Abstract:
A method for drilling wells in which the tubular ( 5 ) can be added or removed from the drill string ( 17 ) whilst the drill is rotating with the mud and drilling fluids being circulated continuously and kept separated from the environment to reduce pollution. A connector is used with an inlet ( 15 ) and outlet ( 10 ) for the mud etc. and which incorporates rams ( 11 ) to seal off and separate the flow of mud as a tubular is added or removed.

Description:
RELATED APPLICATONS 
     This Application is a Continuation-In-Part of U.S. application Ser. No. 09/284,449, filed Apr, 12, 1999, now U.S. Pat. No. 6,315,051, U.S. application Ser. No. 09/284,449 being a §371 Application of PCT/GB97/02815 having a Priority Date of Oct. 15, 1996 based upon G.B. Serial Nos. 9,621,509 and 9,621,510, and a continuation-in-part of Application PCT/GB99/03411 having a Priority Date of Oct. 14, 1998 based upon G.B. Serial No. 9,822,303. 
    
    
     FIELD 
     This invention relates to drilling wells, and more particularly, to methods and apparatus for drilling wells much more efficiently and effectively so as to substantially reduce the multi-million dollar cost of drilling a well. 
     BACKGROUND 
     It is well known in the drilling industry, and particularly in the field of drilling for oil, natural gas and other hydrocarbons, that drill strings comprise a large plurality of tubular sections, hereinafter “tubulars”, which are connected by male threads on the pins and female threads in the boxes. It is also well known that such tubulars must be added to the drill string, one-by-one, or in “stands” of 2 or 3 connected tubulars, as the string carrying the drill bit drills into the ground; a mile more below ground being common in the oil drilling art. For various reasons during the drilling, and after the bore hole has been drilled, it is necessary to withdraw the drill string, in whole or in part. Again, each tubular or stand must be unscrewed, one-by-one, as the drill string is brought up to the extent required. 
     With prior art systems, each time that a tubular is added or removed it is necessary to stop the drilling process, and the circulation of drilling fluid. This presents a costly delay in the overall drilling operation. This is because the circulation of drilling fluids is extremely critical to maintaining a steady down hole pressure and a steady and near constant Equivalent Circulating Density (ECD) as is well known in the drilling art. Also, when tripping the drill string into or out of the well, the lack of continuous circulation of a drilling fluid causes pressure changes in the well which increases the probability of “kicks” as is well known. 
     In addition to the drilling operation, the placement of casings in the bore hole is also necessary. As in the case of tubulars, the placement of casing sections in the prior art presents the same fundamental problems. That is, the flow of drilling fluids must be halted, and the drill string must be withdrawn in its entirety before the casing can be run into the well, which in some instances requires circulation of fluids and rotation of the casing. 
     SUMMARY 
     The present invention substantially reduces the time and cost of drilling operations by making it possible to continuously circulate drilling fluids while tubulars are added or removed, and also as casing strings are run into the bore hole. In addition, the present invention makes it possible to continue to rotate the drill string, if desired, while adding or removing tubulars. Bearing in mind that hundreds of tubulars are required per mile of drill string, the present invention eliminates hundreds of interruptions of the circulation of drilling fluids, and a like number of breaks in the rotation of the drill string and the drilling operation per mile of drilling. 
    
    
     BRIEF DESCRIPTION OF DRAWINGS 
     FIGS. 1-3 are simplified, side elevational schematics of the structural elements of three embodiments of the present invention; 
     FIG. 3A is a simplified elevational view, partly in cross-section, further illustrating one embodiment of the invention; 
     FIGS. 4A-6A are simplified, side elevational schematics of the operational mode of the embodiment of the invention shown in FIG. 3; 
     FIG. 7 is a schematic elevational view in cross-section of one preferred embodiment of the present invention; 
     FIGS. 8A-8H are schematic elevational views, in cross-section, showing the operational method of the FIG. 7 embodiment; 
     FIG. 9 is a side elevational view, partly in cross-section, showing one embodiment of the present invention in greater detail; 
     FIG. 9A is a cross-sectional view taken along view line  9 A— 9 A of FIG. 9; 
     FIG. 9B is a cross-sectional view taken along view line  9 B— 9 B of FIG. 9; 
     FIG. 9C is the same cross-sectional view with the grips extended; 
     FIG. 9D is an elevational plan view taken along view line  9 D— 9 D of FIG. 9B with the outer casing removed for clarity; 
     FIG. 10 is an enlarged view of the lower portion of FIG. 9; 
     FIG. 11 is a cross-sectional view taken along view line  11 — 11  of FIG.  11 A. 
     FIGS. 11A and 11B comprise a composite cross-sectional view taken along view lines  11 A and  11 B of FIG. 11; 
     FIGS. 12 to  19  are elevational views, partly in cross-section illustrating the relative positions of the components as a new tubular is connected to the string; 
     FIGS. 20,  20 A and  20 B schematically illustrate the different positions in which the grips and slips may be located in the present invention; and 
     FIGS. 21-27 are elevational views, partly in cross-section, illustrating another embodiment of the present invention in which the grips are positioned outside of the coupler. 
    
    
     DETAILED DESCRIPTION 
     Referring first to FIG. 1, numeral  10  indicates a conventional power drive, known in the art as a “top drive”, and the top drive is provided with an inlet  11  for receiving drilling fluid as is well known. Top drive  10  carries a conventional “saver sub”  12 , and tubular  13  includes a threaded male pin  15  and a threaded female box  14  or upset as is conventional in oil drilling. Tubular  13  may be positioned vertically above drill string  16  by known handlers  17 A- 17 B. Of course, instead of tubulars, it will be understood that casing sections may be similarly positioned by the handlers for insertion into the bore hole by the present invention. 
     Surrounding string  16  is one example of a preferred coupler  18  according to the principles the present invention. Coupler  18  comprises a pressure resistant hull or casing  19 , which may be integral with a stack  20  of conventional blow out preventers (BOP&#39;s). In the embodiment of FIG. 1, coupler  18  includes a plurality of elements in vertical arrangement as follows. Numerals  22 A and  22 B indicate upper and lower high pressure fluid seals. In this regard it will be understood that such seals may be conventional BOP&#39;s or RBOP&#39;s or annular preventers as known, or may be any other type of seal capable of withstanding the particular fluid pressure in a given drilling operation. Below seal  22 A is a valve  23  which is illustrated as having horizontally movable valve portions  23 A and  23 B. These portions may be moved from the open position as shown to a closed position in which the valve portions engage each other to form a fluid tight seal. Thus, valve  23  divides coupler  18  into upper and lower chambers  21 A and  21 B which may be fluid sealed from each other. For example, it will be understood that valve  23  may comprise a slide valve, or a ram preventer, or blind preventer, as these terms are known in the drilling art, or other structures which may be opened and closed such as to form a fluid tight seal between the upper and lower chambers of the coupler; valve  23  being hereinafter referred to as a “valve” or “blind preventer”. 
     Below valve  23  are lower rotary grips  24 , and below them are slips  25 . In this regard it will be understood that the grips may be motorized roller grips, or of other conventional designs motorized to rotate about their vertical axes, and the slips are support elements which have a central aperture smaller than the diameter of box or upset  14 . While the grips  24  and slips  25  are shown as being separate elements in some Figures, the grips and slips may be integrated into a single unit and motorized so that both may be rotated and moved radially inwardly and outwardly as one element. It will also be noted that a plurality of inlets/outlets are provided, such as  29 A, B and C for example, for the flow of drilling fluids and other fluids as will be further explained. 
     The embodiment of FIG. 2 is the same as that in FIG. 1 except that an additional set of upper rotary grips  26  is provided for the reason to be more fully explained hereinafter. Similarly, the embodiment of FIG. 3 is similar to the FIG. 2 embodiment except that upper grips  26 , lower grips  24  and lower slips  25  may be one, single, integrated unit. Also, arrows  27  in FIGS. 2 and 3 indicate that lower and/or upper grips may be moved vertically, along the longitudinal axis of the drill string, as will be more fully described hereafter. It will also be noted that instead of coupler  18  and BOP stack  20  being integrated with the coupler on top of the stack, the coupler and BOP stack may be separate units with the coupler supported by the rig floor  39 . 
     With respect to the motorized grips  24  and  26 , it will be apparent that one or both of the conventional rotary grips may be motorized as shown schematically in FIG.  3 A. For example, the upper and lower grips may be provided with ring gears  32  and  33  which may by driven by drive gears  36  and  38  through shafts  35  and  37  by motors M- 1  and M- 2 . Thus, each of the grips  24  and  26  may be held stationary or rotated about the longitudinal axis of the string and tubular as will be more fully described hereafter. 
     FIGS. 4A-6A illustrate, and Table I describes in detail, one mode of steps whereby the FIGS. 2 and 3 embodiments may continuously maintain the flow of drilling fluid into and out of the bore hole while tubulars are added to the drill string. In these FIGS., arrows  30  indicate rotation of the top drive and arrows  31  represent the rotation of the grips within casing  19 . The bold arrows indicate the driving element, and the lighter arrows indicate that the element is idling and being driven by the other element. With respect to the FIG. 1 embodiment, it will be understood that the operation is the same, except that, without upper grips  26 , top drive  10  is used to rotate the tubular relative to the string in order to make or break the threaded connection therebetween. It will also be understood by those skilled in the drilling art that upper slips may be provided in the FIGS. 1-3 embodiments. 
     While the steps of the new method of the present invention are apparent from Table I and FIGS. 4A-6A, the following highlights should be noted. This method 
     
       
         
               
             
               
               
               
               
             
           
               
                 TABLE I 
               
             
             
               
                   
               
               
                 Adding one pipe, or stand of pipes, to the drill string 
               
               
                 Activity sequence for one cycle 
               
             
          
           
               
                 Activities: 
                 ‘Top drive’ 
                 ‘Coupler 
                 ‘Handlers’ 
               
               
                   
               
               
                 1. 
                 Drilling or ‘tripping 
                 Disengaged 
                 — 
               
               
                   
                 in’ 
               
               
                 2. 
                 — 
                 Rotate &amp; close slips 
                 — 
               
               
                 3. 
                 Lower ‘upset’ onto 
                 — 
                 — 
               
               
                   
                 slips 
               
               
                 4. 
                 — 
                 Rotate &amp; close grips 
               
               
                   
                   
                 and close annular pre- 
                 — 
               
               
                   
                   
                 venters 
               
               
                 5. 
                 Rotate tubular passive- 
                 Rotate lower grips 
                 — 
               
               
                   
                 ly (idle) 
                 actively (drive) 
               
               
                 6. 
                 — 
                 Flushing mud in &amp; air 
                 — 
               
               
                   
                   
                 out 
               
               
                 7. 
                 Raise tubular passively 
                 Break tool joint &amp; 
                 — 
               
               
                   
                   
                 back off 
               
               
                 8. 
                 Hold position 
                 Release upper grips 
                 — 
               
               
                 9. 
                 Raise to clear blind 
                 — 
                 — 
               
               
                   
                 preventer 
               
               
                 10. 
                 Stop circulation 
                 Close blind preventer 
                 — 
               
               
                 11. 
                 Flushing mud out &amp; 
                 — 
                 — 
               
               
                   
                 air in 
               
               
                 12. 
                 — 
                 Open upper annular 
                 — 
               
               
                   
                   
                 preventer 
               
               
                 13. 
                 Rise up to accept new 
                 — 
                 — 
               
               
                   
                 pipe 
               
               
                 14. 
                 — 
                 — 
                 Handlers 
               
               
                   
                   
                   
                 offer up 
               
               
                   
                   
                   
                 new pipe to 
               
               
                   
                   
                   
                 top drive 
               
               
                 15. 
                 Lower &amp; make up tool 
                 — 
                 — 
               
               
                   
                 joint 
               
               
                 16. 
                 — 
                 —                    
                 Top handler 
               
               
                   
                   
                   
                 releases 
               
               
                 17. 
                 Lower pipe to blind 
                 — 
                 Lower han- 
               
               
                   
                 preventer 
                   
                 dler guides 
               
               
                 18. 
                 — 
                 Close upper annular 
                 — 
               
               
                   
                   
                 preventer 
               
               
                 19. 
                 Flushing mud in &amp; 
                 — 
                 Lower han- 
               
               
                   
                 air out 
                   
                 dler restrains 
               
               
                 20. 
                 — 
                 Open blind preventer 
                 — 
               
               
                 21. 
                 Lower pipe to upper 
                 — 
                 — 
               
               
                   
                 grips 
               
               
                 22. 
                 — 
                 Close upper grips 
                 — 
               
               
                 23. 
                 Rotate passively (Idle) 
                 Rotate upper grips 
                 — 
               
               
                   
                   
                 actively (drive) 
               
               
                 24. 
                 Lower passively 
                 Make up tool joint 
                 — 
               
               
                 25. 
                 — 
                 Flushing mud out &amp; 
                 — 
               
               
                   
                   
                 air in 
               
               
                 26. 
                 Rotate tubular actively 
                 Rotate lower grips 
                 Handlers 
               
               
                   
                 (drive) 
                 passively (idle) 
                 disengage 
               
               
                 27. 
                 — 
                 Open &amp; stop rotating 
               
               
                   
                   
                 both grips &amp; open 
               
               
                   
                   
                 annular preventers 
               
               
                 28. 
                 Raise drill string off 
                 — 
                 — 
               
               
                   
                 slips 
               
               
                 29. 
                 — 
                 Open &amp; stop rotating 
                 — 
               
               
                   
                   
                 slips 
               
               
                 30 = 1 
                 Carry on drilling or 
                 Disengaged 
                 — 
               
               
                   
                 ‘tripping in’ and repeat 
               
               
                   
                 cycle. 
               
               
                   
               
               
                 Notes:  
               
               
                 ‘Flushing mud in &amp; air out’ includes bringing the space up to full mud pump pressure  
               
               
                 ‘Flushing mud out &amp; air in’ includes de-pressuring the space to atmospheric pressure  
               
             
          
         
       
     
     utilizes the top drive to provide the downward force necessary to push the tubular into the coupler against the pressure therein. Accordingly, this method is more applicable to adding individual tubulars, rather than stands, and it will be understood that conventional top drives may be modified to produce greater downward force than usual depending upon the degree of pressure in a particular application. For example, conventional top drives can only be used for pressures in the bore hole and in the coupler up to about 500 psi. Above this pressure, and particularly in the range of 1,000 to 5,000 psi which are frequently encountered, conventional top drives must be modified with stronger structural support and bearings in order to counteract the higher pressures. At these very high pressures it will also be understood that the handlers guide the tubulars and, if necessary, prevent any buckling of the tubulars. 
     In activity  1 , the string is drilling in the conventional mode and is driven by top drive  10 , although other forms of drive will become apparent hereinafter. In activities  2  and  3 , lower slips  25  have closed about the string, and box  14  has been lowered onto the slips while mud or other drilling fluid continues to be supplied through the top drive to the string. In activity  4 , the upper and lower grips engage the tubular and the string, respectively, and rotate with them. In activity  5 , the lower grips take over while the top drive begins to idle in its rotation. In activity  6 , mud or other drilling fluid is flushed through the coupler and the coupler is pressurized. In activity  7 , the saver sub is unscrewed from the string such as by slower rotation of the upper grips relative to the lower grips. In activity  8 , valve  23  remains open as the top drive rises and upper grips  26  open and release the saver sub. The top drive and saver sub continue to rise as shown in activity  9  while mud continues to be supplied to and through the top drive, as well as through passage  29 B. In activity  10 , valve  23  closes and circulation of the mud or other drilling fluid through the top drive is stopped. However, a continued flow of fluid is effected through passage  29 B, the lower chamber of the coupler and down through the string. In activity  11 , the mud or other drilling fluid is flushed through inlet passage  29 B and outlet passage  29 A, and the fluid is replaced by air at atmospheric pressure. Also, lower grips  24  may continue to rotate the drill string through activities  5  to  25  if continuous rotation of the string is desired with or without continuous drilling. Activity  12  shows that the flushing has been completed and the supply of mud or other drilling fluid to the top drive and through the saver sub has stopped. In activity  13 , the saver sub has been fully retracted and valve  23  remains closed. Drilling fluid continues to be supplied through passage  29 B and down through the string, and it will be noted that this supply of drilling fluid continues through all of activities  13  to  24 . In activity  14 , the handlers  17 A and  17 B deliver a new tubular, which is connected to the saver sub in activity  15 . In activities  16  to  18 , the lower end of the new tubular is lowered into the upper chamber by handler  17 B, and the upper annular preventers or seals  22 A are closed and sealed about the new tubular. Of course, the mud or other drilling fluid continues to be supplied to the bore hole by supply to and through the lower chamber as previously described, and valve  23  remains closed and sealed. In activity  19 , the upper chamber is flushed and depressurized through passage  29 A prior to opening of the valve as shown in activity  20 . In activity  21  the new tubular is lowered and guided by handler  17 B, and in activity  22  the new tubular is gripped by upper grips  26 . Throughout these activities, drilling fluid is resumed through the top drive, saver sub and the new tubular to the drill string; the flow of drilling fluids through the top drive and through passage  29 B being overlapping and mixed within the lower chamber. In activities  23 - 24 , upper grips  26  rotate the new tubular relative to the string and thereby make the connection. In this regard, it will be understood that the required relative rotation and torquing may be accomplished by rotation of the new tubular while the string is held stationary, or by rotation of both the tubular and the string in the same direction but at different rotational speeds. Thus, the connection, or disconnection, of a tubular may be accomplished with the string held stationary, or while continuing to rotate the string as desired. 
     In activities  24  to  30 , the supply of drilling fluid to and through the top drive is continued while both chambers are flushed in activity  25 , and the rotational driving of the new tubular is resumed by the top drive with the grips idling as shown in activity  26 . In activity  27  the upper and lower seals  22 A and  22 B are opened, as are valve  23  and grips  24  and  26 . These conditions are continued in activities  27  to  30  while lower slips  25  are opened in activity  29  and the top drive begins to lower the drill string in the normal drilling operation as described in activity  1 . Of course, the removal of a tubular or stand is accomplished by performing the above-described activities in reverse order, while continuing to supply the necessary fluids to the bore hole, and while continuing to rotate the drill string with or without further drilling. 
     Referring to FIG. 7, another preferred embodiment of the invention is illustrated with the same elements numbered with the same numerals as in FIGS. 1-3. In addition, numeral  34 A indicates the carrier for vertical and rotary movement of the upper grips and slips and numeral  34 B indicates the carrier for rotary movement of the lower grips  24  and slips  25 ; both of the upper and lower slips and grips being illustrated as being integral. As shown most clearly shown in FIGS. 8C to  8 F, the mating portions  23 A and B of valve  23  are designed of a size and shape so as to be able to open to a diameter greater than that of the upper grips and carrier  34 A. Thus, the lower end of each tubular may be lowered below valve  23 , and coupled with the upper tubular of the string in the lower portion of coupler  18 . In this schematic, the inlet/outlets are shown for the flow of drilling fluids such as mud and for hydraulic fluid to move carrier  34 A vertically as will be further explained hereinafter. 
     FIGS. 8A-8H illustrate the detailed steps of the method of this embodiment to connect a new tubular. In FIG. 8A, a new tubular  13  is to be added to string  16 . The top of the string is gripped by the lower grips and slips, and valve  23  is closed. Upper grips and slips and upper seal  22 A are open, and lower seal  22 B is closed. At this time, pressurized drilling fluid is supplied through inlet  29 D and flows down the drill string so as to continue the circulation of fluid in the bore hole. Also, the lower grips may continue to be rotated, by a drive motor such as M 2  shown in FIG.  3 A and rotate the drill string so that the drilling operation may also be continuous if desired. 
     In FIG. 8B the tubular has been lowered by the top drive into the upper chamber of the coupler and is gripped by upper grips. Upper seal  22 A is closed, as is valve  23 , so that pressurized drilling fluid may be passed down the tubular from the top drive and out of the coupler through outlet  29 A. The lower grips and slips may continue to rotate the drill string if desired, and drilling fluid continues to be supplied to the bore hole through inlet  29 D and through the lower chamber and downwardly through the drill string. Valve  23  remains closed at this time so as to separate the upper and lower chambers of the coupler. 
     In FIG. 8C, upper and lower seals  22 A-B remain closed while valve  23  has been opened so as to be able to lower tubular  13  and the upper grips and slips below the level of valve  23  and into engagement with upper end of the drill string. During this time, the lower grips  24  may continue to rotate the drill string, and pressurized drilling fluid continues to be supplied through both the tubular and inlet  29 D. In FIG. 8D, new tubular  13  has moved down into threaded engagement with box  14  of the uppermost tubular of the drill string. This threaded engagement may be made by the upper grips and slips rotating tubular  13  at a differential speed in the same direction as the drill string. Alternatively, as in the FIG. 1 embodiment, the new tubular may be rotated by the top drive. In either case, the joint is made and torqued so that the new tubular becomes the uppermost tubular of the drill string. As in the previously described steps, circulation of drilling fluid continues through new tubular  13  into the drill string and into the bore hole. In addition, the drill string may continue to be rotated at all times by the lower grips and slips if continuous drilling is desired. Thus, continuous circulation of the drilling fluid to the bore hole is achieved, as can continuous string rotation an drilling, while each new tubular is added. 
     FIG. 8E shows that, having connected the new tubular, the mud within the coupler may be drained out via  29 D and all of the seals and grips and slips retracted. The top drive continues drilling; or simply lowering the drill string when tripping into the well. 
     FIG. 8F shows that, when the drill string has lowered sufficiently to need the addition of a new tubular, the saver sub of the top drive has reached the region of the lower grips, at which point the seals and grips and slips are all re-applied, the coupler refilled with mud and the saver sub is disconnected from the drill string as shown. 
     FIG. 8G shows the valve  23  closed to isolate the upper chamber from the lower chamber and also shows that the mud circulation continues into the drill string via inlet  29 D and the mud can be drained from the saver sub and upper chamber via outlet  29 A. 
     FIG. 8H shows that the upper seal  22 A and upper grips and slips  26  and  28  can be retracted and allow the top drive and saver sub to rise up and accept a new tubular. 
     Referring to the simplified assembly drawing comprising FIG. 9, the elements previously described are illustrated with the same numerals as in the prior FIGS. Coupler  18  comprises a high pressure casing  19  with tubular  13  positioned above drill string  16  and ready to be connected to the top of the string. At this time, valve  23  is closed, and box  14  is immediately below the center line of the valve. Valve portions  23 A and  23 B carry resilient bumpers  23 C, D to be more fully described hereafter. High pressure seal  22 A is closed and sealed against tubular  13 , and lower high pressure seal  22 B is closed and sealed about string  16 . It will also be noted that upper grips  26  and upper slips  28  are in engagement with tubular  13 , and that lower grips  24  and lower slips  25  engage drill string  16 . In this embodiment, both the upper and lower slips and grips are positioned within high pressure casing  19 . However, it will be understood that these may be positioned above and below casing  19  as will be described hereinafter. As further illustrated in FIG. 9, the sub-assembly of the upper grips and slips is contained within a cage  34 A, and the complete assembly of the lower grips and slips is contained within a cage  34 B. Upper cage  34 A is mounted stationary between upper and lower casing portions  19 A, and lower cage  34 B is mounted stationary between upper and lower casing portions  19 A. The bumpers may be composed of any firm but slightly resilient material which can withstand the pressures and drilling fluids such as, for example, hard rubber. Bumpers  23 C and D may be of various shapes and are shown, for example, as segments which extend a few inches horizontally from the center line of the valve, and extend upwardly and downwardly a few inches from valve plates  23 A and B with open passages between the segments. Thus, the bumpers not only provide a centering and cushioning effect on the tubular and on the string, but also, they continuously allow drilling fluids to pass through the bumpers. That is, they permit continuous flow of fluids from the tubular into the upper chamber, and from the lower chamber into the string, as will be more fully described in detail hereafter. 
     Referring to FIGS. 9,  9 B-D and  10 , lower cage  34 B containing the sub-assembly of lower slips and grips is illustrated most clearly. A carrier  40 B is mounted for rotational movement within cage  34 B, and also for axial movement if desired. Annular seals  42 A, B and C are preferably provided between the carrier and the cage as shown most clearly in FIG.  10 . Carrier  40 B includes a plurality of vertically extending threaded drive screws  44  which are positioned circumferentially about the carriage. As shown most clearly in FIGS. 9,  9 D and  10 , lower grips  24  are supported and moved radially inwardly and outwardly by pairs of links  45  and  46 . One end of each of these links is pivotally connected to the grip, and the other end of each link is pivotally connected to a threaded follower  47 ,  48 . Followers  47 ,  48  move vertically when drive screws  44  are rotated. In this regard, it will be understood that the upper and lower portions of the drive screws are threaded in opposite directions. Thus, followers  47  and  48  move vertically apart when the drive screw is rotated in one direction, and they move vertically toward each other when the drive screw is rotated in the reverse direction. Followers  47  and  48  are shown in FIG. 10 as having moved to the position closest to each other. In this position, links  45 ,  46  are in their most radially inward position such that grips  24 , and their friction and/or wear pads  24 ′, have been forced radially inwardly into their clamping position about box  14 . Conversely, when drive screws  44  are rotated in the opposite direction, followers  47 ,  48  are moved vertically away from each other such that the radial length of the links is shortened and the grips move radially outwardly to their retracted and non-engagement position. 
     In FIG. 10, lower slips  25  are shown in their radially inwardly extended position in engagement with string  16  and the lower chamfered or conical surface  14 ′ of box  14 . In this position, a positive lock is made at the bottom of the box such that the extreme weight of the string cannot pull the string downwardly, even if grips  24  are retracted or are not capable of supporting the weight by frictional engagement. Preferably, slips  25  include friction or wear liners  25 ′. Each slip is connected to and moved radially inwardly and outwardly by a pair of links  51 ,  52 . The radially inner end of each thrust link  51  is pivotally connected to a slip  25  and the opposite end of each link  51  is pivotally connected to a threaded follower  54  which is carried on a drive screw  58 . At the same time, the mid-portion of each of thrust links  51  is pivotally connected to an actuator link  52 , and the opposite end of each link  52  is pivotally connected to a follower  56 . Followers  56  are carried by drive screws  44 , which also drive followers  47 ,  48 . Preferably, four to eight drive screws  44  are positioned circumferentially around the string as shown in FIGS. 9B,  9 C and  11 . As drive screws  44  are rotated in one direction, by means to be described hereafter, followers  56  are moved upwardly. As the followers move upwardly, links  52  pull the upper portions of links  51  and slips  25  radially outwardly and out of engagement with string  16  and box  14 . Conversely, rotation of drive screws  44  in the reverse direction drives followers  56  downwardly and links  51  and  52  force slips  25  inwardly so as to positively lock string  16  against any downward movement regardless of the position of grips  24 . 
     It will also be understood that, once slips  25  engage string  16  and the chamfered surface  14 ′ of box  14 , continued rotation of drive screws  58  will cause followers  54  to move further upward while slips  25  are locked against the chamfered edge of the box. This provides for accommodating different vertical sizes of boxes in common use. It will also be understood that continued upward movement of followers  54  must be accommodated by making the upper portions of drive screws  44  and/or the threads on followers  56  to be a slip-thread or otherwise flexible connection. That is, the threads on screws  44  and followers  56  may be of such dimensions, or of such materials, such as resilient materials, such that followers  56  move upwardly on screws  44  under relatively light load or pressure, as previously described, but under the substantially greater load and pressure of the heavy drill string, the threads of followers  56  may slip over the threads of drive screws  44  without further clamping the already clamped slips  25 . 
     In order to rotate string  16 , if continued rotation of the string is desired while tubulars are added, or removed, carrier  40 B is surrounded by and connected to an annular gear  60 . Gear  60  is in engagement with driving gear  62  carried by shaft  64 . Thus, when shaft  64  is rotated, by drive means to be described, carrier  40 B is rotated about the vertical axis of string  16 . Rotation of carrier  40 B causes slips  25 , and particularly grips  24 , to rotate about the vertical axis, and this rotation causes string  16  to be rotated even though it may be a mile or more in length in the bore hole. 
     The drive assemblies for rotating drive screws  44  and  58  will now be described with reference to FIGS. 9D and 10. Drive screws  44 , which actuate the grips and the slips, are connected at their lower ends to gears  80 . A ring gear  78  is provided which has teeth on its inner annular surface which engage drive gear  80 . The ring gear also has teeth on its outer annular surface which engage drive gear  76  driven by shaft  74 . 
     The drive assembly for rotating drive screws  58  to raise and lower slips  25  is essentially similar, and it comprises a drive shaft  72  which rotates drive gear  70 . Drive gear  70  engages the outer annular teeth of a ring gear  73  while the inner annular teeth of the ring gear engage gear  66  connected to rotate drive screws  58 . 
     It will be readily understood that each of the vertically extending drive shafts such as  64 ,  72  and  74  are driven by conventional reversible motors, not shown, which may be of either the known electric or hydraulic types. It will also be understood that each of these drive shafts are designed such as to be able to be vertically elongated or shortened as carriers  40 A and B are moved vertically within cages  34 A and B as will be further described. For example, the drive shafts may be of the splined or telescoping type as is known in the art of conventional drive shafts. Also, while only lower cage  34 B and carrier  40 B have been described in detail, it is apparent from FIG. 9 that the same structural elements are provided with respect to upper cage  34 A and carrier  40 A. 
     In addition to the rotational movement of carrier  40 B by ring gear  60  and drive gears  62  and  64  as described, carriage  40 B may also be moved vertically so as to raise and lower drill string  16 . That is, as shown most clearly in FIG. 9, there is a first vertical distance between the bottom of pin  15  and the top of box  14 , and also a second distance for the pin to thread into the box in order to make the threaded connection. Accordingly, carrier  40 A must be able to move downwardly by such distance, or carrier  40 B must be able to move upwardly by such distance, or each carrier must move one-half of the required distance. The present invention provides the capability to perform each of these modes as will now be described with reference to FIGS. 11,  11 A and  11 B. 
     Referring first to FIG. 11, in addition to drive shafts  64 ,  72  and  74 , one preferred embodiment of the present invention further provides additional vertical screws  90  for vertically moving carriers  40 A and  40 B upwardly and downwardly. For purposes of simplicity, the following description will be with respect to carrier  40 B; however, it will be understood that carrier  40 A may be moved vertically in the same manner. Screws  90  are positioned circumferentially apart as shown in FIG. 11 so as to not interfere with the previously described drive shafts  64 ,  72  and  74 , or with seals  22 A and B. Upon rotation of screws  90  in one direction, by conventional motors, casing or piston  100  moves carriage  40 B upwardly or downwardly as desired for the functions or steps hereinafter described. Alternatively, casing or piston  100  may be controlled as to its vertical position by hydraulic means as shown in the break-away view of FIG.  11 B. That is, the bottom surface  102  of casing element  100  may be designed to be a piston, with suitable piston rings as desired. Thus, the high well pressure may act, through the mud or other drilling fluid on the lowermost surface  102  of piston  100 . Against this pressure, the piston may be controlled by pressurized fluid entering the sealed chamber  94  through passage  104 . Therefore, whether operated mechanically or hydraulically, carriers  40 A and  40 B may be controlled as to their vertical positions, which in turn, controls the vertical positions of string  16  and/or new tubular  13 . In both cases it will be understood that a key  106  and keyway  108  as shown in FIG. 10, or other anti-rotational element is provided in order to prevent the carriers from rotating relative to cages  34 A and  34 B. 
     FIG. 12 illustrates the relative positions of the elements when a new tubular is to be added to the string. At this time the string is gripped by lower grips  24  and is positively locked against downward movement by slips  25 . Lower high pressure seal  22 B is closed about string  16 , and valve  23  is closed thereby separating the coupler into upper and lower chambers as previously described. Upper high pressure seal  22 A is open, and upper grips  26  and slips  28  are in their retracted position thereby enabling a new tubular to be lowered into the upper chamber of the coupler. Also, it will be noted that carriers  40 A and  40 B are in their uppermost and lowermost positions, respectively. 
     In FIG. 13, a new tubular has been lowered into the upper chamber and has been gripped by upper grips  26  and slips  28 . In this position, it will be noted that pin  15  has engaged bumper  23 C which sets the correct position of the new tubular without shock or damage to valve  23 . It will also be noted that upper seal  22 A has closed and is sealed around the new tubular, and that the vertical positions of carriers  40 A and  40 B are the same as in prior FIG.  12 . At this time, drilling mud or other drilling fluid may continue to pass down the tubular into the upper chamber from which it may exit through a passage such as  29 A or  29 B by virtue of the flow passages in bumper  23 C as previously described. In addition, drilling fluid may be admitted into the lower chamber through passage  29 C or  29 D from which it may exit down the string through the lower bumper of similar construction. Accordingly, it will be apparent that drilling fluid may be circulated continuously through the upper and lower chambers of the coupler, and down the string into the bore hole while new tubulars are added to the string, or removed therefrom. In addition, it will be understood that if it is desired to continue drilling during the addition of tubulars, carrier  40 B may continue to be rotated such as through ring gear  60  and drive gear  62  as previously described. At this time the upper end of the string remains secured in a fixed vertical position, but drilling may continue due to elongation; i.e., stretching of the string, or by use of a bumper sub or similar extension, such that the bit continues to drill downwardly if continuous drilling is desired. 
     FIG. 14 illustrates the elements in the same positions as in FIG. 13, but also illustrates valve  23  as having been opened. Opening of valve  23  allows carrier  40 A to pass downwardly and carrier  40 B to move upwardly. Also, the upper and lower chambers are in open communication such that the string may receive continuing flow of drilling fluid from both the new tubular and from that supplied to the coupler such as through passages  29 A and/or B and/or  29 C and D. 
     FIG. 15 illustrates the position of the elements after carrier  40 A has moved downwardly, and carrier  40 B has moved upwardly, to make the connection of the new tubular to the string. That is, for example, by rotating the new tubular by the upper grips, or by the top drive, while bringing the tubular down and the string upwardly by the respective vertical movements of carriers  40 A and  40 B. In this regard it will be understood that the string may be held stationary by the lower grips while only the tubular is rotated by the upper grips in order to screw the pin into the box. Alternatively, if the string is being rotated by lower grips  24  for down hole operational reasons or in order to continuously drill, the tubular may be rotated in the same direction but at a higher RPM. In either event, the connection is properly torqued and fluid flow to the coupler may be terminated since the flow of drilling fluids down the new tubular to the string is fully sufficient to continue continuous drilling circulation of drilling fluid, and drilling if desired. Thereafter, all of the slips and grips are retracted as shown in FIG.  16  and the drilling continues for the length of the new tubular until the next new tubular is added in the same manner. If the coupler is not mounted on or integral with the BOP stack, the drilling fluid in the coupler is flushed out and drained through passage  29 D before lower seal  22 B is opened. Conversely, it will be apparent that the above-described steps may be performed in the reverse order when it is desired to remove tubulars. 
     From the foregoing description of one preferred mode of operation, it will be apparent that upper carrier  40 A may be held vertically stationary while string  16  is raised the required distance by upward movement of lower carrier  40 B. However, in view of the substantial weight of the string, it is preferred that lower carrier  40 B be designed to remain stationary, and that the full distance of the required movement is performed by upper carrier  40 A. This embodiment is illustrated in FIGS. 17-19 and it will be apparent from FIG. 17 that piston  100  of the lower assembly may be eliminated thereby simplifying the overall design. As illustrated in FIG. 18, upper carrier  40 A and keyway  106  are designed to be sufficiently long such that carrier  40 A may move downwardly by the full distance required to make the connection. This is further illustrated in the assembly drawing of FIG.  19 . In this illustration it will be apparent that the distance to be traveled downwardly by the new tubular is more than sufficiently provided for by the downward vertical movement of carrier  40 A within cage  34 A. 
     With regard to the locations of the grips and slips relative to casing  19  and valve  23 , FIG. 20 schematically illustrates eight relative locations which are possible with the present invention. For example, FIG. 20A illustrates both the upper grips  26  and the lower grips  24  as being outside of casing  19 . FIG. 20B illustrates upper grips  26  as being in the casing above valve  23 , and the lower grips outside and below the casing. FIG. 20C illustrates the upper grips as being in the lower chamber while the lower grips  24  are outside and below the chamber. In FIG. 20D, the upper grips are illustrated above the casing with the lower grips in the lower chamber of the casing. FIG. 20E illustrates the embodiment shown in FIG. 9, as previously described, in which upper grips  26  are within the casing and above the valve, and lower grips  24  are in the lower chamber of the casing and below the valve. FIG. 20F illustrates the positions of the grips as previously described with respect to the FIG. 2 embodiment in which both of the upper and lower grips are within the casing and below the valve. In FIG. 20G, the upper grips are outside and above the casing while the lower grips are in the upper chamber of the casing. Lastly, FIG. 20H illustrates the embodiment in which both of upper grips  26  and lower grips  24  are in the upper chamber of the casing above valve  23 . 
     In addition to the above, it has discovered that, for use in the present invention, certain positions and combinations of slips, grips and seals are substantially preferred and lead to unexpected advantages and results. For example, FIG. 20A illustrates the multiple positions which are possible, at least theoretically, for the positions of the seal and lower slips relative to each other and relative to chamber  19 . Similarly, FIG. 20B illustrates the theoretically possible locations of the seal and upper slips and grips relative to each other and to chamber  19 . While all of these locations are physically possible, some locations produce unexpectedly superior results. For example, the surfaces of the upsets are usually much rougher than that of the tubular body. Therefore, the lower seal  22 B would wear out unless it is more expensive RBOP. Therefore, embodiments g to l in FIG. 20A are preferred for substantially longer and more effective seal life without resorting to rotating seals. At the same time, it has been noted that the grips should engage the upset, and not the tubular body, in order to prevent potentially serious damage to the surface of the tubular. Therefore, it has been discovered that the upset of the tubular should be gripped by the grips such as illustrated in FIGS. 20A a, b, c, g, h, i, m, n and o. 
     The theoretical options for the upper seals and upper slips and grips are also illustrated in FIG.  20 B. However, the principles described with reference to FIG. 20A also apply. Thus, the embodiments of FIGS. 20B b and h have been discovered to produce the most unexpected results in combination with the other elements of the present invention. As a result, it has been discovered that the preferred positioning of the seals, grips and slips, including the serious factor of minimizing the vertical height of the coupler which also is very important for achieving the optimum results of the present invention, is to position the elements as illustrated in FIGS. 20A h and  20 B h if the slips and/or grips are located within the pressure casing  19 . In the future, as the industry modifies its present equipment, the optimum results have been discovered to be with  20 B h above and  20 A n below. 
     As previously stated, the advantages of the present invention may also be accomplished by positioning the grips, and slips if desired, outside of pressure casing  19 . This embodiment is illustrated schematically in FIGS. 21-27. As shown in FIGS. 21-22, in this embodiment the high pressure casing  119  is positioned between the upper grips assembly  100 A and the lower grips assembly  100 B. Upper grips assembly  100 A engages a tubular  113  and lower grips assembly engages a drill string  116 . High pressure casing  119  encloses an upper seal  122 A, a lower seal  122 B, and a valve  123 . It will be understood that these elements correspond to previously described elements  19 ,  22 A-B and  23 , and that they operate in the same manner as their previously described counterparts. It will be apparent to those skilled in the art that the lubricants and drilling fluids may be supplied to and from casing  119  in various ways similar to that previously described. However, one preferred embodiment is illustrated in FIG. 22 in which lubricant for the upper annular preventer or seal  122 A may be supplied through port or passage  102 . Passage  104  may be provided for supplying mud and purge air to the upper chamber from which it may be discharged through passages  106 . Mud or other drilling fluid may be supplied to the lower chamber through passage  108  so as to flow down the drill string for continuous circulation as previously described, and excess drilling fluid and/or purge air may exit the lower chamber through passages  110 . An additional passage  107  is preferably provided for injecting a lubricant or dope in contact with the pin and box when valve  23  is open and the pin has been lowered. 
     As further shown in FIG. 22, centering elements or rams  124 ,  126  and  128  are preferably provided. The rams extend at a 90° angle relative to valve  23 , and may be moved radially inwardly to engage and center the lower end of tubular  113  and the upper end of drill string  116 , by conventional electric or hydraulic motors not shown, as the tubular and string are about to be coupled. Centralizing ram  126  may also be used to centralize pin  115  relative to box  114  when valve  123  is open just prior to the coupling. 
     Referring now to FIG. 23, the lower grip assembly  100 B is schematically illustrated in one preferred embodiment, and it will be understood that the upper grip assembly may be the same but reversed so as to be upside down. Grip assembly  100 B includes an outer casing or shell  130  within which a drum  132  is contained and mounted for rotation between upper and lower thrust bearings  134 A and  134 B. Drum  132  includes an annular ring gear  136  which may be driven by one or more drive gears  138  rotated by one or more drive shafts  140  which are driven by conventional reversible motor(s) not shown. Thus, drum  132  may be rotated clockwise or counter-clockwise in order to rotate grips  142  about the axis of string  116 . Grips  142  are moved radially inwardly and outwardly by sets of links  143  and  144  are which moved vertically by followers  147 A and B carried by drive screws  146  in the same manner as previously described. Drive screws  146  are connected to and rotated by drive gears  148  supported by thrust bearings  150 . Drive gears  148  are rotated by an annular gear  152  having inner teeth which engage gears  148 , and having outer teeth which engage one or more drive gears  154 . Drive gears  154  may be driven by conventional motors through shafts  156  extending through high pressure seals  158 . 
     The operation of this embodiment will be readily understood from the prior description in that drive screws  146 , having upper and lower reverse threads, move links  143  and  144  inwardly and outwardly depending upon the direction of rotation of drive screws  146  and the direction and speed differential of drive shafts  140  and  156 . In addition, it will be understood that grips  142  may also function as slips in that the downward force created by the weight of the string causes lower links  144  to increase the gripping force on the string. That is, the grips and lower links act as wedges which prevent downward axial movement of the string. Similarly, the upper set of links  143 ′ in grip assembly  100 A act as wedges forcing grips  142 ′ into tighter engagement with the tubular as the high pressure in the coupler chamber applies a substantial upward force on the tubular before the connection is made with the string. In addition, in the preferred embodiment, the axial length of the grips is made greater than that of the previously described grips. For example, instead of a common length in the order of 6 to 10 inches, grips  142  and  142 ′ are preferably in the order of 18 to 24 inches in axial length. 
     As previously discussed and as illustrated in FIGS. 21,  22  and  25 , one or other or both of tubular  113  and string  116  must be moved vertically toward each other for connecting or removing a tubular to or from the string. FIG. 25 illustrates one preferred embodiment in which coupler casing  119  and lower grip assembly  100 B may remain stationary while upper grips assembly  100 A and tubular  113  are moved the required vertical distance by a power system  170 , although it will be apparent that lower grips assembly  100 B may be moved on similar manner if desired. In the embodiment as illustrated, upper grips assembly  100 A includes an offset casing portion  160  which carries an internally threaded power sleeve  162 . Casing  119  of the coupler includes an offset housing  164  which carries a threaded power screw  166 . Power screw  166  is connected to and rotated by a gear  168  which is driven by a drive gear and shaft  172 . Gear  168  and power screw  166  are provided with a thrust bearing  174  at the lower end. Power sleeve  162  slides through high pressure seal  178  and seals against the inside of casing  164  with high pressure seal  176 . Therefore, as power screw  166  is rotated by shaft and gear  172 , and gear  168 , the power screw moves power sleeve  162  and upper grip assembly  100 A downwardly or upwardly as desired to make or break the connection of the tubular. Alternatively, the power gear assembly may be replaced by a hydraulic power assembly. Additionally, hydraulic fluid at a pressure equal to or proportional to the mud pressure in the drill string may be admitted through passage  179  to pressure balance the forces and thereby reduce the force on the threads of the screw. Of course, it is preferred to provide two or more power systems  170  circumferentially spaced about the vertical axis of the grip assembly in order to balance the forces and apply the total force desired. In addition, the preferred embodiment includes a vertically extending stop or guide  180  which extends between the grip assembly  100 A and the casing  119  so as to allow the vertical movement just described while acting against any torque forces therebetween. 
     FIGS. 26 and 27 illustrate the application of the external grips to tubulars which do not have external upsets or boxes, and to tubulars having small diameters and relatively thicker walls. Without external upsets, the distance between upper and lower seals  122 A and  122 B may be greatly reduced. Additionally, the grips may be shortened due to the greater thickness of the tubular wall. As a result, it has been discovered that the vertical height of the overall casing and external grips may be substantially reduced. In this embodiment, the vertical height of coupler casing  119 ′ is reduced such that it may be in the order of the vertical height of the entire power system  170 , and the high pressure casing  119  and the lower grips assembly  100 B may be one, integrated casing. 
     From the foregoing brief description of several embodiments of the present invention, it will be apparent that very substantial savings in the cost of drilling may be achieved. It is also to be understood that the present invention may be remote controlled, such as in off-shore under sea drilling operations, by remotely controlling the drive motors by radio or sonar signals. It will also be understood that, instead of the coupler being supported by a rig floor, the coupler may be mounted on handlers for mobile operation so as to perform hand-to-hand or hand-over-hand drilling operations as more fully described in published PCT Applications WO 98/16716 and WO 00/22278 which are hereby incorporated by reference. Of course, it is to be understood that the foregoing description of several preferred embodiments is intended to be purely illustrative of the principles of the invention, rather than exhaustive thereof, and that the present invention is not intended to be limited other than as expressly set forth in the following claims interpreted under the doctrine of equivalents.