An on/off tool running and well completion method includes deploying a packer in a well bore; providing an assembly having an on/off tool and a tool spacer sleeve carried by the on/off tool; providing a tubing string; coupling the on/off tool of the assembly to the tubing string; inserting the assembly and the tubing string in the well bore; irrigating the packer by circulating packer fluid through the well bore, the assembly and the tubing string to clean the packer; determining a depth of the packer in the well bore; and latching the on/off tool of the assembly to the packer once.

FIELD 
     Embodiments of the disclosure generally relate to methods of completing hydrocarbon production wells. More particularly, embodiments of the disclosure relate to an on-off tool running and well completion method and assembly in which seals in an on/off tool are protected from abrasion as the tool is coupled to a packer deployed in a hydrocarbon well preparatory to completion of the well. 
     BACKGROUND 
     In the completion of hydrocarbon wells, it is common practice to isolate one or more subterranean hydrocarbon-producing formation zones from each other within a well bore using packers. Conventional practice may include deploying a packer with a seal stinger or seal bore at a desired depth within the well bore using a hydraulic setting tool on a wireline, tubing string or the like. After the hydraulic setting tool is next retrieved from the well, an on/off tool may be lowered into the well bore on a tubing string, slid over the stinger and latched onto the top of the packer. A set of seals is typically seated inside the on/off tool to impart a fluid-tight seal between the tool and the stinger as the tool slides over the stinger and latches onto the packer. 
     After the on/off tool is latched to the packer, downward pressure may be applied to the tubing string to compress the tubing and approximate the compression dynamics of the production string. The compressed tubing string may then be marked at the well surface to indicate the approximate depth of the packer in the well bore. Next, the on/off tool may be unlatched from the packer and the tubing string retrieved from the well bore. The number and length of the subs in the production string may be “spaced out” or taken into account to determine the number of joints to be used in the production string according to the depth of the packer as indicated by the mark on the tubing string. Finally, the production string may be assembled at the well surface and an on/off tool coupled to the production string and inserted into the well bore until the on/off tool lands on the packer and is coupled thereto typically by rotation of the production string. A Christmas tree may then be assembled at the well surface to complete the well and hydrocarbons produced from the production string through the Christmas tree. 
     One of the drawbacks inherent in the conventional method of latching the on/off tool to the packer during the procedure of marking the packer depth on the tubing string is that mud, sand and other sediments tend to settle on the top of the packer and the stinger as the packer is deployed in the well bore. The presence of the sediments on top of the packer and the stinger may impede latching of the on/off tool to the packer. Consequently, repeated attempts may be required to successfully conclude the latching and marking operation as the on/off tool is raised and lowered on the stinger and makes repeated contact with the top of the packer. As the on/off tool repeatedly slides over the stinger during these attempts, the sediments tend to abrade or erode and damage the seals, necessitating frequent replacement of the seals. 
     SUMMARY 
     Illustrative embodiments of the disclosure are generally directed to an on/off tool running and well completion method. An illustrative embodiment of the method includes deploying a packer in a well bore; providing an assembly having an on/off tool and a tool spacer sleeve carried by the on/off tool; providing a tubing string; coupling the on/off tool of the assembly to the tubing string; inserting the assembly and the tubing string in the well bore; irrigating the packer by circulating packer fluid through the well bore, the assembly and the tubing string to clean the packer; determining a depth of the packer in the well bore; and latching the on/off tool of the assembly to the packer once. 
     Embodiments of the disclosure are further generally directed to an on/off tool running and well completion assembly for a tubing string. An illustrative embodiment of the assembly includes an on/off tool adapted for attachment to the tubing string, a tool spacer sleeve telescopically receiving the on/off tool and at least one breakable connection normally securing the on/off tool and the tool spacer sleeve in stationary relationship with respect to each other. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       Illustrative embodiments of the disclosure will now be described, by way of example, with reference to the accompanying drawings, in which: 
         FIG. 1  is a side view of an illustrative embodiment of an on/off tool running and well completion assembly inserted in a well casing (in longitudinal sectional view), with an on/off tool of the assembly unlatched from a packer deployed in the well casing; 
         FIG. 2  is a longitudinal sectional view of the on/off tool running and well completion assembly, inserted in the well casing (also in longitudinal sectional view) with the on/off tool of the assembly unlatched from the packer; 
         FIG. 3  is a side view of the on/off tool running and well completion assembly inserted in the well casing (in longitudinal sectional view), with the on/off tool (not illustrated) of the assembly latched to the packer; 
         FIG. 4  is a longitudinal sectional view of the on/off tool running and well completion assembly, inserted in the well casing (also in longitudinal sectional view) with the on/off tool of the assembly latched to the packer; 
         FIG. 5  is a longitudinal sectional view of the on/off tool with a seal pack seated in a seal cavity in the on/off tool; 
         FIG. 6  is a longitudinal sectional view of the on/off tool and the packer stinger with the stinger extending through the seal pack as the on/off tool is slid over the stinger and coupled to the packer (not illustrated); 
         FIG. 7A  is a side view of an exemplary tool spacer sleeve according to an illustrative embodiment of the on/off tool running and well completion assembly and method; 
         FIG. 7B  is a longitudinal sectional view of a tool spacer sleeve pinned to an on/off tool (also in longitudinal sectional view) according to an illustrative embodiment of the on/off tool running and well completion assembly and method; 
         FIG. 7C  is a longitudinal sectional view of the tool spacer sleeve unpinned from the on/off tool and the on/off tool positioned inside the tool spacer sleeve in implementation of the on/off tool running and well completion method; 
         FIG. 7D  is a longitudinal sectional view of the tool spacer sleeve unpinned from the on/off tool and suspended from the on/off tool as the on/off tool and the tool spacer sleeve of the assembly are removed from a well bore (not illustrated); 
         FIG. 8  is a sectional view of an exemplary seal pack which is suitable for the on/off tool in an illustrative embodiment of the on/off tool running and well completion assembly; 
         FIG. 9  is a schematic diagram which illustrates deployment of a packer in a well bore of a subterranean well casing according to an illustrative embodiment of the on/off tool running and well completion method; 
         FIG. 10  is a schematic diagram which illustrates insertion of an on/off tool, attached to a production string (partially in section), and a tool spacer sleeve, attached to the on/off tool, into the well bore according to an illustrative embodiment of the on/off tool running and well completion assembly; 
         FIG. 11  is a schematic diagram which illustrates engagement of the tool spacer sleeve with the deployed packer and placement of a packer depth mark on the production string at the well surface to indicate the approximate the depth of the packer in the well bore on the tubing string; 
         FIG. 12  is a schematic diagram which illustrates circulation of packer fluid through the well annulus, the tool spacer sleeve, the on/off tool and the production string, respectively, to the surface of the well bore to remove sediments from the packer top sub and the stinger of the packer preparatory to coupling the on/off tool to the packer; 
         FIG. 13A  is a schematic diagram which illustrates placement of an adjusted packer depth mark on the tubing string at the surface level of the well bore after circulation of the packer fluid is completed; 
         FIG. 13B  is a schematic diagram which illustrates partial removal of the production string from the well bore and placement of a final packer depth mark on the production string, taking into account tubing compression, “space out” of production string subs and stroke of the on/off tool, to indicate the depth of the packer in the well bore; 
         FIG. 14  is a schematic diagram which illustrates downward pressurization of the production string in the well bore to shear the connection between the on/off tool and the tool spacer sleeve and couple the on/off tool to the packer; 
         FIG. 15  is a schematic diagram which illustrates a Christmas tree assembled on the completed well and production of hydrocarbons from the tubing string through the Christmas tree; and 
         FIG. 16  is a partially schematic longitudinal sectional view illustrating the packer deployed in the well bore and the tool spacer sleeve attached to the on/off tool and engaging the packer, more particularly illustrating circulation of well circulation fluid from the well annulus through fluid flow notches in the lower end of the tool spacer sleeve, the interior of the tool spacer sleeve, the on/off tool and the production string (not illustrated) back to the well surface, respectively. 
     
    
    
     DETAILED DESCRIPTION 
     The following detailed description is merely exemplary in nature and is not intended to limit the described embodiments or the application and uses of the described embodiments. As used herein, the word “exemplary” or “illustrative” means “serving as an example, instance, or illustration.” Any implementation described herein as “exemplary” or “illustrative” is non-limiting and is not necessarily to be construed as preferred or advantageous over other implementations. All of the implementations described below are exemplary implementations provided to enable persons skilled in the art to practice the disclosure and are not intended to limit the scope of the appended claims. Moreover, the illustrative embodiments described herein are not exhaustive and embodiments or implementations other than those which are described herein and which fall within the scope of the appended claims are possible. Furthermore, there is no intention to be bound by any expressed or implied theory presented in the preceding technical field, background, brief summary or the following detailed description. Relative terms such as “upper”, “lower”, “above”, “below”, “top”, “horizontal” and “vertical” as used herein are intended for descriptive purposes only and are not necessarily intended to be construed in a limiting sense. 
     Referring initially to  FIGS. 1-8  of the drawings, an illustrative embodiment of the on/off tool running and well completion assembly, hereinafter assembly, is generally indicated by reference numeral  1 . The assembly  1  is shown inserted in a well casing  18  of a subterranean hydrocarbon production well  17  ( FIGS. 9-15 ) in exemplary implementation of the on/off tool running and well completion method, hereinafter method, which will be hereinafter described. Accordingly, a packer assembly  24  which may have a conventional design typically includes a retrievable packer  25  deployed in the well casing  18  to isolate adjacent hydrocarbon production zones (not illustrated) from each other in the well casing  18 , typically in the conventional manner, prior to completion of the well  17 . The packer  25  may be fitted with a packer top sub  26  and a packer stinger  22  which extends from the packer top sub  26 . It will be recognized and understood that while the on/off tool running and well completion assembly and method will be described herein with reference to a vertical subterranean hydrocarbon production well  17 , the assembly and method are equally applicable to horizontal and other non-vertical wells in which such designations as “top”, “bottom”, “upper” and “lower” may not necessarily apply. 
     The assembly  1  includes an on/off tool  2   a . As illustrated in  FIGS. 5 and 6 , the on/off tool  2   a  has a tool wall  2   b  which may be generally elongated and cylindrical and is traversed by a tool bore  8 . The tool wall  2   b  may include an upper tool top sub  3  and a lower stinger connection portion  5 . In implementation of the method, which will be hereinafter described, the tool top sub  3  facilitates connection of the on/off tool  2   a  to a production string  28   a  ( FIGS. 10-15 ) and the stinger connection portion  5  facilitates coupling of the on/off tool  2   a  to the packer stinger  22  ( FIGS. 1-4 ) on the packer  25 . The on/off tool  2   a  may additionally include at least one exterior pin seat  6  which may be generally at the lower portion of the stinger connection portion  5  for purposes which will be hereinafter described. A circumferential tool lip  2   c  may extend from the exterior surface of the tool wall  2   b , generally adjacent to the pin seat or seats  6 , for purposes which will be hereinafter described. In some embodiments, a pair of diametrically-opposed stinger slots  9  may be provided in the stinger connection portion  5  of the on/off tool  2   a  to facilitate attachment of the on/off tool  2   a  to the packer stinger  22  ( FIGS. 2 and 4 ) as will be hereinafter described. A seal cavity  4  may be included in the tool bore  8  of the on/off tool  2   a  generally between the tool top sub  3  and the stinger connection portion  5 . 
     As further illustrated in  FIGS. 5 and 6 , a seal pack  50  is seated in the seal cavity  4  of the on/off tool  2   a . As illustrated in  FIG. 6 , in implementation of the method, the seal pack  50  receives the packer stinger  22  as the on/off tool  2   a  approaches the packer top sub  26  ( FIGS. 1-4 ) of the packer  25  preparatory to latching of the on/off tool  2   a  to the packer stinger  22 . The seal pack  50  imparts a fluid-tight and gas-tight seal between the interior surface of the on/off tool  2   a  and the exterior surface of the packer stinger  22 . The design and composition of the seal pack  50  resist abrasion imparted by sediments which may be present on the packer stinger  22  and/or the packer top sub  26  as the on/off tool  2   a  descends on the packer stinger  22 . 
     An exemplary seal pack  50  which is suitable for the on/off tool  2   a  is illustrated in  FIG. 8 . The seal pack  50  may include a pair of outer backup seals  51   a ,  51   b  at opposite ends of the seal pack  50 . Each outer backup seal  51   a ,  51   b  may have a generally flat or planar, annular outer seal surface  52  and an annular inner seal groove  53  which may have a generally V-shaped cross-section. In some embodiments, each outer backup seal  51   a ,  51   b  may include corrosion-resistant steel, for example and without limitation. 
     Outer V-packing seals  56   a ,  56   b  may seat against the respective outer backup seals  51   a ,  51   b . Each outer V-packing seal  56   a ,  56   b  may include an annular outer seal lip  57  which inserts in the companion seal groove  53  of the corresponding outer backup seal  51   a ,  51   b . Each outer V-packing seal  56   a ,  56   b  may also include a pair of concave, angled or tapered inner seal surfaces  58  and an annular seal groove  59  which is at the inner terminus of the inner seal surfaces  58  and may have a generally U-shaped cross-section. In some embodiments, each V-packing seal  56   a ,  56   b  may include virgin PEEK (polyether ether ketone), for example and without limitation. 
     Jacket seals  62   a ,  62   b  may seat against the respective outer V-packing seals  56   a ,  56   b . Each jacket seal  62   a ,  62   b  may include a pair of convex tapered outer jacket seal surfaces  63  which engage the respective inner seal surfaces  58  of the corresponding V-packing seal  56   a ,  56   b . An annular jacket seal lip  64  may extend from the outer jacket seal surfaces  63  and inserts in the companion inner seal groove  59  of the corresponding outer V-packing seal  56   a ,  56   b . Each jacket seal  62   a ,  62   b  may further include an annular outer jacket seal wall  65 , an annular inner jacket seal wall  66  and an annular seal groove  67  which is between the outer jacket seal wall  65  and the inner jacket seal wall  66  and may have a generally U-shaped cross-section. A seal groove spring  68  may line the interior surface of the seal groove  67 . In some embodiments, each jacket seal  62   a ,  62   b  may include PTFE (polytetrafluoroethylene), for example and without limitation. Each seal groove spring  68  may be nickel-cobalt alloy, for example and without limitation. 
     Seal rings  70   a ,  70   b  may seat against the respective jacket seals  62   a ,  62   b . Each Seal ring  70   a ,  70   b  may include an annular ring seal lip  71  which inserts into the companion seal groove  67  of the corresponding jacket seal  62   a ,  62   b  and an annular inner seal surface  72  which may be generally flat or planar. In some embodiments, each seal ring  70   a ,  70   b  may include corrosion-resistant steel, for example and without limitation. 
     Backup seals  76   a ,  76   b  may seat against the respective seal rings  70   a ,  70   b . Each backup seal  76   a ,  76   b  may include a generally flat or planar, annular outer seal surface  77  which engages the inner seal surface  72  of the corresponding seal ring  70   a ,  70   b . Each backup seal  76   a ,  76   b  may further include a pair of annular, concave, tapered inner seal surfaces  78  and an annular seal groove  79  which is at the inner terminus of the inner seal surfaces  78  and may have a generally U-shaped cross-section. In some embodiments, each middle jacket seal  76   a ,  76   b  may include virgin PEEK, for example and without limitation. 
     Jacket seals  82   a ,  82   b  may seat against the respective backup seals  76   a ,  76   b . Each jacket seal  82   a ,  82   b  may have a construction and composition which are the same as or similar to those of the jacket seals  62   a ,  62   b , where like reference numerals designate like elements. The jacket seal lip  64  of each jacket seal  82   a ,  82   b  may insert into the companion seal groove  79  of the corresponding backup seal  76   a ,  76   b.    
     Seal rings  84   a ,  84   b  may seat against the respective jacket seals  82   a ,  82   b . Each seal ring  84   a ,  84   b  may have a construction and composition which are the same as or similar to those of the seal rings  70   a ,  70   b , where like reference numerals designate like elements. The ring seal lip  71  of each seal ring  84   a ,  84   b  may insert into the companion seal groove  67  of the corresponding adjacent jacket seal  82   a ,  82   b.    
     Backup seals  86   a ,  86   b  may seat against the respective seal rings  84   a ,  84   b . Each backup seal  86   a ,  86   b  may have a construction and composition which are the same as or similar to those of the backup seals  76   a ,  76   b , where like reference numerals designate like elements. The outer seal surface  77  of each backup seal  86   a ,  86   b  may engage the inner seal surface  72  of the corresponding adjacent seal ring  84   a ,  84   b.    
     Jacket seals  88   a ,  88   b  may seat against the respective backup seals  86   a ,  86   b . Each jacket seal  88   a ,  88   b  may have a construction and composition which are the same as or similar to those of the jacket seals  82   a ,  82   b , where like reference numerals designate like elements. The jacket seal lip  64  of each jacket seal  88   a ,  88   b  may insert into the companion seal groove  79  of the corresponding adjacent backup seal  86   a ,  86   b.    
     Seal rings  90   a ,  90   b  may seat against the respective jacket seals  88   a ,  88   b . Each seal ring  90   a ,  90   b  may have a construction and composition which are the same as or similar to those of the seal rings  84   a ,  84   b , where like reference numerals designate like elements. The ring seal lip  71  of each seal ring  90   a ,  90   b  may insert into the companion seal groove  67  of the corresponding jacket seal  88   a ,  88   b.    
     Innermost jacket seals  92   a ,  92   b  may seat against the respective seal rings  90   a ,  90   b . Each innermost jacket seal  92   a ,  92   b  may have a generally flat or planar, annular outer seal surface  93  which engages the inner seal surface  72  of the corresponding seal ring  70   a ,  70   b . Each innermost jacket seal  92   a ,  92   b  may further include an annular inner seal wall  94 , an annular outer seal wall  95  and an annular seal groove  96  between the inner seal wall  94  and the outer seal wall  95 . An annular seal groove spring  97  may line the interior surface of the seal groove  96 . In some embodiments, each innermost jacket seal  92   a ,  92   b  may include PTFE (polytetrafluoroethylene), for example and without limitation. Each seal groove spring  97  may include nickel-cobalt alloy, for example and without limitation. 
     Innermost seal rings  100   a ,  100   b  may seat against the respective innermost jacket seals  92   a ,  92   b . Each innermost seal ring  100   a ,  100   b  may have a construction and composition which are the same as or similar to those of the seal rings  84   a ,  84   b , where like reference numerals designate like elements. The ring seal lip  71  of each seal ring  100   a ,  100   b  may insert into the companion seal groove  96  of the corresponding innermost jacket seal  92   a ,  92   b . The inner ring surface  72  of each innermost seal ring  100   a ,  100   b  may engage the inner ring surface  72  of the adjacent innermost seal ring  100   a ,  100   b.    
     It will be appreciated by those skilled in the art that the seal pack  50  may include at least one pair of jacket seals, at least one pair of seal rings and at least one pair of backup seals, respectively. Therefore, it will be recognized and understood that the foregoing described arrangement and number of the jacket seals, the seal rings and the backup seals in the seal pack  50  serves as a non-limiting example among many possible arrangements of these elements in the seal pack  50 . In some non-limiting illustrative embodiments, one or more pairs of the jacket seals, the seal rings and the backup seals may be omitted from the seal pack  50 . In still other embodiments, the seal pack  50  may include additional pairs of the jacket seals, the seal rings and the backup seals. 
     As illustrated in  FIGS. 7A-7D  of the drawings, the assembly  1  further includes a tool spacer sleeve  10   a  which is initially attached to the on/off tool  2   a  through at least one breakable connection, as illustrated in  FIG. 7B , in implementation of the method. The tool spacer sleeve  10   a  includes a spacer sleeve wall  11  which may be generally elongated and cylindrical and has an upper sleeve end  13   a  and a lower sleeve end  14 . A spacer sleeve bore  12  traverses the spacer sleeve wall  11  from the upper sleeve end  13   a  to the lower sleeve end  14 . A sleeve lip  13   b  may protrude from the inner surface of the spacer sleeve wall  11  into the spacer sleeve bore  12  generally at the sleeve upper end  13   a . At least one fluid flow notch  15  may be provided in the sleeve lower end  14  for purposes which will be hereinafter described. 
     As illustrated in  FIG. 7B , in implementation of the method, the on/off tool  2   a  is initially attached to the tool spacer sleeve  10   a  through at least one breakable connection which normally secures the on/off tool  2   a  in stationary relationship with respect to the tool spacer sleeve  10   a . The on/off tool  2   a  may be partially disposed or telescopically received in the spacer sleeve bore  12  and protrude from the sleeve upper end  13   a . The on/off tool  2   a  may be attached to the tool spacer sleeve  10   a  according to any breakable connection which is suitable for the purpose. In some embodiments, at least one pin seat  6  may be provided typically in the exterior surface of the stinger connection portion  5  of the on/off tool  2   a . At least one pin opening  10   b  ( FIG. 7A ) may extend through the spacer sleeve wall  11  and the sleeve lip  13   b  of the tool spacer sleeve  10   a . At least one sleeve pin  16  may extend through each pin opening  10   b  in the tool spacer sleeve  10   a  and is normally seated in the corresponding registering pin slot  6  in the on/off tool  2   a  to attach the on/off tool  2   a  to the tool spacer sleeve  10   a . A tool seal (not illustrated) may be interposed between the exterior surface of the stinger connection portion  5  of the on/off tool  2   a  and the interior surface of the tool spacer sleeve  10   a.    
     Also in implementation of the method, as will be hereinafter described, the on/off tool  2   a  is latched to the packer stinger  22  ( FIGS. 1-4 ) of the packer  25 . Accordingly, as illustrated in  FIG. 7B , a predetermined magnitude of downward pressure  44  may be applied to the on/off tool  2   a  to shear the sleeve pins  16  ( FIG. 7B ) and displace the on/off tool  2   a  downwardly in the spacer sleeve bore  12 , as illustrated in  FIG. 7C , and onto the packer stinger  22  to latch the on/off tool  2   a  to the packer stinger  22 . Alternative techniques other than the sleeve pins  16  which are known by those skilled in the art and consistent with the functional requirements of the assembly  1  may be used to attach the on/off tool  2   a  to the tool spacer sleeve  10   a  in such a manner that application of the predetermined magnitude of pressure  44  ( FIG. 7C ) to the on/off tool  2   a  compromises a mechanical connection between the top sub  2  and the tool spacer sleeve  10   a  and causes detachment of the on/off tool  2   a  from the tool spacer sleeve  10   a.    
     As illustrated in  FIG. 7D , under some circumstances it may be desirable to retrieve the assembly  1  from a hydrocarbon production well  17  ( FIG. 9 ) in which the assembly  1  is deployed. Therefore, the on/off tool  2   a  can be detached from the stinger  22  typically in the conventional manner and lifted from the well  17  with the tool spacer sleeve  10   a  on a production string  28   a  ( FIGS. 10-15 ) to which the assembly  1  is attached. As the on/off tool  2   a  travels upwardly with respect to the initially stationary tool spacer sleeve  10   a , the tool lip  2   c  on the on/off tool  2   a  engages the sleeve lip  13   b  on the interior of the tool spacer sleeve  10   a . Thus, the tool spacer sleeve  10   a  is suspended from the rising on/off tool  2   a  as the production string  28   a  carries the on/off tool  2   a  and the tool spacer sleeve  10   a  of the assembly  1  out of the well  17 . 
     Referring next to  FIGS. 9-16  of the drawings, sequential implementation of an illustrative embodiment of the method is illustrated. As illustrated in  FIG. 9 , the hydrocarbon production well  17  may include a subterranean well casing  18  having a well bore  19 . While the well casing  18  illustrated in  FIG. 9  is vertical, in some applications the well casing  18  may be disposed in a horizontal or other non-vertical orientation. The packer  25  and packer stinger  22  may be deployed in the well bore  19  at a desired depth to isolate hydrocarbon production zones (not illustrated) from each other in the well bore  19  prior to completion of the well  17 . Accordingly, the packer  25  may be deployed in the well bore  19 , with the packer stinger  22  extending from the packer  25 , using a hydraulic setting tool  35  provided on a wireline  30  or a tubing string  30  or the like, typically in the conventional manner. 
     Upon subsequent retrieval of the wireline  30  from the well bore  19 , the packer  25  and packer stinger  22  remain in the well bore  19 , as illustrated in  FIG. 10 . The tool top sub  3  on the on/off tool  2   a  of the assembly  1  may be attached to a production string  28   a  via threading or other suitable method. The tool spacer sleeve  10   a  may be attached to the on/off tool  2   a  using the sleeve pin or pins  16 , such as was heretofore described with respect to  FIG. 7B , or suitable alternative attachment technique. In some embodiments, the production string  28   a  may be a conventional multi-segmented or jointed tubing string in which the production string  28   a  is assembled at the well surface by operation of a rotary table (not illustrated) typically in the conventional manner. 
     As illustrated in  FIG. 11 , the production string  28   a  may be initially assembled at the well surface and inserted into the well bore  19  until the assembly  1  is proximate to the packer  25 . In some embodiments, the production string  28   a  may be initially assembled and inserted into the well bore  19  until the tool spacer sleeve  10   a  of the assembly  1  reaches a selected proximity to the packer  25 , after which further assembly and insertion of the production string  28   a  may be temporarily halted. Assembly and insertion of the production string  28   a  may then be resumed very slowly until the tool spacer sleeve  10   a  lightly tags the packer top sub  26  ( FIGS. 1-4 ) of the packer  25 . At that point, a packer depth mark  31  may be placed on the production string  28   a  at the surface level of the well bore  19  (or at some other reference level) to indicate the approximate depth of the packer  25  in the well bore  19 . As the tool spacer sleeve  10   a  is lowered in place on the packer top sub  26 , the spacer sleeve bore  12  ( FIG. 7A ) of the tool spacer sleeve  10   a  receives the packer stinger  22 . 
     During deployment of the packer  25  in the well bore  19  ( FIG. 9 ), sand, dirt and other sediments (not illustrated) may cover the packer top sub  26  and the packer stinger  22 . Thus, as illustrated in  FIG. 12 , packer fluid  34  may be used to irrigate and clean the sediments from the packer top sub  26  and the packer stinger  22  before the on/off tool  2   a  is coupled to the packer stinger  22 . Accordingly, as illustrated in  FIG. 16 , as the sleeve lower end  14  of the tool spacer sleeve  10   a  contacts the packer top sub  26  of the packer  25 , the fluid flow notches  15  in the sleeve lower end  14  of the tool spacer sleeve  10   a  establish fluid communication between the well annulus  20  and the interior of the tool spacer sleeve  10   a , the on/off tool  2   a  and the production string  28   a . The packer fluid  34  may next be circulated from the well surface downwardly through the well annulus  20  and the fluid flow notches  15  and then upwardly through the tool space sleeve  10 , the on/off tool  2   a  and the production string  28   a  back to the well surface, respectively. As it flows through the fluid flow notches  15  and upwardly through the tool space sleeve  10 , the packer fluid  34  cleans the sediments (not illustrated) from the surface of the packer sub  26  and the stinger  22 . 
     As further illustrated in  FIG. 12 , throughout circulation of the packer fluid  34 , downward pressure  44  may be applied to the tool spacer sleeve  10   a  via the production string  28   a  and the on/off tool  2   a  to ensure that the packer fluid  34  contacts and substantially removes the sediments from the packer top sub  26 . In some embodiments, the downward pressure  44  may have a magnitude of about 1˜4000 lbs, although pressures which are greater than 4000 lbs. may be used in some applications. Therefore, the sleeve pins  16  ( FIG. 7B ) or other attachment mechanism which attaches the on/off tool  2   a  to the tool spacer sleeve  10   a  may have a shear strength which is greater than the downward pressure  44  to withstand pressurization of the production string  28   a  during circulation of the packer fluid  34 . 
     As illustrated in  FIG. 13A , upon conclusion of the packer fluid circulation operation ( FIG. 12 ), the position of the packer depth mark  31  which was previously made on the production tubing  28  ( FIG. 11 ) on the tubing string  30  relative to the surface of the well bore  19  or other reference level may be checked since circulation of the packer fluid  34  may have removed sediments from the top of the packer  25  and caused the production string  28   a  to settle in the well bore  19 . In the event that the original packer depth mark  31  falls below the surface of the well bore  19  or other reference level due to settling of the production string  28   a , the packer depth mark  31  may be erased and an adjusted packer depth mark  32  may be placed on the production string  28   a  at the well bore surface or other reference level to more accurately indicate the depth of the packer  25  in the well bore  19  on the production string  28   a.    
     Prior to latching the on/off tool  2   a  to the packer stinger  22 , it may be necessary to determine the length of the production string  28   a  which is required to land the on/off tool  2   a  on the packer stinger  22 . Thus, the length of the production string  28   a  which is necessary to lightly land the on/off tool  2   a  on the packer stinger  22  may be calculated. Accordingly, as illustrated in  FIG. 13B , some of the top tubing, joints  28   b  may be disassembled from the top of the production string  28   a  to raise the assembly  1  from the top packer sub  26  of the packer  25 . The required length of the production string  28   a  is then calculated, the calculated length of the production string  28   a  taking into account desired tubing compression due to the depth of the packer  25  in the well bore  19 , “space out” of subs and other tubing string elements in the production string,  28   a  and the stroke distance of the on/off tool  2   a  through the tool spacer sleeve  10   a  as it is displaced from the pinned position ( FIG. 7B ) to the landed or latched position on the packer stinger  22 . These calculations may be made using tubing compression and space-out calculation methods which are known by those skilled in the art. When the required length of the production string  28   a  has been calculated, a final packer depth mark  38  may be made on the production string  28   a . The final packer depth mark  38  may correspond to the level of the surface of the well bore  19  or other reference level when the on/off tool  2   a  lands on the packer stinger  22 . 
     As illustrated in  FIG. 14 , the production string  28   a  may be assembled and inserted into the well bore  19  initially until the adjusted packer depth mark  32  reaches the surface of the wellbore  19  or other reference level, thus indicating that the tool spacer sleeve  10   a  has landed on the packer top sub  26  of the packer  25 . Next, a sufficient magnitude of downward pressure  45  is applied to the production string  28   a  to shear the sleeve pins  16  ( FIG. 7B ) or other attachment mechanism which attaches the on/off tool  2   a  the tool spacer sleeve  10   a . As the location of the final packer depth mark  38  is noted, the production string  28   a  is slowly inserted into the well bore  19  until the final packer depth mark  38  reaches the surface of the well bore  19  or other reference level, thus indicating that the on/off tool  2   a  has landed on and latched to the packer stinger  22 . 
     The production string  28   a  may be pulled upwardly in the well bore  19  and then slacked to ensure that the on/off tool  2   a  has been latched to the packer stinger  22 . As illustrated in  FIG. 15 , the production string  28   a , suspended from a tubing hanger  36 , may be installed typically in the conventional manner. The well annulus  20  and the production string  28   a  may be tested to ensure a proper seal imparted by the seal pack  50  ( FIG. 6 ) between the inner surface of the on/off tool  2   a  and the outer surface of the packer stinger  22 . A Christmas tree  40  may be installed to facilitate production of hydrocarbons  42  from the well bore  19  typically in the conventional manner. 
     After the hydrocarbon production zone which is serviced by the production string  28   a  has been depleted or in the event that the well  17  requires service, the assembly  1  may be removed from the well bore  19  and the method may be repeated with respect to another hydrocarbon production zone in the well  17 . As illustrated in  FIG. 7D  and was heretofore described, it will be appreciated by those skilled in the art that upon retrieval of the production string  28   a  from the well bore  19 , the sleeve lip  13   b  on the tool spacer sleeve  10   a  engages the pin seat or pin seats  6  in the stinger connection portion  5  of the on/off tool  2   a . Thus, the tool spacer sleeve  10   a  may be suspended from the on/off tool  2   a  and carried out of the well bore  19  with the on/off tool  2   a  as the production string  28   a  is extracted from the well bore  19 . 
     It will be appreciated by those skilled in the art that the on/off tool running and well completion method facilitates coupling of a production string  28   a  to a packer  25  once without the need to repeatedly tag the packer stinger  22  with the on/off tool  2   a  (in which the seal pack  50  is installed) during the tubing string latching and marking operation. Consequently, the structural integrity of the on/off tool  2   a , the packer stinger  22  and the seals in the seal pack  50  is substantially preserved since damage or abrasion to these elements by sediments is prevented or minimized. This results in substantial cost savings which may otherwise be required in repair or replacement of the on/off tool  2   a , the packer stinger  22  and/or the seal pack  50 , as well as enhanced sealing capability of the seal pack  50  between the interior surface of the on/off tool  2   a  and the exterior surface of the packer stinger  22 . 
     While illustrative embodiments of the disclosure have been described above, it will be recognized and understood that various modifications can be made and the appended claims are intended to cover all such modifications which may fall within the spirit and scope of the disclosure.