Patent Publication Number: US-2006006648-A1

Title: Tubular goods with threaded integral joint connections

Description:
RELATED APPLICATION  
      This application claims the benefit of U.S. Provisional Patent Application entitled “Tubular Goods With Threaded Integral Joint Connections”, Ser. No. 60/610,321 filed, Sep. 16, 2004, the contents of which are hereby incorporated by reference in their entirety.  
      This application claims the benefit of U.S. Provisional Patent Application entitled “Tubular Goods With Threaded Integral Joint Connections”, Ser. No. 60/620,182 filed, Oct. 19, 2004, the contents of which are hereby incorporated by reference in their entirety.  
      This application is a U.S. Continuation-In-Part patent application based on pending application entitled “Tubular Goods With Expandable Threaded Connections” Ser. No. 10/382,625, filing date Mar. 6, 2003 entitled “Tubular Goods With Expandable Threaded Connections” now U.S. Pat. No. ______.  
      This application is a copending application to the divisional patent application entitled, “Tubular Goods with Expandable Threaded Connections”, Ser. No. 10/828,069, filed Apr. 20, 2004, which is a divisional application of the patent application entitled “Tubular Goods With Expandable Threaded Connections”, Ser. No. 10/382,625, filing date Mar. 6, 2003 entitled “Tubular Goods With Expandable Threaded Connections” now U.S. Pat. No. ______.  
    
    
     TECHNICAL FIELD  
      The present invention is related to tubular members and more particularly to oil country tubular goods having integral joints with threaded connections.  
     BACKGROUND OF THE INVENTION  
      Wellbores for producing oil, gas or other fluids from selected subsurface formations, are typically drilled in stages. For example, a wellbore may be drilled with a drill string and a first drill bit having a first diameter. At a desired depth for a first portion of the wellbore, the drill string and drill bit are removed from the wellbore. Tubular members of smaller diameter, often referred to as casing or a casing string, placed in the first portion of the wellbore. An annulus formed between the inside diameter of the wellbore and the outside diameter of the casing is filled with cement. The cement provides support for the casing and isolates subsurface formations or strata from each other. Many wellbores are completed with relatively large diameter casing located near the well surface and smaller diameter casing extending therefrom in a telescoping or stair step pattern to a downhole location.  
      Very deep and/or very long wells, sometimes referred to as extended reach wells (20,000 feet or greater), may have three or four changes in casing diameter from the well surface to total depth of the wellbore. Each change in casing diameter often results in decreasing the diameter of associated production tubing used to produce formation fluids. Changes in casing diameter associated with deep wells and/or long wells often result in significantly increased drilling and well completion costs. A number of oil and gas wells have been completed using solid, expandable casing. Electric resistant welded (ERW) pipe has frequently been used to form such casing.  
     SUMMARY OF THE INVENTION  
      In accordance with teachings of the present invention, solid, radially expandable tubular goods with threaded connections are provided to complete wellbores. One aspect of the present invention includes providing threaded connections which may be used with integral joints to releasably engage tubular goods with each other and to accommodate downhole, radial expansion of the tubular goods during completion of a wellbore. The threaded connections and associated integral joints preferably maintain desired fluid tight seals and mechanical strength after such radial expansion. Integral joints and associated threaded connections formed in accordance with teachings of the present invention may also be used with tubular goods which are not designed for radial expansion in a wellbore.  
      Tubular members may be formed with either flush type integral joints or swage type integral joints having threaded connections formed in accordance with teachings of the present invention. Each threaded connection may include a pin end of a first tubular member and a box end of a second tubular member releasably engaged with each other. For some applications the threaded connections may include modified buttress type thread forms or thread profiles with positive stab flank angles and negative load flank angles. The tubular members and associated threaded connections may be formed using materials and techniques selected to allow radial expansion at downhole locations in a wellbore.  
      For some well completions the pin end and box end of each tubular member may be formed with substantially the same nominal outside diameter. The combined wall thickness of each threaded connection may be substantially the same as the nominal wall thickness of the tubular members. A string or series of tubular members releasably engaged with each other by threaded connections formed in accordance with teachings of the present invention may have a generally uniform inside diameter and a generally uniform outside diameter. Such threaded connections may be described as “flush joints.” 
      For other well completions each tubular member may be formed with a box end having a nominal outside diameter larger than the nominal outside diameter of the associated tubular member. Each tubular member may have a pin end with a tapered outside diameter equal to less than the nominal outside diameter of the associated tubular member. The inside diameter of the box end of each tubular member is preferably selected to accommodate the tapered outside diameter of the pin end of another tubular member. The combined wall thickness of each threaded connection may be larger than the nominal wall thickness of the respective tubular members. A string or series of tubular members releasably engaged with each other by threaded connections formed in accordance of teachings of the present invention may have a generally uniform inside diameter except for a respective annular recess formed proximate each thread connection. The outside diameter of the string or series of tubular members may be relatively uniform except for the increased outside diameter of each box end proximate each threaded connection. Such threaded connections may sometimes be described as “swage joints.” 
      Technical benefits of the present invention include providing solid, radially expandable tubular members with threaded connections that substantially reduce or eliminate requirements for telescoping or tapering of a wellbore from an associated well surface to a desired downhole location. The threaded connections preferably maintain both desired mechanical strength and fluid tight integrity during radial expansion of the tubular members and associated threaded connections. Thread profiles formed in accordance with teachings of the present invention may be treated by blasting with fine grains of sand (sometimes referred to as sugar blasting) to reduce or minimize potential galling between threaded surfaces.  
      For some applications one or more thread profiles may be coated or plated with a layer of tin, tin alloys, zinc or other materials selected to help maintain fluid tight seals between respective thread profiles of associated pin members and box members. Heat and pressure generated during radial expansion of tubular members and associated threaded connections may cause such materials to flow into any void spaces resulting from expansion of the threaded connections.  
      For one embodiment each threaded connection may include thread profiles with five buttress type threads per inch and a taper of approximately three fourths of an inch per foot. For another embodiment each treaded connection may include thread profiles with six buttress type threads per inch and a taper of approximately one and one fourth inches per foot.  
      A pin end associated with each threaded connection may have a respective chamfer formed at an angle of approximately fifteen degrees (15°) and sized to satisfactorily engage a respective shoulder formed on the interior of an associated box end at a corresponding angle of approximately fifteen degrees (15°). Each thread form may have load flank angles of approximately minus five degrees or negative five degrees (−5°) and stab flank angles of approximately positive twenty-five degrees or plus twenty-five degrees (+25°).  
      For some embodiments each thread formed may have load flank angles of approximately minus five degrees or negative five degrees (−5°) and stab flank angles of approximately positive ten degrees or plus ten degrees (+10°). A pin end associated with each threaded connection may terminate with an end surface or extreme end extending approximately normal to the longitudinal axis of an associated first tubular member. A first chamfer may be formed on the inside diameter of each pin end proximate the respective extreme end. The pin end may be sized to satisfactorily engage an associated box end. A tapered sealing surface extending from the extreme end of each pin end may engage a corresponding tapered sealing surface formed within the associated box end for use in forming a fluid barrier disposed therebetween. The box end associated with each threaded connection may also terminate with an end surface or extreme end extending approximately normal to the longitudinal axis of an associated second tubular member. A second chamfer may be formed on the outside diameter of each box end proximate the extreme end. The extreme end of the box end may be sized to engage a respective shoulder disposed on the exterior of the first tubular member. The shoulder may be spaced longitudinally from the extreme end of the associated pin end.  
      Radially expandable tubular goods formed in accordance with teachings of the present invention may allow wells to be completed to relatively deep geological locations or at extended distances from a production platform which may have been difficult and/or expensive to reach using traditional well drilling and casing technology. The use of solid, radially expandable tubular goods with threaded connections may allow wellbores to be drilled and completed with only one size of casing extending from a well surface to a relatively deep downhole location and/or extended reach location. As a result of requiring only one or two sizes of casing to complete a wellbore, surface equipment, associated drilling rigs, drill strings and bit sizes may be standardized to significantly reduce costs.  
      For some applications tubular members with integral joint connections formed in accordance with teachings of the present invention may be radially expanded by as much as twenty percent (20%) of their original outside diameter and satisfactorily hold as much as three thousand five hundred pounds per square inch (3,500 psi) of internal fluid pressure after such expansion. Integral joint connections formed in accordance with teachings of the present invention may provide required mechanical strength to complete deep and/or extended reach wellbores and provide required fluid, pressure tight seals between the interior and the exterior of associated tubular members.  
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
      A more complete and thorough understanding of the present invention and advantages thereof may be acquired by referring to the following description taken in conjunction with the accompanying drawings, in which like reference numbers indicate like features, and wherein:  
       FIG. 1A  is a schematic drawing in section and in elevation with portions broken away of a first tubular member having a pin end and a box end with respective threaded portions and sealing surfaces formed in accordance with teachings of the present invention;  
       FIG. 1B  is an enlarged schematic drawing in section with portions broken away of the pin end of the tubular member of  FIG. 1A ;  
       FIG. 1C  is an enlarged schematic drawing in section with portions broken away of the box end of the tubular member of  FIG. 1A ;  
       FIG. 2  is a schematic drawing in section with portions broken away showing a second tubular member aligned with the first tubular member of  FIG. 1A  prior to releasable engagement with each other in accordance with teachings of the present invention;  
       FIG. 3  is a schematic drawing in section with portions broken away showing the box end of the second tubular member releasably engaged with the pin end of the first tubular member in a hand tight position prior to forming a swage type integral joint connection;  
       FIG. 4  is a schematic drawing in section with portions broken away showing the box end of the second tubular member releasably engaged with the pin end of the first tubular member to form the swage type integral joint connection in accordance with teachings of the present invention;  
       FIG. 5A  is a schematic drawing in section and in elevation with portions broken away showing a first tubular member having a pin end and a box end with respective threaded portions and sealing surfaces formed in accordance with teachings of the present invention;  
       FIG. 5B  is an enlarged schematic drawing in section with portions broken away of the pin end of the tubular member of  FIG. 5A ;  
       FIG. 5C  is an enlarged schematic drawing in section with portions broken away of the box end of the tubular member of  FIG. 5A ;  
       FIG. 6  is a schematic drawing in section with portions broken away of a second tubular member aligned with the first tubular member of  FIG. 5A  prior to releasable engagement with each other in accordance with teachings of the present invention;  
       FIG. 7  is a schematic drawing in section with portions broken away showing the box end of the second tubular member releasably engaged with the pin end of the first tubular member in a hand tight position prior to forming a flush type integral joint connection in accordance with the teachings of the present invention;  
       FIG. 8  is a schematic drawing in section with portions broken away showing the box end of the second tubular member releasably engaged with the pin end of the first tubular member in a power tight position to form the flush type integral joint connection;  
       FIG. 9  is a schematic drawing in section with portions broken away showing an enlarged view of a threaded connection with at least one threaded portion having a layer of tin or other malleable coating disposed thereon in accordance with teachings of the present invention; and  
       FIG. 10  is a schematic drawing in section with portions broken away showing an enlarged view of the threaded connection of  FIG. 9  after radial expansion.  
    
    
     DETAILED DESCRIPTION OF THE INVENTION  
      Preferred embodiments of the invention and its advantages are best understood by reference to  FIGS. 1A-10  wherein like numbers refer to same and like parts.  
      The terms “oil country tubular goods” and “OCTG” are used in this application to include casing, tubing, pup joints, couplings and any other type of pipe or tubular member associated with drilling, producing or servicing oil wells, natural gas wells, geothermal wells or any other subsurface wellbore. Threaded connections incorporating teachings of the present invention may be formed on a wide variety of oil country tubular, both expandable and nonexpandable goods.  
      The terms “welded pipe” and “welded tubular goods” are used in this application to include any pipe, tubular member or coupling manufactured from flat rolled steel or steel strips which passed through equipment designed to create a longitudinal butt joint and was welded along the longitudinal butt joint. A line of forming rollers may be used to create such longitudinal butt joints. The resulting longitudinal butt weld or longitudinal seam weld may be formed using various techniques such as electric resistance welding (ERW), arc welding, laser welding, high frequency induction welding and any other techniques satisfactory for producing longitudinal seam welds. Welded pipe and welded tubular goods may be produced in individual links or may be produced in continuous links from coiled skelp and subsequently cut into individual links.  
      The terms “flush joint” and “flush type connection” are used in this application to describe a threaded connection formed between two, hollow tubular members with both tubular members having approximately the same nominal outside diameter, inside diameter and wall thickness. The outside diameter, inside diameter and combined wall thickness of the threaded connection are also approximately equal to the corresponding dimensions of the tubular members.  
      The terms “swage joint” and “swage type connection” may be used in this application to describe a threaded connection formed between two, hollow tubular members. Each tubular member may have a respective box end and pin end. Each box end may have an outside diameter larger than a nominal outside diameter of the associated tubular member. The interior dimensions and configuration of each box end are preferably selected to be compatible with corresponding exterior dimensions and configuration of an associated pin end. The outside diameter of the resulting threaded connection will generally be larger than the nominal outside diameter of the associated tubular members. The inside diameter of the threaded connection will generally be approximately equal to the nominal inside diameter of the associated tubular members except for an annular recess which may be formed proximate the extreme end of the associated pin end. The combined wall thickness of the threaded connection may be larger than the nominal wall thickness of the associated tubular members.  
      The term “integral joint” may be used to describe a threaded connection formed between two hollow tubular members without the use of a coupling or any other device. Examples of such integral joints include, but are not limited to, threaded flush joints and threaded swage joints.  
      Various aspects of the present invention will be described with respect to radially expandable tubular members which have been formed using electric resistant welding (ERW) technology. However, the present invention is not limited to use with radially expandable tubular members produced by ERW technology. A wide variety of other tubular members and oil country tubular goods (OCTG) may be releasably engaged with each other by threaded connections formed in accordance with teachings of the present invention.  
      ERW technology often allows better quality control of wall thickness associated with welded pipe and minimizes material defects. Tubular members formed in accordance with teachings of the present invention from ERW pipe may have better performance characteristics, such as mechanical strength and fluid tight integrity, after radial expansion as compared with tubular members formed from seamless pipe. However, threaded connections and integral joints formed in accordance with teachings of the present invention are not limited to use on tubular goods formed from ERW pipe.  
      Various aspects of the present invention will be discussed with respect to tubular members  20  and  120  as shown in  FIGS. 1A-10 . To describe some features of the present invention, tubular members  20  and  120  may sometimes be designated as  20   a ,  20   b ,  120   a  and  120   b.    
      For some applications, tubular members  20  and  120  may be sections of a casing string used to complete a wellbore (not expressly shown). Tubular members  20  and  120  may have some overall dimensions and configurations compatible with a conventional oil field casing string. For other applications, various types of downhole well completion tools (not expressly shown) may have threaded portions corresponding with threaded portions of tubular members  20  and/or  120 . For example, a liner hanger (not expressly shown) may be formed with a pin end and/or a box end having dimensions corresponding respectively with the pin end or the box end of tubular members  20  or  120 .  
       FIGS. 1A-10  generally show pin end  21  of tubular members  20  and pin end  121  of tubular members  120  in an “up” position and box  22  of tubular members  20  and box end  122  of tubular member  120  in a “down” position. Generally, tubular members such as drill strings, casing and production tubing are inserted or run into a wellbore with the box end looking up and the pin end directed down. Box end “up” is often preferred for making and breaking threaded connections associated with OCTG. As discussed later in more detail, tubular members  20  and  120  may be oriented with respective pin ends  21  and  121  in an “up” position to aid in radial expansion of tubular member  20  and  120  at a selected downhole location in a wellbore. However, tubular goods having threaded connections incorporating teachings of the present invention may be installed in a wellbore with either box end “up” or pin end “up” as required for each well completion.  
      Threaded portions  31  and  131  formed on respective pin ends  21  and  121  preferably have external thread profiles. Threaded portions  32  and  132  formed within respective box ends  22  and  122  preferably have internal thread profiles which may be releasably engaged with another tubular member having a pin end with threaded portion  31  or  131 . Threaded portions  31 ,  32 ,  131  and  132  may have thread forms or thread profiles similar to American Petroleum Institute (API) buttress threads for oil country tubular goods. API Specification Standard SB contains information for various types of threads associated with OCTG.  
      For some embodiments of the present invention as shown in  FIGS. 1A-10 , threaded portions  31 ,  32 ,  131  and  132  may be generally described as having modified buttress thread forms. Threaded portions  31 ,  32 ,  131  and  132  formed in accordance with teachings of the present invention preferably include several significant differences as compared with more conventional buttress thread forms. For example, thread forms or thread profiles associated with threaded portions  31 ,  32 ,  131  and  132 , preferably having negative load flank angles and positive stab flank angles. The tapered thread profiles associated with threaded portions  31 ,  32 ,  131  and  132  and the positive flank angles cooperate with each other to facilitate makeup of box end  22  with associated pin end  21  and the makeup of box end  122  with associated pin end  121 . See  FIGS. 2, 3  and  4  and  FIGS. 6, 7  and  8 .  
      First flank angles or stab flank angles formed in accordance with teachings of the present invention may vary between approximately positive ten degrees (+10°) and positive forty-five degrees (+45°). Threaded connections formed in accordance with teachings of the present invention may have second flank angles or load flank angles between approximately negative three degrees (−3°) and negative fifteen degrees (−15°).  
      Various features of tubular goods and threaded connections formed in accordance with teachings of the present invention allow radial expansion of the tubular goods and associated threaded connections while maintaining desired mechanical strength and fluid tight integrity. These features include negative load flank angles  44  and  84  which retain close, intimate contact between associated threaded portions  31 ,  32 ,  131  and  132  during radial expansion of tubular members  20 . The negative angle of the load flanks may be selected in accordance with teachings of the present invention to provide desired tensile strength to prevent disengagement of associated threaded portions  31 ,  32 ,  131  and  132  during radial expansion.  
       FIG. 1A  shows tubular member  20  which may be formed using electric resistance welding (ERW) technology. For this embodiment, tubular member  20  may be generally described as an elongated, hollow section of casing. Tubular member  20  includes first end or pin end  21  and second end or box end  22  with longitudinal bore  24  extending therethrough. Longitudinal bore  24  may be defined in part by longitudinal axis  23  and inside diameter  52 . Threaded portions  31  and  32  incorporating teachings of the present invention are preferably formed on respective pin end  21  and box end  22  of each tubular member  20 .  
      Tubular members  20  may be initially formed with blank ends (not expressly shown). One end of each tubular member  20  may be swaged to form an enlarged outside diameter and an enlarged inside diameter corresponding with overall dimensions associated with box end  22 . Various swaging techniques may be satisfactorily used to form box end  22  on one end of each tubular member  20 . During the swaging process the outside diameter and the inside diameter of box end  22  will generally be increased as compared with other portions of associated tubular member  20 . The inside diameter of pin end  21  will generally remain the same as inside diameter  52  of tubular member  20 . The nominal wall thickness of box end  22  will generally remain approximately the same as the nominal wall thickness of tubular member  20 . Swaging techniques may be particularly beneficial for use with radially expandable tubular members.  
      As shown in  FIG. 1B  thread forms associated with threaded portion  31  may include first flank or stab flank  42  and second flank or load flank  44  extending between respective thread crests  46  and thread roots  48 . In a similar manner as shown in  FIG. 1C , thread forms associated with threaded portion  32  include first flank or stab flank  82  and second flank or load flank  84  extending between respective thread crests  86  and thread roots  88 . For some applications, first flanks or stab flanks  42  and  82  may be formed at an angle of approximately positive ten degrees (+10°) relative to a plane disposed normal to longitudinal axis  23  of longitudinal bore  24 . Second flanks or load flanks  44  and  84  may be formed at an angle of approximately negative five degrees (−5°) relative to the same plane.  
      For some applications thread roots  88  of threaded portion  32  may be larger (for example 0.001 inches) than thread crests  46  of threaded portion  31  to accommodate redistribution and flow of coating  100  during both power tight make up of associated threaded connections and downhole radial expansion of tubular members  20 . See  FIGS. 9 and 10 . The height of thread crests  46  and  86  may be reduced to increase the mechanical strength of the associated threaded connection. For example thread crests  46  and  86  may have a height of approximately 0.052 inches as compared with more typical buttress thread heights of 0.062 inches.  
      Box end  22  may be formed by swaging portions of each tubular member  20  starting from extreme end  26  to provide desired overall dimensions of length, outside diameter, inside diameter and wall thickness. Threaded portion  32  may be formed between extreme end  26  and enlarged recess  50 . Enlarged recess  50  may sometimes be described as a “grease trap” which receives any excess thread dope or grease placed on threaded portions  31  or  32 . Enlarged recess  50  may be particularly helpful to receive excess thread dope or grease during make up of threaded connections such as shown in  FIG. 4 . Threaded portion  32  may terminate proximate enlarged recess  50 . Chamfer  28  may be formed on the outside diameter of box end  22  adjacent to extreme end  26 . Chamfer  28  may sometimes be formed at an angle of approximately eighty degrees (80°) relative to longitudinal axis  23 . Tapered sealing surface  34  may be formed on the inside diameter of box end  22  adjacent to enlarged recess  50 .  
      For some applications, threaded portion  32 , enlarged recess  50  and tapered sealing surface  34  may be formed by a single pass of a thread cutting machine (not expressly shown) extending through end  26  of longitudinal bore  24  to form interior portions of box end  22 . Enlarged recess  50  may accommodate withdrawal of an associated thread cutting tool depending upon the design and configuration of the specific thread cutting tool.  
      As shown in  FIGS. 1A and 1B , pin end  21  may include extreme end  25 , threaded portion  31  and shoulder  27  disposed on the exterior of associated tubular member  20 . Extreme end  25  of pin end  21  may extend generally normal to associated longitudinal axis  23 . Chamfer  29  may be formed on the interior of pin end  20  adjacent to extreme end  25 . For some applications chamfer  29  may extend at an angle of approximately forty-five degrees ( 450 ) relative to associated longitudinal axis  23 . Shoulder  27  may also extend generally normal to associated longitudinal axis  23 . Shoulder  27  is preferably sized to engage extreme end  26  of associated box end  22 .  
      The inside diameter of box end  22  will generally be enlarged as compared with inside diameter  52  of associated pin end  21 . The dimensions of each pin end  21  and box end  22  are preferably selected such that inside diameter  52  of pin end  21  of tubular member  20   a  will be generally aligned with inside diameter  52  of tubular member  20   b  when pin end  21  has been engaged with associated box end  22 . See  FIGS. 2, 3  and  4 . Annular recess  40  may be formed within each threaded connection proximate extreme end  25  of respective pin end  21 . Chamfer  29  may be provided on pin end  21  to minimize any interference with movement of well tools or drift check tools (not expressly shown) through longitudinal bores  24 . Extreme end  25  and adjacent portions of pin end  21  may be deflected towards longitudinal axis  32  during make up with associated box end  22 .  
      Tubular members  20   a  and  20   b  formed in accordance with the teachings of the present invention are shown releasably engaged with each other in  FIGS. 3 and 4 . Tubular members  20   a  and  20   b  may be formed from ERW pipe having substantially the same nominal outside diameter, inside diameter and wall thickness. Each box end  22  may have a larger outside diameter as compared to other portions of respective tubular members  20   a  and  20   b . As a result, when box end  22  of tubular member  20   b  is releasably engaged with pin end  21  of tubular member  20   a , the resulting threaded connection may be described as “swage joint” with respect to the outside diameter of box end  22  being larger than the adjacent outside diameter of tubular member  20   a . Inside diameter  52  of respective longitudinal bores  24  and pin end  21  are substantially equal. See  FIGS. 3 and 4 .  
       FIG. 2  shows a typical orientation of first tubular member  20   a  and second tubular member  20   b  prior to making up tubular members  20   a  and  20   b  for insertion into a wellbore (not expressly shown). The present invention allows multiple tubular members  20  to be releasably engaged with each other to form a casing string to complete a wellbore. First tubular member  20   a  may be positioned on a drilling platform or well servicing platform (not expressly shown) over a wellbore with pin end  21  looking up to receive box end  22  of second tubular member  20   b . Various types of pipe tongs and other powered equipment associated with making and breaking threaded connections between oil country tubular goods may be satisfactorily used to releasably engage box end  22  of second tubular member  20   b  with pin end  21  of first tubular member  20   a . For purposes of describing various features of the present invention, the process of making up or releasably engaging box end  22  of tubular member  20   b  will be described with respect to pin end  21  of tubular member  20   a.    
      Threaded portions  31  and  32  may have approximately the same length  36 . Length  36  for threaded portion  31  may be measured from extreme end  25  of pin end  21  to shoulder  27  formed on the exterior of tubular member  20 . Length  36  of threaded portion  32  of each tubular member  20  may be measured from extreme end  26  to a plane extending generally normal to longitudinal axis  23  proximate the end of tapered sealing surface  34  opposite from associated enlarged recess  50 . See  FIG. 1A . Length  36  of threaded portions  31  and  32  for tubular members  20   a  and  20   b  may be selected so that extreme end  26  of box end  22  will abut shoulder  27  of associated pin end  21  and tapered sealing surface  35  of pin end  21  will preferably be engaged with tapered sealing surface  34  of box end  22 . See  FIGS. 3 and 4 .  
      Threaded connections as shown in API Specification Standard  5 B may be made up to a “basic hand-tight position” and to a “basic power-tight position” as indicated by markings on the exterior of associated oil country tubular goods. The hand tight position for box end  22  of tubular member  20   b  relative to pin end  21  of tubular member  20   a  is shown in  FIG. 3 .  
      For some applications threaded portions  31  and  32  may have matching thread profiles with at least five (5) threads per inch. For other applications threaded portions  31  and  32  may have six (6) threads per inch. Various dimensions associated with threaded portions  31  and  32  may be selected to provide a hand tight position defined in part by a stand off of approximately two (2) threads between extreme end  25  of tubular member  20   a  and shoulder  28  of tubular member  20   b . See  FIG. 3 .  
      Examples of dimensions associated with threaded connections having a hand tight position with a two thread stand off are shown in Tables 1 and 2. A typical stand off for threaded connections associated with oil country tubular goods that have a hand tight position may often be one thread or less. The two thread stand off in the hand tight position assists in maintaining mechanical integrity and fluid tight or pressure tight integrity of the associated threaded connection during radial expansion.  
      For some applications, relatively smooth nonthreaded portion or tapered sealing surface  35  may be formed as part of threaded portion  31  extending from extreme end  25  of each pin end  21 . Relatively smooth nonthreaded portion or tapered sealing surface  34  may also be formed within box end  22  extending from enlarged recess  50 . Sealing surfaces  34  and  35  may form a “tapered” metal to metal seal or fluid barrier disposed therebetween. For some applications, sealing surfaces  34  and  35  may extend at a taper approximately equal to the taper of associated thread profiles  31  and  32 .  
      Metal to metal contact may be formed between tapered sealing surfaces  34  and  35  when threaded portions  31  and  32  have a standoff of two threads. Further tightening of threaded portions  31  and  32  may result in deflection of pin end  121  by approximately 0.025 inches proximate tapered sealing surface  35 . An enhanced metal to metal seal or fluid barrier may be formed between sealing surfaces  34  and  35  as a result of the deflection.  
      Engagement between tapered sealing surface  34  of box end  22  and tapered sealing surface  35  of box end  21  may result in improved performance of associated threaded connections during radial expansion of tubular members  20   a  and  20   b  at a down hole location within a wellbore. When an expansion mandrel or similar tool moves through longitudinal bores  24 , direct contact between nonthreaded portions  34  and  35  will result in radial expansion without disengagement of associated threaded portions  34  and  35 . For some applications, nonthreaded portions  34  and  35  may have a length of approximately one (1) inch or more. Nonthreaded portions  34  and  35  cooperate with each other to coordinate radial expansion of pin end  21  with box end  22  during deformation of the associated threaded connections.  
       FIG. 5A  shows tubular member  120  which may be formed using electric resistance welding (ERW) technology. For this embodiment, tubular member  120  may be generally described as an elongated, hollow section of casing. Tubular member  120  includes first end or pin end  121  and second end or box end  122  with longitudinal bore  24  extending therethrough. Longitudinal bore  24  may be defined in part by longitudinal axis  23  and inside diameter  52 . Tubular members  120  may be initially formed with blank ends (not expressly shown). Respective threaded portions  131  and  132  incorporating teachings of the present invention may then be formed on pin end  121  and box end  122  using conventional pipe threading machines and equipment (not expressly shown). Threaded portions  131  and  132  may have similar dimensions and configurations as described for threaded portions  31  and  32  of tubular members  20 . For other applications the dimensions and configuration of threaded portions  131  and  132  may be modified in accordance with teachings of the present invention.  
      As shown in  FIG. 5B  thread forms associated with threaded portion  131  may include first flank or stab flank  42  and second flank or load flank  44  extending between respective thread crests  46  and thread roots  48 . In a similar manner as shown in  FIG. 5C , thread forms associated with threaded portion  132  include first flank or stab flank  82  and second flank or load flank  84  extending between respective thread crests  86  and thread roots  88 . For some applications, first flanks or stab flanks  42  and  82  may be formed at an angle of approximately positive twenty-five degrees (+25°) relative to a plane disposed normal to longitudinal axis  23  of longitudinal bore  24 . Second flanks or load flanks  44  and  84  may be formed at an angle of approximately negative five degrees (−5°) relative to the same plane.  
      As discussed later in more detail, pin end  121  may include first shoulder  127  sized to engage extreme end  126  of box end  121  of an associated tubular member  120 . See  FIG. 8 . Second shoulder  128  may be formed in box end  122  with enlarged recess  50  disposed between second shoulder  128  and threaded portion  132 . Threaded portion  132  may terminate proximate enlarged recess  50 . Shoulder  128  in box end  122  may have a negative angle compatible with chamfer  134  having a positive angle formed on extreme end  125  of pin end  121 . For some applications, threaded portion  132 , enlarged recess  50  and shoulder  128  may be formed by a single pass of a thread cutting machine (not expressly shown) starting from extreme end  126  of longitudinal bore  24  to form interior portions of box end  122 . Box end  122  may have the same nominal outside diameter, inside diameter and wall thickness as tubular member  120 .  
      As shown in  FIGS. 5A and 5B , chamfered surface  134  may be formed at extreme end  125  of pin end  121 . For some applications chamfered surface  134  may extend at an angle of approximately positive fifteen degrees (+15°) relative to a plane disposed normal to longitudinal axis  23  of longitudinal bore  24 . Shoulder  128  of box end  122  may be formed at an angle of approximately negative fifteen degrees (−15°) relative to a plane disposed normal to longitudinal axis  23  of longitudinal bore  24 . For other applications chamfered surface  134  may be formed with a positive angle between approximately seventy-five degrees (+75°) and ninety degrees (+90°). Shoulder  128  may be formed with a generally corresponding negative angle between approximately fifteen degrees (−15°) and zero degrees (0°). As a result, when box end  122  of tubular member  120   b  is releasably engaged with pin end  21  of tubular member  120   a , the resulting threaded connection may be described as “flush joint” with respect to the outside diameter of box end tubular member  120   a  and  120   b  and inside diameters of respective longitudinal bores  24 . See  FIGS. 7 and 8 .  
       FIG. 6  shows a typical orientation of second tubular member  120   b  and first tubular member  120   a  prior to making up tubular members  120   b  and  120   a  for insertion into a wellbore (not expressly shown). The present invention allows multiple tubular members  120  to be releasably engaged with each other to form a casing string to complete a wellbore. Generally, first tubular member  120   a  will be positioned on a drilling platform or well servicing platform (not expressly shown) over a wellbore with pin end  121  looking up to receive box end  122  of second tubular member  120   b . Various types of pipe tongs and other powered equipment associated with making and breaking threaded connections between oil country tubular goods may be satisfactorily used to releasably engage box end  122  of second tubular member  120   b  with pin  121  of first tubular member  120   a.    
      Threaded portions  131  and  132  may have approximately the same length  36 . Length  36  for threaded portion  131  may be measured from extreme end  125  of pin end  121  to first shoulder  127  formed on the exterior of tubular member  120 . Length  36  of threaded portion  132  of tubular member  120  may be measured from extreme end  126  of box end  122  to second shoulder  128  formed on the interior of box end  122 . Length  36  of threaded portions  131  and  132  may be selected so that extreme end  126  of box end  122  will abut first shoulder  127  on the exterior of pin end  121  and extreme end  125  of pin end  121  will abut second shoulder  128  of box end  122 . See  FIGS. 7 and 8 .  
      Threaded connections as shown in API Specification Standard  5 B may be made up to a “basic hand-tight position” and to a “basic power-tight position” as indicated by markings on the exterior of associated oil country tubular goods. The hand tight position for box end  122  of tubular member  120   b  relative to pin end  121  of tubular member  120   a  is shown in  FIG. 7 .  
      For some applications threaded portions  131  and  132  may have matching thread profiles with five (5) threads per inch. For other applications threaded portions  131  and  132  may have more than five (5) threads per inch. Various dimensions associated with threaded portions  131  and  132  of tubular members  120  may be selected to provide a hand tight position defined in part by a stand off of approximately two (2) threads between extreme end  25  of tubular member  120   a  and shoulder  28  of tubular member  120   b . See  FIG. 7 .  
      For some applications, relatively smooth nonthreaded portion  135  may be formed as part of threaded portion  131  extending from extreme end  125  of pin end  121 . Relatively smooth nonthreaded portion  137  may be formed in box end  122  between shoulder  128  and enlarged recess  50 . Threaded portions  135  and  137  may be tapered to engage each other when pin end  121  and box end  122  are engaged with each other. A fluid barrier may be formed by engagement of nonthreaded portions  135  and  137  with each other.  
      Engagement between nonthreaded portions  135  of pin end  121  and nonthreaded portion  137  of box end  122  results in improved performance of associated threaded connections during radial expansion of tubular members  120   a  and  120   b  at a down hole location within a wellbore. When an expansion mandrel or similar tool moves through longitudinal bores  24 , direct contact between nonthreaded portions  135  and  137  will result in radial expansion without disengagement of associated threaded portions  31  and  32 . For some applications, nonthreaded portions  135  and  137  may have a length of approximately one (1) inch. Nonthreaded portions  135  and  137  cooperate with each other to coordinate radial expansion of pin end  121  with box end  122  during deformation of the threaded connection.  
      A threaded flush joint type connection formed in accordance with teachings of the present invention may have a power-tight position defined in part by extreme end  126  of box end  122  of tubular member  120   b  directly contacting shoulder  127  tubular member  120   a  and extreme end  25  of pin end  121  of tubular member  120   a  directly contacting shoulder  128  of box end  122  of tubular member  120   b . The power-tight position for releasably engaging tubular members  120   a  and  120   b  with each other is shown in  FIG. 8 .  
      Another feature of the present invention which helps maintain desired fluid tight integrity during radial expansion includes chamfer  134  formed on extreme end  125  of pin end  121  and shoulder  128  formed within box end  122 . As previously noted, shoulder  128  is preferably formed with a negative angle selected to match a corresponding positive angle associated with chamfer  134 . The associated angles and the tensile strength of material used to form tubular members  120  cooperate with each other to retain close, intimate contact between extreme end  125  of pin end  121  and respective shoulder  128  of box end  122 .  
      For some applications, a layer of tin based material or other suitable malleable material may be coated or plated on threaded portions  31  and  34 . For the embodiment of the present invention as shown in  FIGS. 9 and 10 , coating  100  may be disposed on internal threaded portions  32  of box end  22 . For purposes of illustrating various features of the present invention the thickness of coating  100  is shown larger than a typical coating on a threaded connection formed in accordance with teachings of the present invention. Modified buttress thread forms associated with threaded portions  31  and  32  and coating  100  cooperate with each other to provide improved fluid tight integrity with respect to internal fluid pressure following radial expansion of associated threaded connections. Coating  100  may be applied by various processes such as plating after threaded portion  32  has been formed in box end  22 .  
      Various types of downhole tools such as an “expansion mandrel” (not expressly shown) may be used to radially expand tubular members  20  and  120  after being disposed at a desired downhole location in a wellbore. During a typical expansion process, pressure or force may be exerted by the expansion mandrel pressing against the inside diameter of respective pin ends  21  or  121 . Resulting radial forces may be transferred to respective box ends  22  or  122  which results in radial expansion of associated box end  22  or box end  122 . Such pressure and associated friction will typically cause portions of coating  100  to flow and fill any gaps or void spaces formed between respective threaded portions  31  and  32  or  131  and  132  which may occur during downhole radial expansion of associated tubular members  20  and  120 . See  FIG. 10 .  
      For some applications, specifications associated with threaded portions  31  and  32  may be selected to provide approximately 0.0005 inches of clearance between respective flank angles  42  and  82  and flank angles  44  and  84  and approximately zero clearance between respective roots  48  and  88  and crests  46  and  86 . During makeup of an associated threaded connection, portions of coating  100  will typically be displaced from respective flanks  82  and  84  and deposited in thread roots  48  and  88 . The presence of excess coating  100  in roots  48  and  88  may result in some radial deflection of pin end  21  into longitudinal bore  24  during make up of tubular members  20   a  and  20   b  or tubular members  120   a  and  120   b . For some applications chamfer  134  formed on pin end  121  will engage or lock with respective shoulder  128  to minimize the effects of such radial deflection. In a similar manner, negative load flank angles  44  and  84  will engage or lock with each other to also minimize the effects of such radial deflection.  
      For some applications pin end  21  or pin end  121  may deflect radially inward approximately 0.002 inches during power tight make of the associated threaded connection. Radial expansion of tubular members  20  and  120  at a downhole location may substantially reduce or remove any inward deflection of pin end  21 .  
               TABLE 1                       EXAMPLES OF TYPICAL DIMENSIONS FOR THREAD PROFILES                                                                                            End of Pipe   Length                                   to   Face of           Threads   Length           Pitch                  H   Box end   Taper       Size   Per   Perfect           Diameter at   and Tight   to Plane   Per       Nominal OD   Inch   Threads   E7   L4   E7   Standoff   of E7   Foot               6.000   6   2.000   1.300   2.600   5.7155   0.3334   0.9666   0.750                                                                 BHS                                   Pin       C                   Recess   B1   Angle of   D   E       Size   A   A1   Diameter   Pin Recess   Pin Bevel   Angle of   Length to       Nominal   Pin Nose   Pin Nose   at   Length at   at End of   Box end   Center of       OD   Diameter   Length   Shoulder   Shoulder   Pipe   Shoulder   Box end               6.000   5.570   0.300   5.830   0.300   15°   75°   1.000                                                 F   F1                       Diameter of   Length of Box   G   G1           Box end   end   Diameter of Box   Length of Box       Size   Counterbore   Counterbore   end Recess at   end Recess at   K       Nominal   Recess at Face   Recess at Face   Center of Box   Center of Box   Wall       OD   of Box end   of Box end   end   end   Thickness               6.000   5.840   0.300   5.580   0.300   0.305                  
 
     
       
         
           
               
             
               
                 TABLE 2 
               
               
                   
               
               
                   
               
               
                 EXAMPLES OF TYPICAL DIMENSIONS FOR THREAD PROFILES 
               
               
                   
               
             
            
               
                 PIN - DIMENSIONS 
               
            
           
           
               
               
               
               
               
               
               
               
               
               
               
               
            
               
                 PIPE 
                 ACTUAL 
                   
                   
                   
                   
                   
                   
                   
                 PITCH DIA 
                 “L7” END OF 
                 HAND TIGHT 
               
               
                 SIZE 
                 O.D. 
                 WALL 
                 I.D. 
                 “B” 
                 L4 
                 A1 
                 B1 
                 “A” 
                 @ E7 
                 PIN TO “E7” 
                 STANDOFF 
               
               
                   
               
               
                 5.000 
                 5.025 
                 .296 
                 4.433 
                 4.865 
                 2.800 
                 .400 
                 .200 
                 4.5983 
                 4.741 
                 1.450 
                 .400 
               
               
                 5.500 
                 5.530 
                 .304 
                 4.922 
                 5.360 
                 2.800 
                 .400 
                 .200 
                 5.0933 
                 5.236 
                 1.450 
                 .400 
               
               
                   
               
            
           
           
               
            
               
                 BOX - DIMENSIONS 
               
            
           
           
               
               
               
               
               
               
               
               
               
               
               
               
               
            
               
                   
                   
                   
                   
                   
                   
                   
                   
                   
                   
                 “L7” END 
                   
                   
               
               
                   
                   
                   
                   
                   
                   
                   
                   
                   
                 PITCH 
                 OF 
                 GREASE 
                 HAND 
               
               
                 PIPE 
                 ACTUAL 
                   
                   
                   
                   
                   
                   
                   
                 DIA @ 
                 PIN TO 
                 TRAP 
                 TIGHT 
               
               
                 SIZE 
                 O.D. 
                 WALL 
                 I.D. 
                 “B” 
                 L4 
                 A1 
                 B1 
                 “A” 
                 E7 
                 “E7” 
                 “G” 
                 STANDOFF 
               
               
                   
               
               
                 5.000 
                 5.025 
                 .296 
                 4.433 
                 4.5833 
                 2.800 
                 .300 
                 .300 
                 4.859 
                 4.741 
                 .950 
                 4.690 
                 .400 
               
               
                 5.500 
                 5.530 
                 .304 
                 4.922 
                 5.0783 
                 2.800 
                 .300 
                 .300 
                 5.354 
                 5.236 
                 .950 
                 5.185 
                 .400 
               
               
                   
               
               
                   NOTE:    
               
               
                   Diameter and length dimensions in Tables 1 and 2 are in inches.    
               
            
           
         
       
     
      Although the present invention and its advantages have been described in detail, it should be understood that various changes, substitutions and alternations can be made herein without departing from the spirit and scope of the invention as defined by the following claims.