Patent Publication Number: US-8118102-B2

Title: Downhole swivel apparatus and method

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This is a continuation of U.S. patent application Ser. No. 11/745,899, filed 8 May 2007 (issuing as U.S. Pat. No. 7,828,064 on 9 Nov. 2010), which was a continuation-in-part of U.S. patent application Ser. No. 11/284,425, filed 18 Nov. 2005, which application was a non-provisional of each of the following provisional patent applications: 
     U.S. Provisional Patent Application Ser. No. 60/631,681, filed 30 Nov. 2004; 
     U.S. Provisional Patent Application Ser. No. 60/648,549, filed 31 Jan. 2005; 
     U.S. Provisional Patent Application Ser. No. 60/671,876, filed 15 Apr. 2005; and 
     U.S. Provisional Patent Application Ser. No. 60/700,082, filed 18 Jul. 2005. 
     Additionally, this is a continuation of U.S. patent application Ser. No. 11/745,899, filed 8 May 2007 (issuing as U.S. Pat. No. 7,828,064 on 9 Nov. 2010), which application was a non-provisional of each of the following provisional patent applications: 
     U.S. Provisional Patent Application Ser. No. 60/890,068, filed 15 Feb. 2007; and 
     U.S. Provisional Patent Application Ser. No. 60/798,515, filed 8 May 2006. 
     Priority of each of the above referenced full utility and provisional applications is hereby claimed. 
     Each of the above referenced full utility and provisional patent applications is incorporated herein by reference. 
    
    
     STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
     Not applicable 
     REFERENCE TO A “MICROFICHE APPENDIX” 
     Not applicable 
     BACKGROUND 
     In deepwater drilling rigs, marine risers extending from a wellhead fixed on the ocean floor have been used to circulate drilling fluid or mud back to a structure or rig. The riser must be large enough in internal diameter to accommodate a drill string or well string that includes the largest bit and drill pipe that will be used in drilling a borehole. During the drilling process drilling fluid or mud fills the riser and wellbore. 
     After drilling operations, when preparing the wellbore and riser for production, it is desirable to remove the drilling fluid or drilling mud. Removal of drilling fluid or drilling mud is typically done through a displacement using a completion fluid. 
     Because of its relatively high cost, this drilling fluid or drilling mud is typically recovered for use in another drilling operation. Displacing the drilling fluid or drilling mud in multiple sections is desirable because the amount of drilling fluid or mud to be removed during completion is typically greater than the storage space available at the drilling rig for either completion fluid and/or drilling fluid or drilling mud. 
     It is contemplated that the term drill string or well string as used herein includes a completion string and/or displacement string. It is believed that rotating the drill string or well string (e.g., completion string) during the displacement process helps to better remove the drilling fluid or mud along with down hole contaminants such as mud, debris, and/or other items. It is believed that reciprocating the drill or well string during the displacement process also helps to loosen and/or remove unwanted downhole items by creating a plunging effect. Reciprocation can also allow scrapers, brushes, and/or well patrollers to better clean desired portions of the walls of the well bore and casing, such as where perforations will be made for later production. 
     During displacement there is a need to allow the drilling fluid or mud to be displaced in two or more sections. During displacement there is a need to prevent intermixing of the drilling fluid or mud with displacement fluid. During displacement there is a need to allow the drill or well string to rotate while the drilling fluid or mud is separated into two or more sections. 
     During displacement there is a need to allow the drill string or well string to reciprocate longitudinally while the drilling fluid or mud is separated into two or more sections. 
     BRIEF SUMMARY 
     The method and apparatus of the present invention solves the problems confronted in the art in a simple and straightforward manner. 
     One embodiment relates to a method and apparatus for deepwater rigs. In particular, one embodiment relates to a method and apparatus for removing or displacing working fluids in a well bore and riser. 
     In one embodiment displacement is contemplated in water depths in excess of about 5,000 feet (1,524 meters). 
     One embodiment provides a method and apparatus having a swivel which can operably and/or detachably connect to an annular blowout preventer thereby separating the drilling fluid or mud into upper and lower sections and allowing the drilling fluid or mud to be displaced in two stages or operations under a well control condition. 
     In one embodiment a swivel can be used having a sleeve or housing that is rotatably and sealably connected to a mandrel. The swivel can be incorporated into a drill or well string. 
     In one embodiment the sleeve or housing can be fluidly sealed to and/or from the mandrel. 
     In one embodiment the sleeve or housing can be fluidly sealed with respect to the outside environment. 
     In one embodiment the sealing system between the sleeve or housing and the mandrel is designed to resist fluid infiltration from the exterior of the sleeve or housing to the interior space between the sleeve or housing and the mandrel. 
     In one embodiment the sealing system between the sleeve or housing and the mandrel has a higher pressure rating for pressures tending to push fluid from the exterior of the sleeve or housing to the interior space between the sleeve or housing and the mandrel than pressures tending to push fluid from the interior space between the sleeve or housing and the mandrel to the exterior of the sleeve or housing. 
     In one embodiment a swivel having a sleeve or housing and mandrel is used having at least one flange, catch, or upset to restrict longitudinal movement of the sleeve or housing relative to the annular blow out preventer. In one embodiment a plurality of flanges, catches, or upsets are used. In one embodiment the plurality of flanges, catches, or upsets are longitudinally spaced apart with respect to the sleeve or housing. 
     One embodiment allows separation of the drilling fluid or mud into upper and lower sections. 
     One embodiment restricts intermixing between the drilling fluid or mud and the displacement fluid during the displacement process. 
     One embodiment allows the riser and well bore to be separated into two volumetric sections where the rigs can carry a sufficient amount of displacement fluid to remove each section without stopping during the displacement process. In one embodiment, fluid removal of the two volumetric sections in stages can be accomplished, but there is a break of an indefinite period of time between stages (although this break may be of short duration). 
     In one embodiment displacement is performed in the upper portion before displacement in the lower portion second. 
     In one embodiment displacement is performed in the lower portion before the displacement in the upper portion. 
     In one embodiment a displacement fluid is used in at least one of the sections before a completion fluid is used. 
     In one embodiment, at least partly during the time the riser and well bore are separated into two volumetric sections, the drill or well string does not move in a longitudinal direction relative to the swivel during displacement of fluid. 
     In one embodiment, at least partly during the time the riser and well bore are separated into two volumetric sections, the drill or well string is reciprocated longitudinally during displacement of fluid. In one embodiment a reciprocation stroke of about 65.5 feet (20 meters) is contemplated. In one embodiment about 20.5 feet (6.25 meters) of the stroke is contemplated for allowing access to the bottom of the well bore. 
     In one embodiment about 35, about 40, about 45, and/or about 50 feet (about 10.67, about 12.19, about 13.72, and/or about 15.24 meters) of the stroke is contemplated for allowing at least one pipe joint-length of stroke during reciprocation. In one embodiment reciprocation is performed up to a speed of about 20 feet per minute (6.1 meters per minute). 
     In one embodiment, at least partly during the time the riser and well bore are separated into two volumetric sections, the drill or well string is intermittently reciprocated longitudinally during displacement of fluid. In one embodiment the rotational speed is reduced during the time periods that reciprocation is not being performed. In one embodiment the rotational speed is reduced from about 60 revolutions per minute to about 30 revolutions per minute when reciprocation is not being performed. 
     In one embodiment, at least partly during the time the riser and well bore are separated into two volumetric sections, the drill or well string is continuously reciprocated longitudinally during displacement of fluid. 
     In one embodiment, at least partly during the time the riser and well bore are separated into two volumetric sections, the drill or well string is reciprocated longitudinally the distance of at least the length of one joint of pipe during displacement of fluid. 
     In one embodiment, at least partly during the time the riser and well bore are separated into two volumetric sections, the drill or well string is rotated during displacement of fluid. In one embodiment rotation of speeds up to 60 revolutions per minute are contemplated. 
     In one embodiment, at least partly during the time the riser and well bore are separated into two volumetric sections, the drill or well string is intermittently rotated during displacement of fluid. 
     In one embodiment, at least partly during the time the riser and well bore are separated into two volumetric sections, the drill or well string is continuously rotated during displacement of fluid of at least one of the volumetric sections. 
     In one embodiment, at least partly during the time the riser and well bore are separated into two volumetric sections, the drill or well string is alternately rotated during displacement of fluid during. 
     In one embodiment, at least partly during the time the riser and well bore are separated into two volumetric sections, the direction of rotation of the drill or well string is changed during displacement of fluid. 
     In various embodiments, at least partly during the time the riser and well bore are separated into two volumetric sections, the drill or well string is reciprocated longitudinally the distance of at least about 1 inch (2.54 centimeters), about 2 inches (5.08 centimeters), about 3 inches (7.62 centimeters), about 4 inches (10.16 centimeters), about 5 inches (12.7 centimeters), about 6 inches (15.24 centimeters), about 1 foot (30.48 centimeters), about 2 feet (60.96 centimeters), about 3 feet (91.44 centimeters), about 4 feet (1.22 meters), about 6 feet (1.83 meters), about 10 feet (3.048 meters), about 15 feet (4.57 meters), about 20 feet (6.096 meters), about 25 feet (7.62 meters), about 30 feet (9.14 meters), about 35 feet (10.67 meters), about 40 feet (12.19 meters), about 45 feet (13.72 meters), about 50 feet (15.24 meters), about 55 feet (16.76 meters), about 60 feet (18.29 meters), about 65 feet (19.81 meters), about 70 feet (21.34 meters), about 75 feet (22.86 meters), about 80 feet (24.38 meters), about 85 feet (25.91 meters), about 90 feet (27.43 meters), about 95 feet (28.96 meters), and about 100 feet (30.48 meters) during displacement of fluid and/or between the ranges of each and/or any of the above specified lengths. 
     In various embodiments, the height of the swivel&#39;s sleeve or housing compared to the length of its mandrel is between two and thirty times. Alternatively, between two and twenty times, between two and fifteen times, two and ten times, two and eight times, two and six times, two and five times, two and four times, two and three times, and two and two and one half times. Also alternatively, between 1.5 and thirty times, 1.5 and twenty times, 1.5 and fifteen times, 1.5 and ten times, 1.5 and eight times, 1.5 and six times, 1.5 and five times, 1.5 and four times, 1.5 and three times, 1.5 and two times, 1.5 and two and one half times, and 1.5 and two times. 
     In one embodiment one or more brushes and/or scrapers are used in the method and apparatus. 
     In one embodiment a mule shoe is used in the method and apparatus. 
     In one embodiment the mule shoe is spaced relative to the sleeve such that it is about 53 feet (16.15 meters) above the true depth of the well bore. In one embodiment the quick lock/quick unlock system is moved to an unlocked state using about 35,000 or 40,000 pounds (156 or 178 kilo newtons) of longitudinal thrust load between the mandrel and the sleeve. 
     In one embodiment a single action bypass sub is used in the method and apparatus. 
     In one embodiment a single action bypass sub jetting tool is used in the method and apparatus. 
     In one embodiment most of the upper volumetric section is first displaced with sea water. 
     In one embodiment the upper volumetric section (e.g., riser) is displaced with a first fluid (such as brine or seawater). The annular blow out preventer can be open during this step. Next, drilling fluid or mud is circulated in the lower volumetric section (e.g., well bore) at the same time rotation and/or reciprocation of the drill or well string is performed (at least intermittently) until the circulated drilling fluid or mud meets specified criteria. The annular seal of the blowout preventer is closed on the sleeve or housing of the swivel during this step. Next, the drilling fluid or mud in the lower stage is displaced with a second fluid (e.g., a completion fluid such as calcium bromide) and the second fluid is circulated until it meets specified criteria. The annular seal of the annular blowout preventer is still closed during this step. Finally, the first fluid in the upper volumetric section is displaced with the second fluid by pumping the second fluid both through the bottom of the drill or well string, and through the booster line, and then the second fluid is circulated until the second fluid exiting the riser meets specified criteria. The annular seal is opened during this step. Increased flow rates in the upper volumetric section can be achieved by simultaneously pumping fluid down the drill or work string along with pumping through the booster line. In various of the above stages cleaning pills of certain fluids can be pumped in before the second fluid is used to displace. The upper and lower volumetric sections can be completed using the above steps. 
     In one embodiment performing displacement in two or more stages while the annular blowout preventer is closed on a swivel having rotation and/or reciprocation allows for better management of the large amounts of fluids involved in the displacement process. Additionally, such process allows for the entire completion string to be rotated and/or reciprocated while the annular blowout preventer is sealed on the sleeve or housing of the swivel thereby providing a well control condition during displacement while allowing rotation and/or reciprocation. Without inserting the rotating and/or reciprocating swivel, sealing the annular blowout preventer on the completion string would effectively prevent rotation and/or reciprocation of the completion string during displacement (because rotation and/or reciprocation of the string while the annular BOP is sealed would prematurely damage the sealing element of the annular BOP). With the rotating and/or reciprocating swivel there is well control with rotation and/or reciprocation during the displacement process. 
     In one embodiment high capacity thrust bearings (external and/or internal to the housing or sleeve) can be incorporated to address the possibility that an operator will cause the sleeve or housing of the swivel to reach the end of its stroke and contact a stop on the end of the mandrel. In this situation the thrust bearing transmits the thrust load from the sleeve or housing through the thrust bearing and to the mandrel. Additionally, the thrust bearing can allow the sleeve to rotate relative to the stop which it contacted so that rotation can be achieve even at the longitudinal limits of reciprocation. 
     In one embodiment is provided a rotating and reciprocating tool which allows the completion process to be separated into two stages or divided into two separate processes with each process having its own distinctive starting and stopping point. Normally, completion would be performed as a single stage process. 
     After drilling is complete, drilling mud and debris are removed from the well bore and subsea riser and replaced with a clean, weighted completion fluid. The area in and around the well production zone is of great importance. During the completion (cleaning and weighting) process dirty drilling mud can be pushed out of the well using a series of chemical pills (each pill comprising several barrels of a particular chemical composition) followed by the inert weighted completion fluid. 
     Considering the high costs for hourly rig operations and costs for chemicals and fluids used during the completion process, shortening this completion time and reducing the volumes of fluids and chemicals used are desirable. 
     Typically, a well bore will have connected thereto a subsea riser which extends from the sea floor to the rig. In a single stage completion process (e.g., one not using the rotating and reciprocating tool) chemical pills, followed by clean, weighted completion fluid, can be pumped at a maximum speed down to the bottom of the well bore through the bore of completion string. After exiting the bore of the completion string this pumped fluid turns direction and flows up the well bore (through the well bore annulus) and continues up the subsea riser to the rig. One concern with single stage completions is the risk that, at any time in the single stage completion process, the flow will be substantially slowed or stopped causing different weights mud, chemical pills, and final weighted completion fluid to intermix. Such intermixing will cause the overall completion process to fail requiring the completion process to be started over or accepted with a less than perfect completion. Both options are disadvantageous and can increase the overtime production rate of the well. 
     The rotating and reciprocating tool can be closed on by the annular blowout preventer (“annular BOP”). Typically, the annular BOP is located immediately above the ram BOP which ram BOP is located immediately above the sea floor and mounted ON THE well head. As an integral part of the string, the mandrel of the rotating and reciprocating tool supports the full weight, torque, and pressures of the entire string located below the mandrel. 
     The rotating and reciprocating tool allows the completion process to be separated into two volumetric stages: (a) the volume below the annular BOP and (b) the volume above the annular BOP. Separation is advantageous because it allows the smaller (but more difficult) volume of fluid to be completed separately from the completion of the larger (but easier) volume fluid. The fluid to be displaced and completed above the annular BOP is in a relatively large diameter and volume riser (compared to the volume of the well bore), but such riser fluid is typically easier to bring up to completion standards because, among other reasons, the walls of the riser are typically cleaner (and easier to clean) compared to the walls of the wellbore. The fluid to be displaced and completed below the annular BOP is in a relatively smaller volume (compared to the riser), but is typically more difficult to bring up to completion standards because, among other reasons, the walls of the well bore are not as clean as the walls of the riser. By separating these two volumetric sections, the smaller, more difficult volume to complete (for the wellbore) can be completed without combining or intermixing such volume with the larger more easily completed volume (for the riser). 
     In one example of two stage displacement job, the riser can have a volume capacity of approximately 2000 barrels of fluid where the well bore had a volume capacity of approximately 1000 barrels. It can be more efficient and simpler to prepare for a six hour displacement of the 1000 barrels of fluids in the well bore with the fluids returning to the rig floor in a path other than through the riser (i.e., through the choke line). This can be performed while the riser fluid is separated from the well bore fluid by the closed and sealed annular BOP. By comparison, a single stage displacement of the same well and riser would take approximately 18 hours to displace the 3000 barrels of fluid volumes (the volumes in both the riser and wellbore) all of which are in direct contact with each other and can intermix. In the first stage, where the well bore is being completed/cleaned, the fluid below the annular BOP is displaced with completion fluid until a predetermined standard for the fluid is achieved. During this first stage both riser and wellbore volumes are secured from intermixing with each other (completing only ⅓ of the total fluid volume—compared to the total volumes of both wellbore and riser—and ⅓ of the total time required in a single stage completion process). In the second stage, where the riser fluid is being completed/cleaned, the fluid above the annular BOP is separated and secured from intermixing with the now completed well bore fluid. For the riser fluid cleaning pills and completion fluids are pumped from the rig floor, down the boost line to the bottom of the subsea riser just above the annular BOP. These fluids then flow up the riser until a predetermined standard for completion of the riser fluid is obtained. After the riser fluid has achieved the pre-determined completion standard, the annular BOP can be opened allowing the riser and wellbore volumes to contact each other. At this point additional completion fluid can be pumped down the center of the completion string&#39;s bore to the bottom of the well where it turns and flows up the already completed/cleaned wellbore. Because the annular BOP is opened, this completed/cleaned wellbore fluid now flows through the open annular BOP and around the rotating and reciprocating tool and combines with additional completion fluid which can be pumped into the riser through the boost line, thereby increasing fluid velocity through the riser which can have a substantially larger diameter than the wellbore. 
     After completion of the first stage of a two stage completion process the wellbore is now clean, completed, and secure. The rig personnel can take a break, manage, and prepare for performing the second stage of the two stage completion (the displacement/completion of the subsea riser). This preparation may require the transfer of fluids to waiting boats, cleaning of tanks, lines, and other equipment. When the preparation for the second stage is finished, 2000 barrels of riser fluid can be displaced, taking 12 hours. The first stage well bore completion (under the annular BOP) remains secure because the annular BOP does not open until sufficient completion fluid is in the riser which will allow sufficient time to close the annular BOP if a problem occurred. 
     Having the annular BOP closed on the housing of the rotating and reciprocating tool during the first and/or second stages, allows the completion string to be rotated and reciprocated (while the annular BOP separates riser and wellbore volumes) along with having mud, pills, and/or completion fluid pumped through the string&#39;s center bore to the wellbore, up the well bore, and up the choke or kill lines to the rig. During the completion process movement, rotation, reciprocation or a combination of these helps keep unwanted material from setting in and hampering completion. Preferably, rotation speeds are high to get maximum effect. However, it is not recommended that rotation speeds exceed 60 revolutions per minute, as these can cause a whip effect in the completion string and also cause problems for brush and wipers installed along the completion string. 
     Completion engineers believe it is important to have access to as close as possible to the bottom of the wellbore to properly address this bottom area. In a preferred embodiment the rotating and reciprocating tool provides 63 feet (19.2 meters) of reciprocating stroke. This 63 foot (19.2 meter) stroke provides a nominal working stroke of 45 foot (13.72 meters) (preferably equal to the length of a single joint of pipe) with an 18 foot (5.49 meter) extra stroke capacity. The extra stroke capacity provides a factor of safety for dealing with errors in determining the Total Depth to the bottom of the wellbore. For example, if the true Total Depth is actually 10 feet (3 meters) deeper than the calculated Total Depth, the rotating and reciprocating tool has enough excess stroke capacity to absorb the 10 foot (3 meter) error in depth allowing the bottom of the completion string to reach the true bottom of the wellbore (i.e., true Total Depth) so that this bottom area can be properly addressed. If the extra stroke capacity had not been in place and there was an error in calculating Total Depth (e.g., 10 feet or 3 meters), the bottom of the string would not reach the bottom of the wellbore (missing by the 10 foot or 3 meter error) and effectively prevent the unreached part of the wellbore from being properly completed. Alternatively, the entire completion string could be tripped out of the hole, an extra length of string added to the string, and having to trip back in the entire completion string—assuming the necessary additional amount of string can actually be determined—and causing a large amount of wasted time). 
     If the true Total Depth was actually shorter than calculated the error would effectively limit the amount of stroke of the mandrel and string relative to the sleeve would be shorted by the bottom of the completion string being stopped by the bottom of the wellbore. This shortened stroke would prevent a portion of each full joint of casing from seeing a stroke. Particularly in deviated wells where at least part of the string is in contact with the sidewall of the wellbore, reciprocation of a full joint length of pipe allows the pipe joint connection upsets that are in contact with the sides of the casing to scrape (and at least partially clean) the side of the casing for at least the length of contact (and possibly for the entire length of reciprocation) which assists in completing the wellbore such as by helping eliminate areas where unwanted material might tend to accumulate and/or settle. 
     In one embodiment, a sheer pin can be used to lock the sleeve relative to the mandrel. Although, a sheer pin can be used to lock the sleeve relative to the mandrel, it has the disadvantage that it can be used only once. While the sheer pin can hold the sleeve in a fixed longitudinal position relative to the mandrel, in order to allow the mandrel to reciprocate relative to the sleeve, the sheer pin must be sheered (such as by pushing and/or pulling on the mandrel at a time when the annular BOP is closed on the sleeve, the closed annular BOP exerting a longitudinal shearing force, such as on one of the catches, until the longitudinal force is sufficient sheer the pin). Once sheered, the pin can no longer be used to lock the sleeve and mandrel relative to each other. If the annular BOP is opened and the mandrel moved up and/or down, the position of the unlocked sleeve relative to the mandrel can change (as described below) and subsequently become uncertain so that the sleeve&#39;s position thereafter cannot be practically determined. 
     Although one methodology for locating the sleeve relative to the mandrel without a quick lock/quick unlock system can be to position the sleeve at either the upper most (or lower most) point of reciprocation between the sleeve and mandrel; and assume that the sleeve will remain in such position when the completion engineer attempts again close the annular BOP on the sleeve. There is a certain amount of friction (between the sleeve and the mandrel) which will tend to keep the sleeve and mandrel in one longitudinal position relative to each other. Additionally, if the sleeve is located at the lowermost point of reciprocation, gravity acting on the sleeve will also tend to keep the sleeve at this lowermost point for positioning the sleeve. However, this procedure has the risk that something with occur which causes the sleeve to be moved relative to the mandrel. For example, the sleeve may be knocked against and/or catch on something downhole (e.g., a discontinuity in the wall) causing the sleeve to move longitudinally relative to the mandrel. Once moved, the position of the sleeve relative to the mandrel will no longer be known, and attempts to determine such position face many difficulties. If the sleeve is moved relative to the mandrel while the sleeve is outside of the annular BOP, the entire completion string may have to be pulled (or tripped out) so that the sleeve can be again positioned relative to the mandrel, causing much wasted time and effort. Alternatively, iterative attempts to close the annular BOP on the sleeve may be made, such as by positioning the mandrel and closing the annular BOP (hoping that the annular BOP closes on the sealing area of the sleeve). If the annular BOP is not successfully closed in the sleeve during the first attempt, then the mandrel can be positioned at a different point and another attempt made to close the annular BOP on the sleeve. However, this iterative process is extremely time consuming which extra time can cause problems with the completion process (such as by letting fluids interact with each other and/or separate). Furthermore, even if by luck the annular BOP actually closes on the sealing area of the sleeve, this may not be known by the operator or completion engineer—as the operator or completion engineer may not be able to tell from the rig that proper closure of the annular BOP on the sleeve has occurred (or at least whether proper closed has been obtained may be uncertain). Additionally, the annular BOP may attempt to seal on the non-sealing area of the sleeve, or mandrel which could harm the annular BOP and/or sleeve, and/or cause the sleeve to again move longitudinally (which new longitudinal movement may resist new attempts to close on the sleeve. 
     Catches 
     The annular BOP is designed to fluidly seal on a large range of different sized items—e.g., from 0 inches to 18¾ inches (0 to 47.6 centimeters) (or more). However, when an annular BOP fluid seals on the sleeve of the rotating and reciprocating tool, fluid pressures on the sleeve&#39;s exposed effective cross sectional area exert longitudinal forces on the sleeve. These longitudinal forces are the product of the fluid pressure on the sleeve and the sleeve&#39;s effective cross sectional area. Where different pressures exist above and below the annular BOP (which can occur in completions having multiple stages), a net longitudinal force will act on the sleeve tending to push it in the direction of the lower fluid pressure. If the differential pressure is large, this net longitudinal force can overcome the frictional force applied by the closed annular BOP on the sleeve and the fractional forces between the sleeve and the mandrel. If these frictional forces are overcome, the sleeve will tend to slide in the direction of the lower pressure and can be “pushed” out of the closed annular BOP. In one embodiment catches are provided which catch onto the annular BOP to prevent the sleeve from being pushed out of the closed annular BOP. 
     For example, lighter sea water above the annular BOP seal and heavier drilling mud, or weighted pills, and/or weighted completion fluid, or a combination of all of these can be below the annular BOP requiring an increased pressure to push such fluids from below the annular BOP up through the choke line and into the rig (at the selected flow rate). This pressure differential (in many cases causing a net upward force) acts on the effective cross sectional area of the tool defined by the outer diameter of the string (or mandrel) and the outer diameter of the sleeve. For example, the outer sealing diameter of the tool sleeve can be 9¾ inches (24.77 centimeters) and the outer diameter of the tool mandrel can be 7 inches (17.78 centimeters) providing an annular cross sectional area of 9¾ inches (24.77 centimeters) OD and 7 inches ID (17.78 centimeters). Any differential pressure will act on this annular area producing a net force in the direction of the pressure gradient equal to the pressure differential times the effective cross sectional area. This net force produces an upward force which can overcome the frictional force applied by the annular BOP closed on the tool&#39;s sleeve causing the sleeve to be pushed in the direction of the net force (or slide through the sealing element of the annular BOP). To resist sliding through the annular BOP, catches can be placed on the sleeve which prevent the sleeve from being pushed through the annular BOP seal. 
     In an of the various embodiments the following differential pressures (e.g., difference between the pressures above and below the annular BOP seal) can be axially placed upon the sleeve or housing against which the catches can be used to prevent the sleeve from being axially pushed out of the annular BOP (even when the annular BOP seal has been closed)—in pounds per square inch: 500, 750, 1000, 1250, 1500, 1750, 2000, 2250, 2500, 2750, 3000, 3250, 3,500, 3750, 4,000, 4,250, 4,500, 4,750, 5,000, or greater (3,450, 5,170, 6,900, 8,620, 10,340, 12,070, 13,790, 15,510, 17,240, 18,960, 20,690, 22,410, 24,130, 25,860, 27,700, 29,550, 31,400, 33,240, 35,090, 36,940 kilopascals). Additionally, ranges between any two of the above specified pressures are contemplated. Additionally, ranges above any one of the above specified pressures are contemplated. Additionally, ranges below any one of the above specified pressures are contemplated. This differential pressures can be higher below the annular BOP seal or above the annular BOP seal. 
     Interchangeable Fittings for the Catches 
     The annular seals and/or physical structure of different types/brands of annular BOPs can be substantially different requiring the use of different catches. To facilitate the use of the rotating and reciprocating tool in different types/brands of annular BOPs, the sleeve can be comprised of a generic or base sleeve with attachable (and/or detachably connectable) specialized annular BOP fittings. In one embodiment, a generic or base sleeve with a generic base catch is provided. However, in one embodiment a plurality of specialized adaptors or catch attachments may be detachably connectable to the generic or base sleeve allowing the conversion of the generic or base sleeve to a specialized sleeve with one or more catches for a particular type/brand of annular BOP. This embodiment avoids the need to manufacture multiple specialized sleeves for a plurality of types/brands of annular BOPs. In one embodiment the specialized adapters can be flange adapters that are designed to fit the closed annular seal and not damage the seal when the sleeve is pushed or pulled against the annular sleeve. 
     Radial Bearings 
     In one embodiment the rotating and reciprocating tool can include large radial bearing capacity, the radial bearings working in an oil bath. The large capacity bearings can address the wiping loads that will exist when the completion string is run at high speeds. 
     Thrust Bearings 
     In one embodiment the rotating and reciprocating tool can include a thrust bearing on its pin end to allow free relative rotation between the mandrel and sleeve even where the completion string with mandrel is pulled up to (and possibly beyond) the upper stroke extent of the rotating and reciprocating tool. The closed annular BOP holds the sleeve rotationally fixed notwithstanding the mandrel being rotated and/or reciprocated and the bottom catch would limit upward movement of the sleeve within the annular BOP. If, for whatever reason, the operator, attempts to pull up the completion string/mandrel to the upper limit of the stroke between the sleeve and mandrel, the sleeve will be pulled up the annular BOP until its lower catch interacts with the annular BOP to prevent further upward movement of the sleeve. At this point a longitudinal thrust load between the sleeve and the mandrel will be created. The thrust bearing will absorb this thrust load while facilitating relative rotation between the sleeve and the mandrel (so that the sleeve can remain rotationally fixed relative to the annular BOP). Without the thrust bearing, frictional and/or other forces between the sleeve and the mandrel caused by the thrust load can cause the sleeve to start rotating along with the mandrel, and then relative to the annular BOP. Relative rotation between the sleeve and annular BOP is not desired as it can cause wear/damage to the annular BOP and/or the annular seal. In one embodiment this thrust bearing is an integral part of a clutch/latch/bearing assembly. 
     In one embodiment the rotating and reciprocating tool can include a thrust bearing on its box end to allow free relative rotation between the mandrel and sleeve even where the completion string with mandrel is pushed down to (and possibly beyond) the lower stroke extent of the rotating and reciprocating tool. The closed annular BOP holds the sleeve rotationally fixed notwithstanding the mandrel being rotated and/or reciprocated and the upper catch would limit downward movement of the sleeve within the annular BOP. If, for whatever reason, the operator, attempts to push down the completion string/mandrel to the lower limit of the stroke between the sleeve and mandrel, the sleeve will be pushed down the annular BOP until its upper catch interacts with the annular BOP to prevent further downward movement of the sleeve. At this point a longitudinal thrust load between the sleeve and the mandrel will be created. The thrust bearing will absorb this thrust load while facilitating relative rotation between the sleeve and the mandrel (so that the sleeve can remain rotationally fixed relative to the annular BOP). Without the thrust bearing, frictional and/or other forces between the sleeve and mandrel caused by the thrust load can cause the sleeve to start rotating along with the mandrel, and then relative to the annular BOP. Relative rotation between the sleeve and annular BOP is not desired as it can cause wear/damage to the annular BOP and/or the annular seal. In one embodiment, this thrust bearing is an outer thrust bearing. 
     Quick Lock/Quick Unlock 
     After the sleeve and mandrel have been moved relative to each other in a longitudinal direction, a downhole/underwater locking/unlocking system is needed to lock the sleeve in a longitudinal position relative to the mandrel (or at least restricting the available relative longitudinal movement of the sleeve and mandrel to a satisfactory amount compared to the longitudinal length of the sleeve&#39;s effective sealing area). Additionally, an underwater locking/unlocking system is needed which can lock and/or unlock the sleeve and mandrel a plurality of times while the sleeve and mandrel are underwater. 
     In one embodiment is provided a system wherein the underwater position of the longitudinal length of the sleeve&#39;s sealing area (e.g., the nominal length between the catches) can be determined with enough accuracy to allow positioning of the sleeve&#39;s effective sealing area in the annular BOP for closing on the sleeve&#39;s sealing area. After the sleeve and mandrel have been longitudinally moved relative to each other when the annular BOP was closed on the sleeve, it is preferred that a system be provided wherein the underwater position of the sleeve can be determined even where the sleeve has been moved outside of the annular BOP. 
     In one embodiment is provided a quick lock/quick unlock system for locating the relative position between the sleeve and mandrel. Because the sleeve can reciprocate relative to the mandrel (i.e., the sleeve and mandrel can move relative to each other in a longitudinal direction), it can be important to be able to determine the relative longitudinal position of the sleeve compared to the mandrel at some point after the sleeve has been reciprocated relative to the mandrel. For example, in various uses of the rotating and reciprocating tool, the operator may wish to seal the annular BOP on the sleeve sometime after the sleeve has been reciprocated relative to the mandrel and after the sleeve has been removed from the annular BOP. 
     To address the risk that the actual position of the sleeve relative to the mandrel will be lost while the tool is underwater, a quick lock/quick unlock system can detachably connect the sleeve and mandrel. In a locked state, this quick lock/quick unlock system can reduce the amount of relative longitudinal movement between the sleeve and the mandrel (compared to an unlocked state) so that the sleeve can be positioned in the annular BOP and the annular BOP relatively easily closed on the sleeve&#39;s longitudinal sealing area. Alternatively, this quick lock/quick unlock system can lock in place the sleeve relative to the mandrel (and not allow a limited amount of relative longitudinal movement). After being changed from a locked state to an unlocked state, the sleeve can experience its unlocked amount of relative longitudinal movement. 
     In one embodiment is provided a quick lock/quick unlock system which allows the sleeve to be longitudinally locked and/or unlocked relative to the mandrel a plurality of times when underwater. In one embodiment the quick lock/quick unlock system can be activated using the annular BOP. 
     In one embodiment the sleeve and mandrel can rotate relative to one another even in both the activated and un-activated states. In one embodiment, when in a locked state, the sleeve and mandrel can rotate relative to each other. This option can be important where the annular BOP is closed on the sleeve at a time when the string (of which the mandrel is a part) is being rotated. Allowing the sleeve and mandrel to rotate relative to each other, even when in a locked state, minimizes wear/damage to the annular BOP caused by a rotationally locked sleeve (e.g., sheer pin) rotating relative to a closed annular BOP. Instead, the sleeve can be held fixed rotationally by the closed annular BOP, and the mandrel (along with the string) rotate relative to the sleeve. 
     In one embodiment, when the locking system of the sleeve is in contact with the mandrel, locking/unlocking is performed without relative rotational movement between the locking system of the sleeve and the mandrel—otherwise scoring/scratching of the mandrel at the location of lock can occur. In one embodiment, this can be accomplished by rotationally connecting to the sleeve the sleeve&#39;s portion of quick lock/quick unlock system. In one embodiment a locking hub is provided which is rotationally connected to the sleeve. 
     In one embodiment a quick lock/quick unlock system on the rotating and reciprocating tool can be provided allowing the operator to lock the sleeve relative to the mandrel when the rotating and reciprocating tool is downhole/underwater. Because of the relatively large amount of possible stroke of the sleeve relative to the mandrel (i.e., different possible relative longitudinal positions), knowing the relative position of the sleeve with respect to the mandrel can be important. This is especially true at the time the annular BOP is closed on the sleeve. The locking position is important for determining relative longitudinal position of the sleeve along the mandrel (and therefore the true underwater depth of the sleeve) so that the sleeve can be easily located in the annular BOP and the annular BOP closed/sealed on the sleeve. 
     During the process of moving the rotating and reciprocating tool underwater and downhole, the sleeve can be locked relative to the mandrel by a quick lock/quick unlock system. In one embodiment the quick lock/quick unlock system can, relative to the mandrel, lock the sleeve in a longitudinal direction. In one embodiment the sleeve can be locked in a longitudinal direction with the quick lock/quick unlock system, but the sleeve can rotate relative to the mandrel during the time it is locked in a longitudinal direction. In one embodiment the quick lock/quick unlock system can simultaneously lock the sleeve relative to the mandrel, in both a longitudinal direction and rotationally. In one embodiment the quick lock/quick unlock system can relative to the mandrel, lock the sleeve rotationally, but at the same time allow the sleeve to move longitudinally. 
     Activation by Relative Longitudinal Movement 
     In one embodiment the quick lock/quick unlock system can be activated (and placed in a locked state) by movement of the sleeve relative to the mandrel in a first longitudinal direction. In one embodiment the quick lock/quick unlock system is deactivated (and placed in an unlocked state) by movement of the sleeve relative to the mandrel in a second longitudinal direction, the second longitudinal direction being substantially in the opposite longitudinal direction compared to the first longitudinal direction. 
     In one embodiment the first longitudinal direction is toward one of the longitudinal ends of the mandrel. In one embodiment the second longitudinal direction is toward the longitudinal center of the mandrel. 
     In one embodiment the quick lock/quick unlock system can be changed from an activated to a deactivated state when the sleeve is at least partially located in the annular BOP. In one embodiment the quick lock/quick unlock system can be changed from a deactivated state to an activated state when the sleeve is at least partially located in the annular BOP. 
     In one embodiment the quick lock/quick unlock system can be changed from an activated to a deactivated state when the annular BOP is closed on the sleeve. In one embodiment the quick lock/quick unlock system can be changed from a deactivated state to an activated state when the annular BOP is closed on the sleeve. 
     In one embodiment the quick lock/quick unlock system can be changed from an activated to a deactivated state when the sleeve is sealed with respect to the annular BOP. 
     In one embodiment the quick lock/quick unlock system can be changed from a deactivated state to an activated state when the sleeve is sealed with respect to the annular BOP. 
     In one embodiment, at a time when the sleeve is at least partially located in the annular BOP, the quick lock/quick unlock system can be activated (and placed in a locked state) by movement of the sleeve relative to the mandrel in a first longitudinal direction to a locking location. In one embodiment, at a time when the sleeve is at least partially located in the annular BOP, the quick lock/quick unlock system is deactivated (and placed in an unlocked state) by movement of the sleeve relative to the mandrel in a second longitudinal direction away from the locking location, the second longitudinal direction being substantially in the opposite direction compared to the first longitudinal direction. 
     In one embodiment, direction at a time when the annular BOP is closed on the sleeve, the quick lock/quick unlock system is activated (and placed in a locked state) by movement of the sleeve relative to the mandrel in a first longitudinal. In one embodiment, at a time when the annular BOP is closed on the sleeve, the quick lock/quick unlock system is deactivated (and placed in an unlocked state) by movement of the sleeve relative to the mandrel in a second longitudinal direction, the second longitudinal direction being substantially in the opposite longitudinal direction compared to the first longitudinal direction. 
     In one embodiment, at a time when the sleeve is sealed with respect to the annular BOP, the quick lock/quick unlock system is activated (and placed in a locked state) by movement of the sleeve relative to the mandrel in a first longitudinal direction. In one embodiment, at a time when the sleeve is sealed with respect to the annular BOP, the quick lock/quick unlock system is deactivated (and placed in an unlocked state) by movement of the sleeve relative to the mandrel in a second longitudinal direction, the second longitudinal direction being substantially in the opposite longitudinal direction compared to the first longitudinal direction. 
     Activation by Moving to a Locking Position 
     In one embodiment, at a time when the sleeve is at least partially located in the annular BOP, the sleeve is moved to a locking position relative to the mandrel. In one embodiment, at a time when the sleeve is at least partially located in the annular BOP, a quick lock/quick unlock system is changed from a deactivated state to an activated state by moving the sleeve to specified locking position on the mandrel. In one embodiment, at a time when the sleeve is at least partially located in the annular BOP, a quick lock/quick unlock system is changed from an activated state to a deactivated activated state by moving the sleeve away from a specified position on the mandrel. 
     In one embodiment, at a time when the annular BOP is closed on the sleeve, the sleeve is moved to a locking position relative to the mandrel. In one embodiment, at a time when the annular BOP is closed on the sleeve, a quick lock/quick unlock system is changed from a deactivated state to an activated state by moving the sleeve to specified locking position on the mandrel. In one embodiment, at a time when the annular BOP is closed on the sleeve, a quick lock/quick unlock system is changed from an activated state to a deactivated activated state by moving the sleeve away from a specified position on the mandrel. 
     In one embodiment, at a time when the sleeve is sealed in the annular BOP, the sleeve is moved to a locking position relative to the mandrel. In one embodiment, at a time when the sleeve is sealed in the annular BOP, a quick lock/quick unlock system is changed from a deactivated state to an activated state by moving the sleeve to specified locking position on the mandrel. In one embodiment, at a time when the sleeve is sealed in the annular BOP, a quick lock/quick unlock system is changed from an activated state to a deactivated activated state by moving the sleeve away from a specified position on the mandrel. 
     Activation by Exceeding a Specified Minimum Locking Force 
     In one embodiment the quick lock/quick unlock system is activated when at least a first specified minimum longitudinal force is placed on the sleeve relative to the mandrel. In one embodiment the first specified minimum longitudinal force is used to determine whether the sleeve is locked relative to the mandrel. That is where the sleeve cannot absorb at least the first specified minimum longitudinal the quick lock/quick unlock system can be considered in a deactivated state. In one embodiment, the specified minimum longitudinal force is a predetermined force. 
     In one embodiment the quick lock/quick unlock system is deactivated when at least a second specified minimum longitudinal force is placed on the sleeve relative to the mandrel. In one embodiment the second specified minimum longitudinal force is used to determine whether the sleeve is locked relative to the mandrel. That is where the sleeve cannot absorb at least the second specified minimum longitudinal the quick lock/quick unlock system can be considered in a deactivated state. In one embodiment the first specified minimum longitudinal force is substantially equal to the second specified minimum longitudinal force. In one embodiment the first specified minimum longitudinal force is substantially greater than the second specified minimum longitudinal force. In one embodiment the first specified minimum longitudinal force takes into account the amount of longitudinal friction between the sleeve and the mandrel. In one embodiment the second specified minimum longitudinal force takes into account the amount of longitudinal friction between the sleeve and the mandrel. In one embodiment both the first specified minimum longitudinal force and the second specified minimum longitudinal force take into account the amount of longitudinal friction between the sleeve and the mandrel. In one embodiment the first specified minimum longitudinal force takes into account the longitudinal force applied to the sleeve based on differing pressures above and below the annular BOP. In one embodiment the second specified minimum longitudinal force takes into account the longitudinal force applied to the sleeve based on differing pressures above and below the annular BOP. In one embodiment both the first specified minimum longitudinal force and the second specified minimum longitudinal force take into account the longitudinal force applied to the sleeve based on differing pressures above and below the annular BOP. 
     Example of a Specified Minimum Locking Force 
     In one example of operation with deep water wells, the annular BOP can be located between 6000 to 7000 feet (1,830 to 2,130 meters) below the rig floor. The quick lock/quick unlock system can be activated by closing the annular BOP on the sleeve and pulling up with a force of approximately 35,000 or 40,000 pounds (156 or 178 kilo newtons). The quick lock/quick unlock system can be de-activated by closing the annular BOP on the sleeve and lowering the mandrel relative to the sleeve. When approximately 35,000 or 40,000 pounds (156 or 178 kilo newtons) of longitudinal force (e.g., exerted by the weight of the string not being supported by the rig) is created between the mandrel and the sleeve, the quick lock/quick unlock system can become deactivated and unlock the sleeve from the mandrel so that the mandrel can be reciprocated relative to the sleeve (where the annular BOP is closed on the sleeve). For this example, the specified minimum differential longitudinal force of 35,000 or 40,000 pounds (156 or 178 kilo newtons) can be used to overcome 5,000 or 10,000 pounds (22 or 45 kilo newtons) of longitudinal friction (such as seal friction) and 30,000 pounds (134 kilo newtons) from the quick lock/quick unlock system. This minimum longitudinal force (e.g., 35,000 or 40,000 pounds (156 or 178 kilo newtons)) can address the risk that the sleeve does not get bumped out of its locked longitudinal position when the sleeve is moved outside of the annular BOP (i.e., unlocking the quick lock/quick unlock system and causing the operator to lose the position of the sleeve relative to the mandrel). The minimum longitudinal force also ensures that the sleeve will not float up/sink down the mandrel as a result of fluid flow around the sleeve when the annular BOP is open (such as when returns are taken up the riser). 
     In another example the longitudinal frictional force (such as seal friction) can be reduced from 10,000 pounds to about 5,000 pounds (45 to 22 kilo newtons)(such as where fluid pressure from above the box end of the sleeve or house is allowed to migrate to the seals on the pin end of the sleeve or housing thereby reducing the net pressure on the seals of the bottom end). In this case a force of approximately 35,000 pounds (156 kilo newtons) would activate the quick lock/quick unlock system. 
     Various Options for Allowable Reciprocation when in a Locked State 
     In one embodiment is provided a quick lock/quick unlock system where the sleeve and mandrel reciprocate relative to each other a specified distance even when locked, however, the amount of relative reciprocation increases when unlocked. In one embodiment the amount of allowable relative reciprocation even in a locked state facilitates operation of a clutching system between the sleeve and mandrel. In one embodiment the amount of allowable relative reciprocation even in a locked state allows relative longitudinal and rotational movement between a locking hub and the sleeve to allow a clutching system to align the hub for interlocking with a fluted area of the mandrel. In one embodiment the amount of allowable relative reciprocation even in a locked state is between 0 and 12 inches (0 and 30.48 centimeters), between 0 and 11 inches (0 and 27.94 centimeters), 10, 9, 8, 7, 6, 5, 4, 3, 2, 1, ¾, ½, ¼, ⅛ inches (25.4, 22.86, 20.32, 17.78, 15.24, 12.7, 10.16, 7.62, 5.08, 2.54, 1.91, 1.27, 0.64, 0.32 centimeters). In one embodiment the amount of allowable relative reciprocation even in a locked state is between ⅛ inch (0.32 centimeters) and any of the specified distances up to 12 inches (30.48 centimeters). In other embodiments the amount of allowable relative reciprocation even in a locked state is between ¼ inches (0.64 centimeters) and any of the specified distances up to 12 inches (30.48 centimeters). In other embodiments the amount of allowable relative reciprocation even in a locked state is between ½, ¾, 1, etc. and any of the specified distances. In other embodiments the amount of allowable relative reciprocation even in a locked state is between any possible permutation of the specified distances. 
     Spring Lock/Unlock 
     In one embodiment a spring and latch quick lock/quick unlock system is provided between the sleeve and the mandrel. The spring can comprise one or more fingers (or a single ring) which detachably connects to a connector located on the mandrel, such as a locking valley. In one embodiment a ramp on the mandrel can be provided facilitating the bending of the one or more fingers (or ring) before they lock/latch into the connecting valley. In one embodiment is provided a backstop to resist longitudinal movement of the sleeve relative to the mandrel after the one or more fingers (or ring) have locked/latched into the valley. 
     In one embodiment is provided a quick lock/quick unlock system which locks and unlocks on a non-fluted area of the mandrel. In one embodiment this system can include a locking hub with fingers which detachably locks on a raised area of the mandrel where the raised area does not include radial discontinuities (e.g., it is not fluted). In one embodiment is provided a locking hub that can rotate relative, but is restricted on the amount of longitudinal movement relative to the sleeve, the rotational movement of the hub with the sleeve reducing rotational wear between the hub and mandrel (as the locking hub can remain rotationally static relative to the sleeve). In one embodiment the locking hub can be restricted from longitudinally moving relative to the sleeve. In one embodiment locking hub can be used without a clutching system. In one embodiment bearing surfaces can be provided between the sleeve and locking hub to facilitate relative rotational movement between the sleeve and the hub. In one embodiment the mandrel is about 7 inches in outer diameter and shoulder area is about 7½ inches (19.05 centimeters). 
     In one embodiment is provided a quick lock/quick unlock system which includes a hub rotationally connected to the sleeve, and the hub can have a plurality of fingers, the mandrel can have a longitudinal bearing area and a locking area (located adjacent to the bearing area). In one embodiment the fingers can pass over the bearing area without touching the bearing area. In one embodiment the fingers can be radially expanded by the locking area, and then lock in the locking area. In one embodiment longitudinal movement of the sleeve relative to the mandrel can be restricted by the shoulder area. In one embodiment longitudinal movement of the hub relative to the mandrel can be restricted by the shoulder area. In one embodiment longitudinal movement of the sleeve relative to the mandrel can be restricted by the shoulder area contacting the hub and the hub contacting thrusting against the sleeve. 
     Fluted Mandrel 
     In one embodiment the pin end of the mandrel can include a plurality of flutes to facilitate fluid flow past the pin end as it passes though the well head. Because of the loads which the pin end of the mandrel is expected to absorb (e.g., the weight of the string and tools located below the mandrel), the mandrel should be designed with sufficient strength to safely absorb these loads. However, the size of the mandrel at the pin end to safely absorb these loads can be such that it tends to severely restrict fluid flow through the wellhead when the pin end of the mandrel passes through the wellhead. That is, the annular space created between the pin end of the mandrel and the inner diameter of the well head is sufficiently small that it can excessively restrict fluid flow through this annular space. This space restriction would only occur at times when the pin end of the mandrel is located at the well head and may not substantially impair the completion operations of many completion operations. However, in an abundance of caution this possible restriction has been addressed by providing a fluted area around the pin end. The fluted area would allow a plurality of flow paths (in the valleys of the flutes) to reduce the resistance to fluid flow when the pin end is within the wellhead. 
     These flutes, however, provide a challenge to the operation of the quick lock/quick unlock system as the flutes provide rotational discontinuities. Because the sleeve and mandrel may be rotating relative to each other at the time that the quick lock/quick unlock system is to be activated (i.e., locked) and/or deactivated (i.e., unlocked), these rotational discontinuities may damage or cause other problems when the locking system is activated and/or deactivated. Because the relative rotational position between the sleeve and the mandrel may not be known at the time of activation/deactivation, a positioning or clutching system can be used to properly align/locate the quick lock/quick unlock system for activation/deactivation. The clutching system can also prevent relative rotation between the locking/unlocking system and the locking area of the mandrel thus resisting scratching/scarring/wearing between these two areas if relative rotation was allowed during locking/unlocking 
     Clutch 
     In one embodiment, to insure that the latch fingers align with the locking grooves in the mandrel, the locking hub can be rotatable relative to the sleeve and clutching guide bosses can be provided on the locking hub. These guide bosses can engage the spaces in the flute grooves and prevent further relative rotation between the locking hub and the mandrel. Furthermore, these guide bosses can align the fingers of the locking hub with the locking areas on the mandrel to set of the predetermined amount of locking force. Without the alignment, the amount of locking force could be changed base on the relative alignment between that fingers and the locking areas of the mandrel (e.g., if only five percent of the fingers are in contact with the mandrel&#39;s locking areas then the locking force would be less than if one hundred percent of the fingers are in contact with the mandrel&#39;s locking areas). The guide bosses can be aligned in the valleys of flutes thereby aligning the fingers of the locking hub with the locking areas on the mandrel. The guide bosses aligning in the valleys can also cause the locking hub to remain rotationally static relative to the mandrel and rotate relative to the sleeve. When the latch fingers contact the upset of the upsets of the latching groove (e.g., latching area) cut in the raised flute of the fluted area of the mandrel, the latch fingers push the longitudinally and rotationally floating thrust hub longitudinally up against the bearing surface of the sleeve&#39;s pin end. As the pin end of the mandrel continues to move longitudinally towards the center of the sleeve, the latch fingers are forced over the upsets of the latching groove and into the groove. A little further movement makes the leading beveled ends of the raised flutes contact the locking hub (which hub is now in contact with the bearing area of the sleeve) which transfers further upward mandrel load to the sleeve through the thrust bearing of the locking hub. 
     Additional Clearance Design for High Pressures 
     In one embodiment the rotating and reciprocating tool is designed to work under high external pressure. This design requires that fits be allowed with sufficient clearance at sea level so that when the tool reaches its working depth and pressures the proper manufacturing clearances exist. In order to accomplish this dimensional changes to the sleeve and mandrel based on the change in external pressure from the surface to the sea floor are taken into account. 
     In another embodiment, the rotating and reciprocating tool is designed to allow fluid pressure to migrate from the box end to the pin end to reduce the net pressure in bending on the interior and exterior of the sleeve along with the net pressure in bending on the interior and exterior of the mandrel. 
     General Method Steps 
     In one embodiment the method can comprise the following steps: 
     (a) lowering the rotating and reciprocating tool to the annular BOP, the tool comprising a sleeve and mandrel; 
     (b) after step “a”, having the annular BOP close on the sleeve; 
     (c) after step “b”, causing relative longitudinal movement between the sleeve and the mandrel; 
     (d) after step “c”, moving the sleeve outside of the annular BOP; 
     (e) after step “d”, moving the sleeve inside of the annular BOP and having the annular BOP close on the sleeve; 
     (f) after step “e”, causing relative longitudinal movement between the sleeve and the mandrel. 
     In one embodiment, during step “a”, the sleeve is longitudinally locked relative to the mandrel. 
     In one embodiment, after step “b”, the sleeve is unlocked longitudinally relative to the mandrel. 
     In one embodiment, after step “c”, the sleeve is longitudinally locked relative to the mandrel. 
     In one embodiment, during step “c” operations are performed in the wellbore. 
     In one embodiment, during step “f” operations are performed in the wellbore. 
     In one embodiment, during step “c” the tool is fluidly connected to a string having a bore and fluid is pumped through at least part of the string&#39;s bore. 
     In one embodiment, during step “f” the tool is fluidly connected to a string having a bore and fluid is pumped through at least part of the string&#39;s bore. 
     In one embodiment, during step “c” the tool is fluidly connected to a string having a bore and fluid is pumped through at least part of the string&#39;s bore and a jetting tool is used to jet a portion of the wellbore, BOP, and/or riser. In one embodiment the jetting tool is a SABS jetting tool. 
     In one embodiment, during step “f” the tool is fluidly connected to a string having a bore and fluid is pumped through at least part of the string&#39;s bore and a jetting tool is used to jet a portion of the wellbore, BOP, and/or riser. In one embodiment the jetting tool is a SABS jetting tool. 
     In one embodiment, longitudinally locking the sleeve relative to the mandrel shortens an effective stroke length of the sleeve from a first stroke to a second stroke. 
     In one embodiment, during step “a”, the mandrel can freely rotate relative to the sleeve. 
     In one embodiment, after step “b”, the mandrel can freely rotate relative to the sleeve. 
     In one embodiment, after step “c”, the mandrel can freely rotate relative to the sleeve. 
     (Longer to Shorter) In one embodiment, while underwater, the sleeve is changed from a state of having a first length of longitudinal stroke relative to the mandrel to a state of having a second length of longitudinal stroke relative to the mandrel, the second length of longitudinal stroke being shorter than the first length of longitudinal stroke. In one embodiment the second length of longitudinal stroke is substantially zero. In one embodiment the changing of states in longitudinal stroke is accomplished at a time when the annular BOP is closed on the sleeve. In one embodiment, subsequent to the change in states of longitudinal strokes, the sleeve is moved out of the annular BOP (either lowered from and/or raised out of the annular BOP). 
     (Shorter to Longer) In one embodiment, while underwater and subsequent to the change in state from the first to second longitudinal strokes, the sleeve is changed back from the state of having the second length of longitudinal stroke relative to the mandrel to the state of having the first length of longitudinal stroke relative to the mandrel. In one embodiment the changing of states in longitudinal stroke is accomplished at a time when the annular BOP is closed on the sleeve. In one embodiment, subsequent to the change back in state from the second to the first longitudinal strokes, the mandrel is reciprocated and/or rotated relative to the sleeve while the annular BOP is closed on the sleeve. In one embodiment, subsequent to the change in states of longitudinal strokes, the sleeve is moved out of the annular BOP (either lowered from and/or raised out of the annular BOP). 
     (Longer to Shorter) In one embodiment the sleeve, while underwater and subsequent to the change in state from second to first lengths of longitudinal strokes, the state of longitudinal stroke is changed again from the first to the second lengths. In one embodiment the changing of states in longitudinal stroke is accomplished at a time when the annular BOP is closed on the sleeve. In one embodiment, subsequent to the change in states of longitudinal strokes, the sleeve is moved out of the annular BOP (either lowered from and/or raised out of the annular BOP). 
     (Shorter to Longer) In one embodiment, while underwater and subsequent to the changes in state from the first to second, second to first, and first to second longitudinal strokes, the sleeve is changed back from the state of having the second length of longitudinal stroke relative to the mandrel to the state of having the first length of longitudinal stroke relative to the mandrel. In one embodiment the changing of states in longitudinal stroke is accomplished at a time when the annular BOP is closed on the sleeve. In one embodiment, subsequent to the change back in state from the second to the first longitudinal strokes, the mandrel is reciprocated and/or rotated relative to the sleeve while the annular BOP is closed on the sleeve. In one embodiment, subsequent to the change in states of longitudinal strokes, the sleeve is moved out of the annular BOP (either lowered from and/or raised out of the annular BOP). 
     In any of the various embodiments disclosed herein, while underwater the entire time, the sleeve is changed between the first and second states of longitudinal strokes (from the first to the second or from the second to the first) 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 23, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, 36, 37, 38, 39, 40, 41, 42, 43, 44, 45, 46, 47, 48, 49, 50, or more times, or any range between, below, or above any of the above specified number of times. These options of changing from states while underwater is assisted by the quick lock/quick unlock system. 
     SAB&#39;s Jetting Tool 
     In one embodiment the sleeve at the pin end has beveled edge that matches the well head bushing. This can be helpful where the operator lowers rotating and reciprocating tool with the sleeve locked on the mandrel to a point where it contacts the wellhead bushing. The beveled edge of the end of the sleeve will allow it to rest safely on the wellhead bushing until the wellhead bushing provides a large enough longitudinal force on the sleeve to cause the quick lock/quick unlock system deactivate and enter an unlocked state allowing the sleeve to move longitudinally relative to the mandrel and limit the reactive force placed on the wellhead bushing preventing damage to the wellhead bushing. Additionally, the matching bevel of the sleeve with the bevel of the wellhead prevents the sleeve from getting stuck in the well head bushing. 
     To provide the completion engineers with the flexibility: 
     (a) to use the rotating and reciprocating tool while the annular BOP is sealed on the sleeve and while taking return flow up the choke or kill line (i.e., around the annular BOP); or 
     (b) to open the annular BOP and take returns up the subsea riser (i.e., through the annular BOP); or 
     (c) to open the annular BOP and move the completion string with the attached rotating and reciprocating tool out of the annular BOP (such as where the completion engineer wishes to use the SABs jetting tool to jet the BOP stack or perform other operations required the completion string to be raised to a point beyond where the effective stroke capacity of the rotating and reciprocating tool can absorb the upward movement by the sleeve moving longitudinally relative to the mandrel) and, at a later point in time, reseal the annular BOP on the sleeve of the rotating and reciprocating tool. 
     The drawings constitute a part of this specification and include exemplary embodiments to the invention, which may be embodied in various forms. 
    
    
     
       BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS 
       For a further understanding of the nature, objects, and advantages of the present invention, reference should be had to the following detailed description, read in conjunction with the following drawings, wherein like reference numerals denote like elements and wherein: 
         FIGS. 1-1A  are schematic diagrams showing a deep water drilling rig with riser and annular blowout preventer; 
         FIG. 2  is another schematic diagram of a deep water drilling rig showing a swivel detachably connected to an annular blowout preventer (a second annular blowout preventer is also shown); 
         FIG. 3  is a schematic diagram of one embodiment of a reciprocating and/or rotating swivel; 
         FIGS. 4A through 4C  are schematic diagrams illustrating reciprocating motion of a drill or well string through an annular blowout preventer; 
         FIG. 5  is a side view of a swivel where sections from the upper and lower portions of the mandrel have been omitted in order to show in a single figure (to scale) the entire swivel; 
         FIG. 6  is a sectional side view of the swivel in  FIG. 5  where part of the sleeve or housing has been removed; 
         FIG. 7  is a sectional view of the bottom portion of the swivel of  FIG. 5  where part of the sleeve or housing has been removed; 
         FIG. 8  is a sectional view of the top portion of the swivel of  FIG. 5  where part of the sleeve or housing has been removed; 
         FIG. 9  is a perspective view of the bottom portion of the swivel of  FIG. 5  where the sleeve or housing has been moved to the bottom portion of the mandrel; 
         FIG. 10  is a sectional view of the swivel shown in  FIG. 9  where part of the sleeve or housing has been removed to show various internal components; 
         FIG. 11  is a perspective view of the top portion of the swivel of  FIG. 5  where the sleeve or housing has been moved to the top portion of the mandrel; 
         FIG. 12  is a sectional view of the swivel shown in  FIG. 11  where part of the sleeve or housing has been removed to show various internal components; 
         FIG. 13  is a perspective view of a mandrel for the swivel of  FIG. 5 ; 
         FIG. 14  is a sectional view of the middle portion of the mandrel of  FIG. 13 ; 
         FIG. 15  is a sectional view of the upper portion of the mandrel of  FIG. 13 ; 
         FIG. 16  is a sectional view of the bottom portion of the mandrel of  FIG. 13 ; 
         FIG. 17  is a view of the sleeve or housing for the mandrel of  FIG. 5  with end caps attached; 
         FIG. 18  is a sectional view of the sleeve or housing of  FIG. 17  showing various components; 
         FIG. 19  is a sectional view of the sleeve or housing for the mandrel of  FIG. 5  with all attachments removed; 
         FIG. 20  is a sectional view of the upper portion of the sleeve or housing of  FIG. 17 ; 
         FIG. 21  is a sectional view of the lower portion of the sleeve or housing of  FIG. 17 ; 
         FIG. 22  is a sectional view showing one embodiment for the bearing and packing assembly for the swivel of  FIG. 5 ; 
         FIG. 23  is a perspective view of a bearing or bushing shown in  FIG. 22 ; 
         FIG. 24  is a perspective view of the packing housing shown in  FIG. 22 ; 
         FIG. 25  is a perspective view of the packing housing shown in  FIG. 22 ; 
         FIG. 26  is a perspective view of a spacer for the bearing and packing assembly shown in  FIG. 22 ; 
         FIG. 27  is a perspective view of female packing ring for the bearing and packing assembly shown in  FIG. 22 ; 
         FIG. 28  is a perspective view of a packing ring for the bearing and packing assembly shown in  FIG. 22 ; 
         FIG. 29  is a perspective view of a male packing ring for the bearing and packing assembly shown in  FIG. 22 ; 
         FIG. 30  is a perspective view of a packing nut for the bearing and packing assembly shown in  FIG. 22 ; 
         FIG. 31  is a perspective view of a retainer plate for the bearing and packing assembly shown in  FIG. 22 ; 
         FIG. 32  is a sectional perspective view of a bearing cap for the upper end of the sleeve or housing shown in  FIG. 17 ; 
         FIG. 33  is a sectional perspective view of the bearing housing for the lower end cap of the sleeve or housing shown in  FIG. 17 ; 
         FIG. 34  is a sectional perspective view of a bearing thrust plate for the lower end of the sleeve or housing shown in  FIG. 17 ; 
         FIG. 35  is a sectional perspective view of a cap for the lower end of the sleeve or housing shown in  FIG. 17 ; 
         FIG. 36  is a sectional view of showing the sleeve or housing of  FIG. 17  shear pinned to the lower end of the mandrel; 
         FIG. 37  is an enlarged sectional perspective view showing the sleeve or housing pinned to the mandrel at the lower end of the mandrel; 
         FIG. 38  is a sectional perspective view showing the sleeve or housing for the swivel of  FIG. 5  entering the annular blowout preventer where the mandrel is pinned to the sleeve or housing; 
         FIG. 39  is a sectional perspective view showing the sleeve or housing for swivel of  FIG. 5  in a working position inside the annular blowout preventer (annular seal omitted for clarity) and the mandrel extended downstream of the sleeve or housing; 
         FIG. 40  is a sectional perspective view showing the swivel of  FIG. 5  leaving the annular blowout preventer; 
         FIG. 41  is a sectional perspective view showing the swivel of  FIG. 5  moving down the stack towards the well head; 
         FIG. 42  is a sectional perspective view showing the swivel of  FIG. 5  contacting the well head; 
         FIG. 43  also shows the swivel of  FIG. 5  contacting the top of the well head; 
         FIG. 44  is a perspective view of a pressure testing apparatus with part of the end sleeve or housing removed to show internal components; 
         FIGS. 45 through 47  illustrate one embodiment where a quick lock/quick unlock system is placed in a locked state. 
         FIGS. 48 through 50  illustrate one embodiment where a quick lock/quick unlock system is placed in an unlocked locked state. 
         FIG. 51  is an enlarged view of the apparatus in  FIG. 45 . 
         FIG. 52  is a perspective view of the apparatus in  FIG. 45 . 
         FIG. 53  is an enlarged perspective view of the apparatus of  FIG. 49  wherein a section is cut through the sleeve. 
         FIG. 54  is a perspective view of the apparatus of  FIG. 47 . 
         FIG. 55  is a sectional view of the apparatus of  FIG. 45  where the locking hub has been removed to better show various components. 
         FIG. 56  is a perspective view of a locking hub. 
         FIG. 57  is a sectioned perspective view of the locking hub of  FIG. 56 . 
         FIGS. 58 through 60  show various embodiments of a generic sleeve with specialized removable adaptors for different annular BOPs. 
         FIG. 61  is an exploded perspective view of one specialized removable adaptor for an annular BOP. 
         FIG. 62  is an exploded perspective view of a second specialized removable adaptor for a second annular BOP. 
         FIG. 63  is a perspective view of the specialized removable adaptor attached to the sleeve. 
         FIG. 64  is a schematic diagram illustrating one embodiment of the method and apparatus. 
         FIG. 65  is a sectional perspective view of the upper part of an alternative rotating and reciprocating swivel with alternative packing assembly. 
         FIG. 66  is a closeup view of the swivel of  FIG. 65 . 
         FIG. 67  is a sectional perspective view of the packing unit for the swivel of  FIG. 65 . 
         FIG. 68  is a sectional perspective view of the upper part of an alternative swivel with alternative packing assembly. 
         FIG. 69  is a closeup view of the swivel of  FIG. 68 . 
         FIG. 70  is a sectional perspective view of the packing unit for the swivel of  FIG. 68 . 
     
    
    
     DETAILED DESCRIPTION 
       FIGS. 1 and 2  show generally the preferred embodiment of the apparatus of the present invention, designated generally by the numeral  10 . Drilling apparatus  10  employs a drilling platform S that can be a floating platform, spar, semi-submersible, or other platform suitable for oil and gas well drilling in a deep water environment. For example, the well drilling apparatus  10  of  FIGS. 1 and 2  and related method can be employed in deep water of for example deeper than 5,000 feet (1,500 meters), 6,000 feet (1,800 meters), 7,000 feet (2,100 meters), 10,000 feet (3,000 meters) deep, or deeper. 
     In  FIGS. 1A and 2 , an ocean floor or seabed  87  is shown. Wellhead  88  is shown on seabed  11 . One or more blowout preventers can be provided including stack  75  and annular blowout preventer  70 . The oil and gas well drilling platform S thus can provide a floating structure S having a rig floor F that carries a derrick and other known equipment that is used for drilling oil and gas wells. Floating structure S provides a source of drilling fluid or drilling mud  22  contained in mud pit MP. Equipment that can be used to recirculate and treat the drilling mud can include for example a mud pit MP, shale shaker SS, mud buster or separator MB, and choke manifold CM. 
     An example of a drilling rig and various drilling components is shown in FIG. 1 of U.S. Pat. No. 6,263,982 (which patent is incorporated herein by reference). In  FIGS. 1 ,  1 A, and  2  conventional slip or telescopic joint SJ, comprising an outer barrel OB and an inner barrel IB with a pressure seal therebetween can be used to compensate for the relative vertical movement or heave between the floating rig S and the fixed subsea riser R. A Diverter D can be connected between the top inner barrel IB of the slip joint SJ and the floating structure or rig S to control gas accumulations in the riser R or low pressure formation gas from venting to the rig floor F. A ball joint BJ between the diverter D and the riser R can compensate for other relative movement (horizontal and rotational) or pitch and roll of the floating structure S and the riser R (which is typically fixed). 
     The diverter D can use a diverter line DL to communicate drilling fluid or mud from the riser R to a choke manifold CM, shale shaker SS or other drilling fluid or drilling mud receiving device. Above the diverter D can be the flowline RF which can be configured to communicate with a mud pit MP. A conventional flexible choke line CL can be configured to communicate with choke manifold CM. The drilling fluid or mud can flow from the choke manifold CM to a mud-gas buster or separator MB and a flare line (not shown). The drilling fluid or mud can then be discharged to a shale shaker SS, and mud pits MP. In addition to a choke line CL and kill line KL, a booster line BL can be used. 
       FIG. 2  is an enlarged view of the drill string or work string  60  that extends between rig  10  and seabed  87  having wellhead  88 . In  FIG. 2 , the drill string or work string  60  is divided into an upper drill or work string  85  and a lower drill or work string  86 . Upper string  85  is contained in riser  80  and extends between well drilling rig S and swivel  100 . An upper volumetric section  90  is provided within riser  80  and in between drilling rig  10  and swivel  100 . A lower volumetric section  92  is provided in between wellhead  88  and swivel  100 . The upper and lower volumetric sections  90 ,  92  are more specifically separated by annular seal unit  71  that forms a seal against sleeve  300  of swivel  100 . Blowout preventer  70  is positioned at the bottom of riser  80  and above stack  75 . A well bore  40  extends downwardly from wellhead  88  and into seabed  87 . Although shown in  FIG. 2 , in many of the figures the lower completion or drill string  86  (which would be connected to and supported by pin end  150  of mandrel  110 ) has been omitted for purposes of clarity. 
     After drilling operations, when preparing the wellbore  40  and riser R for production, it is desirable to remove the drilling fluid or mud. Removal of drilling fluid or mud is typically done through displacement by a completion fluid. Because of its relatively high cost, this drilling fluid or drilling mud is typically recovered for use in another drilling operation. Displacing the drilling fluid or mud in multiple sections is desirable because the amount of drilling fluid or mud to be removed during completion is typically greater than the storage space available at the drilling rig S for either completion fluid and/or drilling fluid or drilling mud. 
     In deep water settings, after drilling is stopped, the total volume of drilling fluid or drilling mud in the well bore  40  and the riser R can be in excess of the storage capacity of the rig S. Many rigs S do not have the capacity for storing this total volume of drilling mud and/or supplying the total volume of completion fluid when displacing in one step the total volume of drilling fluid or drilling mud in the well bore  40  and riser R. Accordingly, displacement is typically done in two or more stages. Additionally, displacing in two stages is believed to reduce the total volume of completion fluid required versus that required in a single stage displacement. Furthermore, logistical benefits can be obtained by displacing in two stages by dealing with smaller volumes of displacement fluid in each stage along with the ability to prepare certain operations for the second displacement stage simultaneously with displacing the first stage. Additionally, where a problem occurs during one of the stages only the fluid impacted by that stage need be addressed which is a smaller volume than the fluid for displacing riser and well bore in a single stage. 
     Where the displacement process is performed in two or more stages, there is a risk that, during the time period between stages, the displacing fluid will intermix or interface with the drilling fluid or mud thereby causing the drilling fluid or mud to be unusable or require extensive and expensive reclamation efforts before being usable. 
     Detailed descriptions of one or more preferred embodiments are provided herein. It is to be understood, however, that the present invention may be embodied in various forms. Therefore, specific details disclosed herein are not to be interpreted as limiting, but rather as a basis for the claims and as a representative basis for teaching one skilled in the art to employ the present invention in any appropriate system, structure or manner. 
       FIGS. 1-1A  are schematic views showing oil and gas well drilling rig  10  connected to riser  80  and having annular blowout preventer  70  (commercially available).  FIG. 2  is a schematic view showing rig  10  with swivel  100  separating upper drill or well string  85  and lower drill or well string  86 . Swivel  100  is shown detachably connected to annular blowout preventer  70  through annular packing unit seal  71 .  FIG. 3  is a schematic diagram of one embodiment of a swivel  100  which can rotate and/or reciprocate. With such construction drill or well string  85 ,  86  can be rotated and/or reciprocated while annular blowout preventer  70  is sealed around swivel  100  thereby separating a fluid in riser R into upper and lower longitudinal sections.  FIGS. 4A through 4C  are schematic diagrams illustrating reciprocating motion of drill or well string  85 , 86  through annular blowout preventer  70 . 
     Swivel  100  can be seen in more detail in  FIG. 3 . Swivel  100  includes a sleeve or housing  300 . Mandrel  110  is contained within a bore of sleeve  300  (see  FIGS. 7 and 8 ).  FIG. 3  shows a fragmentary view of the preferred embodiment of the apparatus of the present invention, particularly illustrating swivel  100 . Swivel  100  includes an outer sleeve or housing  300  having a generally vertically oriented open-ended bore that is occupied by mandrel  110 . Mandrel  110  provides upper and lower end portions. The upper end portion has joint of pipe  700  and enlarged area  730 . The lower end portion of mandrel  110  has fluted area  135  and saver sub  800  (see  FIG. 13 ). Joint of pipe  700  and enlarged area  730  provide frustoconical area  740 , protruding section  750 , and upper portion  710  of joint of pipe  700  (see  FIG. 15 ). 
     In  FIG. 3 , sleeve  300  provides upper radiused area  332  that connects with base  331 . Sleeve  300  also provides lower radiused area  342  that is connected to lower base  341 . Upper catch, shoulder or flange  326  is connected to upper base  331 . Similarly, lower catch, shoulder or flange  328  connects to lower base  341 . Upper retainer cap  400  is connected to upper catch, shoulder or flange  326  while lower retainer cap  500  is connected to lower catch, shoulder or flange  328  as shown. In  FIG. 3 ,  410  designates the tip of retainer cap  400 . In  FIG. 3 , the numeral  520  designates the tip of retainer cap  500 . The base  530  of retainer cap  500  defines the connection with lower catch, shoulder or flange  328 . 
       FIGS. 3 and 4A  through  4 C schematically illustrating reciprocating motion of sleeve or housing  300  relative to mandrel  110 . The length  180  of mandrel  110  compared to the overall length  350  of sleeve or housing  300  can be configured to allow sleeve or housing  300  to reciprocate (e.g., slide up and down) relative to mandrel  110 .  FIGS. 4A through 4C  are schematic diagrams illustrating reciprocation and/or rotation between sleeve or housing  300  along mandrel  110  (allowing reciprocation and/or rotation between drill or work string  85 , 86  at a time when the volume of fluid is desireably to be separated into two volumetric sections by the closing of annular blowout preventer  70 . 
     In  FIG. 4A , arrow  113  schematically indicates that mandrel  110  is moving downward relative to sleeve or housing  300 . Arrows  114  and  115  in  FIGS. 4B-4C  schematically indicate upward movement of mandrel  110  relative to sleeve or housing  300 . In  FIGS. 4A and 4C , arrows  116  and  118  schematically indicate counterclockwise rotation between mandrel  110  and sleeve or housing  300 . In  FIG. 4B , arrow  117  schematically indicates clockwise rotation between mandrel  110  and sleeve or housing  300 . The change in direction between arrows  113  and  114 , 115  schematically indicates a reciprocating motion. The change in direction between arrows  116 , 118  and  117  schematically indicates an alternating type of rotational movement. 
     Swivel  100  can be made up of mandrel  110  to fit in line of a drill or work string  85 , 86  and sleeve or housing  300  with a seal and bearing system to allow for the drill or work string  85 ,  86  to be rotated and reciprocated while swivel  100  where annular seal unit  71  (see  FIGS. 2 ,  4 A- 4 C) separates the fluid column in riser  80  from the fluid column in wellbore  40 . This can be achieved by locating swivel  100  in the annular blow out preventer  70  where annular seal unit  71  can close around sleeve or housing  300  forming a seal between sleeve or housing  300  and annular seal unit  71 , as seen in  FIGS. 2 ,  4 A- 4 C, and the sealing system between sleeve or housing  300  and mandrel  110  of swivel  100  forming a seal between sleeve or housing  300  and mandrel  110 , thus separating the two fluid columns  90 ,  92  (above and below annular seal unit  71 ) allowing the fluid columns  90 ,  92  to be displaced individually. 
     In deep water settings, after drilling is stopped the total volume of drilling fluid  22  in the well bore  40  and the riser  80  can be in excess of about 5,000 barrels. This drilling fluid or mud  22  must be removed to ready the well for completion (usually ultimately replaced by a completion fluid). Because of its relatively high cost this drilling fluid or mud  22  is typically recovered for use in another drilling operation. Removal of drilling fluid or mud  22  is typically done through displacement by a completion fluid  96  or displacement fluid  94 . However, many rigs  10  do not have the capacity to store and/or supply 5,000 plus barrels of completion fluid  96 , displacement fluid  94 , and/or drilling fluid or mud  22  and thereby displace “in one step” the total volume of drilling fluid or mud  22  in the well bore  40  and riser  80  volumes. Accordingly, the displacement process is done in two or more stages. However, where the displacement process is performed in two or more stages, there is a high risk that, during the time period between the stages, the displacing fluid  94  and/or completion fluid  96  will intermix and/or interface with the drilling fluid or mud  22  thereby causing the drilling fluid or mud  22  to be unusable or require extensive and expensive reclamation efforts before being used again. 
     Additionally, it has been found that, during displacement of the drilling fluid or mud  22 , rotation of the drill or well string  85 ,  86  causes a rotation of the drilling fluid or mud  22  in the riser  80  and well bore  40  and obtains a better overall recovery of the drilling fluid or mud  22  and/or completion of the well. Additionally, during displacement there may be a need to move in a vertical direction (e.g., reciprocate) and/or rotate the drill or well string  85 , 86  while performing displacement and/or completion operations, such as cleaning, scraping, and/or brushing the sides of the well bore. 
     In one embodiment the riser  80  and well bore  40  can be separated into two volumetric sections  90 ,  92  (e.g., 2,500 barrels each) where the rig  10  can carry a sufficient amount of displacement fluid  94  and/or completion fluid  96  to remove each section without stopping during the displacement process. In one embodiment, fluid removal of the two volumetric sections  90 ,  92  in stages can be accomplished, but there is a break of an indefinite period of time between stages (although this break may be of short duration). 
     In one embodiment swivel  100  is provided which can be detachably connected to an annular blowout preventer  70  thereby separating the drilling fluid or mud  22  into upper and lower sections  90 ,  92  (roughly in the riser  80  and well bore  40 ) and allowing the or mud  22  to be removed in two stages while the drill or well string  85 , 86  is rotated and/or reciprocated. 
     In one embodiment, at least partly during the time the riser  80  and well bore  40  are separated into two volumetric sections, the drill or well string  85 , 86  is reciprocated longitudinally during displacement. In one embodiment, at least partly during the time the riser  80  and well bore  40  are separated into two volumetric sections, the drill or well string  85 ,  86  is intermittently reciprocated longitudinally during displacement of fluid. 
     In one embodiment, at least partly during the time the riser  80  and well bore  40  are separated into two volumetric sections, the drill or well string  85 ,  86  is continuously reciprocated longitudinally during displacement. In one embodiment, at least partly during the time the riser  80  and well bore  40  are separated into two volumetric sections, the drill or well string  85 ,  86  is reciprocated longitudinally the distance of at least the length of one joint of pipe during displacement of fluid. 
     In one embodiment, at least partly during the time the riser  80  and well bore  40  are separated into two volumetric sections, the drill or well string  85 ,  86  is rotated during displacement of fluid. In one embodiment, at least partly during the time the riser  80  and well bore  40  are separated into two volumetric sections, the drill or well string  85 ,  86  is intermittently rotated during displacement of fluid. In one embodiment, at least partly during the time the riser  80  and well bore  40  are separated into two volumetric sections, the drill or well string  85 ,  86  is continuously rotated during displacement of fluid. 
     In one embodiment, at least partly during the time the riser  80  and well bore  40  are separated into two volumetric sections, the drill or well string  85 , 86  is alternately rotated during displacement of fluid. In one embodiment, at least partly during the time the riser  80  and well bore  40  are separated into two volumetric sections, the direction of rotation of the drill or well string  85 ,  86  is changed during displacement of fluid. 
     In  FIGS. 1-3 ,  4 A- 4 C swivel  100  can also be used for reverse displacement in which the fluid is pumped in through the choke/kill lines down the annular of wellbore  40  and back up drill workstring  85 , 86 . This process would help to remove items and/or debris which had fallen to the bottom of wellbore  40  that are difficult to remove using forward displacement (where the fluid is pumped down the workstring  85 , 86  displacing up through the annular to the choke/kill lines). 
     The amount of reciprocation (or stroke) can be controlled by the difference between the length of mandrel  110  and the length  350  of the sleeve or housing  300 . As shown in  FIG. 3 , the stroke of swivel  100  can be the difference between height H  180  of mandrel  110  and length L 1   350  of sleeve or housing  300 . In one embodiment height H  180  can be about eighty feet (24.38 meters) and length L 1   350  can be about eleven feet (3.35 meters). In other embodiments the length L 1   350  can be about 1 foot (30.48 centimeters), about 2 feet (60.98 centimeters), about 3 feet (91.44 centimeters), about 4 feet (122.92 centimeters), about 5 feet (152.4 centimeters), about 6 feet (183.88 centimeters), about 7 feet (213.36 centimeters), about 8 feet (243.84 centimeters), about 9 feet (274.32 centimeters), about 10 feet (304.8 centimeters), about 12 feet (365.76 centimeters), about 13 feet (396.24 centimeters), about 14 feet (426.72 centimeters), about 15 feet (457.2 centimeters), about 16 feet (487.68 centimeters), about 17 feet (518.16 centimeters), about 18 feet (548.64 centimeters), about 19 feet (579.12 centimeters), and about 20 feet (609.6 centimeters) (or about midway spaced between any of the specified lengths). In various embodiments, the length of the swivel&#39;s sleeve or housing  300  compared to the length H 180  of its mandrel  110  is between two and thirty times. Alternatively, between two and twenty times, between two and fifteen times, two and ten times, two and eight times, two and six times, two and five times, two and four times, two and three times, and two and two and one half times. Also alternatively, between 1.5 and thirty times, 1.5 and twenty times, 1.5 and fifteen times, 1.5 and ten times, 1.5 and eight times, 1.5 and six times, 1.5 and five times, 1.5 and four times, 1.5 and three times, 1.5 and two times, 1.5 and two and one half times, and 1.5 and two times. 
     In various embodiments, at least partly during the time the riser  80  and well bore  40  are separated into two volumetric sections, the drill or well string  85 , 86  is reciprocated longitudinally the distance of at least about ½ inch (1.27 centimeters), about 1 inch (2.54 centimeters), about 2 inches (5.04 centimeters), about 3 inches (7.62 centimeters), about 4 inches (10.16 centimeters), about 5 inches (12.7 centimeters), about 6 inches 15.24 centimeters), about 1 foot (30.48 centimeters), about 2 feet (60.96 centimeters), about 3 feet (91.44 centimeters), about 4 feet (1.22 meters), about 6 feet (1.83 meters), about 10 feet (3.048 meters), about 15 feet (4.57 meters), about 20 feet (6.096 meters), about 25 feet (7.62 meters), about 30 feet (9.14 meters), about 35 feet (10.67 meters), about 40 feet (12.19 meters), about 45 feet (13.72 meters), about 50 feet (15.24 meters), about 55 feet (16.76 meters), about 60 feet (18.29 meters), about 65 feet (19.81 meters), about 70 feet (21.34 meters), about 75 feet (22.86 meters), about 80 feet (24.38 meters), about 85 feet (25.91 meters), about 90 feet (27.43 meters), about 95 feet (28.96 meters), about 100 feet (30.48 meters), and/or between the range of each or a combination of each of the above specified distances. 
       FIGS. 3 ,  4 A- 4 C,  5  through  12  show one embodiment of swivel  100 .  FIG. 5  is a side view of swivel  100  where sections from the upper and lower portions of mandrel  110  have been omitted to show swivel  100  in a single figure.  FIG. 6  is a sectional side view of swivel  100  where part of the sleeve or housing  300  has been removed.  FIG. 7  is a sectional view of the bottom portion of the swivel  100 .  FIG. 8  is a sectional view of the top portion of swivel  100 .  FIG. 9  is a perspective view of the bottom portion of the swivel of  FIG. 5  where sleeve or housing  300  has been moved to the bottom portion of mandrel  110 .  FIG. 10  is a sectional view of swivel  100  where part of the sleeve or housing  300  has been removed to show various internal components.  FIG. 11  is a perspective view of the top portion of swivel  100  where sleeve or housing  300  has been moved to the upper portion  120  of mandrel  110 .  FIG. 12  is a sectional view of swivel  100  where part of sleeve or housing  300  has been removed to show various internal components. 
     Swivel  100  can be comprised of mandrel  110  and sleeve or housing  300 . Sleeve or housing  300  can be rotatably, reciprocably, and/or sealably connected to mandrel  110 . Accordingly, when mandrel  110  is rotated and/or reciprocated sleeve or housing  300  can remain stationary to an observer insofar as rotation and/or reciprocation is concerned. Sleeve or housing  300  can fit over mandrel  110  and can be rotatably, reciprocably, and sealably connected to mandrel  110 . 
     In  FIG. 3 , sleeve or housing  300  can be rotatably connected to mandrel  110  by one or more bushings and/or bearings  1100 , preferably located on opposed longitudinal ends of sleeve or housing  300 . 
     In  FIG. 3 , sleeve or housing  300  can be sealingly connected to mandrel  110  by a one or more seals, preferably located on opposed longitudinal ends of sleeve or housing  300 . The seals can seal the gap  315  between the interior  310  of sleeve or housing  300  and the exterior of mandrel  110 . 
     In  FIG. 3 , sleeve or housing  300  can be reciprocally connected to mandrel  110  through the geometry of mandrel  110  which can allow sleeve or housing  300  to slide relative to mandrel  110  in a longitudinal direction (such as by having a longitudinally extending distance H  180  of the exterior surface of mandrel  110  a substantially constant diameter). 
     In  FIG. 3 , bushings and/or bearings  1100  can include annular bearings, tapered bearings, ball bearings, teflon bearing sleeves, and/or bronze bearing sleeves, allowing for low friction levels during rotating and/or reciprocating procedures. 
     The various components of swivel  100  will be individually described below. 
     Mandrel 
       FIG. 13  is a perspective view of mandrel  110 .  FIG. 14  is a sectional view of the middle portion of mandrel  110 .  FIG. 15  is a sectional view of the upper portion of mandrel  110 .  FIG. 16  is a sectional view of the bottom portion of mandrel  110 . Mandrel  110  can comprise upper end  120  and lower end  130 . Mandrel  110  preferably is designed to take substantially all of the structural load from upper well string  85  and lower well string  86  (at least the load of lower well string  86 ). Mandrel  110  lower end  130  can include a pin connection  150  or any other conventional connection. Upper end  120  can include box connection  140  or any other conventional connection. Central longitudinal passage  160  (see  FIG. 16 ) can extend from upper end  120  through lower end  130 . As shown in  FIGS. 2-3 , mandrel  110  can in effect become a part of upper and lower well string  85 , 86 . Because of a long desired length for mandrel  110 , it can include two sections—upper end or section  120  and lower end or section  130  which are connected at connection point  162 . At connection point  162  upper end  120  can include a pin connection  164  and lower end can include a box connection  166  (although other conventional type connections can be used). To assist in sealing central longitudinal passage  160 , at connection  162  one, two, or more seals can be used (such as polypack seals  168 ,  170  or other seals). 
     In one embodiment upsets, such as joints of pipe can be placed respectively on upper and lower sections  120 ,  130  of mandrel  110  which act as stops for longitudinal movement of sleeve  300 . Upset or joints of pipe can include larger diameter sections than the outer diameter of mandrel. Having larger diameters can prevent sleeve  300  from sliding off of mandrel  110 . Joints of pipe can act as saver subs for the ends of mandrel  110  which take wear and handling away from mandrel  110 . Joints of pipe are preferably of shorter length than a regular  20  or  40  foot joint of pipe, however, can be of the same lengths. In one embodiment joints of pipe include saver portions which engage sleeve or housing  300  at the end of mandrel  110 . Saver portions can be shaped to cooperate with the ends of sleeve or housing  300 . Saver portions can be of the same or a different material than sleeve or housing  300 , such as polymers, teflon, rubber, or other material which is softer than steel or iron. In one embodiment a portion or portions of mandrel  110  itself can be enlarged to act as a stop(s) for movement of sleeve  300 . 
     As shown in  FIGS. 13 and 15 , joint of pipe  700  can be connected to upper portion  120  of mandrel  110 . Joint  700  can comprise upper portion  710 , lower portion  720 , enlarged area  730 , frustoconical area  740 , and protruding section  750 . Joint  700  can limit the upper range of reciprocal motion between sleeve or housing  300  and mandrel  110 . As shown in  FIGS. 13 and 15 , lower portion  130  of mandrel can include 
     As shown in  FIGS. 13 and 16 , lower portion  130  of mandrel  110  can include enlarged fluted area  135 . Fluted area  135  can be used to limit the maximum downward movement by sleeve or housing  300  relative to mandrel  110 . This area can be fluted to assist in fluid flow between the external diameter of fluted area and the internal diameter of a passageway through which fluted area is passing (for example, the internal diameter of well head  88 ). Where these two diameters are relatively close to each other, the flutes can assist in fluid flow between the two diameters.  FIG. 16  also shows a saver sub  800  connected to the pin end  150  of mandrel  110 , which can protect or save the threaded area of pin end  150 . 
     To reduce friction between mandrel  110  and sleeve  300  during rotational and/or reciprocational type movement, mandrel  110  can include a hard chromed area on its outer diameter throughout the travel length (or stroke) of sleeve  300  which can assist in maintaining a seal between mandrel  110  and sleeve or housing  300 &#39;s sealing area during rotation and/or reciprocation activities or procedures. Alternatively, the outer diameter throughout the travel length (or stroke) of sleeve or housing  300  can be treated, coated, and/or sprayed welded with a materials of various compositions, such as hard chrome, nickel/chrome or nickel/aluminum (95 percent nickel and 5 percent aluminum). A material which can be used for coating by spray welding is the chrome alloy TAFA 95MX Ultrahard Wire (Armacor M) manufactured by TAFA Technologies, Inc., 146 Pembroke Road, Concord N.H. TAFA 95 MX is an alloy of the following composition: Chromium 30 percent; Boron 6 percent; Manganese 3 percent; Silicon 3 percent; and Iron balance. The TAFA 95 MX can be combined with a chrome steel. Another material which can be used for coating by spray welding is TAFA BONDARC WIRE-75B manufactured by TAFA Technologies, Inc. TAFA BONDARC WIRE-75B is an alloy containing the following elements: Nickel 94 percent; Aluminum 4.6 percent; Titanium 0.6 percent; Iron 0.4 percent; Manganese 0.3 percent; Cobalt 0.2 percent; Molybdenum 0.1 percent; Copper 0.1 percent; and Chromium 0.1 percent. Another material which can be used for coating by spray welding is the nickel chrome alloy TAFALOY NICKEL-CHROME-MOLY WIRE-71T manufactured by TAFA Technologies, Inc. TAFALOY NICKEL-CHROME-MOLY WIRE-71T is an alloy containing the following elements: Nickel 61.2 percent; Chromium 22 percent; Iron 3 percent; Molybdenum 9 percent; Tantalum 3 percent; and Cobalt 1 percent. Various combinations of the above alloys can also be used for the coating/spray welding. The exterior of mandrel  110  can also be coated by a plating method, such as electroplating or chrome plating. Its surface and its surface can be ground/polished/finished to a desired finish to reduce friction packing assemblies. 
     Mandrel  110  can be machined from a 4340 heat treated steel bar stock or heat treated forgings (alternatively, can be from a rolled forging). Preferably, ultra sound inspections are performed using ASTM A388. Preferably, internal and external surfaces are wet magnetic particle inspected using ASTM 709 (No Prods/No Yokes). The preferred overall length of mandrel  110  is about 77 feet (23.5 meters). The preferred length of upper end  120  is 38.64 feet (11.78 meters) and lower end  130  is about 38.5 feet (11.73 meters). Preferably pin end  150  and box end  140  can be joined through a modified 5½ inch (14 centimeter) FH connection. Preferably, design of these connections is based on a 7½ inch (19 centimeter) outer diameter, 3½ inch (8.9 centimeter) inner diameter and a material yield strength of 135,000 psi (931,000 kilopascals). Mandrel  110  is preferably designed to handle the tensile and torsional loads that a completion string supports (such as from annular blowout preventer  70  to the bottom of well bore  40 ) and meet the requirements of API Specifications 7 and 7G. The following properties are preferred: 
                                    minimum tensile yield   135,000 psi (931,000 kilopascals) (Tensile       strength   tested per ASTM A370, 2% offset           method).       minimum elongation percent   13%       Brinell hardness range   341/388 BHN       impact strength   average impact value not less than 27 foot-           pounds with no single value below 12           foot-pounds when tested at −4 degrees F.           (−20 degrees C.) as per ASTM E23.                    
Mandrel&#39;s  100  box  140  and pin  150  rotary shouldered connections preferably conform to dimensions provided in tables 25 and 26 of API specification 7.
 
     At connection  162 , there is preferably included connecting portions with 7 inch outer diameter s and 3½ inch (8.9 centimeters) inner diameters having a material yield strength of 135,000 psi (931,000 kilopascals). The two connecting portions  120 ,  130  are preferably center piloted to insure that their outer diameters remain concentric after makeup. Preferably, the box and pin bevel diameter is eliminated at connection  162  and dual high pressure seals are used to seal from fluids migration both internally and externally. Preferably, fluid tongs are used to make up connection  162  to prevent scarring or damage to the exterior surface of mandrel  110 . In an alternative embodiment o-rings with one or two backup rings on either side can be used. Strength and Design Formulas of API 7G-APPENDIX A provide the following load carrying specifications for mandrel  110 . 
                                End Connections                                 Torque To Yield               Rotary Shoulder connection   90,400   foot-pounds (122.5 kN-M);       Recommended makeup torque   54,250   foot-pounds (73.6 kN-M);       at 60% of Yield Stress               Tensile Load to Yield               at 0 psi internal pressure   2,011,500   pounds (9,140 kilo newtons);                         Center Connection                                 Torque To Yield               Rotary Shoulder connection   70,800   foot-pounds (96 kN-M);       Recommended makeup torque   42,500   foot-pounds (57.6 kN-M);       at 60% of Yield Stress               Tensile Load to Yield               at 0 psi internal pressure   2,011,500   pounds (9,140 kilo newtons);                 *These center connection ratings also apply to connections between the        upper end and the box end limit sub. The maximum make up torque for wet        tongs is believed to be 34,000 foot-pounds.                         Mandrel burst pressure   55,500   psi (383,000 kilopascals)       Mandrel collapse pressure   40,500   psi (279,000 kilopascals)                    
Sleeve or Housing
 
       FIG. 17  is a top view of sleeve or housing  300 .  FIG. 18  is a sectional view of sleeve or housing  300  showing various components.  FIG. 19  is a longitudinal sectional view of sleeve or housing  300  with attachments removed.  FIG. 21  is a sectional view of the lower portion of sleeve or housing  300 .  FIG. 20  is a sectional view of the upper portion of sleeve or housing  300 . 
     Sleeve or housing  300  can include upper end  302  ( FIG. 20 ), lower end  304  ( FIG. 21 ), and interior section  310 . In one embodiment sleeve or housing  300  can slide and/or reciprocate relative to mandrel  110 . At least a portion of the surface of sleeve or housing  300  can be designed to increase its frictional coefficient, such as by knurling, etching, rings, ribbing, etc. This can increase the gripping power of annular seal  71  (of blow-out preventer  70 ) against sleeve or housing  300  where there exists high differential pressures above and below blow-out preventer  70  which differential pressures tend to push sleeve or housing  300  in a longitudinal direction. 
     Sleeve or housing can include upper and lower catches, shoulders, flanges  326 , 328  (or upsets) on sleeve or housing  300 . Upper and lower catches, shoulders, flanges  326 , 326  restrict relative longitudinal movement of sleeve or housing  300  with respect to blow out preventer  70  where high differential pressures exist above and or below blow-out preventer  70  which differential pressures tend to push sleeve or housing  300  in a longitudinal direction. 
     When displacing, housing or sleeve  300  is preferably located in annular blowout preventer  70  with annular seal  71  closed on sleeve or housing  300  between upper and lower catches, shoulders, flanges  326 ,  328 . As displacement is performed differential pressures tend to push up or down on sleeve or housing  300  causing one of the catches, flanges, shoulders to be pushed against annular blowout preventer  70  seal  71 . It is believed that this differential pressure acts on the cross sectional area of sleeve or housing  300  (ignoring the catch, shoulder, sleeve) and the mandrel&#39;s  110  seven inch diameter. One example of a differential force is 125,000 pounds (556 kilo newtons) of thrust which sleeve or housing  300  transfers to annular blowout preventer  70 . These forces should be taken into account when designing catches, shoulders, flanges to transfer such forces to blowout preventer  70 , such as through annular seal  71  or back support for this annular seal. 
     Upper and lower catches, shoulders, flanges  326 ,  328  can be integral with or attachable to sleeve or housing  300 . In one embodiment one or both catches, shoulders, flanges  326 ,  328  are integral with and machined from the same piece of stock as sleeve or housing  300 . In one embodiment one or both catches, shoulders, flanges  326 ,  328  can be threadably connected to sleeve or housing  300 . In one embodiment one or both catches, shoulders, flanges  326 ,  328  can be welded or otherwise connected to sleeve or housing  300 . In one embodiment one or both catches, shoulders, flanges  326 ,  328  can be heat or shrink fitted onto sleeve or housing  300 . In one embodiment upper and lower catches, shoulders, flanges  326 ,  328  are of similar construction. In one embodiment upper and lower catches, shoulders, flanges  326 ,  328  have shapes which are curved or rounded to resist cutting/tearing of annular seal unit  71  if by chance annular seal unit  71  closes on either upper or lower catch, shoulder, flange  326 ,  328 . In one embodiment upper and lower catches  326 ,  328  have are constructed to avoid any sharp corners to minimize any stress enhances (e.g., such as that caused by sharp corners) and also resist cutting/tearing of other items. 
     In one embodiment the largest radial distance (i.e., perpendicular to the longitudinal direction) from end to end for either catch, shoulder, flange  326 ,  328  is less than the size of the opening in the housing for blow-out preventer  70  so that sleeve or housing  300  can pass completely through blow-out preventer  70 . In one embodiment the upper surface of upper catch, shoulder, flange  326  and/or the lower surface of lower catch, shoulder, flange  328  have frustoconical shapes or portions which can act as centering devices for sleeve or housing  300  if for some reason sleeve or housing  300  is not centered longitudinally when passing through blow-out preventer  70  or other items in riser  80  or well head  88 . In one embodiment upper catch, shoulder, flange  326  is actually larger than the size of the opening in the housing for blow-out preventer  70  which will allow sleeve or housing to make metal to metal contact with the housing for blow-out preventer  70 . 
     In one embodiment the largest distance from either catch, shoulder, flange  326 , 328  is less than the size of the opening in the housing for blow-out preventer  70 , but large enough to contact the supporting structure for annular seal unit  71  thereby allowing metal to metal contact either between upper catch, shoulder, flange  326  and the upper portion of supporting structure for seal unit  71  or allowing metal to metal contact between lower catch, shoulder, flange  328  and the lower portion of supporting structure for seal unit  71 . This allows either catch, shoulder, flange to limit the extent of longitudinal movement of sleeve or housing  300  without relying on frictional resistance between sleeve or housing  300  and annular seal unit  71 . Preferably, contact is made with the supporting structure of annular seal unit  71  to avoid tearing/damaging seal unit  71  itself. 
     In one embodiment non-symmetrical upper and lower catches, shoulders, flanges  326 ,  328  can be used. For example a plurality of radially extending prongs can be used. As another example a single prong can be used. Additionally, channels, ridges, prongs or other upsets can be used. The catches or upsets to not have to be symmetrical. Whatever the configuration upper and lower catches, shoulders, flanges  326 ,  328  should be analyzed to confirm that they have sufficient strength to counteract longitudinal forces and/or thrust loads expected to be encountered during use. 
     Upper catch, shoulder, flange  326  can include base  331 , radiused area  332 , and upper end  302 . Upper end  302  can be shaped to fit with upper retainer cap  400 . Upper retainer cap  400  can itself include upper surface  420  which accepts thrust loads on sleeve or housing  300 . In one embodiment, upper surface  420  can be shaped to avoid sharp corners and act as a centering device when being moved uphole, such as up through blow out preventer  70 . 
     Radiused area  332  can be included to reduce or minimize stress enhancers between catch, shoulder, flange  326  and sleeve or housing  300 . Other methods of stress reduction can be used. Alternatively radiused area  332  and base  331  can be shaped to coordinate with annular seal member  71  of annular blow-out preventer  70 , such as where there will be no metal to metal contact between catch, shoulder, flange  326  and blow-out preventer  70  (e.g., where catch, shoulder, flange  326  only contacts annular seal member  71  and does not contact any of the supporting framework for annular seal member  71 ). Lower catch, shoulder, flange  328  can be similar to, symmetric with, or identical to upper catch, shoulder, or flange  326 . 
     In an alternative embodiment lower and/or upper catches, shoulders, flanges  328 ,  326  can be shaped to act as centering devices for swivel  100  if for some reason swivel  100  is not centered longitudinally when passing through blow-out preventer  70 . 
     Sleeve or housing  300  can include upper and lower lubrication ports  311 ,  312 . Ports  311 , 312  can be used to lubricate the bearings located under the ports. When in service it is preferred that lubrication ports  311 , 312  be closed through threadable pipe plugs (or any pressure relieving type connection). This will prevent fluid migration through ports  311 , 312  when swivel  100  is exposed to high pressures (e.g., 5,000 pounds per square inch)(34.48 megapascals) or even higher pressure such as when in deep water service (e.g. 8,600 feet or 2,620 meters). It is preferred that the heads of pipe plugs placed in lubrication ports  311 , 312  will be flush with the surface. Flush mounting will minimize the risk of having sleeve or housing  300  catch or scratch something when in use. 
     End caps can be provided for sleeve or housing  300 . 
     Upper end  302  of sleeve or housing  300  can be connected to upper retainer cap  400 . Upper retainer cap  400  can serve as a bearing surface where sleeve or housing  300  moves all the way to the upper end of upper portion  120  of mandrel. Looking at  FIG. 5 , protruding section  750  of joint  700  will enter tip  420  of retainer cap  400 . At this point tip will serve as to transfer loads to sleeve or housing  300 . If drill or well string  85 , 86  is rotating relative to sleeve or housing  300 , tip  420  will also serve as a bearing surface. Upper retainer cap  400  can be connected to sleeve or housing  300  using first and second plurality of bolts  470 ,  472 . 
     Lower end  304  of sleeve or housing  300  can be connected to lower retainer cap  500 . Lower retainer cap  500  can serve as a bearing surface where sleeve or housing  300  moves all the way to the lower end of lower portion  120  of mandrel. Looking at  FIG. 10 , fluted area  135  will operatively connect with bearing  570 . At this point fluted section  135  will transfer loads to sleeve or housing  300 . If drill or well string  85 , 86  is rotating relative to sleeve or housing  300 , bearing  570  will also serve as a bearing surface. Lower retainer cap  500  can be connected to sleeve or housing  300  using first and second plurality of bolts  541 ,  545 . 
       FIG. 32  is a sectional perspective view of one embodiment for an upper bearing cap  400  for the upper end of sleeve or housing  300 . Upper retainer cap  400  can comprise tip  420 , base  430 , plurality of ribs  405 . Recessed area  450  and plurality of openings  460  can be used to connect upper bearing cap  400  to upper catch, shoulder, flange  326  of sleeve or housing  300 . First plurality of fasteners  470  along with second plurality of fasteners  472  can make such connection. 
       FIGS. 10 and 33  through  35  show one embodiment for a lower retainer cap  500  for the lower end of sleeve or housing  300 . Lower retainer cap  500  can comprise tip  520 , base  530 , and housing  540 . Housing  540  can include recessed area  552  which can rotatively and slidably support thrust hub or bearing  570 . As shown in  FIG. 33 , base  500  can comprise first end  550  and second end  560 . At first end  550  can be recessed area  552  which can accept bearing  570 . At second end  560  can be recessed area  562  which can accept end cap  1500  of bearing and packing assembly  1000 . Also at second end  560  can be first plurality of openings  542  and second plurality of openings  544  which may extend from second end  560  to recessed area  562 . 
     As shown in  FIG. 34 , bearing  570  can comprise first end  572  and second end  574 . At first end can be a plurality of tips and recesses  576  which can detachably interconnect with fluted area  135  of mandrel  110 . Additionally angled section  578  can be provided as a bearing surface in the event that a thrust load is transmitted from fluted area  135  to sleeve or housing  300 . 
     As shown in  FIG. 35 , cover  590  can comprise first end  592  and second end  594 . At first end  592  can be a plurality of openings  596 . An exterior angled section  598  can extend from first end  592  to adjacent second end  594 . An interior beveled section can be provided. A plurality of radial openings  600  can be provided for shear pins  610 . Preferably, four shear pins  610  are used. 
     In one embodiment a method and apparatus is provided to restrict items which can come loose from swivel  100  and fall downwhole. Various systems can be used to prevent plurality of fasteners  541 , 542  (shown in  FIG. 10 ) from becoming loose or unfastened during use of swivel  100 . One method is to use a specified torquing procedure. A second method is to use a thread adhesive (such as Lock Tite) on fasteners  541 , 542 . Another is to use a plurality of snap rings or set screws above the heads of fasteners  541 , 542 . Tip  520  of retainer cap  500  ( FIG. 21 ) can be designed to prevent the plurality of fasteners  542  from falling out. 
     Sleeve or housing  300  can be machined from a 4340 heat treated steel bar stock or heat treated forgings (alternatively, can be from a rolled forging). Preferably, ultra sound inspections are performed using ASTM A388. Preferably, internal and external surfaces are wet magnetic particle inspected using ASTM 709 (No Prods/No Yokes). The following properties are preferred: 
     
       
         
           
               
               
             
               
                   
               
             
            
               
                 minimum tensile yield strength 
                 135,000 psi (931,000 kilopascals) 
               
               
                   
                 (Tensile tested per ASTM A370, 
               
               
                   
                 2% offset method). 
               
               
                 minimum elongation percent 
                 15% 
               
               
                 Brinell hardness range 
                 293/327 BHN 
               
               
                 impact strength 
                 average impact value not less than 
               
               
                   
                 31 foot-pounds (42 N-M) with no 
               
               
                   
                 single value below 24 foot-pounds 
               
               
                   
                 (32.5 N-M) when tested at 4 
               
               
                   
                 degrees F. (15.6 degrees C.) as per 
               
               
                   
                 ASTM E23. 
               
               
                 minimum preferred factor of safety 
                 5.26:1 
               
               
                 (based on yield strength and 
                   
               
               
                 pressure at lower choke line valve) 
                   
               
               
                 sleeve or housing burst pressure 
                  28,500 psi (197,000 kilopascals) 
               
               
                 sleeve or housing collapse pressure 
                  23,500 psi (162,000 kilopascals) 
               
               
                   
               
            
           
         
       
     
     Preferably, on opposed longitudinal ends of sleeve or housing  300  thrust bearings are provide. These thrust bearings can serve as a safety feature where an operator attempts to over-stroke the mandrel  100  relative to the sleeve or housing  300  causing engagement between these two items and creation of a thrust load. The thrust bearing rating is preferably as follows: 
                                        Box End               continuous rating @60 RPM   200,000 pounds   (890 kilo newtons)       (3000 hours)               intermittent rating @ 60 RPM   400,000 pounds   (1,780 kilo newtons)        (300 hours)               structural rating @ 0 RPM   1,600,000 pounds   (7,100 kilo newtons)       Pin End               continuous rating @60 RPM   135,000 pounds   (600 kilo newtons)       (3000 hours)               intermittent rating @ 60 RPM   270,000 pounds   (1,200 kilo newtons)        (300 hours)               structural rating @ 0 RPM   1,100,000 pounds   (4,900 kilo newtons)                    
Bearing and Packing Assembly
 
       FIG. 22  is a sectional view showing one embodiment for bearing and packing assembly  1000 . Bearing and packing assembly can include bearing  1100 , packing housing  1200 , packing stack  1300 , packing retainer nut  1400 , and retainer plate  1500 .  FIG. 23  is a perspective view of a bearing or bushing  1100 .  FIG. 24  is a perspective view of packing housing  1200 .  FIG. 25  is a perspective view of packing unit  1300 .  FIG. 30  is a perspective view of a packing nut  1400 .  FIG. 31  is a perspective view of a retainer plate  1500 . Bearing and packing assembly  1000  can be substantially the same for upper and lower portions of sleeve  300 , and only one assembly  1000  will be described below. Lower retainer cap  500  can be used to keep bearing and packing assembly  1000  in sleeve or housing  300 . Upper retainer cap  400  can be used to maintain bearing and packing assembly  1000  in sleeve or housing  300 . 
       FIG. 23  is a perspective view of a bearing or busing  1100 . Bushing  1100  can be of metal or composite construction—either coated with a friction reducing material and/or comprising a plurality of lubrication enhancing inserts  1182  (not shown). Alternatively, bearing or bushing  1100  can rely on lubrication provided by different metals moving relative to one another. Bushings with lubrication enhancing inserts can be conventionally obtained from Lubron Bearings Systems located in Huntington Beach, Calif. Bushing  1100  is preferably comprised of ASTM B271-C95500 centrifugal cast nickel aluminum bronze base stock with solid lubricant impregnated in the sliding surfaces. Lubrication enhancing inserts preferably comprise PTFE teflon epoxy composite dry blend lubricant (Lubron model number LUBRON AQ30 yield pressure 15,000 psi) and/or teflon and/or nylon. Different inserts can be of similar and/or different construction. Alternatively, lubrication enhancing inserts can be AQ30 PTFE non-deteriorating graphite free solid lubricant suitable for long term submersion in seawater. Preferably, lubrication inserts take up more than 30 percent of the bearing surface areas seeing relative movement. For example one surface of bearing or bushing  1100  can have inserts of one construction/composition while a second surface of can have inserts of a different construction/composition. Additionally, inserts on one surface can be of varying construction/composition. Circular inserts are preferred however, other shaped inserts can be used. Bearing or bushing  1100  can comprise outer surface  1110 , inner surface  1120 , upper surface  1130 , and lower surface  1140 . Inserts  1182  can be limited to the surfaces of bearing or bushing  1100  which see movement during relative rotation and/or longitudinal movement between mandrel  110  and sleeve or housing  300  (with swivel  100  this would be the inner surface  1120  of bearing or bushing  1100 ). 
     Preferably, bearing or bushing  1100  is a heavy duty sleeve type bearing which is self lubricated and oil bathed. Preferably, it is designed to handle high radial loads and allow mandrel  110  to rotate and reciprocate. 
     As shown in  FIG. 21 , bearing or bushing  1100  can be supported between shoulder  380  of sleeve and packing housing  1200 . Relative rotation between bearing or bushing  1100  and packing housing  1200  can be prevented by having a plurality of tips  1230  (of housing  1200 —see  FIG. 24 ) operatively connected to a plurality of recessed areas  1190  (of bushing  1100 ). Packing housing  1200  is itself connected to sleeve or housing  300 . Accordingly, mandrel  110  will turn relative to bearing or bushing  1100  where mandrel turns relative to sleeve or housing  300 , but bearing or bushing  1100  will not turn relative to sleeve or housing  300 . 
     Assisting in lubricating surfaces which move relative to busing or bearing  1100 , one or more radial openings  1150  can be radially spaced apart around each bushing or bearing  1100  through a perimeter pathway  1160 . Through openings  1150  a lubricant can be injected which can travel to inner surface  1120  along with lower surface  1140  providing a lubricant bath. The lubricant can be grease, oil, teflon, graphite, or other lubricant. The lubricant can be injected through a lubrication port (e.g., upper lubrication port  311  or lower lubrication port  312 ). Perimeter pathway  1160  can assist in circumferentially distributing the injected lubricant around bearing or bushing  1100 , and enable the lubricant to pass through the various openings  1150 . Preferably no sharp surfaces/corners exist on outer surface  1110  of bearing or bushing  1100  which can damage seals and/or o-rings when (during assembly and disassembly of swivel  100 ) bearing or bushing  1100  passes by the seals and/or o-rings. Alternatively, outer surface  1110  can be constructed such that it does not touch any seals and/or o-rings when being inserted into sleeve or housing  300 . 
       FIGS. 10 ,  12 ,  20 ,  21 ,  22 , and  24  best show packing housing  1200 . Packing housing  1200  can comprise first end  1210 , second end  1220 , plurality of tips  1230 , first opening  1240 , perimeter recess  1242 , second opening  1250 , and shoulder  1252 . Packing housing can hold packing stack  1300  which sealingly connects with mandrel  110 . As shown in  FIG. 21 , packing housing  1200  can be sealingly connected to lower end of sleeve or housing  300  through one or more seals (such as polypack seals)  373 ,  375 , which seals respectively sit in recesses  372 , 374 . Similarly, as shown in  FIG. 20 , a second packing housing  1200  can be sealingly connected to the upper end of sleeve or housing  300  through one or more seals (such as polypack seals)  383 ,  385 , which seals respectively sit in recesses  382 , 384 . 
       FIG. 25  is a perspective view of packing unit  1300 . Upper and lower packing units  1300  can each comprise male packing ring  1370 , plurality of seals  1322 , female packing ring  1320 , spacer ring  1310 , and packing retainer nut  1400  (shown in  FIG. 30 ). Packing retainer nut  1400  can be threadably connected to packing housing  1200  at threaded connection  1460 . Tightening packing retainer nut  1400  squeezes plurality of seals  1322  between packing housing  1200  and retainer nut  1400  thereby increasing sealing between sleeve or housing  300  (through packing housing  1200 ) and swivel mandrel  110 . 
       FIG. 26  is a perspective view of a spacer unit  1310  which can comprise first end  1312 , second end  1314 , and enlarged section  1316  and is preferably from SAE 660 BRONZE or SAE 954 Aluminum Bronze.  FIG. 27  is a perspective view of female backup ring (or packing ring)  1320  which can include plurality of grooves for transmission of lubricant to plurality of seals  1322 . Preferably, backup ring  1320  is composed of a bearing grade peek material (such as material number 781 supplied by CDI Seals out of Humble, Tex.).  FIG. 28  is a perspective view of an exemplar packing ring or seal (e.g.,  1330 , 1340 , 1350 , 1360 ) for the plurality of seals  1322 .  FIG. 29  is a perspective view of a male packing ring  1370  which can comprise first end  1372  and second end  1374  and is preferably machined from SAE 660 BRONZE or SAE 954 Aluminum Bronze with a flat head and 45 degrees from the vertical. 
     Plurality of seals  1322  can comprise first seal  1330  (which is preferably a bronze filled teflon v-ring having a 7 inch diameter (17.78 centimeters) and ½ inch (1.27 centimeters) thickness) (such as material number 714 supplied by CDI Seals out of Humble, Tex.); second seal  1340  (which is preferably a teflon v-ring having a 7 inch diameter (17.78 centimeters) and ½ inch (1.27 centimeters) thickness)(such as material number 711 supplied by CDI Seals out of Humble, Tex.); third seal  1350  (which is preferably a viton v-ring having a 7 inch diameter (17.78 centimeters) and ½ inch (1.27 centimeters) thickness) (such as material number 951 supplied by CDI Seals out of Humble, Tex.); and fourth seal  1370  (which is preferably a teflon v-ring having a 7 inch diameter (17.78 centimeters) and ½ inch (1.27 centimeters) thickness)(such as material number 711 supplied by CDI Seals out of Humble, Tex.). Seals can be Chevron type “VS” packing rings. Alternatively, one of the seals can be can be Garlock 8913 rope seals. Rope seals have surprisingly been found to extend the life of remaining plurality of seals because they are believed to secrete lubricants, such as graphite, during use. Where a rope seal is used it is preferable that the rope seal be placed next to first seal  1330 . In one embodiment plurality of seals are rated at 10,000 psi (6,900 kilopascals). 
       FIG. 30  is a perspective view of packing retainer nut  1400 . Packing retainer nut  1400  can comprise first end  1410 , second end  1440 , base  1450 , and threaded area. Plurality of tips  1420  and plurality of recessed areas  1430  can be on first end  1410 . 
       FIG. 31  is a perspective view of a retainer plate  1500 . Packing retainer plate or end cap  1500  can comprise first end  1510  and second end  1530 . On first end  1510  can be a plurality of openings. On second end can be a plurality of tips  1540  and recessed areas  1550 . Retainer plate or end cap  1500  can include mechanical seal  1560  to prevent dirt and debris from coming between retainer plate or end cap  1500  and mandrel  110 . Similar retainer plates or end caps can be placed in the upper and lower sections of sleeve or housing  300 . Retainer plate or end cap  1500  can be used to lock packing retainer nut  1400  in place and prevent retainer nut  1400  from loosening during operation. Plurality of tips  1540  and recessed areas  1550  for retainer plate or end cap  1500  can interlock with plurality of recessed areas  1430  of retainer nut  1400 . First plurality of bolts  470  and second plurality of bolts  472  can lock retainer plate or end cap  1500  to sleeve or housing  300 . 
     In one embodiment, as shown in  FIG. 44  plurality of seals  1322  are pressure tested before being placed in sleeve or housing  300 . Pressure testing can be performed using dummy pipe  1580  and testing plate  1590 . Testing plate  1590  can include radial injection port  1596  and seals  1592 ,  1594 . Dummy pipe  1580  will tend to seal with plurality of seals  1322 . A fluid is pumped into radial port  1596  and travels towards plurality of seals  1322  in the direction of arrow  1598 . Plurality of seals  1322 , if working, will stop fluid migration. However, plurality of seals  1322  will tend to compress longitudinally in the direction of arrow  1598 . After a successful test, plate  1590  is removed and packing retainer nut  1400  is tightened to take up the slack in plurality of seals  1322  caused by the longitudinal compression. Testing and tightening of plurality of seals  1322  are preferably performed where dummy pipe is still contacting plurality of seals, otherwise plurality of seals with tend to radially expand when packing retainer nut  1400  is tightened. 
     Movement of Swivel to Annular BOP 
     When being positioned downhole, sleeve or housing  300  can be temporarily set at a fixed position relative to mandrel  110 . Fixing the position of sleeve or housing  300  relative mandrel  110  facilitates tracking the position of sleeve or housing  300  as it goes downhole. Otherwise, the allowable stroke of sleeve or housing  300  relative to mandrel  110  would make it difficult to determine a true downhole position of sleeve or housing  300  as it could have slide relative to mandrel  110  as swivel  100  travels downhole. In one embodiment this fixed position is adjacent the upper end  120  of mandrel  110 , such as by being shear pinned to upper end or retainer cap  400 . 
     In one embodiment this fixed position is adjacent to the lower end  130  of mandrel  110 .  FIGS. 36 through 38  show sleeve or housing  300  temporarily fixed to a position adjacent the lower end  130  of mandrel  110 . Tip  520  of lower retainer cap  500  can include a plurality of openings  596  (see  FIG. 35 ). Fluted area  135  of mandrel  110  can include a plurality of recessed areas  136 . A plurality of shear pins  610  can be used to fix sleeve or housing  300  relative to mandrel  110 . A plurality of snap rings  612  can be used to fix the plurality of shear pins  610 . An adhesive  614 , such as Lock Tite, can be used to fix the plurality of tips  611  of the plurality of shear pins  610  inside plurality of openings  136 . When sleeve or housing  300  enters annular blowout preventer  70  (shown in  FIG. 38 ), annular seal  71  (not shown for clarity) can be closed maintaining sleeve or housing  300  at a fixed point. Now, the position of sleeve or housing  300  is known based on its relative position to mandrel  110 . After annular seal  71  is closed, drill or work string  85 , 86  can be moved in the direction of arrow  630  in  FIG. 38  causing plurality of tips  611  to shear from plurality of pins  610 , mandrel  110  to move relative to sleeve or housing  300 . Plurality of shear pins  610  will be held in place in plurality of openings  600  by plurality of snap rings  612 . Plurality of tips  611  will be held in place in plurality of openings  136  by adhesive  614 . In this manner no pieces will fall downhole after shearing takes place. Preferably, shear pins  610  have a torque of 225 inch-pounds (25.42 inch pounds) applied to them and will shear at about 42,200 pounds (188 kilo newtons) providing shear at about 40,000 pounds (178,000 kilo newtons). After shearing, sleeve or housing  300  will be free to reciprocate relative to mandrel  110 . 
     Moving Past Annular BOP 
     Sleeve or housing  300  can be designed so that it can be detachably connected to annular blow-out preventer  70  and pass through annular blow-out preventer  70 .  FIG. 38  is a sectional perspective view showing sleeve or housing  300  entering annular blowout preventer  70  where mandrel  110  is shear pinned to sleeve or housing  300 .  FIG. 39  is a sectional perspective view showing sleeve or housing  300  in a working position relative to annular blowout preventer  70  wherein mandrel  110  extended downstream (in the direction of arrow  640 ) of sleeve or housing  300 . In this manner annular seal  71  (not shown for clarity) can be used to detachably connect sleeve or housing  300  to annular blowout preventer  70 . 
       FIG. 40  is a sectional perspective view showing sleeve or housing  300  of swivel  100  leaving annular blowout preventer  70  in the direction of arrow  650 . Here, the annular seal  71  would be opened to allow sleeve or housing  300  to move in the direction of arrow  650 .  FIG. 41  is a sectional perspective view showing swivel  100  continue moving down stack  75  in the direction of arrow  660  towards wellhead  88 . 
     It is preferred that sleeve or housing  300  of swivel  100  be prevented from passing through wellhead  88 . Here, this preference is accomplished by making the diameter of lower catch, shoulder, flange  328  larger than the smallest opening in wellhead  88 . Additionally, it is preferred that where sleeve or housing  300  and wellhead  88  make contact any damage be reduced. Here, reduction of damage from contact is accomplished by making the contacting portion of swivel  100  conform to the shape of the smallest opening in wellhead  88 .  FIG. 42  is a sectional perspective view showing swivel  100  contacting well head  88 .  FIG. 43  also shows swivel  100  contacting the top of well head  88 . Tip  520  of lower retainer cap  500  can include angled section  578  which can be designed to sit in the top of riser  88  thereby preventing damage to riser  88  where sleeve or housing  300  contacts or places a thrust load on riser  88 . In another embodiment, a contacting surface can be provided, such as hard rubber, polymer, etc. 
     Upper and lower catches, shoulders, flanges  326 ,  328  can be positioned/designed/spaced so that they will not coincide with spaced apart longitudinal cavities/openings in stack  75  thereby preventing locking of sleeve or housing  300  with stack  75 . 
     Quick Lock/Quick Unlock 
     After the sleeve  2300  and mandrel  110  have been moved relative to each other in a longitudinal direction, a downhole/underwater locking/unlocking system  3000  can be used to lock the sleeve  2300  in a longitudinal position relative to the mandrel  110  (or at least restricting the available relative longitudinal movement of the sleeve  2300  and mandrel  110  to a satisfactory amount compared to the longitudinal length of the sleeve&#39;s effective sealing area schematically represented as “L” in  FIG. 60 ). Additionally, an underwater locking/unlocking system is needed which can lock and/or unlock sleeve  2300  and mandrel  110  a plurality of times. 
     In one embodiment is provided a quick lock/quick unlock system  3000  which locks and unlocks on a non-fluted area of mandrel  110 . In one embodiment this system  3000  can include a locking hub  3110  with fingers  3120  which detachably locks on a raised area  3400  of mandrel  110  where raised area  3400  does not include radial discontinuities (e.g., it is not fluted). In one embodiment is provided a locking hub  3110  that can rotate relative, but is restricted on the amount of longitudinal movement relative to sleeve  2300 , the rotational movement of hub  3110  with sleeve  2300  minimizing rotational wear between hub  3110  and mandrel  110  (as locking hub  3110  can remain rotationally static relative to sleeve  2300 ). In one embodiment locking hub  3110  can be restricted from moving longitudinally relative to sleeve  2300 . In one embodiment locking hub  3110  can be used without a clutching system. In one embodiment bearing surfaces can be provided between sleeve  2300  and locking hub  3110  to facilitate relative rotational movement between sleeve  2300  and hub  3110 . In one embodiment mandrel  110  is about 7 inches (17.78 centimeters) in outer diameter and shoulder area  137  is about 7½ inches (19.05 centimeters). 
       FIGS. 45 through 47  illustrate one embodiment where a quick lock/quick unlock system  3000  is placed in a locked state from an unlocked state.  FIGS. 48 through 50  illustrate one embodiment where quick lock/quick unlock system  3000  is placed in an unlocked locked state from a locked state.  FIG. 51  is an enlarged view of the quick lock/quick unlock system  3000 .  FIG. 52  is a perspective view of the quick lock/quick unlock system  3000  in an unlocked state.  FIG. 53  is an enlarged perspective view of quick lock/quick unlock system  3000  system is very close to being a locked state.  FIG. 54  is a perspective view of quick lock/quick unlock system  3000  in a locked state.  FIG. 55  is a sectional view of lower end  2304  of sleeve  2300  where first part  3100  of quick lock/quick unlock system has been removed so that the portions of lower end  2304  can be better viewed.  FIG. 56  is a perspective view of the first part  3100  (or a locking hub) of quick lock/quick unlock system  3000 .  FIG. 57  is a sectioned perspective view of locking hub  3100 . 
     Generally, quick lock/quick unlock system  3000  can comprise first part or locking hub  3000  which detachable connects to second part  3400 . First part or locking hub  3100  can comprise bearing and locking hub  3110  which includes at least one finger  3130 , and preferably a plurality of fingers  3120 . Preferably the plurality of fingers  3120  can be symmetrically spread about the radius of locking hub  3000 . Where the plurality of fingers are used, each finger can be constructed substantially similar to the other fingers and only one example finger  3130  will be described. As shown in  FIG. 53 , each finger  3130  can comprise a base  3160 , length  3170 , and tip  3140 . Preferably at the tip  3140  is included latching area  3150 . Second part  3400  can comprise angled area  3420 , flat area  3440 , latching area  3410 , and recessed area  3460 . Preferably latching area  3150  can detachably interlock with latching area  3410  of second part  3400 . Angled area  3420  can assist in latching area  3150  in being asserted into recessed area  3460  and latching with latching area  3410 . Arrow  3172  in  FIG. 53  schematically indicates that tip  3140  will radially expand when moving over angled area  3420 . Tip  3140  will move in the opposite direction as arrow  3172  when tip moves into recessed area  3460 . Once interlocked the longitudinal movement of sleeve  2300  will be restricted relative to mandrel  110 . 
     Where second part  3400  of quick connect/quick disconnect system  3000  includes radial discontinuities (such as illustrated in fluting  135  shown in mandrel  110  in  FIGS. 45 through 55 ) a clutching system  3600  can be used to align first part  3100  and second part  3400  for connection purposes. In one embodiment a clutching system  3600  is provided which facilitate alignment of plurality of fingers  3120  with the plurality of latching areas  3410  of second part  3400 . As best shown in  FIG. 56 , clutching system  3600  can include a plurality of alignment members  3610 . Each of the alignment members can include a conical, tapered or arrow shaped portion  3630 . Each of the alignment members can be attached to bearing and locking hub  3110  through a fastener  3640  (best shown in  FIGS. 53 and 56 ). As best shown in  FIG. 53 , the aligning or conical, tapered or arrow shaped portions  3630  of the plurality of alignment members  3610  interact with plurality of recessed areas  136  of the fluted areas to align the plurality of fingers  3120  with the plurality of latching areas  3410  of second part  3400 . To facilitate this alignment function angled areas  138  can be provided on each of the flutes of the fluted area  135 . If partially offset or misaligned, the angled areas can interact with the arrow shaped portions of the plurality of alignment members  3610  and rotationally align the plurality of fingers  3120  for proper locking with the plurality of latching areas  3410  of second part  3400 . A plurality of angled areas  137  can also be provided to facilitate rotational alignment. To also facilitate this alignment locking hub  3110  has a degree of longitudinal movement relative to sleeve  2300 . As shown in  FIG. 53  a recessed area  2552  is provided wherein locking hub  3110  can experience longitudinal (and also rotational movement). Longitudinal movement can is limited in one direction by base  3200  of locking hub  3110  contacting base  2554  of recessed area  2552 , and in a second direction by shoulder  3260  contacting interior angled section  2600 . Base  3200  and shoulder  3260  are bearing surfaces which facilitate relative movement when in contact with another surface. Additionally, outer diameter  3205  is a bearing surface facilitating rotational movement of locking hub  3110  relative to sleeve  2300 . Limiting relative longitudinal movement of locking hub  3110  relative to mandrel  110 , first shoulder  3220  will contact the plurality of angled sections  137  of fluted area  135 . When base  3200  of locking hub contacts base  2554  sleeve  2300  will be prevented from further movement towards pin end  150  of mandrel  110 . Even when in such contact sleeve  2300  can rotating relative to mandrel (and vice versa) by locking hub  3110  rotating relative to sleeve through the bearing surfaces of locking hub  3110 . 
     The plurality of alignment members  3610  also cause bearing or locking hub  3110  to become rotationally static relative to mandrel  110  and fluted area  135 . Making locking hub  3110  rotationally static relative to fluted area  135  prevents scratching or scarring by the tips of the fingers rotating relative to the latching area  3410  during locking and/or unlocking Because the locking hub  3110  is rotationally static relative to the mandrel  110  and the mandrel  110  may be rotating relative to sleeve  2300 , locking hub  3110  can rotate relative to sleeve  2300 . 
       FIGS. 45 through 47  illustrate one embodiment where quick lock/quick unlock system  3000  is placed in a locked state from an unlocked state. Sleeve  2300  is assumed to be held in a static state (such as by annular BOP  70  not shown for clarity). Mandrel  110  is moved in the direction of arrow  2320  so that the tips  3140  of plurality of fingers  3120  will move toward the second part  3400  (which can include a plurality of latching areas  3410 ). By interaction with the plurality of flutes  136 , plurality of alignment members  3610  will align plurality of fingers  3120  with the plurality of latching areas  3410 .  FIG. 46  shows that latching has occurred with further movement in the direction of arrow  2630  until shoulder  3220  contacts plurality angled areas  137  as shown in  FIG. 47 . Further attempts to move in the direction of arrow  2640  will cause a thrust load to be generated in the direction of arrow  2640  and transferred to sleeve  2300  by locking hub  3100  through base  3200  contacting surface  3554 , and ultimately transferring the thrust load to annular BOP  70  holding sleeve  2300  longitudinally static. Arrows  2682  and  2684  schematically indicates that sleeve  2300  and mandrel  110  can rotate relative to each other even when quick lock/quick unlock system  3000  is in a locked state. 
       FIGS. 48 through 50  illustrate one embodiment where quick lock/quick unlock system  3000  is placed in an unlocked locked state from a locked state. Sleeve  2300  is assumed to be held in a static state (such as by annular BOP  70  not shown for clarity). Mandrel  110  is moved in the direction of arrow  2650  so that locking hub (which is locked on mandrel) is also moved in the direction of arrow  2650  until shoulder  3260  contacts shoulder  2600  ( FIG. 49 ) and the tips  3140  of plurality of fingers  3120  will move away from the second part  3400  (which can include a plurality of latching areas  3410 ). By interaction with the plurality of flutes  136 , plurality of alignment members  3610  will keep aligned plurality of fingers  3120  with the plurality of latching areas  3410 .  FIG. 49  shows that unlatching has occurred.  FIG. 50  shows further movement in the direction of arrow  2670  until plurality of fingers having been moved out of fluted area  135  and reciprocation can occur when quick lock/quick unlock system  3000  is in a locked state. 
     In one embodiment is provided a quick lock/quick unlock system  3000  wherein the underwater position of the longitudinal length of the sleeve&#39;s sealing area (e.g., the nominal length between the catches) can be determined with enough accuracy to allow positioning of the sleeve&#39;s effective sealing area in the annular BOP  70  for closing on the sleeve&#39;s  2300  sealing area (“L” in  FIG. 60 ). After sleeve  2300  and mandrel  110  have been longitudinally moved relative to each other when annular BOP  70  was closed on sleeve  2300 , it is preferred that a system  3000  be provided wherein the underwater position of sleeve  2300  can be determined even where sleeve  3000  has been moved outside of annular BOP  70 . 
     In one embodiment is provided a quick lock/quick unlock system  3000  for locating the relative position between sleeve  2300  and mandrel  110 . Because sleeve  2300  can reciprocate relative to mandrel  110  (i.e., the sleeve and mandrel can move relative to each other in a longitudinal direction), it can be important to be able to determine the relative longitudinal position of sleeve  2300  compared to mandrel  110  at some point after sleeve  2300  has been reciprocated relative to mandrel  110  (or vice versa). For example, in various uses of rotating and reciprocating tool  100 ′, the operator may wish to seal annular BOP  70  on sleeve  2300  sometime after sleeve  2300  has been reciprocated relative to mandrel  110  and after sleeve  2300  has been removed from annular BOP  70 . To address the risk that the actual position of sleeve  2300  relative to mandrel  110  will be lost while tool  100 ′ is underwater, a quick lock/quick unlock system  3000  can detachably connect sleeve  2300  and mandrel  110 . In a locked state, this quick lock/quick unlock system  3000  can reduce the amount of relative longitudinal movement between sleeve  2300  and mandrel  110  (compared to an unlocked state) so that sleeve  2300  can be positioned in annular BOP  70  and annular BOP  70  relatively easily closed on sleeve&#39;s  2300  longitudinal sealing area (“L” in  FIG. 60 ). Alternatively, this quick lock/quick unlock system  3000  can lock in place sleeve  2300  relative to mandrel  110  (and not allow a limited amount of relative longitudinal movement). After being changed from a locked state to an unlocked state, sleeve  2300  can experience its unlocked amount of relative longitudinal movement which is referred to as stroke in other parts of this application. 
     In one embodiment is provided a quick lock/quick unlock system  3000  which allows sleeve  2300  to be longitudinally locked and/or unlocked relative to the mandrel  110  a plurality of times when underwater. In one embodiment the quick lock/quick unlock system  3000  can be activated using annular BOP  70 . 
     In one embodiment sleeve  2300  and mandrel  110  can rotate relative to one another even in both the activated and un-activated states (schematically indicated by arrows  2682 ,  2684  in  FIG. 47 ). In one embodiment, when in a locked state, the sleeve and mandrel can rotate relative to each other. This relative rotation when locked option can be important where annular BOP  70  is closed on sleeve  2300  at a time when string  85 , 88  (of which the mandrel  110  is a part) is being rotated. Allowing sleeve  2300  and mandrel  110  to rotate relative to each other, even when in a locked state, minimizes wear/damage to annular BOP  70  caused by a rotationally locked sleeve  300  (e.g., sheer pin in  FIG. 10 ) rotating relative to a closed annular BOP  70 . Instead, sleeve  2300  can be held fixed rotationally by closed annular BOP  70 , and mandrel  110  (along with string  85 , 88 ) rotate relative to the sleeve (as schematically illustrated in  FIG. 47 ). 
     In one embodiment, when locking system  3000  of sleeve (e.g., first part  3100 ) is in contact with mandrel  110 , locking/unlocking is performed without relative rotational movement between locking system of the sleeve (first part  3100 ) and mandrel  110 —otherwise scoring/scratching of the mandrel at the location of lock can occur. In one embodiment, this can be accomplished by rotational connecting to sleeve  2300  the sleeve&#39;s portion of quick lock/quick unlock system  3000  (e.g., locking hub  3100 ). In one embodiment a locking hub  3100  is provided which is rotationally connected to sleeve  2300 . 
     In one embodiment quick lock/quick unlock system  3000  on rotating and reciprocating tool  100 ′ can be provided allowing the operator to lock sleeve  2300  relative to mandrel  110  when rotating and reciprocating tool  100 ′ is downhole/underwater. Because of the relatively large amount of possible stroke of sleeve  2300  relative to mandrel  110  (i.e., different possible relative longitudinal positions), knowing the relative position of sleeve  2300  with respect to mandrel  110  can be important. This is especially true at the time annular BOP  70  is closed on sleeve  2300 . The locking position is important for determining relative longitudinal position of sleeve  2300  along mandrel  110  (and therefore the true underwater depth of sleeve  2300 —schematically shown in  FIG. 2  as “TD” for tool  100 ) so that sleeve  2300  can be easily located in annular BOP  70  and annular BOP  70  closed/sealed on sleeve  2300 . 
     During the process of moving the rotating and reciprocating tool  100 ′ underwater and downhole, sleeve  2300  can be locked relative to mandrel  110  by quick lock/quick unlock system  3000 . In one embodiment quick lock/quick unlock system  3000  can, relative to mandrel  110 , lock sleeve  2300  in a longitudinal direction. In one embodiment sleeve  2300  can be locked in a longitudinal direction with quick lock/quick unlock system  300 , but sleeve  2300  can rotate relative to mandrel  110  (schematically shown in  FIG. 47 ) during the time it is locked in a longitudinal direction. In one embodiment quick lock/quick unlock system  3000  can simultaneously lock sleeve  2300  relative to mandrel  110 , in both a longitudinal direction and rotationally (not shown but accomplished by non-rotationally attaching locking hub  3100  to sleeve  2300 ). In one embodiment quick unlock/quick unlock system  3000  can, relative to mandrel  110 , lock sleeve  110  rotationally, but at the same time allow sleeve  2300  to move longitudinally (not shown but accomplished by non-rotationally attaching locking hub  3100  to sleeve  2300  and allowing a relative longitudinal movement between locking hub  3100  and sleeve, such as by using recessed area  2552  with fluted areas on locking hub  3100  and recessed area  2552 ). 
     Activation by Relative Longitudinal Movement 
     In one embodiment quick lock/quick unlock system  3000  can be activated (and placed in a locked state) by movement of mandrel  110  relative to sleeve  2300  in a first longitudinal direction (schematically indicated by arrows  2620 ,  2630 , and  2640  in  FIGS. 45 through 47 ). In one embodiment quick lock/quick unlock system  3000  is deactivated (and placed in an unlocked state) by movement of the mandrel  110  relative to sleeve  2300  in a second longitudinal direction, the second longitudinal direction being substantially in the opposite longitudinal direction compared to the first longitudinal direction (schematically indicated by arrows  2650 ,  2660 , and  2670  in  FIGS. 48 through 50 ). 
     In one embodiment the first longitudinal direction is toward the longitudinal center of sleeve  2300  (schematically indicated by arrows  2620 ,  2630 , and  2640  in  FIGS. 45 through 47 ). In one embodiment the second longitudinal direction is away from the longitudinal center of the mandrel (schematically indicated by arrows  2650 ,  2660 , and  2670  in  FIGS. 48 through 50 ). 
     In one embodiment quick lock/quick unlock system  3000  can be changed from an activated to a deactivated state when sleeve  2300  is at least partially located in annular BOP  70 . In one embodiment quick lock/quick unlock system  3000  can be changed from a deactivated state to an activated state when sleeve  2300  is at least partially located in annular BOP  70 . 
     In one embodiment quick lock/quick unlock system  3000  can be changed from an activated to a deactivated state when annular BOP  70  is closed on sleeve  2300 . In one embodiment quick lock/quick unlock system  3000  can be changed from a deactivated state to an activated state when annular BOP  70  is closed on sleeve  2300 . 
     In one embodiment quick lock/quick unlock system  3000  can be changed from an activated to a deactivated state when sleeve  2300  is sealed with respect to annular BOP  70 . In one embodiment quick lock/quick unlock system  3000  can be changed from a deactivated state to an activated state when sleeve  2300  is sealed with respect to annular BOP  70 . 
     In one embodiment, at a time when sleeve  2300  is at least partially located in annular BOP  70 , quick lock/quick unlock system  3000  can be activated (and placed in a locked state) by movement of sleeve  2300  relative to mandrel  110  in a first longitudinal direction to a locking location (schematically indicated by arrows  2620 ,  2630 , and  2640  in  FIGS. 45 through 47 ). In one embodiment, at a time when sleeve is at least partially located in annular BOP  70 , quick lock/quick unlock system is deactivated (and placed in an unlocked state) by movement of sleeve  2300  relative to mandrel  110  in a second longitudinal direction away from the locking location, the second longitudinal direction being substantially in the opposite direction compared to the first longitudinal direction (schematically indicated by arrows  2650 ,  2660 , and  2670  in  FIGS. 48 through 50 ). 
     In one embodiment, direction at a time when annular BOP  70  is closed on sleeve  2300 , quick lock/quick unlock system  3000  is activated (and placed in a locked state) by movement of sleeve  2300  relative to mandrel  110  in a first longitudinal (schematically indicated by arrows  2620 ,  2630 , and  2640  in  FIGS. 45 through 47 ). In one embodiment, at a time when annular BOP  70  is closed on sleeve  2300 , quick lock/quick unlock system  3000  is deactivated (and placed in an unlocked state) by movement of sleeve  2300  relative to mandrel  110  in a second longitudinal direction, the second longitudinal direction being substantially in the opposite longitudinal direction compared to the first longitudinal direction (schematically indicated by arrows  2650 ,  2660 , and  2670  in  FIGS. 48 through 50 ). 
     In one embodiment, at a time when sleeve is sealed with respect to annular BOP  70 , quick lock/quick unlock system is activated (and placed in a locked state) by movement of sleeve  2300  relative to mandrel  110  in a first longitudinal direction (schematically indicated by arrows  2620 ,  2630 , and  2640  in  FIGS. 45 through 47 ). In one embodiment, at a time when sleeve  2300  is sealed with respect to annular BOP  70 , quick lock/quick unlock system  3000  is deactivated (and placed in an unlocked state) by movement of sleeve  2300  relative to mandrel  110  in a second longitudinal direction, the second longitudinal direction being substantially in the opposite longitudinal direction compared to the first longitudinal direction (schematically indicated by arrows  2650 ,  2660 , and  2670  in  FIGS. 48 through 50 ). 
     Activation by Moving to a Locking Position 
     In one embodiment, at a time when sleeve  2300  is at least partially located in annular BOP  70 , sleeve  2300  is moved to a locking position relative to mandrel  110 . In one embodiment, at a time when sleeve  2300  is at least partially located in annular BOP  70 , quick lock/quick unlock system  3000  is changed from a deactivated state to an activated state by moving the sleeve to specified locking position on mandrel  110  (schematically indicated by arrows  2620 ,  2630 , and  2640  in  FIGS. 45 through 47 ). In one embodiment, at a time when sleeve  2300  is at least partially located in annular BOP  70 , quick lock/quick unlock system  3000  is changed from an activated state to a deactivated activated state by moving sleeve  2300  away from a specified position on the mandrel  110  (schematically indicated by arrows  2650 ,  2660 , and  2670  in  FIGS. 48 through 50 ). 
     In one embodiment, at a time when annular BOP  70  is closed on sleeve  2300 , sleeve  2300  is moved to a locking position relative to mandrel  110 . In one embodiment, at a time when annular BOP  70  is closed on sleeve  2300 , quick lock/quick unlock system  3000  is changed from a deactivated state to an activated state by moving sleeve  2300  to a specified locking position on the mandrel (schematically indicated by arrows  2620 ,  2630 , and  2640  in  FIGS. 45 through 47 ). In one embodiment, at a time when annular BOP  70  is closed on sleeve  2300 , quick lock/quick unlock system  3000  is changed from an activated state to a deactivated activated state by moving the sleeve away from a specified position on the mandrel (schematically indicated by arrows  2650 ,  2660 , and  2670  in  FIGS. 48 through 50 ). 
     In one embodiment, at a time when sleeve  2300  is sealed in annular BOP  70 , sleeve  2300  is moved to a locking position relative to mandrel  110 . In one embodiment, at a time when sleeve  2300  is sealed in annular BOP  70 , quick lock/quick unlock system  3000  is changed from a deactivated state to an activated state by moving sleeve  2300  to specified locking position on mandrel  110  (schematically indicated by arrows  2620 ,  2630 , and  2640  in  FIGS. 45 through 47 ). In one embodiment, at a time when sleeve  2300  is sealed in annular BOP  70 , quick lock/quick unlock system  3000  is changed from an activated state to a deactivated state by moving sleeve  2300  away from a specified position on mandrel (schematically indicated by arrows  2650 ,  2660 , and  2670  in  FIGS. 48 through 50 ). 
     Activation by Exceeding a Specified Minimum Locking Force 
     In one embodiment quick lock/quick unlock system  3000  is activated when at least a first specified minimum longitudinal force is placed on sleeve  2300  relative to mandrel  110 . In one embodiment the first specified minimum longitudinal force is used to determine whether sleeve  2300  is locked relative to the mandrel  110 . That is, where sleeve  2300  cannot absorb at least the first specified minimum longitudinal force, quick lock/quick unlock system  3000  can be considered in a deactivated state. In one embodiment, the specified minimum longitudinal force is a predetermined force. In various embodiments the specified minimum longitudinal force is between 5,000, 10,000, 15,000, 20,000, 25,000, 30,000, 35,000, 40,000, 45,000, 50,000, 55,000, 60,000, 65,000, 70,000, 75,000, 80,000, 85,000, 90,000, 95,000, 100,000 pounds force (22, 44, 67, 89, 111, 133, 152, 171, 190, 210, 229, 248, 267, 289, 311, 334, 355, 378, 400, 423, and 445 kilo newtons). In one embodiment various ranges of the above referenced forces can be used for the various possible permutations. 
     In one embodiment quick lock/quick unlock system  3000  is deactivated when at least a second specified minimum longitudinal force is placed on sleeve  2300  relative to mandrel  110 . In one embodiment the second specified minimum longitudinal force is used to determine whether sleeve  2300  is locked relative to mandrel  110 . That is where sleeve  2300  cannot absorb at least the second specified minimum longitudinal the quick lock/quick unlock system  3000  can be considered in a deactivated state. In one embodiment the first specified minimum longitudinal force is substantially equal to the second specified minimum longitudinal force. In one embodiment the first specified minimum longitudinal force is substantially greater than the second specified minimum longitudinal force. In one embodiment the first specified minimum longitudinal force takes into account the amount of longitudinal friction between sleeve  2300  and mandrel  110 . In one embodiment the second specified minimum longitudinal force takes into account the amount of longitudinal friction between sleeve  2300  and mandrel  110 . In one embodiment both the first specified minimum longitudinal force and the second specified minimum longitudinal force take into account the amount of longitudinal friction between sleeve  2300  and mandrel  110 . In one embodiment the first specified minimum longitudinal force takes into account the longitudinal force applied to sleeve  2300  based on differing pressures above and below annular BOP  70 . In one embodiment the second specified minimum longitudinal force takes into account the longitudinal force applied to sleeve  2300  based on differing pressures above and below annular BOP  70 . In one embodiment both the first specified minimum longitudinal force and the second specified minimum longitudinal force take into account the longitudinal force applied to sleeve  2300  based on differing pressures above and below annular BOP  70 . 
     Example of a Specified Minimum Locking Force 
     In one example of operation with deep water wells, annular BOP  70  can be located between 6000 to 7000 feet (1,800 to 2,150 meters) below the rig  10  floor. Quick lock/quick unlock system  3000  can be activated by closing annular BOP  70  on sleeve  2300  and pulling up with a force of approximately 40,000 pounds (178 kilo newtons) (schematically indicated by arrows  2620 ,  2630 , and  2640  in  FIGS. 45 through 47 ). Quick lock/quick unlock system  3000  can be de-activated by closing annular BOP  70  on sleeve  2300  and lowering mandrel  110  relative to sleeve  2300  (schematically indicated by arrows  2650 ,  2660 , and  2670  in  FIGS. 48 through 50 ). When approximately 40,000 pounds (178 kilo newtons) of longitudinal force (e.g., exerted by the weight of string  88  not being supported by rig  10 ) is created between mandrel  110  and sleeve  2300 , quick lock/quick unlock system  3000  can become deactivated and unlock sleeve  2300  from mandrel  110  so that mandrel  110  can be reciprocated relative to sleeve  2300  (where annular BOP  70  is closed on sleeve  2300 ). For this example, the specified minimum differential longitudinal force of 40,000 pounds (178 kilo newtons) can be used to overcome 10,000 pounds (44 kilo newtons) of longitudinal friction (such as seal friction) and 30,000 pounds (133 kilo newtons) from quick lock/quick unlock system  3000 . This minimum longitudinal force (e.g., 40,000 pounds or 178 kilo newtons) can address the risk that sleeve  2300  does not get bumped out of its locked longitudinal position when sleeve  2300  is moved outside of annular BOP  70  (i.e., unlocking quick lock/quick unlock system  3000  and causing the operator to lose the position TD, shown in  FIG. 2 , of sleeve  2300  relative to mandrel  110 ). The minimum longitudinal force also ensures that sleeve  2300  will not float up/sink down mandrel  110  as a result of fluid flow around sleeve  2300  when annular BOP  70  is open (such as when returns are taken up riser  80 ). 
     Various Options for Allowable Reciprocation when in a Locked State 
     In one embodiment is provided quick lock/quick unlock system  3000  where sleeve  2300  and mandrel  110  reciprocate relative to each other a specified distance even when locked, however, the amount of relative reciprocation increases when unlocked (schematically shown in FIGS.  46 , 47  by space in recessed area  2552  and shoulder  2600 ). In one embodiment the amount of allowable relative reciprocation even in a locked state facilitates operation of a clutching system between the sleeve and mandrel (schematically shown in  FIG. 53 ). In one embodiment the amount of allowable relative reciprocation even in a locked state allows relative longitudinal and rotational movement between a locking hub  3100  and sleeve  2300  to allow a clutching system to align hub  3100  for interlocking with fluted  135  area of mandrel  110 . In one embodiment the amount of allowable relative reciprocation even in a locked state is In one embodiment the amount of allowable relative reciprocation even in a locked state is between 0 and 12 inches (0 and 30.48 centimeters), between 0 and 11 inches (0 and 27.94 centimeters), 10, 9, 8, 7, 6, 5, 4, 3, 2, 1, ¾, ½, ¼, ⅛ inches (25.4, 22.86, 20.32, 17.78, 15.24, 12.7, 10.16, 7.62, 5.08, 2.54, 1.91, 1.27, 0.64, 0.32 centimeters). In one embodiment the amount of allowable relative reciprocation even in a locked state is between ⅛ inch (0.32 centimeters) and any of the specified distances up to 12 inches (30.48 centimeters). In other embodiments the amount of allowable relative reciprocation even in a locked state is between ¼ inches (0.64 centimeters) and any of the specified distances up to 12 inches (30.48 centimeters). In other embodiments the amount of allowable relative reciprocation even in a locked state is between ½, ¾, 1, etc. and any of the specified distances. In other embodiments the amount of allowable relative reciprocation even in a locked state is between any possible permutation of the specified distances. 
     Spring Lock/Unlock 
     In one embodiment a spring and latch quick lock/quick unlock system  3000  is provided between sleeve  2300  and mandrel  110 . The spring can comprise one or more fingers  3120  (or a single finger, or a single ring) which detachably connects to a connector  3400  located on mandrel  110 , such as a locking valley  3460 . In one embodiment ramp  3420  on mandrel  110  can be provided facilitating the bending of one or more fingers  3120  (or ring) before they lock/latch into the connecting valley  3460 . In one embodiment is provided a backstop  137  to resist longitudinal movement of sleeve  2300  relative to mandrel  110  after the one or more fingers  3120  (or ring) have locked/latched into the valley  3460 . 
     In one embodiment is provided a quick lock/quick unlock system which includes a hub rotationally connected to the sleeve, and the hub can have a plurality of fingers, the mandrel can have a longitudinal bearing area and a locking area (located adjacent to the bearing area). In one embodiment the fingers can pass over the bearing area without touching the bearing area. In one embodiment the fingers can be radially expanded by the locking area, and then lock in the locking area. In one embodiment longitudinal movement of the sleeve relative to the mandrel can be restricted by the shoulder area. In one embodiment longitudinal movement of the hub relative to the mandrel can be restricted by the shoulder area. In one embodiment longitudinal movement of the sleeve relative to the mandrel can be restricted by the shoulder area contacting the hub and the hub contacting thrusting against the sleeve. 
       FIGS. 58 through 60  show various embodiments of a generic sleeve with specialized removable adaptors for different annular BOPs.  FIG. 59  shows the generic sleeve  2300  which can accommodate various specialized removable adaptors. Different manufacturers of annular BOP  70  have different designs for their respective annular BOPs and annular seals  71 . Accordingly, a catch for one of these seals  71  may, if not designed properly, may actually damage the annular seal  71 . Typically, it is where a longitudinal thrust load is placed by the sleeve on the annular seal  71  (i.e., the catch areas). However, sleeve  2300  is an expensive piece of equipment to manufacture and it is desirably to have a generic sleeve  2300  which can be specialized for various annular BOP  70  configurations. 
     Sleeve  2300  can include upper and lower catches  2326 ,  2328 . Upper catch  2326  can include a plurality of openings  2334  for detachably connecting one or more specialized adaptors. Lower catch  2328  can include a plurality of openings  2344  for detachably connecting one or more specialized adaptors.  FIGS. 58 and 60  show two possible specialized adaptors  4200  and  4400 . Adaptor  4200  can be used for an annular BOP manufactured by Shaffer. Adaptor  4400  can be used for an annular BOP manufactured by Hydril. 
       FIG. 61  is an exploded perspective view of one specialized removable adaptor  4200  for an annular BOP  70 . As shown in  FIG. 61  specialized catch adapter  4200  can comprise first section  4220  and second section  4240  which can be detachably connected to sleeve  2300  as indicated by arrows  4202  and  4204 . First section  4220  can comprise inner diameter  4222 , rounded area  4224 , second rounded area  4226 , and a plurality of openings  4230 . First and second sections can be constructed substantially like each other. Second section  4226  can comprise interior  4242 , base  4244 , angled section  4246 , diameter  4250 , angled area  4252 , and base  4254 . Second section  4226  can also include a plurality of openings  4259  for connecting it to sleeve  2300 . First and second sections  4220  and  4240  are shown as being two separate pieces, but can be a single piece, such as where they are hinged together. A plurality of fasteners  4260  can be used to detachably connect first section  4220  and/or second section  4240  to sleeve  2300 . A plurality of washers  4270  and snap rings  4280  can also be used. The snap rings  4280  can be used to prevent one or more of the fasteners  4260  from becoming loose and falling downhole. 
       FIG. 62  is an exploded perspective view of a second specialized removable adaptor  4400  for a second annular BOP  70 ′.  FIG. 63  is a perspective view of the specialized removable adaptor  4400  attached to sleeve  2300 . As shown in  FIG. 62  specialized catch adapter  4400  can comprise first section  4420  and second section  4440  which can be detachably connected to sleeve  2300  as indicated by arrows  4402  and  4404 . First section  4420  can comprise inner diameter  4422 , base area  4424 , and a plurality of openings  4430 . First and second sections can be constructed substantially like each other. Second section  4440  can comprise interior  4442 , base  4444 , angled section  4446 , and base  4448 . Second section  4440  can also include a plurality of openings  4450  for connecting it to sleeve  2300 . First and second sections  4420  and  4440  are shown as being two separate pieces, but can be a single piece, such as where they are hinged together. A plurality of fasteners  4460  can be used to detachably connect first section  4420  and/or second section  4440  to sleeve  2300 . A plurality of washers  4470  and snap rings  4480  can also be used. The snap rings  4480  can be used to prevent one or more of the fasteners  4460  from becoming loose and falling downhole. 
       FIG. 65  is a sectional perspective view of the upper part of an alternative sleeve  300  for rotating and reciprocating swivel  5000  with alternative packing assembly  5300 .  FIG. 66  is a closeup view of sleeve  300 .  FIG. 67  is a sectional perspective view of packing unit  5300 .  FIG. 68  is a sectional perspective view of the upper part of sleeve  300  for swivel  5000  with alternative packing assembly  6300 .  FIG. 69  is a closeup view of sleeve  300 .  FIG. 70  is a sectional perspective view of packing unit  6300 . 
       FIG. 67  is a sectional perspective view showing one embodiment of a packing unit  5300 , which can preferably be used in the box end of an alternative embodiment of rotating and reciprocating swivel  5000  (see  FIGS. 65 through 70 ). Packing unit  5300  can comprise male packing ring  5370 , plurality of seals  5306 , female packing ring  5320 , spacer ring  5310 , and packing retainer nut  1400  (not shown for clarity). Packing retainer nut  1400  can be threadably connected to packing housing  1200  at threaded connection  1460 . Tightening packing retainer nut  1400  squeezes plurality of seals  5306  between packing housing  1200  and retainer nut  1400  thereby increasing sealing between sleeve or housing  300  (through packing housing  1200 ) and swivel mandrel  110 . 
     Spacer unit  5310  can comprise first end  5312 , second end  5314 , and is preferably from SAE 660 BRONZE or SAE 954 Aluminum Bronze. Female backup ring (or packing ring)  5320  is preferably comprised of a bearing grade peek material (such as material number 781 supplied by CDI Seals out of Humble, Tex.). Packing ring  5330  is preferable a bronze filled teflon seal (such as material number 714 supplied by CDI Seals out of Humble, Tex.). Packing rings  5340  and  5350  are preferable teflon seals (such as material number 711 supplied by CDI Seals out of Humble, Tex.). Male packing ring  5370  which can comprise first end  5372  and second end  5374  and is preferably machined from SAE 660 BRONZE or SAE 954 Aluminum Bronze with a flat head  5374  and 45 degrees from the vertical. Seals can be Chevron type “VS” packing rings. 
       FIG. 70  is a sectional perspective view showing one embodiment for packing unit  6300 . Packing unit  6300  can comprise male packing ring  6350 , plurality of seals  6302 , 6304 , female packing rings  6310 , 6380 , male packing ring  6350 , and packing retainer nut  1400  (not shown for clarity). Plurality of seals  6302  can seal in the opposite direction of plurality of seals  6304 . Packing retainer nut  1400  can be threadably connected to packing housing  1200  at threaded connection  1460 . Tightening packing retainer nut  1400  squeezes plurality of seals  6302 , 6304  between packing housing  1200  and retainer nut  1400  thereby increasing sealing between sleeve or housing  300  (through packing housing  1200 ) and swivel mandrel  110 . 
     Female backup ring (or packing ring)  6310  can comprise first end  6312 , second end  6314 , and is preferably comprised of a bearing grade peek material (such as material number 781 supplied by CDI Seals out of Humble, Tex.). Packing ring  6320  is preferable a bronze filled teflon seal (such as material number 714 supplied by CDI Seals out of Humble, Tex.). Packing rings  6330  and  6340  are preferable teflon seals (such as material number 711 supplied by CDI Seals out of Humble, Tex.). Male packing ring  6350  which can comprise first end  6352  and second end  6354  and is preferably machined from SAE 660 BRONZE or SAE 954 Aluminum Bronze with a flat heads  6353 , 6355  and both being 45 degrees from the vertical. Packing ring  6360  is preferable comprised of teflon (such as material number 711 supplied by CDI Seals out of Humble, Tex.). Packing ring  6370  is preferable a bronze filled teflon seal (such as material number 714 supplied by CDI Seals out of Humble, Tex.). Female backup ring (or packing ring)  6380  can comprise first end  6382 , second end  6384 , and is preferably comprised of a bearing grade peek material (such as material number 781 supplied by CDI Seals out of Humble, Tex.). Seals can be Chevron type “VS” packing rings. 
     Static seals  6400  (polypack seals  6410  and  6420 ) can seal from fluid flow in the direction of arrow  6640 ). Static seal  6430  (polypack seal  6430 ) seals from fluid flow in the direction of arrow  6720 ). Similarly, static seals  5400  (polypack seals  5410 ,  5420 , and  5430 ) seal from fluid flow in the direction of arrow  5710 , and can serve as a backup for static seals  6400 . 
     Packing unit  5300  (and plurality of seals  5306 ) is set up to block fluid flow in the direction of arrow  5700 , but not block fluid flow in the opposite direction (i.e., arrow  5600 ). In one embodiment sealing against fluid pressure in the direction of arrow  5700  is much greater than sealing against fluid pressure in the opposite direction (e.g., 1.5 times greater, 2, 3, 4, 5, 6, 7, 8, 9, 10, 20, 30, 40, 50, 60, 70, 80, 90, 100, 1000, and greater, along with any range between these specified factors). Accordingly, fluid (and fluid pressure) can flow through seals  5306  in the direction of arrow  5600  as schematically shown in  FIG. 65 ) and reach plurality of seals  6302  in the direction of arrows  6700  and  6710  (as schematically shown in  FIG. 68 ). It is expected that fluid pressure on the pin end of rotating and reciprocating swivel  5000  will be higher than pressure on the box end. Therefore, allowing fluid and pressure to flow in the direction of arrow  5600  through plurality of seals  5306  will decrease the net pressure seen by plurality of seals  6302  (the net pressure being the difference between the pressure on the pin end of plurality of seals  6302  and the box end of the plurality of seals  6302 ). 
     By reducing the net pressure to be sealed against, the expected life of seals  6302  is extended, and the expected frictional resistance created by seals  6302  is reduced. Furthermore, the pressure from fluid in the interstitial space between sleeve or housing  300  and mandrel  110  reduces the net force which sleeve  300  must resist in bending compared to a pressure outside of sleeve  300 . Accordingly, the size of sleeve  300  can be reduced based on the lowered net forces it will see. 
     Additionally, plurality of seals  5306  (in the box end of sleeve  300 ) and spaced apart from the primary seal set (plurality of seals  6302  on the pin end of sleeve  300 ), and can serve as a redundant seal set in the event of the failure of the primary seal set  6302 . In this case of failure of primary seal set  6302 , redundant plurality of seals  5306  will be almost completely a fresh set of seals because plurality of seals  5306  do not start to substantially seal unless and until primary plurality of seals  6302  fails (because there is no net pressure in the direction of arrow  5700  in  FIG. 65 ). Furthermore, even if the primary seal set  6302  fails, backup seal set  5306  will only see a net pressure against which it must seal (the net pressure being the difference between the pressure on the box end of plurality of seals  5306  and the pin end of the plurality of seals  5306 ). 
     Additionally, even where primary seal set  6302  fails, the pressure from fluid in the interstitial space between sleeve or housing  300  and mandrel  110  reduces the net force which sleeve  300  must resist in bending compared to an outside pressure on sleeve  300 —although now it is expected that the interstitial pressure will be greater than the pressure on the outside of sleeve or housing  300 . 
     In the unusual circumstance where the pressure from the box end (in the direction of arrows  5600 ,  6700 , and  6710 ) is greater than the pressure from the pin end (in the direction of arrows  660 ,  6610 ,  6630 , and  5700 ), then plurality of seals  6304  will seal against this net pressure in the direction of the pin end. 
       FIGS. 68 and 69  show an alternative construction for lower retainer cap  2500 ′ and tip  2520 ′ of retainer cap where the first plurality of fasteners/bolts  7032  and second plurality of fasteners/bolts  7042  are restricted from falling downhole (e.g., not exposed to the well bore). 
     Here, retainer cap  2500 ′ can comprise thrust bearing  7000  and spacer ring  7100 . Thrust bearing  7000  can comprise first end  7010 , second end  7020 , first plurality of openings  7030 , second plurality of openings  7050 . Spacer ring  7100  can comprise first end  7110 , second end  7120 , and plurality of openings  7200 . Spacer ring  7100  can also include a dowel opening  7140  for an alignment/positioning dowel  7150 . Retainer cap  2500 ′ can be connected to sleeve or housing  300  by first plurality of fasteners  7032  which pass through first plurality of openings  7030 . Tip  2520 ′ can be connected to retainer cap  2500 ′ through second plurality of fasteners  7042  which pass through second plurality of openings  7040  and thread into tip  2520 ′. Plurality of fasteners can have heads  7044  with driving portions  7043 . Here, a plurality of openings  7200  can coincide with the heads of the second plurality of fasteners  7042  for allowing these fasteners to be tightened (such as by using driving portion  7043 ). The longitudinal lengths of the plurality of openings  7200  is preferably substantially shorter than the longitudinal lengths of second plurality of fasteners  7042 . This will prevent one or more of the second plurality of fasteners from falling out of alternative swivel  5000  and swivel cap  2500 ′ if one or more fasteners  7042  become loosened. One or more dowels  7150  can be used to align plurality of openings  7200  with second plurality of openings  7040 . 
     While certain novel features of this invention shown and described herein are pointed out in the annexed claims, the invention is not intended to be limited to the details specified, since a person of ordinary skill in the relevant art will understand that various omissions, modifications, substitutions and changes in the forms and details of the device illustrated and in its operation may be made without departing in any way from the spirit of the present invention. No feature of the invention is critical or essential unless it is expressly stated as being “critical” or “essential.” 
     The following is a parts list of reference numerals or part numbers and corresponding descriptions as used herein: 
     
       
         
           
               
            
               
                   
               
               
                 LIST FOR REFERENCE NUMERALS 
               
            
           
           
               
               
            
               
                 Reference Numeral 
                 Description 
               
               
                   
               
            
           
           
               
               
            
               
                 10 
                 drilling rig/well drilling apparatus 
               
               
                 20 
                 drilling fluid line 
               
               
                 22 
                 drilling fluid or mud 
               
               
                 30 
                 rotary table 
               
               
                 40 
                 well bore 
               
               
                 50 
                 drill pipe 
               
               
                 60 
                 drill string or well string or work string 
               
               
                 70 
                 annular blowout preventer 
               
               
                 71 
                 annular seal unit 
               
               
                 75 
                 stack 
               
               
                 80 
                 riser 
               
               
                 85 
                 upper drill or work string 
               
               
                 86 
                 lower drill or work string 
               
               
                 87 
                 seabed 
               
               
                 88 
                 well head 
               
               
                 90 
                 upper volumetric section 
               
               
                 92 
                 lower volumetric section 
               
               
                 94 
                 displacement fluid 
               
               
                 96 
                 completion fluid 
               
               
                 100 
                 swivel 
               
               
                 110 
                 mandrel 
               
               
                 113 
                 arrow 
               
               
                 114 
                 arrow 
               
               
                 115 
                 arrow 
               
               
                 116 
                 arrow 
               
               
                 117 
                 arrow 
               
               
                 118 
                 arrow 
               
               
                 120 
                 upper end 
               
               
                 130 
                 lower end 
               
               
                 135 
                 fluted area 
               
               
                 136 
                 plurality of recessed areas 
               
               
                 137 
                 angled area or thrust shoulder 
               
               
                 138 
                 angled area (radial alignment) 
               
               
                 140 
                 box connection 
               
               
                 150 
                 pin connection 
               
               
                 160 
                 central longitudinal passage 
               
               
                 162 
                 connection between upper and lower end 
               
               
                 164 
                 connection from upper end (pin) 
               
               
                 166 
                 connection from lower end (box) 
               
               
                 168 
                 seal 
               
               
                 170 
                 seal 
               
               
                 180 
                 H - - length allowed for movement by 
               
               
                   
                 sleeve or housing over mandrel 
               
               
                 300 
                 swivel sleeve or housing 
               
               
                 302 
                 upper end 
               
               
                 304 
                 lower end 
               
               
                 310 
                 interior section 
               
               
                 311 
                 upper lubrication port 
               
               
                 312 
                 lower lubrication port 
               
               
                 315 
                 gap 
               
               
                 322 
                 check valve 
               
               
                 324 
                 check valve 
               
               
                 326 
                 upper catch, shoulder, flange 
               
               
                 328 
                 lower catch, shoulder, flange 
               
               
                 331 
                 upper base 
               
               
                 332 
                 upper radiused area 
               
               
                 341 
                 lower base 
               
               
                 342 
                 lower radiused area 
               
               
                 350 
                 L1 - - overall length of sleeve or housing 
               
               
                   
                 with attachments on upper and lower ends 
               
               
                 360 
                 L2 - - length between upper and lower 
               
               
                   
                 catches, shoulders, flanges 
               
               
                 370 
                 shoulder 
               
               
                 372 
                 recessed area 
               
               
                 373 
                 seal 
               
               
                 374 
                 recessed area 
               
               
                 375 
                 seal 
               
               
                 380 
                 shoulder 
               
               
                 382 
                 recessed area 
               
               
                 383 
                 seal 
               
               
                 384 
                 recessed area 
               
               
                 385 
                 seal 
               
               
                 400 
                 upper retainer cap 
               
               
                 405 
                 plurality of ribs 
               
               
                 420 
                 tip of retainer cap 
               
               
                 430 
                 base of retainer cap 
               
               
                 450 
                 recessed area 
               
               
                 460 
                 plurality of bolt holes 
               
               
                 470 
                 first plurality of bolts 
               
               
                 472 
                 second plurality of bolts 
               
               
                 500 
                 lower retainer cap 
               
               
                 510 
                 upper surface of retainer cap 
               
               
                 520 
                 tip of retainer cap 
               
               
                 530 
                 base of retainer cap 
               
               
                 540 
                 housing 
               
               
                 541 
                 first plurality of fasteners 
               
               
                 542 
                 first plurality of openings 
               
               
                 543 
                 second plurality of fasteners 
               
               
                 544 
                 second plurality of openings 
               
               
                 550 
                 first end 
               
               
                 552 
                 recessed area 
               
               
                 560 
                 second end 
               
               
                 562 
                 recessed area 
               
               
                 570 
                 bearing or thrust hub 
               
               
                 572 
                 first end 
               
               
                 574 
                 second end 
               
               
                 576 
                 plurality of tips and recessed areas 
               
               
                 578 
                 angled section 
               
               
                 590 
                 cover 
               
               
                 592 
                 first end 
               
               
                 594 
                 second end 
               
               
                 595 
                 recessed area 
               
               
                 596 
                 plurality of openings 
               
               
                 598 
                 exterior angled section 
               
               
                 599 
                 beveled section 
               
               
                 600 
                 plurality of openings for shear pins 
               
               
                 610 
                 plurality of shear pins 
               
               
                 611 
                 plurality of tips 
               
               
                 612 
                 plurality of snap rings 
               
               
                 614 
                 adhesive 
               
               
                 620 
                 arrow 
               
               
                 630 
                 arrow 
               
               
                 640 
                 arrow 
               
               
                 650 
                 arrow 
               
               
                 660 
                 arrow 
               
               
                 670 
                 arrow 
               
               
                 680 
                 arrow 
               
               
                 700 
                 joint of pipe 
               
               
                 710 
                 upper portion 
               
               
                 720 
                 lower portion 
               
               
                 730 
                 enlarged area 
               
               
                 740 
                 frustoconical area 
               
               
                 750 
                 protruding section 
               
               
                 800 
                 saver sub 
               
               
                 1000 
                 bearing and packing assembly 
               
               
                 1100 
                 bearing 
               
               
                 1110 
                 outer surface 
               
               
                 1120 
                 inner surface 
               
               
                 1122 
                 inner diameter 
               
               
                 1130 
                 first end 
               
               
                 1140 
                 second end 
               
               
                 1150 
                 opening 
               
               
                 1160 
                 pathway 
               
               
                 1180 
                 recessed areas 
               
               
                 1182 
                 inserts 
               
               
                 1190 
                 plurality of recessed areas 
               
               
                 1192 
                 base 
               
               
                 1200 
                 packing housing 
               
               
                 1210 
                 first end 
               
               
                 1220 
                 second end 
               
               
                 1230 
                 plurality of tips 
               
               
                 1240 
                 first opening 
               
               
                 1242 
                 perimeter recess 
               
               
                 1243 
                 seal (such as polypack) 
               
               
                 1250 
                 second opening 
               
               
                 1252 
                 threaded area 
               
               
                 1250 
                 second opening 
               
               
                 1252 
                 shoulder 
               
               
                 1300 
                 packing stack 
               
               
                 1305 
                 packing unit 
               
               
                 1310 
                 spacer 
               
               
                 1312 
                 first end of spacer 
               
               
                 1314 
                 second end of spacer 
               
               
                 1316 
                 enlarged section of spacer 
               
               
                 1320 
                 female packing end ring 
               
               
                 1322 
                 plurality of seals 
               
               
                 1326 
                 plurality of grooves 
               
               
                 1330 
                 packing ring 
               
               
                 1340 
                 packing ring 
               
               
                 1350 
                 packing ring 
               
               
                 1360 
                 packing ring 
               
               
                 1370 
                 male packing ring 
               
               
                 1372 
                 first end of male packing ring 
               
               
                 1374 
                 second end of male packing ring 
               
               
                 1400 
                 packing retainer nut 
               
               
                 1410 
                 first end 
               
               
                 1420 
                 plurality of tips 
               
               
                 1430 
                 plurality of recessed areas 
               
               
                 1440 
                 second end 
               
               
                 1450 
                 base 
               
               
                 1460 
                 threaded area 
               
               
                 1500 
                 end cap 
               
               
                 1510 
                 first end 
               
               
                 1520 
                 plurality of openings 
               
               
                 1530 
                 second end 
               
               
                 1540 
                 plurality of tips 
               
               
                 1550 
                 plurality of recessed areas 
               
               
                 1560 
                 mechanical seal 
               
               
                 1580 
                 dummy pipe 
               
               
                 1590 
                 testing plate 
               
               
                 1596 
                 radial injection port 
               
               
                 1592 
                 seal 
               
               
                 1594 
                 seal 
               
               
                 1598 
                 arrow 
               
               
                 2300 
                 swivel sleeve or housing 
               
               
                 2302 
                 upper end 
               
               
                 2304 
                 lower end 
               
               
                 2310 
                 interior section 
               
               
                 2311 
                 upper lubrication port 
               
               
                 2312 
                 lower lubrication port 
               
               
                 2315 
                 gap 
               
               
                 2322 
                 check valve 
               
               
                 2324 
                 check valve 
               
               
                 2326 
                 upper catch, shoulder, flange 
               
               
                 2328 
                 lower catch, shoulder, flange 
               
               
                 2331 
                 base 
               
               
                 2332 
                 radiused area 
               
               
                 2334 
                 plurality of openings 
               
               
                 2341 
                 base 
               
               
                 2342 
                 radiused area 
               
               
                 2344 
                 plurality of openings 
               
               
                 2350 
                 L1 - - overall length of sleeve or housing 
               
               
                   
                 with attachments on upper and lower ends 
               
               
                 2360 
                 L2 - - length between upper and lower 
               
               
                   
                 catches, shoulders, flanges 
               
               
                 2370 
                 shoulder 
               
               
                 2372 
                 recessed area 
               
               
                 2373 
                 seal 
               
               
                 2374 
                 recessed area 
               
               
                 2375 
                 seal 
               
               
                 2380 
                 shoulder 
               
               
                 2382 
                 recessed area 
               
               
                 2383 
                 seal 
               
               
                 2384 
                 recessed area 
               
               
                 2385 
                 seal 
               
               
                 2400 
                 upper retainer cap 
               
               
                 2405 
                 plurality of ribs 
               
               
                 2420 
                 tip of retainer cap 
               
               
                 2430 
                 base of retainer cap 
               
               
                 2450 
                 recessed area 
               
               
                 2460 
                 plurality of bolt holes 
               
               
                 2470 
                 first plurality of bolts 
               
               
                 2472 
                 second plurality of bolts 
               
               
                 2500 
                 lower retainer cap 
               
               
                 2510 
                 upper surface of retainer cap 
               
               
                 2520 
                 tip of retainer cap 
               
               
                 2530 
                 base of retainer cap 
               
               
                 2540 
                 housing 
               
               
                 2541 
                 first plurality of fasteners 
               
               
                 2542 
                 first plurality of openings 
               
               
                 2543 
                 second plurality of fasteners 
               
               
                 2544 
                 second plurality of openings 
               
               
                 2550 
                 first end 
               
               
                 2552 
                 recessed area 
               
               
                 2554 
                 base of recessed area 
               
               
                 2560 
                 second end 
               
               
                 2562 
                 recessed area 
               
               
                 2570 
                 length between base of recessed area to 
               
               
                   
                 interior angled section of cover 
               
               
                 2590 
                 cover 
               
               
                 2592 
                 first end 
               
               
                 2594 
                 second end 
               
               
                 2595 
                 recessed area 
               
               
                 2596 
                 plurality of openings 
               
               
                 2598 
                 exterior angled section 
               
               
                 2599 
                 beveled section 
               
               
                 2600 
                 interior angled section 
               
               
                 2612 
                 plurality of snap rings 
               
               
                 2614 
                 adhesive 
               
               
                 2620 
                 arrow 
               
               
                 2630 
                 arrow 
               
               
                 2640 
                 arrow 
               
               
                 2650 
                 arrow 
               
               
                 2660 
                 arrow 
               
               
                 2670 
                 arrow 
               
               
                 2680 
                 arrow 
               
               
                 2682 
                 arrow 
               
               
                 2684 
                 arrow 
               
               
                 2700 
                 joint of pipe 
               
               
                 2710 
                 upper portion 
               
               
                 2720 
                 lower portion 
               
               
                 2730 
                 enlarged area 
               
               
                 2740 
                 frustoconical area 
               
               
                 2750 
                 protruding section 
               
               
                 2800 
                 saver sub 
               
               
                 3000 
                 quick lock/quick unlock system 
               
               
                 3100 
                 first part 
               
               
                 3110 
                 bearing and locking hub 
               
               
                 3112 
                 first end 
               
               
                 3114 
                 second end 
               
               
                 3120 
                 plurality of fingers 
               
               
                 3130 
                 example finger 
               
               
                 3140 
                 tip 
               
               
                 3150 
                 latching area of finger 
               
               
                 3160 
                 base of finger 
               
               
                 3170 
                 length of finger 
               
               
                 3172 
                 arrow 
               
               
                 3200 
                 base 
               
               
                 3205 
                 outer diamater 
               
               
                 3210 
                 inner diameter 
               
               
                 3220 
                 first shoulder or angled section 
               
               
                 3260 
                 second shoulder or angled section 
               
               
                 3400 
                 second part 
               
               
                 3410 
                 latching area 
               
               
                 3420 
                 angled area 
               
               
                 3440 
                 flat area 
               
               
                 3460 
                 recessed area 
               
               
                 3600 
                 clutching member 
               
               
                 3610 
                 plurality of alignment members 
               
               
                 3620 
                 example of alignment member 
               
               
                 3630 
                 arrow shaped portion 
               
               
                 3640 
                 fastener 
               
               
                 3650 
                 plurality of bases for alignment members 
               
               
                 3660 
                 plurality of threaded openings 
               
               
                 3670 
                 example base for alignment member 
               
               
                 4000 
                 generic catches 
               
               
                 4010 
                 base 
               
               
                 4020 
                 connector 
               
               
                 4030 
                 base 
               
               
                 4040 
                 connector 
               
               
                 4200 
                 specialized catch 
               
               
                 4202 
                 arrow 
               
               
                 4204 
                 arrow 
               
               
                 4220 
                 first section 
               
               
                 4222 
                 inner diameter 
               
               
                 4224 
                 rounded area 
               
               
                 4226 
                 second rounded area 
               
               
                 4230 
                 plurality of openings 
               
               
                 4232 
                 inner diameter 
               
               
                 4234 
                 rounded area 
               
               
                 4236 
                 second rounded area 
               
               
                 4240 
                 second section 
               
               
                 4242 
                 interior 
               
               
                 4244 
                 base 
               
               
                 4246 
                 angled section 
               
               
                 4248 
                 second base 
               
               
                 4250 
                 diameter 
               
               
                 4252 
                 angled area 
               
               
                 4254 
                 base 
               
               
                 4259 
                 plurality of openings 
               
               
                 4260 
                 plurality of fasteners 
               
               
                 4270 
                 plurality of washers 
               
               
                 4280 
                 plurality of snap rings 
               
               
                 4400 
                 specialized catch 
               
               
                 4402 
                 arrow 
               
               
                 4404 
                 arrow 
               
               
                 4420 
                 first section 
               
               
                 4422 
                 interior 
               
               
                 4424 
                 base 
               
               
                 4426 
                 angled section 
               
               
                 4430 
                 plurality of openings 
               
               
                 4440 
                 second section 
               
               
                 4442 
                 interior 
               
               
                 4444 
                 base 
               
               
                 4446 
                 angled section 
               
               
                 4448 
                 second base 
               
               
                 4450 
                 plurality of openings 
               
               
                 4460 
                 plurality of fasteners 
               
               
                 4470 
                 plurality of washers 
               
               
                 4480 
                 plurality of snap rings 
               
               
                 5000 
                 rotating and reciprocating swivel 
               
               
                 5300 
                 packing stack 
               
               
                 5306 
                 plurality of seals 
               
               
                 5310 
                 spacer 
               
               
                 5312 
                 first end of spacer 
               
               
                 5314 
                 second end of spacer 
               
               
                 5320 
                 female packing end ring 
               
               
                 5323 
                 enlarged section of female packing ring 
               
               
                 5330 
                 packing ring 
               
               
                 5340 
                 packing ring 
               
               
                 5350 
                 packing ring 
               
               
                 5370 
                 male packing ring 
               
               
                 5372 
                 first end of male packing ring 
               
               
                 5374 
                 second end of male packing ring 
               
               
                 5400 
                 plurality of polypack seals 
               
               
                 5410 
                 polypack seal 
               
               
                 5420 
                 polypack seal 
               
               
                 5430 
                 polypack seal 
               
               
                 5440 
                 polypack seal 
               
               
                 5500 
                 hydrostatic testing port 
               
               
                 5600 
                 arrow 
               
               
                 5700 
                 arrow 
               
               
                 5710 
                 arrow 
               
               
                 5720 
                 arrow 
               
               
                 6300 
                 packing stack 
               
               
                 6302 
                 first plurality of seals 
               
               
                 6304 
                 second plurality of seals 
               
               
                 6310 
                 female packing end ring 
               
               
                 6312 
                 first end of female packing end ring 
               
               
                 6314 
                 second end of female packing end ring 
               
               
                 6316 
                 enlarged section of female packing end 
               
               
                   
                 ring 
               
               
                 6317 
                 reduced section of female packing end ring 
               
               
                 6320 
                 packing ring 
               
               
                 6330 
                 packing ring 
               
               
                 6340 
                 packing ring 
               
               
                 6350 
                 male packing ring 
               
               
                 6352 
                 first end of male packing ring 
               
               
                 6354 
                 second end of male packing ring 
               
               
                 6360 
                 packing ring 
               
               
                 6370 
                 packing ring 
               
               
                 6380 
                 female packing ring 
               
               
                 6382 
                 first end of female packing ring 
               
               
                 6384 
                 second end of female packing ring 
               
               
                 6400 
                 plurality of polypack seals 
               
               
                 6410 
                 polypack seal 
               
               
                 6420 
                 polypack seal 
               
               
                 6430 
                 polypack seal 
               
               
                 6440 
                 polypack seal 
               
               
                 6500 
                 hydrostatic testing port 
               
               
                 6600 
                 arrow 
               
               
                 6610 
                 arrow 
               
               
                 6630 
                 arrow 
               
               
                 6640 
                 arrow 
               
               
                 6700 
                 arrow 
               
               
                 6710 
                 arrow 
               
               
                 6720 
                 arrow 
               
               
                 7000 
                 thrust bearing 
               
               
                 7010 
                 first end 
               
               
                 7020 
                 second end 
               
               
                 7030 
                 first plurality of openings 
               
               
                 7032 
                 first plurality of fasteners/bolts 
               
               
                 7033 
                 driving portion 
               
               
                 7040 
                 second plurality of openings 
               
               
                 7042 
                 second plurality of fasteners/bolts 
               
               
                 7043 
                 driving portion 
               
               
                 7044 
                 bolt head 
               
               
                 7100 
                 spacer ring 
               
               
                 7110 
                 first end 
               
               
                 7120 
                 second end 
               
               
                 7140 
                 dowel opening 
               
               
                 7150 
                 dowel 
               
               
                 7200 
                 plurality of openings 
               
               
                 BJ 
                 ball joint 
               
               
                 BL 
                 booster line 
               
               
                 CM 
                 choke manifold 
               
               
                 CL 
                 diverter line 
               
               
                 CM 
                 choke manifold 
               
               
                 D 
                 diverter 
               
               
                 DL 
                 diverter line 
               
               
                 F 
                 rig floor 
               
               
                 IB 
                 inner barrel 
               
               
                 KL 
                 kill line 
               
               
                 MP 
                 mud pit 
               
               
                 MB 
                 mud gas buster or separator 
               
               
                 OB 
                 outer barrel 
               
               
                 R 
                 riser 
               
               
                 RF 
                 flow line 
               
               
                 S 
                 floating structure or rig 
               
               
                 SJ 
                 slip or telescoping joint 
               
               
                 SS 
                 shale shaker 
               
               
                 W 
                 wellhead 
               
               
                   
               
            
           
         
       
     
     All measurements disclosed herein are at standard temperature and pressure, at sea level on Earth, unless indicated otherwise. All materials used or intended to be used in a human being are biocompatible, unless indicated otherwise. 
     It will be understood that each of the elements described above, or two or more together may also find a useful application in other types of methods differing from the type described above. Without further analysis, the foregoing will so fully reveal the gist of the present invention that others can, by applying current knowledge, readily adapt it for various applications without omitting features that, from the standpoint of prior art, fairly constitute essential characteristics of the generic or specific aspects of this invention set forth in the appended claims. The foregoing embodiments are presented by way of example only; the scope of the present invention is to be limited only by the following claims.