Patent Abstract:
A double swivel for use with a top drive power unit supported for connection with a well string in a well bore to selectively impart longitudinal and/or rotational movement to the well string, a feeder for supplying a pumpable substance such as cement and the like from an external supply source to the interior of the well string in the well bore without first discharging it through the top drive power unit including a mandrel extending through double sleeves which are sealably and rotatably supported thereon for relative rotation between the sleeves and mandrel. The mandrel and sleeves have flow passages for communicating the pumpable substance from an external source to discharge through the sleeve and mandrel and into the interior of the well string below the top drive power unit. The unit can include a packing injection system, clamp, and novel packing configuration. In an alternative embodiment the unit can include a plug or ball insertion tool.

Full Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
       [0001]    This is a continuation of U.S. patent application Ser. No. 13/286,676, filed 1 Nov. 2011 (issuing as U.S. Pat. No. 8,201,627 on Jun. 19, 2012), which was a continuation of U.S. patent application Ser. No. 12/413,636, filed 30 Mar. 2009 (now U.S. Pat. No. 8,047,290 issued on 1 Nov. 2011), which was a continuation of U.S. patent application Ser. No. 11/975,131, filed 16 Oct. 2007 (now U.S. Pat. No. 7,510,007, issued on 31 Mar. 2009), which was a continuation of U.S. patent application Ser. No. 11/334,083, filed 17 Jan. 2006 (now U.S. Pat. No. 7,281,582, issued 16 Oct. 2007), which was a continuation-in-part of U.S. patent application Ser. No. 10/658,092, filed 9 Sep. 2003 (now U.S. Pat. No. 7,007,753, issued 7 Mar. 2006), which was non-provisional of U.S. provisional patent application Ser. No. 60/409,177, filed 9 Sep. 2002, all of which are incorporated herein by reference and to which priority is hereby claimed. 
         [0002]    This is a continuation of U.S. patent application Ser. No. 13/286,676, filed 1 Nov. 2011 (issuing as U.S. Pat. No. 8,201,627 on Jun. 19, 2012), which was a continuation of U.S. patent application Ser. No. 12/413,636, filed 30 Mar. 2009 (now U.S. Pat. No. 8,047,290 issued on 1 Nov. 2011), which was a continuation of U.S. patent application Ser. No. 11/975,131, filed 16 Oct. 2007 (now U.S. Pat. No. 7,510,007, issued on 31 Mar. 2009), which was a continuation of U.S. patent application Ser. No. 11/334,083, filed 17 Jan. 2006 (now U.S. Pat. No. 7,281,582, issued 16 Oct. 2007), which was non-provisional of U.S. provisional patent application Ser. No. 60/644,683, filed 19 Jan. 2005, all of which are incorporated herein by reference and to which priority is hereby claimed. 
     
    
     STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
       [0003]    Not applicable 
       REFERENCE TO A “MICROFICHE APPENDIX” 
       [0004]    Not applicable 
       BACKGROUND 
       [0005]    In top drive rigs, the use of a top drive unit, or top drive power unit is employed to rotate drill pipe, or well string in a well bore. Top drive rigs can include spaced guide rails and a drive frame movable along the guide rails and guiding the top drive power unit. The traveling block supports the drive frame through a hook and swivel, and the driving block is used to lower or raise the drive frame along the guide rails. For rotating the drill or well string, the top drive power unit includes a motor connected by gear means with a rotatable member both of which are supported by the drive frame. 
         [0006]    During drilling operations, when it is desired to “trip” the drill pipe or well string into or out of the well bore, the drive frame can be lowered or raised. Additionally, during servicing operations, the drill string can be moved longitudinally into or out of the well bore. 
         [0007]    The stem of the swivel communicates with the upper end of the rotatable member of the power unit in a manner well known to those skilled in the art for supplying fluid, such as a drilling fluid or mud, through the top drive unit and into the drill or work string. The swivel allows drilling fluid to pass through and be supplied to the drill or well string connected to the lower end of the rotatable member of the top drive power unit as the drill string is rotated and/or moved up and down. 
         [0008]    Top drive rigs also can include elevators are secured to and suspended from the frame, the elevators being employed when it is desired to lower joints of drill string into the well bore, or remove such joints from the well bore. 
         [0009]    At various times top drive operations, beyond drilling fluid, require various substances to be pumped downhole, such as cement, chemicals, epoxy resins, or the like. In many cases it is desirable to supply such substances at the same time as the top drive unit is rotating and/or moving the drill or well string up and/or down, but bypassing the top drive&#39;s power unit so that the substances do not damage/impair the unit. Additionally, it is desirable to supply such substances without interfering with and/or intermittently stopping longitudinal and/or rotational movement by the top drive unit of the drill or well string. 
         [0010]    A need exists for a device facilitating insertion of various substances downhole through the drill or well string, bypassing the top drive unit, while at the same time allowing the top drive unit to rotate and/or move the drill or well string. 
         [0011]    One example includes cementing a string of well bore casing. In some casing operations it is considered good practice to rotate the string of casing when it is being cemented in the wellbore. Such rotation is believed to facilitate better cement distribution and spread inside the annular space between the casing&#39;s exterior and interior of the well bore. In such operations the top drive unit can be used to both support and continuously rotate/intermittently reciprocate the string of casing while cement is pumped down the string&#39;s interior. During this time it is desirable to by-pass the top drive unit to avoid possible damage to any of its portions or components. 
         [0012]    The following US patent is incorporated herein by reference: U.S. Pat. No. 4,722,389. 
         [0013]    While certain novel features of this invention shown and described below 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 maybe 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.” 
       BRIEF SUMMARY 
       [0014]    The apparatus of the present invention solves the problems confronted in the art in a simple and straightforward manner. The invention herein broadly relates to an assembly having a top drive arrangement for rotating and longitudinally moving a drill or well string. In one embodiment the present invention includes a swivel apparatus, the swivel generally comprising a mandrel and a sleeve, the swivel being especially useful for top drive rigs. 
         [0015]    The sleeve can be rotatably and sealably connected to the mandrel. The swivel can be incorporated into a drill or well string and enabling string sections both above and below the sleeve to be rotated in relation to the sleeve. Additionally, the swivel provides a flow path between the exterior of the sleeve and interior of the mandrel while the drill string is being moved in a longitudinal direction (up or down) and/or being rotated/reciprocated. The interior of the mandrel can be fluidly connected to the longitudinal bore of casing or drill string thus providing a path from the sleeve to the interior of the casing/drill string. 
         [0016]    In one embodiment an object of the present invention is to provide a method and apparatus for servicing a well wherein a swivel is connected to and below a top drive unit for conveying pumpable substances from an external supply through the swivel for discharge into the well string, but bypassing the top drive unit. 
         [0017]    In another embodiment of the present invention is provided a method of conducting servicing operations in a well bore, such as cementing, comprising the steps of moving a top drive unit longitudinally and/or rotationally to provide longitudinal movement and/or rotation/reciprocation in the well bore of a well string suspended from the top drive unit, rotating the drill or well string and supplying a pumpable substance to the well bore in which the drill or well string is manipulated by introducing the pumpable substance at a point below the top drive power unit and into the well string. 
         [0018]    In other embodiments of the present invention a swivel placed below the top drive unit can be used to perform jobs such as spotting pills, squeeze work, open formation integrity work, kill jobs, fishing tool operations with high pressure pumps, sub-sea stack testing, rotation of casing during side tracking, and gravel pack or frac jobs. In still other embodiments a top drive swivel can be used in a method of pumping loss circulation material (LCM) into a well to plug/seal areas of downhole fluid loss to the formation and in high speed milling jobs using cutting tools to address down hole obstructions. In other embodiments the top drive swivel can be used with free point indicators and shot string or cord to free stuck pipe where pumpable substances are pumped downhole at the same time the downhole string/pipe/free point indicator is being rotated and/or reciprocated. In still other embodiments the top drive swivel can be used for setting hook wall packers and washing sand. 
         [0019]    In still other embodiments the top drive swivel can be used for pumping pumpable substances downhole when repairs/servicing is being done to the top drive unit and rotation of the downhole drill string is being accomplished by the rotary table. Such use for rotation and pumping can prevent sticking/seizing of the drill string downhole. In this application safety valves, such as TIW valves, can be placed above and below the top drive swivel to enable routing of fluid flow and to ensure well control. 
         [0020]    In an alternative embodiment the unit can include double swivel portions. In another alternative embodiment unit can include an insertion tool for inserting a plug or ball into the unit. 
         [0021]    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 
         [0022]    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: 
           [0023]      FIG. 1  is a schematic view showing a top drive rig with one embodiment of a top drive swivel incorporated in the drill string; 
           [0024]      FIG. 2  is a schematic view of one embodiment of a top drive swivel; 
           [0025]      FIG. 3  is a sectional view of a mandrel which can be incorporated in the top drive swivel of  FIG. 2 ; 
           [0026]      FIG. 4  is a sectional view of a sleeve which can be incorporated into the top drive swivel of  FIG. 2 ; 
           [0027]      FIG. 5  is a right hand side view of the sleeve of  FIG. 4 ; 
           [0028]      FIG. 6  is a sectional view of the top drive swivel of  FIG. 2 ; 
           [0029]      FIG. 6A  is a sectional view of the packing unit shown in  FIG. 6 ; 
           [0030]      FIG. 6B  is a top view of the packing injection ring shown in  FIGS. 6 and 6A ; 
           [0031]      FIG. 6C  is a side view section of the packing injection ring shown in  FIG. 6B ; 
           [0032]      FIG. 7  is a top view of a clamp which can be incorporated into the top drive swivel of  FIG. 2 ; 
           [0033]      FIG. 8  is a side view of the clamp of  FIG. 7 ; 
           [0034]      FIG. 9  is a perspective view and partial sectional view of the top drive swivel shown in  FIG. 2 ; 
           [0035]      FIG. 10  is a schematic view of an alternative embodiment of a top drive swivel having double swivel portions; 
           [0036]      FIG. 11  is a schematic view of an alternative embodiment of a top drive swivel having double swivel portions; 
           [0037]      FIG. 12  is a schematic view of an alternative valve wherein the valve ball holds a plug or ball; 
           [0038]      FIG. 13  shows a tool for inserting a ball into the top drive swivel or drill string; 
       
    
    
     DETAILED DESCRIPTION 
       [0039]    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. 
         [0040]      FIG. 1  is a schematic view showing a top drive rig  1  with one embodiment of a top drive swivel  30  incorporated into drill string  20 .  FIG. 1  is shows a rig  1  having a top drive unit  10 . Rig  5  comprises supports  16 , 17 ; crown block  2 ; traveling block  4 ; and hook  5 . Draw works  11  uses cable  12  to move up and down traveling block  4 , top drive unit  10 , and drill string  20 . Traveling block  4  supports top drive unit  10 . Top drive unit  10  supports drill string  20 . 
         [0041]    During drilling operations, top drive unit  10  can be used to rotate drill string  20  which enters wellbore  14 . Top drive unit  10  can ride along guide rails  15  as unit  10  is moved up and down. Guide rails  15  prevent top drive unit  10  itself from rotating as top drive unit  10  rotates drill string  20 . During drilling operations drilling fluid can be supplied downhole through drilling fluid line  8  and gooseneck  6 . 
         [0042]    At various times top drive operations, beyond drilling fluid, require substances to be pumped downhole, such as cement, chemicals, epoxy resins, or the like. In many cases it is desirable to supply such substances at the same time as top drive unit  10  is rotating and/or moving drill or well string  20  up and/or down and bypassing top drive unit  10  so that the substances do not damage/impair top drive unit  10 . Additionally, it is desirable to supply such substances without interfering with and/or intermittently stopping longitudinal and/or rotational movements of drill or well string  20  being moved/rotated by top drive unit  10 . This can be accomplished by using top drive swivel  30 . 
         [0043]    Top drive swivel  30  can be installed between top drive unit  10  and drill string  20 . One or more joints of drill pipe  18  can be placed between top drive unit  10  and swivel  30 . Additionally, a valve can be placed between top drive swivel  30  and top drive unit  10 . Pumpable substances can be pumped through hose  31 , swivel  30 , and into the interior of drill string  20  thereby bypassing top drive unit  10 . Top drive swivel  30  is preferably sized to be connected to drill string  20  such as 4½ inch IF API drill pipe or the size of the drill pipe to which swivel  30  is connected to. However, cross-over subs can also be used between top drive swivel  30  and connections to drill string  20 . 
         [0044]      FIG. 2  is a schematic view of one embodiment of a top drive swivel  30 . Top drive swivel  30  can be comprised of mandrel  40  and sleeve  150 . Sleeve  150  is rotatably and sealably connected to mandrel  40 . Accordingly, when mandrel  40  is rotated, sleeve  150  can remain stationary to an observer insofar as rotation is concerned. As will be discussed later inlet  200  of sleeve  150  is and remains fluidly connected to a the central longitudinal passage  90  of mandrel  40 . Accordingly, while mandrel  40  is being rotated and/or moved up and down pumpable substances can enter inlet  200  and exit central longitudinal passage  90  at lower end  60  of mandrel  40 . 
         [0045]      FIG. 3  is a sectional view of mandrel  40  which can be incorporated in the top drive swivel  30 . Mandrel  40  is comprised of upper end  50  and lower end  60 . Central longitudinal passage  90  extends from upper end  50  through lower end  60 . Lower end  60  can include a pin connection or any other conventional connection. Upper end  50  can include box connection  70  or any other conventional connection. Mandrel  40  can in effect become a part of drill string  20 . Sleeve  150  fits over mandrel  40  and becomes rotatably and sealably connected to mandrel  40 . Mandrel  40  can include shoulder  100  to supper sleeve  150 . Mandrel  40  can include one or more radial inlet ports  140  fluidly connecting central longitudinal passage  90  to recessed area  130 . Recessed area  130  preferably forms a circumferential recess along the perimeter of mandrel  40  and between packing support areas  131 , 132 . In such manner recessed area will remain fluidly connected with radial passage  190  and inlet  200  of sleeve  150  (see  FIGS. 4 ,  6 ). 
         [0046]    To reduce friction between mandrel  40  and packing units  305 ,  415  ( FIG. 6 ) and increase the life expectancy of packing units  305 ,  415 , packing support areas  131 ,  132  can be 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. Packing support areas  131 ,  132  can also be coated by a plating method, such as electroplating. The surface of support areas  131 ,  132  can be ground/polished/finished to a desired finish to reduce friction and wear between support areas  131 ,  132  and packing units  305 ,  415 . 
         [0047]      FIG. 4  is a sectional view of sleeve  150  which can be incorporated into top drive swivel  30 .  FIG. 5  is a right hand sectional view of sleeve  150  taken along the lines  4 - 4 . Sleeve  150  can include central longitudinal passage  180  extending from upper end  160  through lower end  170 . Sleeve  150  can also include radial passage  190  and inlet  200 . Inlet  200  can be attached by welding or any other conventional type method of fastening such as a threaded connection. If welded the connection is preferably heat treated to remove residual stresses created by the welding procedure. Also shown is protruding section  155  along with upper and lower shoulders  156 , 157 . Lubrication port  210  can be included to provide lubrication for interior bearings. Packing ports  220 ,  230  can also be included to provide the option of injecting packing material into the packing units  305 , 415  (see  FIG. 6 ). A protective cover  240  can be placed around packing port  230  to protect packing injector  235  (see  FIG. 6 ). Optionally, a second protective cover can be placed around packing port  220 , however, it is anticipated that protection will be provided by clamp  600  and inlet  200 . Sleeve  150  can include peripheral groove  205  for attachment of clamp  600 . Additionally, key way  206  can be provided for insertion of a key  700 .  FIG. 5  illustrates how central longitudinal passage  180  is fluidly connected to inlet  200  through radial passage  190 . It is preferred that welding be performed using Preferred Industries Welding Procedure number T3, 1550REV-A 4140HT (285/311 bhn) RMT to 4140 HT (285/311 bhn(RMT) It is also preferred that welds be X-ray tested, magnetic particle tested, and stress relieved. 
         [0048]      FIG. 6  is a sectional view of the assembled top drive swivel  30  of  FIG. 2 . As can be seen sleeve  150  slides over mandrel  40 . Bearings  145 ,  146  rotatably connect sleeve  150  to mandrel  40 . Bearings  145 ,  146  are preferably thrust bearings although many conventionally available bearing will adequately function, including conical and ball bearings. Packing units  305 ,  415  sealingly connect sleeve  150  to mandrel  40 . Inlet  200  of sleeve  150  is and remains fluidly connected to central longitudinal passage  90  of mandrel  40 . Accordingly, while mandrel  40  is being rotated and/or moved up and down pumpable substances can enter inlet  200  and exit central longitudinal passage  90  at lower end  60  of mandrel  40 . Recessed area  130  and protruding section  155  form a peripheral recess between mandrel  40  and sleeve  150 . The fluid pathway from inlet  200  to outlet at lower end  60  of central longitudinal passage  90  is as follows: entering inlet  200  (arrow  201 ); passing through radial passage  190  (arrow  202 ); passing through recessed area  130  (arrow  202 ); passing through one of the plurality of radial inlet ports  140  (arrow  202 ), passing through central longitudinal passage  90  (arrow  203 ); and exiting mandrel  40  via lower end  60  at pin connection  80  (arrows  204 ,  205 ). 
         [0049]      FIG. 6A  shows a blown up schematic view of packing unit  305 . Packing unit  305  can comprise packing end  320 ; packing ring  330 , packing ring  340 , packing injection ring  350 , packing end  360 , packing ring  370 , packing ring  380 , packing ring  390 , packing ring  400 , and packing end  410 . Packing unit  305  sealing connects mandrel  40  and sleeve  150 . Packing unit  305  can be encased by packing retainer nut  310  and shoulder  156  of protruding section  155 . Packing retainer nut  310  can be a ring which threadably engages sleeve  150  at threaded area  316 . Packing retainer nut  310  and shoulder  156  squeeze packing unit  305  to obtain a good seal between mandrel  40  and sleeve  150 . Set screw  315  can be used to lock packing retainer nut  310  in place and prevent retainer nut  310  from loosening during operation. Set screw  315  can be threaded into bore  314  and lock into receiving area  317  on sleeve  150 . Packing unit  415  can be constructed substantially similar to packing unit  305 . The materials for packing unit  305  and packing unit  415  can be similar. 
         [0050]    Packing end  320  is preferably a bronze female packing end. Packing ring  330  is preferably a “Vee” packing ring—Teflon such as that supplied by CDI part number 0500700-VS-720 Carbon Reflon (having 2 percent carbon). Packing ring  340  is preferably a “Vee” packing ring—Rubber such as that supplied by CDI part number 0500700-VS-850NBR Aramid. Packing injection ring  350  is described below in the discussion regarding  FIGS. 6B and 6C . Packing end  360  preferably a bronze female packing end. Packing ring  370  is preferably a “Vee” packing ring—Teflon such as that supplied by CDI part number 0500700-VS-720 Carbon Reflon (having 2 percent carbon). Packing ring  380  is preferably a “Vee” packing ring—Rubber such as that supplied by CDI part number 0500700-VS-850NBR Aramid. Packing ring  390  is preferably a “Vee” packing ring—Teflon such as that supplied by CDI part number 0500700-VS-720 Carbon Reflon (having 2 percent carbon). Packing ring  400  is preferably a “Vee” packing ring—Rubber such as that supplied by CDI part number 0500700-VS-850NBR Aramid. Packing end  410  is preferably a bronze male packing ring. Various alternative materials for packing rings can be used such as standard chevron packing rings of standard packing materials. Bronze rings preferably meet or exceed an SAE 660 standard. 
         [0051]    A packing injection option can be provided for top drive swivel  30 . Injection fitting  225  can be used to inject additional packing material such as teflon into packing unit  305 . Head  226  for injection fitting  225  can be removed and packing material can then be inserting into fitting  225 . Head  226  can then be screwed back into injection fitting  225  which would push packing material through fitting  225  and into packing port  220 . The material would then be pushed into packing ring  350 . Packing ring  350  can comprise radial port  352  and transverse port  351 . The material would proceed through radial port  352  and exit through transverse port  351 . The material would tend to push out and squeeze packing rings  340 ,  330 ,  320  and packing rings  360 ,  370 ,  380 ,  390 ,  400  tending to create a better seal between packing unit  305  with mandrel  40  and sleeve  150 . The interaction between injection fitting  235  and packing unit  415  can be substantially similar to the interaction between injection fitting  225  and packing unit  305 . A conventionally available material which can be used for packing injection fittings  225 ,  235  is DESCO™ 625 Pak part number 6242-12 in the form of a 1 inch by ⅜ inch stick and distributed by Chemola Division of South Coast Products, Inc., Houston, Tex. In  FIG. 6 , injection fitting  235  is shown ninety degrees out of phase and, is preferably located as shown in  FIG. 9 . 
         [0052]    Injection fittings  225 ,  235  have a dual purpose: (a) provide an operator a visual indication whether there has been any leakage past either packing units  305 ,  415  and (b) allow the operator to easily inject additional packing material and stop seal leakage without removing top drive swivel  30  from drill string  20 . 
         [0053]      FIGS. 6B and 6C  shows top and side views of packing injection ring  350 . Packing injection ring  350  includes a male end  355  at its top and a flat end  356  at its rear. Ring  350  includes peripheral groove  353  around its perimeter. Optionally, ring  350  can include interior groove along its interior. A plurality of transverse ports  351 ,  351 ′,  351 ″,  351 ′, etc. extending from male end  355  to flat end  356  can be included and can be evenly spaced along the circumference of ring  350 . A plurality of radial ports  352 ,  352 ′,  352 ″,  352 ′″, etc. can be included extending from peripheral groove  353  and respectively intersecting transverse ports  351 ,  351 ′,  351 ″,  351 ′″, etc. Preferably, the radial ports can extend from peripheral groove  353  through interior groove  354 . 
         [0054]    Retainer nut  800  can be used to maintain sleeve  150  on mandrel  40 . Retainer nut  800  can threadably engage mandrel  40  at threaded area  801 . Set screw  890  can be used to lock in place retainer nut  800  and prevent nut  800  from loosening during operation. Set screw  890  threadably engages retainer nut  800  through bore  900  and sets in one of a plurality of receiving portions  910  formed in mandrel  40 . Retaining nut  800  can also include grease injection fitting  880  for lubricating bearing  145 . Wiper ring  271  set in area  270  protects against dirt and other items from entering between the sleeve  150  and mandrel  40 . Grease ring  291  set in area  290  holds in lubricant for bearing  145 . 
         [0055]    Bearing  146  can be lubricated through grease injection fitting  211  and lubrication port  210 . Bearing  145  can be lubricated through grease injection fitting  881  and lubrication port  880 . 
         [0056]      FIG. 7  is a top view of clamp  600  which can be incorporated into top drive swivel  30 .  FIG. 8  is a side view of clamp  600 . Clamp  600  comprises first portion  610  and second portion  620 . First and second portions  610 ,  620  can be removably attached by fasteners  670 ,  680 . Clamp  600  fits in groove  205 / 605  of sleeve  150  ( FIG. 6 ). Key  700  can be included in keyway  690 . A corresponding keyway  691  is included in sleeve  150  of top drive swivel  30 . Keyways  690 ,  691  and key  700  prevent clamp  600  from rotating relative to sleeve  150 . A second key  720  can be installed in keyways  710 ,  711 . Shackles  650 ,  660  can be attached to clamp  600  to facilitate handing top drive swivel  30  when clamp  600  is attached. Torque arms  630 ,  640  can be included to allow attachment of clamp  600  (and sleeve  150 ) to a stationary part of top drive rig  1  and prevent sleeve  150  from rotating while drill string  20  is being rotated by top drive  10  (and top drive swivel  30  is installed in drill string  20 ). Torque arms  630 ,  640  are provided with holes for attaching restraining shackles. Restrained torque arms  630 ,  640  prevent sleeve  150  from rotating while mandrel  40  is being spun. Otherwise, frictional forces between packing units  305 ,  415  and packing support areas  131 ,  135  of rotating mandrel  40  would tend to also rotate sleeve  150 . Clamp  600  is preferably fabricated from  4140  heat treated steel being machined to fit around sleeve  150 . 
         [0057]      FIG. 9  is an overall perspective view (and partial sectional view) of top drive swivel  30 . Sleeve  150  is shown rotatably connected to mandrel  40 . Bearings  145 ,  146  allow sleeve  150  to rotate in relation to mandrel  40 . Packing units  305 ,  415  sealingly connect sleeve  150  to mandrel  40 . Retaining nut  800  retains sleeve  150  on mandrel  40 . Inlet  200  of sleeve  150  is fluidly connected to central longitudinal passage  90  of mandrel  40 . Accordingly, while mandrel  40  is being rotated and/or moved up and down pumpable substances can enter inlet  200  and exit central longitudinal passage  90  at lower end  60  of mandrel  40 . Recessed area  130  and protruding section  155  form a peripheral recess between mandrel  40  and sleeve  150 . The fluid pathway from inlet  200  to outlet at lower end  60  of central longitudinal passage  90  is as follows: entering inlet  200 ; passing through radial passage  190 ; passing through recessed area  130 ; passing through one of the plurality of radial inlet ports  40 ; passing through central longitudinal passage  90 ; and exiting mandrel  40  through central longitudinal passage  90  at lower end  60  and pin connection  80 . In  FIG. 9 , injection fitting  225  is shown ninety degrees out of phase and, for protection, is preferably located between inlet  200  and clamp  600 . 
         [0058]    Mandrel  40  takes substantially all of the structural load from drill string  20 . The overall length of mandrel  40  is preferably 52 and 5/16 inches. Mandrel  40  can be machined from a single continuous piece of heat treated steel bar stock. NC50 is preferably the API Tool Joint Designation for the box connection  70  and pin connection  80 . Such tool joint designation is equivalent to and interchangeable with 4 ½ inch IF (Internally Flush), 5 inch XH (Extra Hole) and 5½ inch DSL (Double Stream Line) connections. Additionally, it is preferred that the box connection  70  and pin connection  80  meet the requirements of API specifications  7  and  7 G for new rotary shouldered tool joint connections having 6⅝ inch outer diameter and a 2¾ inch inner diameter. The Strength and Design Formulas of API 7G—Appendix A provides the following load carrying specification for mandrel  40  of top drive swivel  30 : (a) 1,477 kpounds tensile load at the minimum yield stress; (b) 62,000 foot-pounds torsion load at the minimum torsional yield stress; and (c) 37,200 foot-pounds recommended minimum make up torque. Mandrel  40  can be machined from  4340  heat treated bar stock. 
         [0059]    Sleeve  150  is preferably fabricated from  4140  heat treated round mechanical tubing having the following properties: (120,000 psi minimum tensile strength, 100,000 psi minimum yield strength, and 285/311 Brinell Hardness Range). The external diameter of sleeve  150  is preferably about 11 inches. Sleeve  150  preferably resists high internal pressures of fluid passing through inlet  200 . Preferably top drive swivel  30  with sleeve  150  will withstand a hydrostatic pressure test of 12,500 psi. At this pressure the stress induced in sleeve  150  is preferably only about 24.8 percent of its material&#39;s yield strength. At a preferable working pressure of 7,500 psi, there is preferably a 6.7:1 structural safety factor for sleeve  150 . 
         [0060]    To minimize flow restrictions through top drive swivel  30 , large open areas are preferred. Preferably each area of interest throughout top drive swivel  30  is larger than the inlet service port area  200 . Inlet  200  is preferably  3  inches having a flow area of 4.19 square inches. The flow area of the annular space between sleeve  150  and mandrel  40  is preferably 20.81 square inches. The flow area through the plurality of radial inlet ports  140  is preferably 7.36 square inches. The flow area through central longitudinal bore  90  is preferably 5.94 square inches. 
         [0061]      FIG. 10  is a schematic view of an alternative embodiment of a top drive swivel  1000  having double swivel portions  1030 ,  2030  and intermediate valve  1006 . Each swivel portion  1030 , 2030  can be constructed similar to top drive swivel  30 . Similar to top drive swivel  30  shown in  FIG. 1 , top drive swivel  1000  can be connected to top drive unit  10  and drill string  20 . Valve  1006  can be a full opening ball valve. One or more additional valves can be included between swivel portions  1030 , 2030 . 
         [0062]    Stabilizing bracket  1005  can be used to stabilize swivels  1030  and  2030  (and sleeves  1050  and  2050 ). Stabilizing bracket can include arm  1010  which can be connected rigidly, slidingly, or otherwise to rig  1  (shown in  FIG. 1 ) or some other fixed member for constraining or restricting movement of sleeves  1050  and  2050 . A sliding connection of arm  1010  allows top drive unit  1  to move drill string  20  up and down at the same time top drive unit  1  rotates drill string  20 . A rigid connection would restrict up and down movement(but not rotation) of drill string  20 . Connecting stabilizing bracket  1010  to rig  1  is preferred to address the tendency of frictional forces (occurring between mandrels  1040  and  2040  and sleeves  1050  and  2050 ) causing sleeves  1050  and  2050  to rotate when mandrels  1040  and  2040  rotate. 
         [0063]    Rotation of top drive unit  1  lcan cause rotation of swivel mandrel  1040  as shown by arrow  1001 . Rotation of swivel mandrel  1040  in the direction of arrow  1001  causes rotation of valve member  1006  as shown by arrow  1002 . Rotation of valve member  1006  in the direction of arrow  1002  causes rotation of swivel mandrel  2040  as shown by arrow  1003 . Rotation of swivel mandrel  2040  in the direction  1003  causes rotation of drill string  20 . Rotation of top drive unit in the opposite direction as that described above will cause rotation of mandrel  1040 , valve member  1006 , and mandrel in the opposite direction of arrows  1001 ,  1002 , and  1003 . 
         [0064]    Line  1300  can be used for fluids or other items which are to be pumped into either or both of swivels  1030 ,  2030 . Line  1300  can comprise manifold  1009 , lines  1301 , 1302  along with valve members  1007  and  1008 . Valve members  1007  and  1008  can be any conventionally available valves such as ball or gate valves and can be manually or automatically operated. Valve member  1007  can control flow to/from swivel  1030 . Valve member  1008  can control flow to/from swivel  2030 . Valve member  1006  can control flow between mandrel  1040  and mandrel  2040 . Control valve  2000  can be included in line  1300  to control flow to/from line  1300 . 
         [0065]    With valve  1006  closed (and valves  1007 , 1008  open) fluids can be pumped from top drive unit  10 , into swivel  2050 , into line  1301 , through open valve  1007 , through manifold  1009 , through open valve  1008 , into mandrel  2040 , through lower portion of mandrel  2041 , and into drill string  20 . Control valve  2000  is typically closed for this flow circuit. This flow circuit allows valve  1006  to be circumvented when valve  1006  is closed. During this time period mandrels  1040 , 2040  can be rotated by top drive  10  while sleeves  1050 , 2050  remain stationary. 
         [0066]    A double swivel construction provides the flexibility of allowing an operator to divert the flow of fluids from line  1300  to swivel  1030  or to swivel  2030  (or to both swivel  1030  and swivel  2030 )while drill string  20  is worked without having to break down drill string  20  or stop operations of top drive unit  10 . For example during cementing operations top drive swivel  1000  can be used to pump cement into drill string  20  which can then be used to cement casing in well bore  14 . With valve  1006  open (and valve  1008  closed) cement can be pumped from line  1300 , through open valve  2000 , through open valve  1007 , into line  1301 , into and into swivel  1050  and mandrel  1040 , through lower portion of mandrel  1041 , through open valve  1006 , into mandrel  2040 , through lower portion of mandrel  2040 , and into drill string  20 . If a plug or ball  2005  (shown in  FIG. 11 ) had been placed above valve  1006 , then the pumped cement would be separated from downstream fluid by plug or ball  2005 . With valve  1008  open (and valve  1006  closed), cement can be pumped from line  1300  through open valve  2000 , through open valve  1008 , and into swivel  2050  and mandrel  2040 , through lower portion of mandrel  2041 , and into drill string  20 . With valves  1006 ,  1007 , and  1008 , cement can be pumped from line  1300  through open valve  2000  and into both swivels  1030 ,  2030 . 
         [0067]      FIG. 11  is a schematic view of an alternative embodiment of a top drive swivel  1000 ′ having double swivel portions. In this embodiment, a valve  2001  is placed between top drive unit  10  and swivel  1000 ′. Valves  1007 , 1008  are placed immediately adjacent swivels  1030 , 2030 . Valve  2001  will prevent any fluid being pumped into swivels  1030 , 2030  from entering top drive unit  10 . Valve  2001  will also prevent any fluid from top drive unit  10  from entering top drive swivel  1000 ′. Shown in  FIG. 11  is plug or ball  2005  which can be used to clean the inside of drill string  20  or to separate two sets of fluids being pumped into drill string  20  (e.g., drilling/completion fluid versus cement). Preferably plug or ball  2005  is a 5½ inch rubber ball for 4½ inch IF drill string  20 . Different sized balls can be used for different size drill or work strings  20 . Additionally conventionally available plugs can also be used. 
         [0068]    In another alternative embodiment, valve  2001  can be placed above valve  1006  and between swivels  1050 , 2050 . Plug or ball  2005  can be placed between valves  2001 , 1006 . In this embodiment valves  2001 , 1006  hold plug or ball  2005  until it is to be dropped into drill string  20 . Plug or ball  2005  is dropped by opening valves  2001 , 1006 . Fluid being pumped through mandrel  1040  will force plug or ball  2005  to drop into drill string  20 . 
         [0069]      FIG. 12  shows another embodiment where valve  1006  is a ball valve and plug or ball  2005  is inserted into the through bore  1006 B of valve ball  1006 A of valve  1006 . Valve  1006  is constructed such that through bore  1006 B can accommodate plug or ball  2005  when valve  1006 A is completely in the closed position. In the closed position valve ball  1006 A will trap plug or ball  2005 , but in the open position fluid pressure (schematically illustrated by arrow  1004 ) will force plug or ball  2005  out of valve  1006  and into drill string  20 . 
         [0070]      FIG. 13  shows a tool  2010  for inserting plug or ball  2005  into position in top drive swivel  1000  or valve  1006 . Tool  2010  can comprise three sections: upper section  2011 , middle section  2013 , and lower section  2012 . Upper section  2011  can include a connection for pumping fluid. Upper section  2011  can be removably connected to middle section  2013  by a threaded section  2014 . Middle section  2013 can include an enlarged inner diameter section  2015  and a narrowing diameter section  2016 . Middle section  2013  can also include an o-ring seal  2014 . Lower section  2012  can include threaded section  2018  and an o-ring seal  2019 . 
         [0071]    To insert plug or ball into valve  1006  of top drive swivel  1000  shown in  FIG. 10 , lower section  2012  can be threaded into the upper portion of mandrel  1040 . Valve  1006  should be partially closed to prevent plug or ball  2005  from passing. Plug or ball  2005  is inserted into enlarged inner diameter section  2015  of tool  2010 . Upper section  2011  is threaded into enlarged diameter section. A pipe or hose is connected to upper section  2011  and pressurized fluid is pumped through upper section  2011  in the direction of arrow  2020 . The pressurized fluid will force plug or ball  2005  through narrowing section  2016  and out through lower section  2012  and into mandrel  1040 . Plug or ball  2005  will continue downward until stopped by valve  1006 . At this point fluid pressure is cut off and tool  2010  is removed. Valve  1006  is complete closed and top drive swivel  1000  is installed in drill string  20 . When plug or ball  2005  is to be dropped into drill string  20 , valve  1006  is opened and fluid is pumped through mandrel  1040  in the in the direction of arrow  2021 . 
         [0072]    The following will illustrate various methods for using swivels  30 , 1000 . 
       Swivel Tool  30  and Swiveling Ball Drop Assembly  1000   
       [0073]    There are many advantages that will lead to successful operations and a reduction in rig time when utilizing Swivel Tool  30  and Swiveling Ball Drop Manifold Assemblies  1000 . 
         [0074]    Cement Plugs set in open hole or in casing can be better distributed along the cement column, especially in directionally drilled wells, as pipe  18 , 20  rotation can be applied while pumping the plugs in place. Swivel Tool  30  will perform efficiently, either in setting a Balanced Plug or using a Plug Catcher. 
         [0075]    When displacing a hole  14  to a reduced mud weight where a high differential pressure may be encountered, the bit can be run to Total Depth and hole  14  displaced in a single step procedure, saving time as to staging in the hole  14 . The pipe  20  can be rotated while the hole  14  is being displaced, which will lead to less contamination of the interface between fluids being displaced and less debris remaining in the hole  14 . 
         [0076]    When the Well  14  is perforated underbalance with a Tubing Conveyed Perforate assembly, the Manifold  1000  assembly can be utilized. A Wireline can be rigged up above the Manifold  1000  and a Correlation Log run, the Tubing Conveyed Perforate moved to be put on depth, lines rigged up and tested, Tubing Conveyed Perforate Packer set, By-Pass  1007  opened, the desired underbalance pumped, By-Pass  1007  closed and the Tubing Conveyed Perforate fired and flow back achieved, By-Pass  1007  opened and the influx reversed out. If the primary detonation of the Tubing Conveyed Perforate is a bar drop, the Full Opening Ball Valve  1006  would be ideal for this purpose. 
         [0077]    The Swivel Manifold  1000 , with the 4½″ IF connections can easily be spaced out with in a stand of drill pipe and stored on the derrick before and after the operation of choice has been performed and easily applied to the Top Drive system  10 . 
         [0078]    The outside torque applied to the Swivel Tool assemblies  1050 ,  2050  is a minimum torque value when the pipe  18 , 20  is rotated, however, a Stiff-Arm  1010  assembly can be easily attached and utilized. 
         [0079]    The Swiveling Ball Drop Manifold  1000  can be equipped with 3 inch Low Torque Valves  1007 , 1008  leading to less restriction when pumping fluid through at higher volumes, if desired. 
       Open Hole Cement Plug Swivel Tool  30  Only 
       [0080]    (1) Pick up Ported Mule Shoe Sub that has been orange peeled in with a round tapered bottom with one-half inch circular port at the bottom of sub with added one-half inch circular ports staggered on side of sub. The round tapered bottom will help keep the Mule Shoe Sub from setting down in a possible ledge or other downhole obstruction. 
         [0081]    (2) Pick up enough Cement Stingers to cover the height of intended cement plug and 100 feet. Scratchers and Centralizers are optional. 
         [0082]    (3) Trip in hole  14  to casing shoe. 
         [0083]    (4) In a strand of Drill Pipe, pick up the Swivel Tool  30  (with a TIW Valve in the open position on top of the Swivel Tool and a Low Torque Valve in the closed position connected to the side-entry port  200  of the Swivel Tool  30  which is called the pump in sub) and set back on derrick  1 . Rig up Cement Lines on rig  1  floor to be ready for connection to Swivel Tool  30 , once in the hole  14  to cement depth. 
         [0084]    (5) Continue in hole  14  to cement depth. 
         [0085]    (6) Rig up cement lines to Swivel Tool  30 . 
         [0086]    (7) Circulate and condition mud. Rotate the Drill Pipe  18 , 20  while circulating. 
         [0087]    (8) Off-Line operations can be performed while circulating. Cementer can prepare the Spacers and Cement Mix water. The Pre-Job Task Meeting can also be conducted and cement lines tested. 
         [0088]    (9) After the desired circulation time has passed, keep Drill Pipe  18 , 20  rotating, close the TIW Valve above the Swivel Tool  30 , pressure up on top of the TIW to +−1000 pounds per square inch with the Top Drive  10  and open the Low Torque Valve to inlet  200 . 
         [0089]    (10) Pump Spacer, Cement, Spacer and displace as per Cement Program with pipe  18 , 20  rotating at all times. 
         [0090]    (11) After cement has been spotted, rig down cement line and store Swivel 
         [0091]    Tool  30  on derrick  1 . 
         [0092]    (12) Pull Drill Pipe  20  out of hole above top of cement. Pump Wiper Ball  2005  to Clean the Drill Pipe  20  if desired. 
         [0093]    (13) Pull out of hole  14 . 
       Cement Plug Swivel Tool  1000 /Ball Launch Manifold Plug Catcher 
       [0094]    (1) Pick up Ported Mule Shoe Sub that has been orange peeled in with a round tapered bottom with one-half inch circular port at the bottom of sub with added one-half inch circular ports staggered on side of sub. The round tapered bottom will help keep the Mule Shoe Sub from setting down in a possible ledge. 
         [0095]    (2) Pick up enough Cement Stingers to cover the height of intended cement plug and 100 feet. Scratchers and Centralizers are optional. 
         [0096]    (3) Pick up Plug Catcher. 
         [0097]    (4) Place Cement Stringers in hole to casing shoe. 
         [0098]    (5) In a stand of Drill Pipe, pick up the Swivel Tool and Ball Launch Manifold Assembly  1000  with the Full Opening Ball Valve  1006  in the closed position with proper Wiper Ball or Dart  2005  loaded above the closed Ball Valve  1006 . Place the Low Torque Valve  1008  on the Lower Swivel Pump-in Sub  2030  in open position. Place the Low Torque Valve  1007  to the Upper Swivel Pump-In Sub  1030  in the closed position. Stand the Swivel Tool and Ball Launch Manifold Assembly  1000  on the derrick  1 . Rig up Cement Lines on rig  1  floor to be ready to be connected to the Ball Launch Manifold  1000  and also where the Drill Pipe  14  can be circulated with Rig Pumps and/or from the Cement Pump with necessary valves to isolate either set of pumps. 
         [0099]    (6) Continue in hole  14  to cement depth. 
         [0100]    (7) Rig up cement lines to the Swivel Manifold  1000 . 
         [0101]    (8) Circulate and condition mud with rig pumps. Rotate the Drill Pipe  18 , 20  while circulating. 
         [0102]    (9) Off-Line Operations can be performed while circulating. Cementer can prepare the Spacers and Cement Mix water. The Pre-Job Task Meeting can also be conducted and cement lines tested. 
         [0103]    (10) After the desired circulation time has been completed, keep the Drill Pipe  18 , 20  rotating and isolate the Rig Pumps from the Cement Pump. Set the Cement Pump to pump thru the Lower Swivel Pump-In Sub  2030 . Maintain rotation of Drill Pipe  18 , 20 . 
         [0104]    (11) Pump the first Spacer and Cement. When pumping the second Spacer, pump the calculated volume of the Cement Stinger. Shut down the Cement Pump, close the Low Torque Valve  1008  to the Lower Swivel Pump-In Sub  2030  and open the Low Torque Valve  1007  to the Upper Swivel Pump-In Sub  1030 . Open the Full Opening Ball 
         [0105]    Valve  1006 , releasing the Wiper Ball or Dart  2005 . 
         [0106]    (12) Displace the Cement. When the Wiper Ball or Dart  2005  lands at the Plug Catcher shut down pumping. 
         [0107]    (13) Store the Swivel Tool and Ball Launch Manifold Assembly  1000  back on the derrick  1 . 
         [0108]    (14) Pull Drill Pipe  20  out of hole  14 , above top of cement. 
         [0109]    (15) Rig up pump line and shear Plug catcher to the Circulation position. 
         [0110]    (16) Pull out of hole  14 . 
       Well Clean Out High Differential Displacement Floater Completion Swivel Tool Only 
       [0111]    (1) Pick up Bit plus Scraper and Brush assembly. 
         [0112]    (2) Trip in hole  14 , with Bit half way from Mud Line and Float Collar, pick up second Scraper/Brush assembly. 
         [0113]    (3) Continue to Trip in hole  14 , tag Float Collar. 
         [0114]    (4) Pick up Swivel Tool  30  (but omitting right angle inlet  200 ). Rig up high pressure pump plus rig pumps to the Swivel Tool  30 . Test lines to desired pressure. 
         [0115]    (5) Circulate bottoms up with existing Mud System with rig pumps, rotate drill pipe  20  while circulating. 
         [0116]    (6) Isolate the rig Pumps and test Production Casing with the high pressure pump, if not already tested. 
         [0117]    (7) Displace the Choke, Kill and Booster lines with Seawater. 
         [0118]    (8) Start displacing the existing Mud System with Seawater by pumping down the Drill Pipe  20  with returns up the Annulus with the High Pressure Pump. Once the Seawater has rounded the Bit and the Differential Pressure declines to a safe working pressure, switch to the Rig Pumps and finish the Displacement. (Maintain pipe  20  rotation throughout the displacement to help in removing debris from around the Tool Joints). 
         [0119]    (9) Pull out of hole  14  until the Scraper/Brush assembly is at the Mud Line (boosting the Riser with Seawater) 
         [0120]    (10) Trip in hole  14 , space out Dual Actuated Ball Service Tool and Riser Brush to be one stand above the Dual Actuated Ball Service Tool and the Riser Brush to be at plus or minus 30 feet above the Riser Flex Joint with the Bit at the Float Collar boost riser while Trip in hole  14 ). 
         [0121]    (11) Rotate pipe  20  and circulate bottoms up with seawater. 
         [0122]    (12) Drop ball and open circulating ports in the Dual Actuated Ball Service Tool. 
         [0123]    (13) Jet wash the Well Head and Blow Out Preventers. 
         [0124]    (14) With the Dual Actuated Ball Service Tool above the Blow Out Preventers, function the Annular and the Pipe Rams to have annular blow out preventer attach to Tool. 
         [0125]    (15) Jet wash the Blow Out Preventers. Pull out of hole  14  jet washing the Marine Riser. Put on the side (lay out) the Riser Brush and Dual Actuated Ball Service Tool. 
         [0126]    (16) Trip in hole  14  to the Float Collar. 
         [0127]    (17) Rotate pipe  20  and circulate bottoms up with seawater. 
         [0128]    (18) Align Fail Safe Valves and Choke Manifold to take returns up the Choke and Kill Lines. 
         [0129]    (19) Pump Spacer Trains down the drill pipe  20  with returns up the Riser. When the Spacer Trains are 75 barrels from the Blow Out Preventers, close the Annular and take returns up the Choke and Kill lines. Slow the pumps if necessary, but do not shut down until the Spacer Trains are circulated from the Hole  14 . 
         [0130]    (20) Align The Choke Manifold and Pump Riser Spacer Trains down the Choke, Kill, and Booster lines. Boost Spacer Trains from the Riser at 22 barrels per minute minimum. 
         [0131]    (21) Displace seawater from the Choke, Kill, and Booster Lines with Filtered Completion Fluid. 
         [0132]    (22) Displace seawater from the Hole  14  with Filtered Completion Fluid. Circulate and filter until the National Turbidity Units are at the desired level. 
         [0133]    (23) Pull out of hole  14 . 
       Well Clean Out High Differential Displacement Floater Completion 
       [0134]    (1) Pick up Bit plus Scraper and Brush assembly. 
         [0135]    (2) Trip in hole  14 , with Bit half way from Mud Line and Float Collar, pick up second Scraper/Brush assembly. 
         [0136]    (3) Continue Trip in hole  14 , tag Float Collar. 
         [0137]    (4) Pick up Swivel Tool/Manifold Assembly  1000  with Full Opening Ball Valve  1006  in the closed position. Rig up high pressure pump plus rig pumps to the Manifold Assembly  1000 . Close the lower Low-Torque Valve  1008  and the upper Low-Torque Valve  1007 . Test lines and open the lower Low Torque Valve  1008 . 
         [0138]    (5) Circulate bottoms up with existing Mud System with rig pumps, rotate Drill Pipe  18 , 20  while circulating. 
         [0139]    (6) Isolate the rig Pumps and test Production Casing with the high pressure pump, if not already tested. 
         [0140]    (7) Displace the Choke, Kill, and Booster lines with Seawater. 
         [0141]    (8) Start displacing the existing Mud System with Seawater with the High Pressure Pump. Once the Seawater has rounded the Bit and the Differential Pressure declines to a safe working pressure, switch to the Rig Pumps and finish the displacement. (Maintain Drill Pipe  18 , 20  rotation throughout displacement to help in removing debris from around Tool Joints). 
         [0142]    (9) Pull out of hole  14  until the Scraper/Brush assembly is at the Mud Line (boosting the Riser with Seawater) 
         [0143]    (10) Trip in hole  14 , space out Dual Actuated Ball Service Tool and Riser Brush to be one stand above the Dual Actuated Ball Service Tool and the Riser Brush to be at plus or minus 30 feet above the Riser Flex Joint with the Bit at the Float Collar (boost riser while Trip in hole  14 ). 
         [0144]    (11) Rotate Drill Pipe  18 , 20  and circulate bottoms up with seawater. 
         [0145]    (12) Drop ball  2005  and open circulating ports in the Dual Actuated Ball Service Tool. 
         [0146]    (13) Jet wash the Well Head and Blow Out Preventers. 
         [0147]    (14) With the Dual Actuated Ball Service Tool above the Blow Out Preventers, function the Annular and the Pipe Rams. 
         [0148]    (15) Jet wash the Blow Out Preventers. Pull out of hole jet washing the Marine Riser. Lay down the Riser Brush and Dual Actuated Ball Service Tool. 
         [0149]    (16) Trip in hole  14  to the Float Collar. 
         [0150]    (17) Rotate pipe  18 , 20  and circulate bottoms up with seawater. 
         [0151]    (18) Align Fail Safe Valves and Choke Manifold to take returns up the Choke and Kill lines. 
         [0152]    (19) Pump Spacer Trains down the Drill Pipe  18 , 20  with returns up the Riser. When the Spacer Trains are 75 barrels from the Blow Out Preventers, close the Annular and take returns up the Choke and Kill Lines. Slow the pumps if necessary, but do not shut down until the Spacer Trains are circulated from the Hole  14 . 
         [0153]    (20) Align The Choke Manifold and Pump Riser Spacer Trains down the Choke, Kill, and Booster Lines. Boost Spacer Trains from the Riser at a minimum of 22 barrels per minute. 
         [0154]    (21) Displace seawater from the Choke, Kill, and Booster lines with Filtered Completion Fluid. 
         [0155]    (22) Displace seawater from the Hole  14  with Filtered Completion Fluid. Circulate and filter until the National Turbidity Units are at the desired level. 
         [0156]    (23) Pull out of hole  14 . 
         [0000]    Tubing Conveyed Perforate Operations with Swivel Tool/Ball Drop Assembly  1000  Well Status: Well Bore has been Cleaned Up; Filtered Completion Fluid is in Place; No Block Squeeze had to be Performed; Sump Packer has been set on Depth with Wireline; Operations can be Performed with Omni or IRIS Valve 
         [0157]    (1) Pick up the Tubing Conveyed Perforating Bottom Hole Assembly (pressure activation as primary detonation of Tubing Conveyed Perforate Guns) plus Snap-Latch assembly. Pick up the Omni or IRIS Valve to be in the Well Test Position. Pick up a Radio Active Sub one stand above the Tubing Conveyed Perforate assembly. 
         [0158]    (2) Trip in Hole  14  with the Tubing Conveyed Perforate assembly, limit run in speed from slip to slip at two minutes per stand (94 foot stands). Drift each stand with maximum Outer diameter Drift. Monitor hole  14  on trip tank while Trip in hole  14  for proper fluid back for pipe displacement to confirm Omni/IRIS Valve is in proper position. 
         [0159]    (3) With Snap-Latch one stand above the Sump Packer, obtain pick-up and slack-off weights. 
         [0160]    (4) Sting into Sump Packer. Pick up the Work String to the neutral pipe weight and mark pipe at the Rotary. Snap out, should take 10,000 k to 20,000 k to snap out. (If any doubt of being in the Sump Packer, rig up Wireline and run Gamma-Ray and Collar Log for correct correlation). 
         [0161]    (5) Pick up Swivel Tool/Ball Drop Assembly  1000  and space out as desired to put the Swivel tool  1000  at the desired distance above the Rotary with the Snap-Latch strung into the Sump packer. 
         [0162]    (6) Rig up Choke Manifold on the Rig  1  Floor with lines from the Swivel Tool  1000  to the Manifold and lines from the High Pressure Pump to the Manifold. Rig up lines down stream of the Choke to take returns to the trip tank and to the Mud Pits. 
         [0163]    (7) Sting into the Sump Packer and pick up to the neutral pre-recorded pipe weight. Set the Tubing Conveyed Perforate Packer by rotating the Work String the desired number of turns and slacking off the desired pipe weight onto Tubing Conveyed Perforate packer. 
         [0164]    (8) Open the Upper Low Torque  1007  and Full Opening Ball Valve  1006  to the Work String  20  plus Choke Manifold Valves in the open position back to the Trip Tank. Close the Annular Blow Out Preventer and test the Tubing Conveyed Perforate Packer to the Annulus side to 1,000 pounds per square inch. Monitor for returns at the Trip Tank, no returns should be observed if the Tubing Conveyed Perforate Packer is holding. 
         [0165]    (9) Cycle the Omni Valve to the Reverse Circulating position. 
         [0166]    (10) Break circulation by pumping down the Work String  20  with returns up the Rig Choke or Kill line. 
         [0167]    (11) Test the Pump Lines, Choke Manifold and Swivel Tool  1000  Valve to the desired pressure. Open the top Low Torque Valve  1007  and the Full Opening Ball Valve  1006 . 
         [0168]    (12) Displace the Work String  20  with a lighter fluid, taking returns up the Rig Choke or Kill line until the desired under balance has been achieved. 
         [0169]    (13) Cycle the Omni Valve to the Well Test Position. 
         [0170]    (14) Pressure up the Annulus to 500 psi. 
         [0171]    (15) Fire the Tubing Conveyed Perforate Guns by pressuring up on the Work String to the calculated detonation pressure. Bleed the pressure to 0. 
         [0172]    (16) Monitor firing of the Guns (usually a 5 to 10 minute delay). Obtain Shut in Tubing Pressure. Calculate the difference between the estimated Bottom Hole  14  Pressure and the actual Bottom hole  14  pressure. 
         [0173]    (17) Open the Well  14  thru the desired Positive Choke size and flow back the desired volume. 
         [0174]    (18) Cycle the Omni Valve to the Reverse Circulating Position. 
         [0175]    (19) Reverse out the Influx plus an additional Work String Volume. 
         [0176]    (20) Bleed the pressure on the Annulus to 0. 
         [0177]    (21) Open the Annular Blow Out Preventer. 
         [0178]    (22) Start the Trip Tank Pump circulating on the Annulus. Open the By-Pass on the Tubing Conveyed Perforate Packer by picking up on the Work string. Monitor the fluid loss to the formation. If excessive losses are occurring, close the By-Pass. 
         [0179]    (23) Pump and displace a Loss Circulation Pill of choice. Balance the Loss Circulation Pill by leaving Pill in the Work String above the Omni Valve and with Pill above the Omni Valve on the outside between the Omni and the casing. 
         [0180]    (24) Open the By-Pass and monitor the Hole  14  on the Trip Tank. The Hole  14  should take the calculated volume of fluid from the Omni Valve to the bottom of the perforations and then become static. 
         [0181]    (25) Close the By-Pass and Cycle the Omni Valve to the Well Test Position. 
         [0182]    (26) Open the By-Pass and reverse out Influx that was trapped below the Omni Ball Valve. 
         [0183]    (27) With the By-Pass in the open position, monitor the hole  14  on the Trip Tank while rigging down the Choke Manifold and pump lines. 
         [0184]    (28) Rig down the Swivel Tool and Ball Drop assembly  1000 . 
         [0185]    (29) Make a 5 stand short trip. 
         [0186]    (30) Circulate bottoms up. 
         [0187]    (31) Pull out of hole. Circulate at desired stages while Pull out of hole  14  as to monitor for possible trapped or swabbed Gas. 
         [0188]    Note: If elected, the Choke Manifold that was rigged up on the Rig Floor can be eliminated and the Rig Choke Manifold could be used instead. The flow back could be flowed back to the Trip Tank and timed with the Super Choke adjusted to obtain the desired Barrel of Oil Per Day rate. This could be done to reduce additional expense and save Rig Time. 
         [0189]    If a Bar Drop is elected to be the primary choice of the Tubing Conveyed Perforate detonation, a Pup Joint can be easily added between the Upper Swivel  1050  and the Top Drive  10 . The Full Opening Ball Valve  1006  would be closed and the Ball Valve Wrench taped. The Lower Low Torque Valve  1008  would then be used for circulation activities. Once all operations have been completed and the well is ready to be perforated, the Tape can be removed and the Bar can be dropped when intended. The tape is installed to the Ball Valve  1006  only as a safety factor so that the Bar will not be accidentally dropped prior to the contemplated drop. 
         [0190]    The following is a list of reference numerals: 
         [0000]    
       
         
               
             
               
               
             
           
               
                   
               
               
                 LIST FOR REFERENCE NUMERALS 
               
             
          
           
               
                 (Part No.) 
                 (Description) 
               
               
                 Reference Numeral 
                 Description 
               
               
                   
               
               
                   1 
                 rig 
               
               
                   2 
                 crown block 
               
               
                   3 
                 cable means 
               
               
                   4 
                 travelling block 
               
               
                   5 
                 hook 
               
               
                   6 
                 gooseneck 
               
               
                   7 
                 swivel 
               
               
                   8 
                 drilling fluid line 
               
               
                  10 
                 top drive unit 
               
               
                  11 
                 draw works 
               
               
                  12 
                 cable 
               
               
                  13 
                 rotary table 
               
               
                  14 
                 well bore 
               
               
                  15 
                 guide rail 
               
               
                  16 
                 support 
               
               
                  17 
                 support 
               
               
                  18 
                 drill pipe 
               
               
                  19 
                 drill string 
               
               
                  20 
                 drill string or work string 
               
               
                  30 
                 swivel 
               
               
                  31 
                 hose 
               
               
                  40 
                 swivel mandrel 
               
               
                  50 
                 upper end 
               
               
                  60 
                 lower end 
               
               
                  70 
                 box connection 
               
               
                  80 
                 pin connection 
               
               
                  90 
                 central longitudinal passage 
               
               
                  100 
                 shoulder 
               
               
                  101 
                 outer surface of shoulder 
               
               
                  102 
                 upper surface of shoulder 
               
               
                  110 
                 interior surface 
               
               
                  120 
                 external surface (mandrel) 
               
               
                  130 
                 recessed area 
               
               
                  131 
                 packing support area 
               
               
                  132 
                 packing support area 
               
               
                  140 
                 radial inlet ports (a plurality) 
               
               
                  145 
                 bearing (preferably combination 6.875 
               
               
                   
                 inch bearing cone, Timken Part number 
               
               
                   
                 67786, and 9.75 inch bearing cup bearing 
               
               
                   
                 cup, Timken part number 67720) 
               
               
                  146 
                 bearing (preferably combination 7 inch 
               
               
                   
                 bearing cone, Timken Part number 67791, 
               
               
                   
                 and 9.75 inch bearing cup bearing cup, 
               
               
                   
                 Timken part number 67720) 
               
               
                  150 
                 swivel sleeve 
               
               
                  155 
                 protruding section 
               
               
                  156 
                 shoulder 
               
               
                  157 
                 shoulder 
               
               
                  158 
                 packing support area 
               
               
                  159 
                 packing support area 
               
               
                  160 
                 upper end 
               
               
                  170 
                 lower end 
               
               
                  180 
                 central longitudinal passage 
               
               
                  190 
                 radial passage 
               
               
                  200 
                 inlet 
               
               
                  201 
                 arrow 
               
               
                  202 
                 arrow 
               
               
                  203 
                 arrow 
               
               
                  204 
                 arrow 
               
               
                  205 
                 peripheral groove 
               
               
                  206 
                 key way 
               
               
                  210 
                 lubrication port 
               
               
                  211 
                 grease injection fitting (preferably grease 
               
               
                   
                 zerk (¼-28 td. in. streight, mat.-monel 
               
               
                   
                 Alemite part number 1966-B) 
               
               
                  220 
                 packing port 
               
               
                  225 
                 injection fitting(preferably packing 
               
               
                   
                 injection fitting (10,000 psi) Vesta - PGI 
               
               
                   
                 Manufacturing part number PF10N4- 
               
               
                   
                 10) (alternatively Pressure Relief Tool for 
               
               
                   
                 packing injection fitting Vesta - PGI 
               
               
                   
                 Manufacturing part number PRT-PIF 12-20) 
               
               
                  226 
                 head 
               
               
                  230 
                 packing port 
               
               
                  235 
                 injection fitting (preferably packing 
               
               
                   
                 injection fitting (10,000 psi) Vesta - PGI 
               
               
                   
                 Manufacturing part number PF10N4- 
               
               
                   
                 10) (alternatively Pressure Relief Tool for 
               
               
                   
                 packing injection fitting Vesta - PGI 
               
               
                   
                 Manufacturing part number PRT-PIF 12-20) 
               
               
                  240 
                 cover 
               
               
                  250 
                 upper shoulder 
               
               
                  260 
                 lower shoulder 
               
               
                  270 
                 area for wiper ring 
               
               
                  271 
                 wiper ring (preferably Parker part number 
               
               
                   
                 959-65) 
               
               
                  280 
                 area for wiper ring 
               
               
                  281 
                 wiper ring (preferably Parker part number 
               
               
                   
                 959-65) 
               
               
                  290 
                 area for grease ring 
               
               
                  291 
                 grease ring (preferably Parker part number 
               
               
                   
                 2501000 Standard Polypak) 
               
               
                  300 
                 area for grease ring 
               
               
                  301 
                 grease ring (preferably Parker part number 
               
               
                   
                 2501000 Standard Polypak) 
               
               
                  305 
                 packing unit 
               
               
                  310 
                 packing retainer nut 
               
               
                  314 
                 bore for set screw 
               
               
                  315 
                 set screw for packing retainer nut 
               
               
                  316 
                 threaded area 
               
               
                  317 
                 set screw for receiving area 
               
               
                  320 
                 packing end 
               
               
                  330 
                 packing ring 
               
               
                  340 
                 packing ring 
               
               
                  350 
                 packing injection ring 
               
               
                  351 
                 transverse port 
               
               
                  352 
                 radial port 
               
               
                  353 
                 peripheral groove 
               
               
                  354 
                 interior groove 
               
               
                  355 
                 male end 
               
               
                  356 
                 flat end 
               
               
                  360 
                 packing end 
               
               
                  370 
                 packing ring 
               
               
                  380 
                 packing ring 
               
               
                  390 
                 packing ring 
               
               
                  400 
                 packing ring 
               
               
                  410 
                 packing end 
               
               
                  415 
                 packing unit 
               
               
                  420 
                 packing retainer nut 
               
               
                  425 
                 set screw for packing retainer nut 
               
               
                  430 
                 packing end 
               
               
                  440 
                 packing ring 
               
               
                  450 
                 packing ring 
               
               
                  460 
                 packing lubrication ring 
               
               
                  470 
                 packing end 
               
               
                  480 
                 packing ring 
               
               
                  490 
                 packing ring 
               
               
                  500 
                 packing ring 
               
               
                  510 
                 packing ring 
               
               
                  520 
                 packing end 
               
               
                  600 
                 clamp 
               
               
                  605 
                 groove 
               
               
                  610 
                 first portion 
               
               
                  620 
                 second portion 
               
               
                  630 
                 torque arm 
               
               
                  640 
                 torque arm 
               
               
                  650 
                 shackle 
               
               
                  660 
                 shackle 
               
               
                  670 
                 fastener 
               
               
                  680 
                 fastener 
               
               
                  690 
                 keyway 
               
               
                  691 
                 keyway 
               
               
                  700 
                 key 
               
               
                  710 
                 keyway 
               
               
                  711 
                 keyway 
               
               
                  720 
                 key 
               
               
                  730 
                 peripheral groove 
               
               
                  800 
                 retaining nut 
               
               
                  801 
                 threaded area 
               
               
                  810 
                 outer surface 
               
               
                  820 
                 inclined portion 
               
               
                  830 
                 bore 
               
               
                  840 
                 inner surface 
               
               
                  850 
                 threaded portion 
               
               
                  860 
                 upper surface 
               
               
                  870 
                 bottom surface 
               
               
                  880 
                 lubrication port 
               
               
                  881 
                 grease injection fitting (preferably grease 
               
               
                   
                 zerk (¼-28 td. in. streight, mat.-monel 
               
               
                   
                 Alemite part number 1966-B) 
               
               
                  890 
                 set screw 
               
               
                  900 
                 bore for set screw 
               
               
                  910 
                 receiving portion for set screw 
               
               
                 1000 
                 top drive swivel 
               
               
                 1001 
                 arrow 
               
               
                 1002 
                 arrow 
               
               
                 1003 
                 arrow 
               
               
                 1005 
                 stabilizing bracket 
               
               
                 1006 
                 intermediate valve 
               
               
                 1006B 
                 bore 
               
               
                 1006A 
                 valve ball 
               
               
                 1007 
                 valve member 
               
               
                 1008 
                 valve member 
               
               
                 1009 
                 manifold 
               
               
                 1010 
                 arm 
               
               
                 1030 
                 swivel portion 
               
               
                 1040 
                 mandrel 
               
               
                 1041 
                 lower portion of mandrel 
               
               
                 1050 
                 sleeve 
               
               
                 1300 
                 line 
               
               
                 1301 
                 line 
               
               
                 1302 
                 line 
               
               
                 2000 
                 valve member 
               
               
                 2001 
                 valve 
               
               
                 2005 
                 plug or ball 
               
               
                 2010 
                 tool 
               
               
                 2011 
                 upper section 
               
               
                 2012 
                 lower section 
               
               
                 2013 
                 middle section 
               
               
                 2014 
                 threaded section 
               
               
                 2015 
                 enlarged inner diameter section 
               
               
                 2016 
                 narrowing diameter section 
               
               
                 2018 
                 threaded section 
               
               
                 2019 
                 o-ring seal 
               
               
                 2020 
                 o-ring seal 
               
               
                 2021 
                 arrow 
               
               
                 2030 
                 swivel portion 
               
               
                 2040 
                 mandrel 
               
               
                 2041 
                 lower portion of mandrel 
               
               
                 2050 
                 sleeve 
               
               
                   
               
             
          
         
       
     
         [0191]    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. 
         [0192]    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.

Technology Classification (CPC): 4