1. Field of the Invention
The present invention relates to the drilling and completion of well bores in the field of oil and gas recovery. More particularly, this invention relates to an apparatus adapted to provide a spacing mechanism between relatively-long strings of tubular string (e.g., a production tubing string, and the like) extending within a well bore. The apparatus may be used in an Upper-completion Single Trip (“UST”) system, and may include a Hydraulic Internal Seal Receptacle (“HISR”) assembly (also known as a “One Trip Stinger Assembly”) as a component thereof.
2. Description of the Related Art
In the oil and gas industry, production string is run thousands of feet into the earth. Well bores are typically drilled by rotating a drill string comprising a plurality of drill pipe segments serially connected to a bottom hole assembly and a drill bit thereby creating the well bore. As the well bore is drilled, tubular casing may be placed in the well bore to protect the well bore. The casing may then be cemented as desired. Progressively smaller diameter casing may be used as the well bore is drilled deeper until a hydrocarbon-bearing formation is penetrated. Once the production casing is in place, production pipe or tubing may also be run within the casing string in the well bore. Production tubing strings may typically be thousands of feet in length, in order to place the lower end of the tubing adjacent the hydrocarbon-bearing subterranean formation. Such systems may be utilized on land or offshore.
The temperature of the long production strings is adapted to change over time. For instance, during production, the temperature of the strings increases. This increase in temperature leads to concomitant increase in the length of the string. If the string is anchored on each end, then the increased length causes compressive stresses to accumulate on within the tubing string.
Similarly, if the tubing string is cooled, the overall length of the string is reduced. Thus, the string is prone to be susceptible to tensile stresses. Due to the overall length of the tubing string, changes in temperature e.g. may impart significant forces thereupon which are detrimental to the operation of the tubing string. For example, when being run downhole, the relatively cool temperature of the brine cools the tubing string such that the metal tubing string contracts. When in production the hydrocarbons passing through the tubing string forces the tubing string to expand its overall length. When operated in a deviated or horizontal well, these forces are exasperated.
To reduce this associated stress, it is desirable to provide a spacing mechanism. The mechanism should be adapted to be placed in the string and accommodate the changing length of the string, thus reducing the associated stresses. Thus, it is desirable to provide a spacing function in the tubing string to act to compensate for the expansion and contraction of these relatively long tubing strings to reduce the associated stresses therein.
It is known to provide spacers in the production string during completion. However, present assemblies are known to prematurely or accidentally actuate, causing difficulties while running downhole. For example, if the spacer tool contacts an unintended obstruction downhole, the tool may accidentally, prematurely release or actuate, thus hampering the running in of the tool.
In some prior art methods, a spacing device is provided which is assembled utilizing shear pins. To activate the spacing device, the shear pins are sheared. However, with such systems, the spacing device may be accidentally actuated by the tool contacted unanticipated debris or an obstruction downhole. Thus, the spacing device begins to function long before desired.
Further, during the completion of the well, it is needed to perform additional functions downhole, such as aligning and running the production tubing in the packer downhole, and locking the production string into a packer downhole.
Presently, it is known to perform each of these functions in separate trips into the wellbore. Each trip down the wellbore adds significant cost and time to the completion project. Thus, it is desirable to perform each of these three functions in a single trip to reduce the overall cost of the project, reduce the number of components utilized in the job, and reduce the number of components falling downhole (e.g. clamps).
Also, desirable to be able to rotate the entire spacing assembly, should any downhole component become lodged and rotation is necessary to attempt to dislodge the assembly.
In other situations, it is desirable to provide a latching mechanism and a mule shoe assembly, which does not require rotation of any downhole components to operate. For instance, when performing the installation of permanent downhole gauges or intelligent-type system, rotation is not possible, as these systems typically include the use of hydraulic lines, electric line, or fiber optics.
Thus, there is a need for an apparatus that provides a spacing function along a tubing string wherein the apparatus is not prone to premature or accidental activation. Preferably, the system is capable of performing the functions of providing a spacer, aligning and running the production tubing in a packer, and locking the production string into the packer in a single trip downhole, thus significantly saving time and cost of the completion process. It is also desirable that the system also provide means for selectively breaking the string such that components above the system may be removed or repaired; once the repair is completed, the system should be able to rejoin the string.
Embodiments of the present invention are directed at overcoming, or reducing and minimizing the effects of, any shortcomings associated with the prior art.
In some embodiments, the invention relates to an assembly for providing a spacing function for production tubing, etc. The invention is also related to providing means for selectively engaging and disengaging the tubing string. The HISR assembly is adapted to maintain its original length during run in, and, when desired, the HISR may be hydraulically actuated to such that relative movement between the crossover assembly 200 and the mandrel assembly 300 is allowed, thus providing the spacing function to relieve stress on the production tubing, both above and below the assembly 100. The load pins 400, being relatively robust, and the operation thereof, act to prevent the premature actuation of the HISR assembly 100 caused by a mechanical force (e.g. pushing on or pulling the HISR assembly 100).
The invention also relates to a system including the HISR assembly, to perform multiple completion operations in a single trip, in some embodiments. The disclosed system may be used in deepwater wells with wet-type Christmas trees for upper completion installations where rotation of the assembly is not possible, especially during installation of permanent downhole gauges or intelligent-type completions. Such installations typically utilize electric, hydraulic, or fiber optic lines, thus precluding rotation of the production string. The system described herein may be composed of an indexing mule-shoe, a shearable type anchor latch, and a Hydraulic Internal Seal Receptacle (“HISR”) for space-out purposes during the landing of the tubing hanger. The HISR assembly is run connected to the shearably anchor latch assembly, seals, and an indexing mule shoe. The automatic indexing mule shoe needs no rotation. Above the system is production or injection tubing, where the permanent downhole gauges or the intelligent type completion is assembled and run to depth. The shearable anchor latch is landed into the production packer. Tubing pressure is then applied to release the Internal Seal Receptacle providing enough travel to space-out the tubing hanger. A secondary mechanical release method is available as well, by using a slick line, wire line, or coiled tubing.
In some embodiments, the HISR system is not only composed of the HISR assembly but also includes a shearable anchor latch, seals, and the indexing mule-shoe. This allows the HISR system to be used in deepwater completions that requires PDG (Permanent downhole gauges) or Intelligent Completions, where the upper completion may be performed in one-trip without requiring rotation of any kind. Thus, the apparatus may be used to eliminate the need multiple trips downhole for completion purposes.
Also disclosed is a method of providing a spacing mechanism, as well as a method of performing multiple completion activities in a single step.
While the invention is susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and will be described in detail herein. However, it should be understood that the invention is not intended to be limited to the particular forms disclosed. Rather, the intention is to cover all modifications, equivalents and alternatives falling within the spirit and scope of the invention as defined by the appended claims.
Illustrative embodiments of the invention are described below as they might be employed in the oil and gas recovery operation and in the completion of well bores. In the interest of clarity, not all features of an actual implementation are described in this specification. It will of course be appreciated that in the development of any such actual embodiment, numerous implementation-specific decisions must be made to achieve the developers' specific goals, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time-consuming, but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure. Further aspects and advantages of the various embodiments of the invention will become apparent from consideration of the following description and drawings.
Embodiments of the invention will now be described with reference to the accompanying figures. Similar reference designators will be used to refer to corresponding elements in the different figures of the drawings.
Referring to
In some embodiments, the HISR assembly 100 generally may be comprised an overshot assembly 200 (or receptacle) functionally associated with a mandrel assembly 300. Also generally, the HISR assembly 100 may be adapted to be run downhole in an initial configuration—wherein the tool in its initial, unreleased, set position having an initial length L1. All components of the HISR assembly 100 are fixed in the initial run in configuration. In the initial configuration, relative axial movement between the overshot assembly 200 and the mandrel assembly 300 is precluded. The HISR assembly 100 may then be selectively activated as described herein, such that relative axial movement between the overshot assembly 200 and the mandrel assembly 300 is selectively allowed. Thus, once fully activated, the overall length of the HISR assembly 100 is less than its initial length L1 and may vary as , described below.
The mandrel assembly 300 of the HISR assembly 100 may include a nipple 310 and at least one polished stinger 350 in this embodiment, described hereinafter.
The overshot assembly 200 is connectable to the tubing or work string 1. The overshot assembly 200 may include a piston 210. A lock ring 280 circumscribes an upper end of the piston 210, as shown in
Various aspects of an embodiment of the piston 210 of the overshot assembly 200 are shown in
The upper end of piston 210 may include a plurality of wickers 270 adapted to engage the lock ring 280. The lock ring 280 may comprise a plurality of wickers on an inner diameter adapted to selectively mate with the wickers 270 on the upper end of the piston 210. That is, as the piston 210 moves downwardly, lock ring 270 (and the wickers thereon) act to prevent the piston 210 from moving upwardly to its original, uppermost position. Also, a shoulder 260 may be provided on the ID (internal or inner diameter) of the piston 210 for backup mechanical activation. Finally, one or more o-ring grooves 271 may be provided to accommodate an o-ring to provided appropriate sealing between various dynamic components.
The overshot assembly 200 is adapted to be selectively connected to the mandrel assembly 300. In the embodiment shown in
Referring to
While the HISR assembly 100 is in the initial set, unreleased configuration, the lower end of the piston 210 is adapted to circumscribe an upper end 312 of the nipple 310 of the mandrel assembly 300. As shown in
For instance, as shown in
As described hereinafter, once the HISR assembly 100 is activated (i.e. after shear pins 218 are sheared), the piston 210 may be moved downwardly with respect to the rest of the overshot assembly 200 and with respect to the nipple 310. As the piston 210 moves downwardly with respect to the nipple 310, the foot 440 is adapted to move from the recess 213 of the opening 212 of the piston 210 into the wider section of the opening 212 of the piston 212. In this configuration, because the opening 212 is larger than the foot 440 of the load pin 400, the load pin 400 is no longer restrained; the spring 410 pushes the load pin 400 outwardly into the void 241 in the pin housing 240. Thus, the load pin 400 is moved to its second or outer position.
It is noted that when in the HISR assembly 100 is first run downhole init unreleased configuration, the overall length of the HISR assembly remains at least substantially constant. Thus, initially, the HISR assembly is not adapted to compensate for changes in the length of the tubing or production string above or below the HISR assembly 100. However, once activated, released or unset, as described hereinafter, the length of the HISR assembly 100 may change and is therefore adapted to compensate for changes in the length of the tubing or production string, thereby reducing the stresses therein and providing a spacing mechanism therefor.
Nipple 310 may also be provided with O-ring grooves to accommodate O-rings. Further, in some embodiments, the nipple 310 may have an upper end 325, which may include a plurality of longitudinal indentations 326 as shown in
The mandrel assembly 300 may include the nipple 310 functionally associated with at least one stinger. As shown in
Located between the mandrel assembly 300 and the overshot assembly 200 are a plurality of internal molded seals 290. The internal molded seals 290 may comprise inverted molded seals. Once the HISR assembly 100 has been fully actuated, the mandrel assembly 300 is adapted to move relative to the overshot assembly 200. However, fluid communication is substantially prevented radially through the HISR assembly 100. That is, the seals 290 act to prevent fluid communication between the ID of the HISR assembly 100 and the annulus (between the tool and the casing). For instance, the internal molded seals 290 sliding along the polished outer diameter of the stinger 350 provides a seal to prevent fluid communication from inside the tubing/nipple 310 through the any component of the overshot assembly 200.
While not shown in the Figures, it is noted that the nipple 310 for each of the mandrel assemblies 300 described above could comprise an inner diameter on an uphole end 312, e.g., having a profile adapted to accommodate a given commercially-available nipple profile. For instance, the ID of the nipple 310 could be provided to complement a plug. Thus, the inner diameter of the nipple 310 may be selectively plugged as desired.
Operation of the embodiment of the HISR assembly 100 of
As described above, the HISR assembly 100 is run downhole during a first stage in which the HISR assembly 100 may be considered set, unreleased, or locked. In stage 1, the shear pins 218 have not been sheared, so axial movement between the piston 210 and the rest of the overshot assembly 200 is precluded. Further, each load pin 400 is secured in its innermost position contacting the groove 320 in the nipple 310. The load pins 400 are secured in the grooves 320 as the notches 432 in the neck 430 of the load pin 430 contacts the recess 213 in of the opening 212 of the piston 210. In stage 1, the HISR assembly 100 has an initial length L1. After running the tubing string 1 and HISR assembly 100 downhole—and once any component downhole of the HISR assembly 100 are run and set downhole—the HISR assembly 100 may be selectively moved to stage 2.
When it is desired to activate the HISR assembly 100, hydraulic pressure is increased by applying pressure to create a differential pressure. Alternatively, the nipple 310 may be plugged and pressure applied, thereby protecting downhole components from the applied pressure. Increasing the hydraulic pressure of the fluid near the upper end of the piston 210 applies a downward force on the piston 210. Once the downward force reaches a predetermined value, e.g. 30,000 lbs. (which corresponds to a 2-3000 p.s.i. increase in hydraulic pressure), the shear pins 218 shear. Backup mechanical activation, as opposed to hydraulic activation, is also possible in some embodiments, as described hereinafter.
With shear pins 218 sheared, the increased hydraulic pressure drives the piston 210 downwardly with respect to the rest of the overshot assembly 200, the nipple 310 and the load pins 400. The piston 210 moves downwardly within the upper outer sleeve 215 such that the gap 229 is reduced in size. The piston 210 continues its downward movement, forcing downhole fluid such as brine out of gap 229 via port the 230. The piston 210 continues its downward movement until the inner shoulder 211 on the piston 210 contacts the pin housing 240. At this point, the lock ring 280 on the upper end of the piston 210 also is adapted to contact wickers 270 on the piston 210 of the overshot assembly 200.
The downward movement of the piston 210 also acts to move the load pin 400 from the recess 213 (which operates to keep each load pin 400 from extending outwardly) of the piston 210 to the larger area in the opening 212 of the piston 210. With the foot 440 of load pin no longer restrained by the recess 213 of the piston opening 212, the springs 410 operate to force the lock pins 400 from the grooves 320 in the nipple 310 radially outwardly into the void 241 below the seal cap 220 of the overshot assembly 200. In this way, the overshot assembly 200 is released from the mandrel assembly 300.
The piston 210 may also compose a shoulder having a larger inner diameter 260 to provide a backup mechanical activation system. To mechanically (as opposed to hydraulically) actuate the system, a shifting tool with collet may be lowered from surface to contact the shoulder 260 of the piston 210. Upon the application of downward mechanical force, the HISR assembly 100 may be unset by mechanical means, as opposed to hydraulic means. The operation of the tool is otherwise similar to the operation described above.
With the load pins 400 no longer secured within the groove 320 of the nipple 310, the overshot assembly 200 (e.g. upper outer sleeve 215, pin housing 240, seal cap 220, lower overshot outer sleeve 250) is fee to move axially with respect to nipple 310 Thus, the overshot assembly 200 is free to move axially with respect to the mandrel assembly 300. That is, overshot assembly 200 may move axially relative to the mandrel assembly 300.
As the overshot assembly 200 moves relative to the nipple 310 and polished stingers 350, the internal seals 290 prevent fluid from escaping from within the mandrel assembly (e.g. nipple 310 and stingers 350) radially through the overshot assembly 200. The polished surface of the stingers 350 of some embodiments of the present invention facilitate the sealing action of the molded seals 290.
Thus, once activated and the load pins no longer connecting the overshot assembly 200 and the mandrel assembly 300, the HISR assembly 100 allows relative axial movement between the mandrel assembly 300 (e.g. the nipple 310 and stingers 350 in some embodiments) and the overshot assembly 200. In this section position, the overall length of the HISR assembly 100 is decreased from the original length L1. As such, the HISR assembly 100 fulfills the space-out function as desired. Depending on the number of polished stingers 350 being utilized, HISR assembly 100 may provide as many feet of spacing out as necessary. Typical applications may include the use of three polished stingers 350 providing thirty feet of spacing out. Thus, when the production tubing 10 contracts (e.g. when not in production), the HISR assembly 100 may expand, thus reducing the tensile stresses on the tubing 1, 10, both above and below the HISR assembly 100. When the production tubing 10 expands (such as during production), the HISR assembly 100 reduces in overall length to accommodate the increased length in the working tubing 1 and production tubing 10. The HISR assembly 100 thereby acts to reduce compressive stresses on the tubing 1, 10.
In this way, as the lengths of the tubing string either above or below (or both) expand or contact, the HISR assembly 100 may change in length to compensate, thus reducing the stress in the tubing string.
As stated above, with the HISR assembly 100 in the first (unreleased or set) stage, the overshot assembly 200 and mandrel assembly 300 are functionally associated such that axial movement therebetween is precluded. However, due to the relative strength of the load pins 400 and the configurations described herein, the HISR assembly 100 is precluded from accidental activation of the tool, unlike prior art systems which utilize shear pins activation. These prior art shear pins are prone to shearing, and thus fully activating the spacing assembly, when component of the downhole tool contact an obstruction downhole. Thus, the use of relatively-strong load pins 400 in conjunction with the components described above act to prevent premature activation of the tool.
Further, rotation of entire system is possible. In some situations, it may be desirable to rotate the HISR assembly 100. For example, if the tool contacted un-expected debris downhole, it may be desirable to rotate the downhole HISR assembly . 100 to try to obtain its release. As the HISR assembly 100 described herein is robust and utilizes the load pin 400 connection instead of a threaded connection, the entire HISR assembly 100 may be rotated clockwise in an attempt to free the string.
As stated above, the nipple 310 for each of the mandrel assemblies described above could comprise an inner diameter having a profile adapted to accommodate a given commercially-available nipple profile. For instance, the ID of the nipple could be provided to complement a nipple for a downhole plug. Thus, in operation, the plug may be lowered into the wellbore via a wire line until the plug mates with the ID of the nipple 310. Once the plug is set within the ID of the nipple 310 and the wire line raised to surface, the tubing string above the HISR assembly may be raised to surface along with the overshot assembly 200 of the HISR assembly 100, leaving the mandrel assembly 300 such as the nipple 310 (now containing the plug) and the polished stingers 350 on the tubing string down hole. In this way, components on the string above the HISR assembly 100 (such as motors, pumps, etc) may be removed to surface and repaired, etc., while providing a plug to cease production from the wellbore. Once the component is repaired or replaced, the overshot assembly 200 of the HISR assembly and the tubing string may be lowered from surface, until the overshot assembly 200 again envelops the mandrel assembly 300 such as the nipple 310 on the stingers. The mule shoe 299 on the overshot assembly 200 is adapted to facilitate the proper orientation of the overshot assembly 200 with the mandrel assembly 300. The plug may then be removed and production may resume.
Thus, the disclosed system provides a versatile assembly which may allow for repair of components uphole of the HISR assembly 100.
The shearable anchor latch 500 in the embodiment shown in
On the lower end of the central mandrel 550 is a shear ring 530, The shear ring 530 includes an upper section 532 or collar adapted to be circumscribed by the collet fingers 525, thus driving the collet fingers 525 radially outwardly to prevent premature release from the packer as described hereinafter. The shear ring 530 may also comprise an attachment section 534 in which the shear ring 530 is attached to the mandrel 550 by a plurality of shear screws 535. As would be realized by one of ordinary skill in the art having the benefit of this disclosure, the number, size, and strength of such shear screws 535 may be varied depending on the predetermined shear force at which pins are desired to be sheared. For instance, in some applications, the number, size, and type of shear screws 535 are selected such that to shear at 90,000 lbs.
The lower end of the mandrel 550 may be attached to a bottom sub 540. As shown in
Operation of the shearable anchor latch 600 is similar to a pop lock or anchor lock known in the art; however, unlike some prior art mechanisms, the shearable anchor latch 600 is adapted to shear away from other downhole components to which the shearable anchor latch 600 is connected upon the application of a predetermined upward force.
Prior art pop locks generally are not significantly robust for the application described herein; however, anchor locks cannot be selectively removed without rotation, which is not desirable. The present shear anchor latch provides a robust latching mechanism that can be selectively decoupled downhole without requiring rotation.
Located at the bottom of the HISR system described herein is an indexing mule shoe 600. That is, the indexing mule shoe 600 is the lowermost component of the system when running downhole.
The indexing mule shoe 600 is shown in
Operation of the indexing mule shoe 600 of the HISR system follows. The tubing string (and the various components of the HISR system) is lowered from surface into a borehole until the indexing mule shoe 600 contacts a packer assembly downhole. It is desirable that the angled portion 635 of the end of the indexing mule shoe contact the packer downhole. That is, if the blunt end 630 contacts the packer, then it is desirable to rotate the mule shoe 600 such that the angled portion 635 contacts the packer properly. The alignment is especially problematic in deviated or horizontal wells.
Thus, if the indexing muleshoe is not correctly aligned with the packer, then the application of downward force will compress the outer sleeve 610 against the inner sleeve 620. The inner sleeve 620 is precluded from further downhole movement via contact with the packer. As the outer sleeve 610 moves downwardly, the gap 612 reduces in size, and the sloped surface 615 of the outer sleeve 610 contacts the complementary sloped surfaced 625 of the inner sleeve 620. The mating of the sloped surfaces 615, 625 acts to rotate the inner sleeve 620 with respect to the outer sleeve 610, thus indexing the muleshoe. In this way, the muleshoe 600 provides the desired rotation of the end 630 of the muleshoe so that the muleshoe may be properly aligned with the packer, while not requiring rotation of other components downhole and not requiring the rotation of the entire HISR system.
The tubing string is pulled upwardly, thus re-created the gap 612, the spring once again biasing the outer sleeve 610 from the inner sleeve 620. The tubing sting is again lowered until the muleshoe contacts the packer. These steps are repeated until the muleshoe 600 is properly aligned with the packer; i.e. until the angled portion 635 of the muleshoe 600 contacts the packer. Once the angled portion 635 of the muleshoe 600 contacts the packer, the muleshoe may then be inserted into the packer and run further downhole.
Once the indexing mule shoe 600 as entered the packer downhole, the tubing string is lowered further. The external seals 560 contact the packer and the production string below the packer, thus facilitating the seal between the HISR system and the packer. The system is lowered until the collet fingers 525 contact the inner diameter of the packer downhole. The collet fingers 525 initially engage the packer. As a test, a slight upward force on the tubing string pulls the mandrel 550 upwardly with respect to the latch 520. This upward movement of the mandrel 550 also causes the upper section 532 of the shear ring 530 to move up and under the collet fingers 525, thus driving the collet fingers radially outwardly to engage the packer further. Thus, the collet fingers 525 (via wickers if used) are adapted to engage the inner diameter of the packer.
Thus, the shearable anchor latch 600 is adapted to selectively connect the HISR system to the packer downhole. However, if it becomes necessary to remove tubing string and HISR system from downhole for any reason, e.g. if a component encounters debris downhole, an upward force will shear the latch and free the HISR assembly 100 as follows.
Application of additional upward force exerts a downward force on the upper section 532 of the shear ring 530, the latch 520 in contact with the upper section 532. Once the upward force reaches a predetermined value, e.g. 90,000 lbs., the shear screws 535 shear, allowing the tubing string including the cross over 501 and top sub 510 to be pulled to surface, while the shear ring 530, mandrel 550, and latch 520 are allowed to fall downhole. Any components on the string below the shear ring also fall downhole.
Thus, the shearable anchor latch 600 provides a secure connection to the packer downhole, while allowing selective disengagement should the string and the rest of the HISR system need to be removed.
Utilizing the above HISR system described above allows all three tools to be run on a single trip. The HISR system may be also be utilized where rotation on the job is precluded. For instance, when operating in a severely deviated or a horizontal well, the torque required to rotate the string may exceed the thread strength of the tubing strings. Further, when installing permanent downhole gauges or intelligent systems, which include hydraulic lines, fiber optic lines, or electrical lines, rotation is precluded to prevent entanglement. Finally, the HISR system described above is especially well-suited for use with submersible pumps. Regarding the submersible pumps, the system is well-suited due to the fact that the pumps require electric lines that cannot be rotated during installation and to the fact that the pumps need periodically maintenance and with the HISR, we can detach the HISR, pull out of the hole with the pump, change or repair and go back and sting on the HISR mandrel again.
Although various embodiments have .been shown and described, the invention is not so limited and will be understood to include all such modifications and variations as would be apparent to one skilled in the art.
The following table lists the description and the references designators as may be utilized herein and in the attached drawings.
This application claims the benefit of U.S. Provisional Application No. 60/648,913 filed Jan. 31, 2005, hereby incorporated by reference in its entirety, entitled “Upper-Completion Single Trip System with Hydraulic Internal Seal Receptacle Assembly,” by Vilela et al.
Number | Name | Date | Kind |
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3381752 | Elliston | May 1968 | A |
6056055 | Falconer et al. | May 2000 | A |
7331388 | Vilcla et al. | Feb 2008 | B2 |
20030066655 | Cook et al. | Apr 2003 | A1 |
Number | Date | Country | |
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20060219413 A1 | Oct 2006 | US |
Number | Date | Country | |
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60648913 | Jan 2005 | US |