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FIELD 
     There is described a tubing injector that is used to inject coiled tubing into a well bore. 
     BACKGROUND 
     U.S. Pat. No. 7,467,659 (Nielsen et al.) discloses a tubing injector with injector mechanisms that move that are capable of moving toward each other or away from each other. There is no redundancy in the Nielsen et al mechanism should one of the injector mechanisms fail. The 2010 BP off shore oil well disaster in the Gulf of Mexico has demonstrated a need for back up systems, should primary systems fail. What is required is a tubing injector with built in redundancy. 
     SUMMARY 
     There is provided a tubing injector which includes a base mountable to a wellhead with a bore positioned on a vertical axis in alignment with a bore of the wellhead. At least one body is detachably secured to the base. A first track is positioned on a first horizontal axis extending outwardly away from the vertical axis on opposed sides of the body. A second track is positioned on a second horizontal axis extending outwardly away from the vertical axis on opposed sides of the body and circumferentially spaced about the vertical axis relative to the first horizontal axis. A first injector pair of cooperating injector mechanisms one of which is positioned on each side of the vertical axis, the first injector pair being movable along with first track between an engaged positioned engaging tubing positioned in the bore of the wellhead and a disengaged position spaced from the vertical axis. A second injector pair of cooperating injector mechanisms one of which is positioned on each side of the vertical axis, the second injector pair being movable along with second track between an engaged positioned engaging tubing positioned in the bore of the wellhead and a disengaged position spaced from the vertical axis. 
     There may be a separate body for each injector that makes up the tubing injector as a whole. A first body supports a portion of the first track on which one of the first injector pair travels. A second body supports a portion of the first track on which another of the first injector pair travels. A third body supports a portion of the second track on which one of the second injector pair travels and a fourth body supports a portion of the second track on which another of the second injector pair travels. A selected injector is removable for repair or replacement by removing from the base one of the first body, the second body, the third body, or the fourth body that supports the selected injector. When the unit is being used with offshore drilling rigs and is positioned on the sea bed, an injector may be removed and replaced by a robot vehicle. The robot vehicle can dive down to the tubing injector, detach the body which supports the injector to be removed and then replace it with a new injector. 
     The tubing injector, as described above, provides redundancy to address safety concerns. The first injector pair is movable to the engaged position, when the second injector pair is moved to the disengaged position. Conversely, the second injector pair is movable to the engaged position, when the second injector pair in moved to the disengaged position. When in the disengaged position, the first injector pair is removable for repair or replacement. Similarly, when in the disengaged position, the second injector pair is removable for repair or replacement. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       These and other features will become more apparent from the following description in which reference is made to the appended drawings, the drawings are for the purpose of illustration only and are not intended to be in any way limiting, wherein: 
         FIG. 1  is a front elevation view of a tubing injector with built in redundancy. 
         FIG. 2  is a side elevation view of the tubing injector with built in redundancy shown in  FIG. 1 . 
         FIG. 3  is a top plan view of the tubing injector with built in redundancy shown in  FIG. 1 . 
         FIG. 4  is a top plan view of the tubing injector with built in redundancy shown in  FIG. 3  with a body with corresponding track and injector removed. 
     
    
    
     DETAILED DESCRIPTION 
     A tubing injector generally identified by reference numeral  10 , will now be described with reference to  FIGS. 1-3 . 
     Structure and Relationship of Parts 
     Referring to  FIG. 1 , a tubing injector  10  includes a base  11  mountable to a wellhead, not shown with a bore positioned on a vertical axis  18  in alignment with a bore of the wellhead. At least one body  12  is detachably secured to the base by a coupling  14 . Referring to  FIG. 3 , a first track  20  is positioned on a first horizontal axis  22  and extends outwardly away from vertical axis  18  on opposed sides  28  of body  12 . A second track  24  is positioned on a second horizontal axis  26  and extends outwardly away from vertical axis  18  on opposed sides  28  of body  12 . Second track  24  is circumferentially spaced about vertical axis  18  relative to first horizontal axis  22 . 
     A first injector pair  30  of cooperating injector mechanisms  32  is positioned such that one is positioned on each side of vertical axis  18 . First injector pair  30  is movable along with first track  20  between an engaged positioned and a disengaged position by expandable hydraulic cylinders  16 . Hydraulic cylinders  16  have a first end  17  and a second end  19 . First end  17  is attached to a vertical reaction frame  21  on body  12  and second end  19  is attached to first track  20  or second track  24 . In the engaged position, first injector pair  30  engages tubing  34  positioned in the bore of wellhead  16 . In the disengaged position, first injector pair  30  is spaced from vertical axis  18 . A second injector pair  36  of cooperating injector mechanisms  30  is positioned such that one is positioned on each side of vertical axis  18 . Second injector pair  36  is movable along with second track  24  between an engaged positioned and a disengaged position. In the engaged position, second injector pair  36  engages tubing  34  positioned in the bore of wellhead  16 . In the disengaged position, second injector pair  36  is spaced from vertical axis  18 . First injector pair  30  is movable to the engaged position when second injector pair  36  is moved to the disengaged position. Second injector pair  36  is movable to the engaged position when first injector pair  30  is moved to the disengaged position. When in the disengaged position, first injector pair  30  or second injector pair  36  are removable from first track  20  and second track  24 , respectively. 
     Referring to  FIG. 3 , in the preferred embodiment, there is a separate body  12   a ,  12   b ,  12   c  and  12   d  for each injector. A first body  12   a  supports a first portion  20   a  of first track  20  on which one of the injectors  30   a  of the first injector pair  30  travels. A second body  12   b  supports a second portion  20   b  of first track  20  on which another injector  30   b  of the first injector pair  30  travels. A third body  12   c  supports a first portion  24   a  of second track  24  on which one of the injectors  36   a  of the second injector pair  36  travels. A fourth body  12   d  supports a second portion  24   b  of the second track  24  on which another injector  36   b  of the second injector pair  36  travels. When an injector  30   a ,  30   b ,  36   a  or  36   b  is selected for removal for repair or replacement, it is removed by removing one of first body  12   a , second body  12   b , third body  12   c , or fourth body  12   d  from base  11 . When a body  12   a ,  12   b ,  12   c  or  12   d  is removed from base  11 , the corresponding track  20   a ,  20   b ,  24   a  or  24   c  and injector  30   a ,  30   b ,  36   a  and  36   b  are removed as a group. Referring to  FIG. 4 , when body  12   c  is removed from base  11 , corresponding track  24   a  and injector  36   a  are also removed as a unit. 
     Operation 
     Referring to  FIG. 2 , body  12  of tubing injector  10  is connected to wellhead  16  by coupling  14 . Referring to  FIG. 3 , first track  20  is positioned on first horizontal axis  22  and second track  24  is positioned on second horizontal axis  26 . Second track  24  is circumferentially spaced about vertical axis  18  relative to first horizontal axis  22 . First injector pair  30  of cooperating injector mechanisms  32  is positioned such that one is positioned on each side of vertical axis  18  and is movable along with first track  20  between an engaged positioned and a disengaged position. In  FIG. 3 , first injector pair  30  is in the engaged position. Second injector pair  36  of cooperating injector mechanisms  30  is positioned such that one is positioned on each side of vertical axis  18  and is movable along with second track  24  between an engaged positioned and a disengaged position. In  FIG. 3 , second injector pair  36  is in the disengaged position. 
     When first injector pair  30  is in the engaged position and in contact with tubing  34 , second injector pair  36  is in the disengaged position. While second injector pair  36  is in the disengaged position, injectors  36  are removable from second track  24  for repair or replacement. When first injector pair  30  becomes worn or requires service or replacement it is moved to the disengaged position by expanding hydraulic cylinders  16  attached to first track  20  and second injector pair  36  engage tubing  34  by contracting hydraulic cylinders  16  attached to second track  24   h . This allows continued use of tubing injector  10  while allowing maintenance on the disengaged injector pairs. 
     Referring to  FIG. 3 , in the event that an injector  30   a ,  30   b ,  36   a  or  36   b  is to be removed, the corresponding body  12   a ,  12   b ,  12   c  or  12   d , respectively, is removed from base  11 . A portion of track  20   a ,  20   b ,  24   a  or  24   b  is also removed at the same time and a new body  12  with corresponding injector and track is attached to base  11 . Referring to  FIG. 4 , when body  12   c  is removed from base  11 , corresponding track  24   a  and injector  36   a  are also removed as a unit. 
     In this patent document, the word “comprising” is used in its non-limiting sense to mean that items following the word are included, but items not specifically mentioned are not excluded. A reference to an element by the indefinite article “a” does not exclude the possibility that more than one of the element is present, unless the context clearly requires that there be one and only one of the elements. 
     The following claims are to be understood to include what is specifically illustrated and described above, what is conceptually equivalent, and what can be obviously substituted. Those skilled in the art will appreciate that various adaptations and modifications of the described embodiments can be configured without departing from the scope of the claims. The illustrated embodiments have been set forth only as examples and should not be taken as limiting the invention. It is to be understood that, within the scope of the following claims, the invention may be practiced other than as specifically illustrated and described.

Summary:
A tubing injector has a first injector pair and a second pair of cooperating injector mechanisms. The first injector pair are positioned on a first track and the second pair are positioned on a second track. The tubing injector provides redundancy to address safety concerns. The first injector pair is movable to the engaged position, when the second injector pair is moved to the disengaged position and vice versa.