production sleeves in multiple zones. A preferred embodiment of the completion system contemplates a selective profile system having four, five, six or more different production sleeve profiles for selective zonal production. For example, specific profiles on the service tool assembly may open and/or close valves in the completion assembly. Other specific profiles associated with coiled tubing tools and/or wire line tools may be used to selectively open and/or close such valves. Also, when coupled with intelligent or interventionless production control systems, such as, but not limited to, those commonly-owned systems referenced above, the improved completion system disclosed herein may provide simultaneous, non-commingled production from multiple zones without mechanical intervention, or a combination of mechanical and hydraulic interventions.
An improved completion system utilizing one or more the present inventions may reduce or eliminate the need to run and/or retrieve packer plugs and/or gravel pack assemblies, and may eliminate multiple perforation runs. Substantial savings in rig time and money, as well as responsible formation management, may be realized by virtue of one or more of the present inventions disclosed and taught with this improved completion system.
A production zone assembly 108 may comprise an automatic locating assembly 106 to locate positively the completion system in its several conditions, such as, but not limited to, a “Frac/Set Down” position, a “Pickup” position, and a “Run-in” position. The automatic locating assembly or “autolocator” 106 preferably comprises a debris barrier, such as, but not limited to, a molded rubber cup positioned above the autolocator 106 and engaging the casing or well bore for preventing or reducing the amount of debris from collecting in the autolocator 106. In addition, a quick union may be interposed between the production packer assembly 102 and the topmost production zone assembly 108 so the completion assembly 100 does not have to be rotated after the tool assembly 200 is positioned therein. Also in each production zone assembly 108, it is preferred to place a shear-out safety joint 109 (e.g.,
A first sealing system 110 is provided for sealing against selected portions of the service tool assembly (
Coupled to the first or lower production zone assembly 108a, is a bottom assembly 104. The bottom assembly 104 may comprise an opening tool activating assembly 122 to activate an opening tool and/or closing tool on the service tool assembly, if such tool or tools have been deactivated. The activating assembly may also provide a positive stop for positioning the service tool assembly (
Turning now to a more detailed description of embodiments and preferred embodiments of the improved completion system,
In the particular embodiment of the autolocator illustrated in
At its proximal end, the inner housing 152 has a floating detent collet 160 comprising a plurality of fingers that are held in place between a shoulder and retaining ring 151. It is preferred that the retaining ring 151 be made from a bearing material, such as bronze. The retaining ring preferably comprises a debris shield to reduce the risk of debris fouling the detent collet assembly 160. The each finger has a profile 162, which corresponds to one or more grooves in the outer housing 150. Preferably, the outer housing 150 has a plurality of detent grooves, which correspond to the various positions or conditions into which the completion system may be placed. For example, detent groove 164 may correspond to a “Run-In” condition, groove 166 may correspond to a “Pick-Up” condition and groove 168 may correspond to a “Frac or Set-down” condition. The detent collet 160 and grooves may be designed for a snap through load of about 1 kip.
As illustrated in
It is preferred that the autolocator assembly 106 also comprises a lockout mechanism 180, such as a sleeve. The lockout sleeve 180 has closing tool profiles 181, 182 so that the closing tool 214 on the completion tool assembly 200 can engage the lockout sleeve 180 to move it relative to the collet assembly 170. When the closing tool assembly 214 engages profile 181, the lockout mechanism 180 may be moved uphole and cause the collet assembly 170 to deflect outwardly. Therefore, the bearing inserts 178, and profiles 176 are moved out of the way and into recess 182.
In the embodiment described in
a illustrates generally a first seal system 110 located adjacent an isolation packer assembly 112. In a preferred embodiment, the first seal system is located above the packer setting port. The seals 190 of the first seal system 110 are preferably molded elastomeric seals 192 on a metal carrier 194, although other sealing technologies, such as, but not limited to, PTFE, PEEK and/or PEKK may be used. The seal system 190 may be described as “inverted” in that the sealing surfaces 192 are exposed to the inside of the production zone assembly 108. As shown in
Also shown in
b illustrates a preferred shear out safety system that may be used with the well completion system. The shear out safety system 600 illustrated in
A preferred embodiment of the shear out safety system is designed to carry about 250,000 pounds during tripping in (as shown in
Applicants prefer that each production zone assembly 108 incorporate a shear out safety system 600. The preferred location of the safety system 600 is between the first sealing system 110 and the autolocator 106. Each product zone assembly may have a shear out safety system 600 that is designed to the same or to a different shear out load, as required or desired by the system design. Thus,
a illustrates formation access valve assembly 114, or frac window, in a production zone assembly 108 and a crossover assembly 212 in a service tool assembly 200. Tool assembly 200 comprises a crossover assembly 212 having a through wall port 242 allowing fluid communication from an inside surface of the tool assembly 200 to an outside tool assembly surface. In a preferred embodiment, the through wall port is formed on an angle of between about 45 to 150 degrees, and more preferably about 120 degrees to the tool centerline, a downhole orientation. The crossover assembly 212 also comprises an internal sleeve 244 having a seat surface 246 adjacent the port 242. In a preferred embodiment, the sealing surface 246 is adapted to seal against a ball or other substantially spherical object that engages the seat 246.
The internal sleeve 244 is slidable relative to the tool assembly 200 and is held in the position shown in
Alternately, and preferably, as shown in
Still further,
Returning to
A formation access valve assembly 260, or frac window, is also illustrated for the production zone assembly 108. The formation access valve assembly 260 comprises a through-wall flow port 262 and a sliding, sealing sleeve 264. The sliding sleeve has a closing profile 266 located adjacent a proximal end and an opening profile (not shown) located adjacent a distal end. Suitable seals are provided so that the port 262 is sealed against fluid flow when the body of the sleeve 264 blocks the port 262. The port 262 is preferably elongated relative to the crossover port 242 so that if autolocator profile 210 on service tool 200 is not engaged in the insert 178 (i.e., groove 176) but rather on top of the insert 178, fluid communication is still achieved between the crossover port 242 and the frac port 262.
a and 6b illustrate the well completion system in the “Run-In” condition in that tool port 242 is not aligned with the packing port 262 and the sliding sleeve 264 has sealed off the packing port 262. In a ‘Frac/Set-down” condition, it will be appreciated the ports 242 and 262 are in substantial alignment and the sliding sleeve 264 no longer seals the port 262.
a illustrates a portion of the service tool assembly 200 comprising a closing tool 290. Closing tool 290 comprises a plurality of collet fingers 292, preferably 6 to 8, spaced about an outer portion of the tool assembly 200. The collet fingers 292 have a closing profile 294 located approximately mid-length, which is adapted to engage a corresponding structure on production screen valves, such as, but not limited to, for example, on sleeves covering ports, to close such valves when desired. The closing tool 290 further comprises a detent 296 that, in the preferred embodiment requires about a 2 kip load to displace the detent in a downhole direction and about 600 lbf. load to displace the detent in an uphole direction Also shown in
b illustrates an alternate embodiment of the closing tool 290. The embodiment shown in
a also illustrates a circulating valve 302 having flow ports 304 and 306. In the “Run-In” position shown in
a illustrates secondary backup autolocator collet assembly 320. Similarly to the primary backup autolocator shoulder, describe with reference to
b illustrates a preferred embodiment of a secondary backup autolocator collet assembly 320. The leftmost drawing shows the assembly 320 in the “Pick-Up” position; the middle drawing shows the assembly 320 in the “Run-In” condition; and the rightmost drawing shows the assembly 320 in the sheared condition. In the “Run-in” condition, the collet is not supported by back-up 321 and is able to deflect out of the way. When the system in the “Pick-Up” condition, the collet 320 is backed-up and is not able to deflect out of the way. The backed-up collet 320 will carry a load dictated by the shear strength of shoulder 333. Shoulder 333 may be set of shear screws, a shear ring or a similar system. In the preferred embodiment, the backed-up collet assembly 320 can carry about 60 ksi. This load carrying capacity is beneficial if debris has fouled the autolocator system 106 and more load is needed to cycle the system. If the autolocator system 106 cannot be cycled by the collet assembly 320 with 60 ksi, the shoulder 333 will shear loose and the collet 320 will once again not be backed up and free deflect at its designed load.
Also shown in
Shown in
As will be recalled from the general discussion of the improved completion system, it is preferred to run the completion tool assembly 200 into the lowermost production assembly 108 while hanging off the rig floor. If the opening tool 330 is not deactivated during this run in, the normally closed production screen valves will be opened as the tool 200 is lowered. After each valve is opened, the operator must reverse direction to use the closing tool 292 to re-close the opened valve. Thus, deactivating the opening tool 330 in this manner saves time, which in turn saves money. The opening tool 330 may be activated when the completion tool assembly 200 engages the opening tool activation assembly 122, or preferably, hydraulically, as discussed below.
To locate the service tool assembly properly in the completion assembly and to activate the opening tool 200, the service tool assembly 220 is lowered into the completion assembly so that the nosepiece 378 contacts the lugs 371 and drives the lugs downward into the recess formed by shoulder 368 allowing the nosepiece to pass by. The service tool assembly 200 continues downhole until nosepiece 378 and specifically portions 377, contact stop collet lugs 351. Further downward movement of the nosepiece 378 against the stop lugs 351 shears the distal base ring 356 free as the sleeve 360 moves downhole relative to the production assembly 108 and compresses spring 362 as shown in the leftmost cross-section of
The service tool assembly is retracted and nosepiece portions 379 contact the underside portion of the stop lugs 351. Further uphole movement causes the opening tool assembly to slide relative to the tool assembly and the opening tool is deactivated by shearing pins 337 at about 4.6 kips. Further uphole movement of the service tool assembly causes the stop lugs to displace into recess 355 and allow the nosepiece to pass by. The nosepiece then contacts the underside of ring lugs 371. Further uphole movement causes the ring to shear free at bout 8 kips. Once the sleeve 360 is sheared free from the ring, the spring 362 maintains the ring lugs 317 and the stop lugs 351 in their respective recesses.
Also shown in
Those of skill in the art will appreciate that the hydraulic pressure used to activate the opening tool 330 by reaction against the pressure device 508 should be less than the pressure needed to set the isolation packers in the production zone assemblies and less than the pressure to activate a shear safety system, if used. Pressuring against the pressure device 508 causes relative movement between the opening collet 330 and the tool body 399 such that the shear pins 337 are defeated and the opening tool is activated. In the particular embodiment of
Referring back to the general discussion of the use and operation of the improved well completion system, once the well completion system has been made up and pressure tested, and the pressure test assembly open, such as by shattering the glass disk with nosepiece 378, the well completion system may be place in the well bore and each zone sequentially or randomly completed in one downhole trip.
The structure, function and use of an embodiment of an improved completion system according to the present invention have now been disclosed. Other and further embodiments can be devised without departing from the general disclosure thereof. For example, the improved completion system can be used with other well treatment operations, including fracturing, gravel packing, acidizing, water packing, and other treatments. Further, the various methods and embodiments of the improved completion system can be included in combination with each other to produce variations of the disclosed methods and embodiments. Discussion of singular elements can include plural elements and vice-versa.
The order of steps can occur in a variety of sequences unless otherwise specifically limited. The various steps described herein can be combined with other steps, interlineated with the stated steps, and/or split into multiple steps. Similarly, elements have been described functionally and can be embodied as separate components or can be combined into components having multiple functions.
The inventions have been described in the context of preferred and other embodiments and not every embodiment of the invention has been described. Obvious modifications and alterations to the described embodiments are available to those of ordinary skill in the art. The disclosed and undisclosed embodiments are not intended to limit or restrict the scope or applicability of the invention conceived of by the Applicants, but rather, in conformity with the patent laws, Applicants intends to protect all such modifications and improvements to the full extent that such falls within the scope or range of equivalent of the following claims.
This application for patent claims benefit of and priority from U.S. Provisional Patent Application Ser. No. 60/678,689, filed on May 6, 2005, and U.S. Provisional Patent Application Ser. No. 60/763,246, filed on Jan. 30, 2006.
Number | Date | Country | |
---|---|---|---|
60678689 | May 2005 | US | |
60763246 | Jan 2006 | US |