Patent Publication Number: US-6220363-B1

Title: Wellhead isolation tool and method of using same

Description:
TECHNICAL FIELD 
     The present invention relates to equipment for servicing oil and gas wells and, in particular, to an apparatus for wellhead isolation permitting a high flow rate during a well treatment to stimulate production. 
     BACKGROUND OF THE INVENTION 
     Most oil and gas wells eventually require some form of stimulation to enhance hydrocarbon flow and make or keep them economically viable. The servicing of the oil and gas wells to stimulate production requires the pumping of fluids under high pressure. The fluids are generally corrosive and abrasive because they are frequently laden with corrosive acids and abrasive proppants such as sharp sand. Consequently, such fluids can cause irreparable damage to wellhead equipment if they are pumped directly through the spools and the various valves that make-up the wellhead. To prevent such damage, wellhead isolation tools have been used and various configurations are known. Examples of such tools are taught in at least the following patents and patent application: 
     U.S. Pat. No. 3,830,304 to Cummins; 
     U.S. Pat. No. 4,241,786 to Bullen; 
     U.S. Pat. No. 4,632,183 to McLeod; 
     U.S. Pat. No. 4,111,261 to Oliver; 
     U.S. Pat. No. 4,867,243 to Gardner et al.; 
     U.S. Pat. No. 5,332,044 to Dallas; 
     U.S. Pat. No. 5,372,202 to Dallas; 
     Canadian Patent No. 1,277,230 to McLeod; 
     Canadian Patent No. 1,281,280 to McLeod; 
     Canadian Patent No. 1,292,675 to McLeod; 
     Canadian Patent Application No. 2,055,656 to McLeod. 
     All of the wellhead isolation tools described in the patents and patent application listed above operate on the same general principle. Each tool includes a mandrel which is inserted through the various valves and spools of the wellhead to isolate those components from the elevated pressures and the corrosive and abrasive fluids used in the well treatment to stimulate production. A top end of the mandrel is connected to one or more high pressure valves through which the stimulation fluids are pumped. A bottom end of the mandrel includes a packoff assembly for achieving a fluid seal with the production tubing in the well. The mandrel is inserted down through the wellhead to the extent that it enters a top of the production tubing string where the packoff assembly seals against the inside of the production tubing, so that the wellhead is completely isolated from the stimulation fluids. 
     The mandrel for a wellhead isolation tool must be constructed to withstand high pressures at least about 10,000 psi. The packoff assembly that is bonded to the bottom end of the mandrel and seals against the inside of the production tubing limits the internal diameter of the mandrel and, consequently, the flow rate at which stimulation fluids are pumped through the mandrel is limited. For example, the maximum internal diameter for a mandrel of any one of the wellhead isolation tools described in the patents and patent application listed above is about 1.5″ (3.8 cm) when designed for use with a wellhead and a production tubing of standard dimensions. If the stimulation fluids are pumped through a mandrel of that size at 200 feet per second, the fluid flow rate is about 26 barrels per minute (BPM). 
     Wellhead isolation tools having a packoff assembly that seals against the inside of the production tubing also suffer from other drawbacks. The packoff assembly has a tendency to catch on constrictions as it is inserted through the wellhead, because the packoff assembly that leads the way through the wellhead, is larger than the mandrel, and has a leading edge of rubberized sealing material that seals against the inside of production tubing. In addition, the joint between the mandrel and the packoff assembly creates eddies in the production stimulation fluids which cause washout in the area of the joint. 
     To overcome the drawbacks of the wellhead isolation tools described in the above-listed prior art, Applicant describes an improved mandrel for a wellhead isolation tool in his co-pending U.S. patent application Ser. No. 08/837,574 filed on Apr. 21, 1997 and entitled APPARATUS FOR INCREASING THE TRANSFER RATE OF PRODUCTION STIMULATION FLUIDS THROUGH THE WELLHEAD OF A HYDROCARBON WELL, the entire specification of which is incorporated herein by reference. The apparatus described in this patent application includes a mandrel for a wellhead isolation tool, and a tubing hanger for use in conjunction with the mandrel. The mandrel includes an annular seal bonded to the outside wall above the bottom end of the mandrel. The annular seal cooperates with the sealing surface in the top end of the tubing hanger to isolate the wellhead equipment from the high pressures and corrosive and abrasive materials pumped into the well during a well treatment to stimulate production. The novel construction for the mandrel and the tubing hanger eliminates the requirement for a packoff assembly attached to the bottom of the mandrel and thereby permits the mandrel to have a larger internal diameter for increasing the transfer rate of production stimulation fluids through the wellhead. However, the annular seal of the mandrel is not adapted to cooperate with a standard tubing hanger. Consequently, a special tubing hanger is required if the mandrel is to be used for wellhead isolation. 
     It is desirable to further improve wellhead isolation tools to permit a high flow rate during a well treatment to stimulate production, without a requirement for a special tubing hanger so that substantially any well can be treated to stimulate production. 
     SUMMARY OF THE INVENTION 
     It is an object of the invention to provide a wellhead isolation tool overcoming the drawbacks of prior art wellhead isolation tools and eliminating the requirement for a special tubing hanger. 
     It is another object of the invention to provide a wellhead isolation tool equipped with a mandrel that has a larger internal diameter for providing a high flow rate of production stimulation fluids through the wellhead. 
     It is a further object of the invention to provide a novel construction for a mandrel having a seal which functions reliably and may be packed off within a standard tubing hanger. 
     It is yet a further object of the invention to provide a wellhead isolation tool equipped with a mandrel that has a leading end which is not prone to catching on constrictions when the mandrel is inserted through the wellhead. 
     In accordance with one aspect of the invention, there is provided an apparatus for wellhead isolation, permitting a high flow rate during a well treatment to stimulate production, comprising: 
     a mandrel adapted to be inserted down into the wellhead to an operative position, the mandrel having an inner surface defining a passage, an outer surface including an upper section of a first diameter, a lower section of a second diameter smaller than the first diameter, a sealing shoulder between the upper and lower sections for supporting an elastomeric seal, the lower section extending past back pressure valve threads and tubing threads of a tubing hanger into an annulus of a tubing of the well which is supported by the tubing hanger and the elastomeric seal being in fluid tight sealing engagement with an annular step in the tubing hanger formed between lift threads and the back pressure valve threads when the mandrel is in the operative position. 
     The elastomeric seal in accordance with one embodiment of the invention preferably comprises a first O-ring seal received in an annular groove on the sealing shoulder of the mandrel, and a second O-ring seal received in an annular groove on the upper section adjacent the sealing shoulder, the sealing shoulder of the mandrel being contoured to conform to the annular step so that the first O-ring seal is sealingly engaged with a substantially radial surface of the annular step and the second O-ring seal is sealingly engaged with a substantially axial surface of the annular step when the mandrel is in the operative position. 
     In accordance with another embodiment of the invention, the elastomeric seal preferably covers the sealing shoulder, a portion of the upper section and a portion of the lower section adjacent the sealing shoulder while the sealing shoulder of the mandrel is preferably contoured to conform the annular step of the tubing hanger. The sealing shoulder of the mandrel preferably further includes an annular ridge which protrudes into the elastomeric seal to inhibit the seal from being extruded away from the sealing shoulder when the mandrel is in the operative position. 
     In more specific terms, the invention provides an apparatus for wellhead isolation which permits a high flow rate during a well treatment to stimulate production, comprising: 
     a mandrel adapted to be inserted down into the wellhead to an operative position, the mandrel having an inner surface defining a passage, an outer surface including an upper section of a first diameter, a lower section of a second diameter smaller than the first diameter, a sealing shoulder between the upper and lower sections for supporting an elastomeric seal, the lower section extending past back pressure valve threads and tubing threads of a tubing hanger into an annulus of a tubing of the well which is supported by the tubing hanger and the elastomeric seal being in fluid tight sealing engagement with an annular step in the tubing hanger formed between lift threads and the back pressure valve threads when the mandrel is in the operative position; 
     a mechanical lockdown mechanism for detachably securing the mandrel to the wellhead when the mandrel is in the operative position; 
     a hydraulic cylinder for inserting the mandrel into and removing the mandrel from the wellhead; and 
     at least two elongated hydraulic cylinder support rods fixed relative to the wellhead for supporting the hydraulic cylinder in vertical and axial alignment with the wellhead, the support rods and the cylinder being removable when the mandrel is locked in the operative position. 
     The mechanical lockdown mechanism preferably includes a pair of complementary thread-engaging surfaces having respective axial lengths adequate to compensate for variations in length of a wellhead into which the mandrel is inserted to ensure the mandrel is locked in the operative position. 
     The advantage of the invention lies in that the elastomeric seal supported by the sealing shoulder of the mandrel is seated against an annular step of the tubing hanger which is located between the lift threads and the back pressure valve threads of a standard tubing hanger so that a special tubing hanger is not required to use the wellhead isolation tool. This reduces the cost of the wellhead equipment while enabling a high fluid flow rate during a well treatment to stimulate production of the well. A mandrel of the tool in accordance with the invention enables significantly higher flow rates during a well stimulation treatment. Furthermore, the elastomeric seal supported by the sealing shoulder of the mandrel in accordance with the invention provides a reliable fluid-tight seal. 
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS 
     The invention will now be further explained by way of example only and with reference to the following drawings in which: 
     FIG. 1 is an elevational view of the mandrel of a wellhead isolation tool in accordance with a preferred embodiment of the invention; 
     FIG. 2 is a partial cross-sectional view of the mandrel, shown in FIG. 1, in an operative position in which the mandrel is inserted into a top of a tubing and sealed with a tubing hanger that receives and supports the tubing; 
     FIG. 3 a  which appears on sheet  1  of the drawings is a partial cross-sectional view of the mandrel shown in FIG. 1, showing the sealing engagement between the mandrel and the tubing hanger; 
     FIG. 3 b  which also appears on sheet  1  of the drawings is a partial cross-sectional view of a mandrel in accordance with a second embodiment of the invention, showing the sealing engagement between the mandrel and the tubing hanger; 
     FIG. 4 a  is a partial cross-sectional view of the wellhead isolation tool in accordance with the invention, showing the mechanical lockdown mechanism in a locked position; 
     FIG. 4 b  is a partial cross-sectional view of the wellhead isolation tool in FIG. 4 a,  showing the mechanical lockdown mechanism in an unlocked position; 
     FIG. 5 is a schematic view of the wellhead isolation tool mounted to a wellhead, the mandrel of the wellhead isolation tool being in the operative position shown in FIG. 2; 
     FIG. 6 a  which appears on sheet  2  of the drawings is a partial cross-sectional view of the mechanical lockdown mechanism in accordance with another embodiment of the invention; and 
     FIG. 6 b  which also appears on sheet  2  of the drawings is a partial cross-sectional view of the mechanical lockdown mechanism in accordance with a further embodiment of the invention. 
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT 
     FIG. 1 shows an elevational view of a mandrel  10  in accordance with a preferred embodiment of the invention. The mandrel  10  may be adapted for use with any known configuration of a wellhead isolation tool. The mandrel  10  is a length of high pressure tubing well known in the art, having a top end  12 , a bottom end  14  and an outer surface  16  with a fluid passage  17  that extends between the top end  12  and the bottom end  14 . The top end  12  includes a threaded connector  18  for connection with a mandrel head, which will be explained below with reference to FIG. 4 a.    
     The outer surface  16  of the mandrel  10  includes an upper section  20  having a first diameter, and a lower section  22  having a second diameter smaller than the first diameter. A sealing shoulder  24  is formed between the upper and the lower sections and supports elastomeric O-ring seals  26 , which will be explained in detail with reference to FIG. 3 a.  The bottom end  14  of the mandrel  10  is preferably bevelled, and the bevelled end  14  together with the reduced diameter of the lower section  22  of the outer surface of the mandrel, facilitates entrance of mandrel  10  through the back pressure threads of a tubing hanger, as will be explained below with reference to FIG.  2 . 
     FIG. 2 shows a partial cross-sectional view of a lower portion of the mandrel  10  in an operative position in which the mandrel  10  is inserted into the top end of a production tubing  28  and sealed with a tubing hanger  30  that receives and supports the production tubing  28 . Generally, the production tubing string of a well is connected at the top to a tubing hanger or tubing coupler which is supported within the tubing spool of the wellhead. The tubing hanger  30  is of standard type, typical for a back pressure hanger design, and does not include a surface designed for sealing engagement with a wellhead isolation tool. Consequently, the high pressure tubing of wellhead isolation tools is traditionally packed off inside the production tubing  28 , as described in the prior art. Alternatively, the standard tubing hanger  30  may be replaced by the special tubing hanger described in Applicant&#39;s U.S. patent application Ser. No. 08/837,574 to provide a sealing surface for packing off the mandrel of the wellhead isolation tool. 
     The standard tubing hanger  30  is well known in the art and includes a cylindrical body made of steel which has a top end  32 , a bottom end  34 , an outer wall  36  and a fluid passage  38  that extends from the top end  32  to the bottom end  34  for fluid communication through the tubing hanger. Acme threads  40  are provided on the outer wall  36  for connection with an adapter or spool, as illustrated in FIG.  5 . The shape and configuration of the tubing hanger  30 , particularly of the outer wall  36 , will depend upon the shape and configuration of the tubing spool in which the tubing hanger  30  is received and supported. Nevertheless, the tubing hanger  30  generally includes threaded surfaces in the fluid passage  38  for different connection functions. Tapered lift threads  42  are provided on an upper portion of the inside of tubing hanger  30  for connection of tools to lift the tubing hanger. Tubing threads  44  are provided on a lower portion of the inside of tubing hanger  30  for connection of the production tubing  28 , as shown in FIG.  2 . Back pressure valve threads  46  are provided between the lift threads  42  and the tubing threads  44 , permitting the installation of a back pressure valve in the fluid passage  38 , so that a blowout preventer can be safely removed from the wellhead. Two annular steps  48  and  50  form respective transitions between the different portions of the inside of the tubing hanger  30 . In accordance with the present invention, the sealing shoulder  24  of the outer surface of the mandrel which supports the elastomeric O-ring seals  26  packs off against the annular step  48  so that the mandrel  10  can be used with a standard tubing hanger to eliminate the requirement for a special tubing hanger to achieve a high flow rate wellhead isolation tool. When the mandrel  10  is inserted into the wellhead in the operative position as shown in FIG. 2, the elastomeric O-ring seals  26  supported by the sealing shoulder  24  are securely seated against the annular step  48  of the tubing hanger  30  between the lift threads  42  and the back pressure valve threads  46 . In this operative position, the lower section  22  of the mandrel  10  extends downwardly past the back pressure valve threads  46  and the tubing threads  44  into the production tubing  28 . Thus, the back pressure valve threads  46  and the tubing threads  44  are protected by the lower section  22  from washout by abrasive proppants pumped into the well during a well treatment to stimulate production. 
     FIG. 3 a  illustrates the detail of the elastomeric O-ring seals  26  shown in FIG.  2 . The elastomeric O-ring seals  26  include a first O-ring seal received in an annular groove  25  on the sealing shoulder  24  and a second O-ring seal received in an annular groove  27  on the upper section  20  adjacent to the sealing shoulder  24 . The sealing shoulder  24  of the mandrel  10  is contoured to conform the annular step  26  so that the first O-ring seal in the annular groove  25  sealingly engages a substantial radial surface of the annular step  48  and the second O-ring seal sealingly engages a substantial axial surface of the annular step when the mandrel  10  is in the operative position. Elastomeric O-ring seals  26  suitable for high pressure applications (10,000-15,000 psi) are commercially available and well known in the art. 
     FIG. 3 b  shows an elastomeric seal on the mandrel  10  in accordance with a second preferred embodiment of the invention. In this embodiment, the mandrel  10  is provided with an improved elastomeric seal as described in Applicant&#39;s co-pending U.S. patent application Ser. No. 09/299,551, filed on Apr. 26, 1999 and entitled HIGH PRESSURE FLUID SEAL FOR SEALING AGAINST A BIT GUIDE IN A WELLLHEAD AND METHOD OF USING, which is incorporated herein by reference. The high pressure fluid seal  52  is an elastomeric material preferably made from a plastic material such as polyethylene or a rubber compound such as nitryl rubber. The elastomeric material preferably has a hardness of about 80-100 durometers. The high pressure fluid seal  52  is bonded directly to the sealing shoulder  24  of the mandrel  10  in a well known manner in the art and covers the sealing shoulder  24 , a portion of the upper section  20  and a portion of the lower section  22  adjacent the sealing shoulder. The sealing shoulder  24  of the mandrel  10  is also preferably contoured to conform the annular step  48  of the tubing hanger. The sealing shoulder  24  of the mandrel  10  may further include at least one downwardly protruding annular ridge  54  which provides an area of increased compression of the high pressure fluid seal  52  in an area preferably adjacent the upper section  20  of the outer surface  16  of the mandrel. The annular ridge  54  not only provides an area of increased compression, it also inhibits extrusion of the high pressure fluid seal  52  from the sealing shoulder  24  when the mandrel  10  is the operative position and exposed to extreme fluid pressures. The annular ridge  54  likewise helps ensure that the high pressure fluid seal  52  securely seats against the annular step  48 , even if the annular step  48  is worn due to impact and abrasion resulting from the movement of well tools into or out of the tubing hanger  30 . 
     FIG. 4 a  shows a wellhead isolation tool  55  including a mechanical lockdown mechanism  56  in accordance with a preferred embodiment of the invention. The mechanical lockdown mechanism  56  is used to lock the mandrel  10  in the operative position as shown in FIG.  2 . As discussed above, because the sealing shoulder  24  with the elastomeric O-ring seals is packed off against the fixed-point annular step  48  of the tubing hanger, the mandrel  10  is required to be accurately positioned and securely locked in this operative position. Consequently, a lockdown mechanism  56  must be provided to compensate for variations in a length of the mandrel  10  and a distance from the annular step  48  of the tubing hanger  30  to the top of the wellhead in different wellheads, as described in Applicant&#39;s co-pending U.S. patent application, filed Jun. 23, 1999 and entitled BLOWOUT PREVENTER PROTECTOR AND SETTING TOOL, which is also incorporated herein by reference. The mechanical lockdown mechanism  56  includes a base plate  58  and a lockdown nut  60  which detachably interconnects the base plate  58  and a mandrel head  62 . The mandrel head  62  is an annular flange, having a central passage  64  defined by an internal wall  66 . An upper flange  68  is adapted for connection of equipment, such as a high pressure valve, which will be described below in more detail. A lower flange  70  retains a top flange  72  of the lockdown nut  60 . Spiral threads  74  are provided on the lower end of the internal wall  66 , so that the mandrel head  62  may be securely attached to the threaded top end  12  of the mandrel  10  (FIG.  1 ), or a threaded top end  78  of mandrel extension  76 , as illustrated in FIG. 4 a.  The mandrel  10  may include one or more mandrel extensions  76 . Each mandrel extension  76  has the threaded top end  78  and a threaded bottom end  80 . The threaded top end  78  is adapted to connect the mandrel head  62  or another mandrel extension  76 , and the threaded bottom end  80  is adapted to connect the mandrel  10  or another mandrel extension  76 . Those connections are in a fluid tight sealing relationship provided by O-rings, one of which, for example, is indicated by reference numeral  81 . The mandrel extension  76  has an outer diameter equal to the diameter of the upper section  20  of the outer surface  16  of the mandrel  10  and an internal diameter equal to the internal diameter of the passage  17  of the mandrel  10 . 
     The central passage  64  of the mandrel head  62  is in full communication with the passage  17  of the mandrel  10  when the mandrel head  62 , the mandrel extension  76  and the mandrel  10  are securely assembled. The central passage  64  has an internal diameter not smaller than the passage  17  of the mandrel  10 . 
     The base plate  58  is preferably a circular disc which includes an integral concentric sleeve  84  perpendicular to the base plate  58 . Spiral threads  86  on the exterior of the integral sleeve  84  are provided, and engageable with complementary spiral threads  88  on the interior surface of the lockdown nut  60 . The base plate  58  and the integral sleeve  84  provide a passage  90  to permit the mandrel  10  and the mandrel extension  76  to pass therethrough. The lockdown nut  60  secures the mandrel head  62  from movement with respect to the base plate when the lockdown nut engages the spiral threads  86  of the integral sleeve  84 . The mandrel head  62  with its upper and lower flanges  68 ,  70 , and the lockdown nut  60  with its top flange  72  are illustrated in FIG. 4 a  as an integral unit assembly, for example, by welding, or the like. However, persons skilled in the art will understand that either one of the mandrel head  62  and the lockdown nut  60  may be constructed to permit disassembly to enable the mandrel head  62  or the lockdown nut  60  to be independently replaced. 
     The passage  90  through the base plate  58  has a recessed region on the lower end for receiving a steel spacer  92  and packing rings  94  preferably constructed of brass, rubber and fabric. The steel spacer  92  and packing rings  94  define a passage of the same diameter as the periphery of the mandrel  10  or the mandrel extension  76 . The steel spacer  92  and the packing rings are removable and may be interchanged to accommodate different sizes of mandrel  10  or mandrel extension  76 . The steel spacer  92  and the packing rings  94  are retained in the recessed region by a retainer nut  96 . The combination of the steel spacer  92 , packing rings and the retainer nut  96  provides a fluid seal to prevent passage to atmosphere of well fluids between the exterior of the mandrel  10  or mandrel extension  76  and the interior of the wellhead when the mandrel  10  and the mandrel extension  76  are inserted into the wellhead, which will be described below with reference to FIG.  6 . 
     FIG. 4 b  illustrates the mechanical lockdown mechanism  56  assembled with the mandrel  10  and the mandrel extension  76  prior to being mounted atop a wellhead for a well stimulation treatment. The lockdown nut  60  is disengaged from the integral sleeve  84  of the base plate  58  and the mandrel head  62  is connected to the threaded top end  78  of the mandrel extension  76 . The mandrel extension  76  is connected to the treaded bottom end  80  of the mandrel  10  to provide the required length for particular wellhead. Hereafter, for the purpose of convenience, the assembled combination of the mandrel  10  and mandrel extension  76  is referred to as an “assembled mandrel”. The base plate  56  is mounted to the top end of the wellhead (FIG. 5) and the combination of the lockdown nut  60 , the mandrel head  62  and the assembled mandrel is inserted from the top into the wellhead, using any one of several setting tools known in the art. 
     FIG. 5 illustrates the wellhead isolation tool  55  and a hydraulic setting tool used to insert the wellhead isolation tool  55  to the operative position for a well treatment to stimulate production. The hydraulic setting tool illustrated in FIG. 5 was described in Applicant&#39;s U.S. Pat. No. 4,867,243 entitled WELLHEAD ISOLATION TOOL AND SETTING AND METHOD OF USING SAME which issued on Sep. 19, 1989 and is incorporated herein by reference. The wellhead is constructed in a well known manner from a series of valves and related flanges. The wellhead schematically illustrated in FIG. 5 includes a tubing spool  98  which receives and supports the tubing hanger  30 . Connected by flange connections to the top of the tubing spool  98 , are a pair of valves  100  and  102 , by way of example. A third valve  104  is connected to the valve  102 . The purpose of the three valves  100 ,  102  and  104  is to control the flow of hydrocarbons from the well. As described above, the wellhead isolation tool  55  is mounted above the wellhead, that is, atop the valve  104 . Mounted above the wellhead isolation tool  55 , is a high pressure valve  106  which is used for fluid flow control during the well treatment to stimulate production, and is also used to prevent well fluids from escaping to atmosphere from the top of the wellhead isolation tool  55  during insertion and removal of the assembled mandrel. The hydraulic setting tool includes a hydraulic cylinder  108  which is mounted to a support plate  110 . The support plate  110  includes a central bore (not shown) to permit a piston rod  112  of the hydraulic cylinder  108  to pass through the support plate  110 . The support plate  110  also includes at least two spaced apart attachment points  114  for attachment of respective hydraulic cylinder support rods  116 . The spaced apart attachment points  114  are preferably equally spaced from the central bore to ensure that the hydraulic cylinder  108  and the piston rod  112  are aligned with the wellhead to which the hydraulic cylinder  108  is mounted. The hydraulic cylinder support rods  116  are respectively attached on their lower ends to corresponding attachment points  118  on the base plate  58 , which is mounted to the top of the valve  104 . As is apparent, the base plate  58  and the support plate  110  have a periphery that extends beyond the wellhead to provide enough radial offset of the cylinder support rods  116  to accommodate the high pressure valves  106 . The cylinder support rods  116  are identical in length and are attached to respective spaced apart attachment points  114 ,  118  on the support plate  110  and base plate  58  by means of thread fasteners or pins (not shown). The piston rod  112  is attached to the top of the high pressure valve  106  by a connector  120  so that mechanical force can be applied to the top of the wellhead isolation tool  55  and the attached high pressure valve  106  to stroke the assembled mandrel in and out of the wellhead. 
     As noted above, mandrel extensions  76  are optional and of variable length so that the assembled mandrel has adequate length to ensure that the top end  12  of the assembled mandrel extends above the top of the valve  104  just enough to enable the mandrel to be secured by the lockdown mechanism  56  described above when the elastomeric O-ring seals  26  are packed off against the annular step  48  of the tubing hanger. However, the distance from the annular step  48  of the tubing hanger  30  to the top of the valve  104  may vary to some extent in different wellheads. This variation cannot be reliably accommodated by a conventional lockdown mechanism such as taught in applicant&#39;s U.S. Pat. No. 4,867,243. 
     The mechanical lockdown mechanism  56  is configured to provide a broader range of adjustment to compensate for variations in the distance from the top of the valve  104  to the top end of the assembled mandrel. The complementary spiral threads  86  and  88  on the respective integral sleeve  84  and lockdown nut  60  having an adequate length to provide the required compensation. Preferably, the respective threads  86  and  88  are at least about 9″ (22.86 cm) in length. A minimum engagement for safely containing elevated fluid pressures acting on the wellhead isolation tool  55  during a well treatment to stimulate production is represented by a section A, shown in FIG. 4 a.  Sections B represents the adjustment available to compensate for variations in the distance from the top of the valve  104  to the top end of the assembled mandrel. Spiral threads with about 9″ of axial length provide about 5″ of adjustment while ensuring that a minimum engagement of the lockdown nut  60  is maintained. 
     FIGS. 6 a  and  6   b  illustrate two of the alternate mechanical lockdown mechanisms  56  in accordance with the invention. In FIG. 6 a,  the spiral threads  88  on the lockdown nut  60  has an axial extent A adequate to ensure the minimum engagement required for safety, and the threads  86  on the integral sleeve  84  of the base plate  58  have full length spiral threads, which include the A section for the minimum engagement and the B section for the adjustment. The mechanical lockdown mechanism  56  illustrated in FIG. 6 b  provides a similar adjustable lockdown with length A for minimum safe threaded engagement on the integral sleeve  84  and full length spiral threads  88  including sections A and B on the lockdown nut  60  for the adjustment. 
     In use of the wellhead isolation tool  55 , the base plate  58  is secured in a fluid sealing relationship to the top of the valve  104  with the lockdown nut  56  is disengaged from the integral sleeve  84  of the base plate  58 , as shown in FIG. 4 b.  The combination of the assembled mandrel, mandrel head  62  and the lockdown nut  60  may be supported by a rig or other insertion tool. The high pressure valve  106  is mounted to the top flange  68  of the mandrel head before insertion of the assembled mandrel into the wellhead. The high pressure valve  106  is closed to prevent well fluids from escaping from the wellhead isolation tool  55  when the assembled mandrel is inserted into the wellhead. The valves  104 ,  102  and  100  are fully opened in sequence to permit the insertion of the assembled mandrel. The assembled mandrel may be inserted through the wellheads using the hydraulic cylindrical setting tool illustrated in FIG. 5 or any other of a plurality of insertion tools well known in the art. If the hydraulic insertion tool is used, the hydraulic cylinder  108 , support plate  110  and the cylinder support rods  116  are mounted on the top of the wellhead so that the hydraulic cylinder  108  is supported in vertical and axial alignment with the wellhead with the piston rod  112  connected by the connector  120  to the top of the high pressure valve  106  and the cylinder support rods  116  are attached at their lower ends to the respective attachments points  118  on the base plate  58 . During insertion of the assembled mandrel, well fluids are prevented from escaping to the atmosphere by the packing rings  94  in the base plate  58 , which was described above with reference to FIG. 4 a.  The assembled mandrel is inserted into the wellhead until the elastomeric O-ring seals  26  sealingly contact the annular step  48  of the tubing hanger  30  and the lockdown nut  60  is rotated down to its locking position so that the assembled mandrel is securely held in the operative position during the entire well treatment to stimulate production. 
     After the assembled mandrel is inserted into the operative position, the hydraulic setting tool is removed from the wellhead and the well treatment to stimulate production may begin. The efficacy of the wellhead isolation tool in accordance with the invention is illustrated in Table I. The fluid flow rates are expressed in barrels per minute (bpm) based on a maximum flow rate of 200 feet per second in different production tubings having standard internal diameters (I.D.). 
     
       
         
           
               
               
               
               
               
             
               
                 TABLE I 
               
             
            
               
                   
               
               
                   
                   
                   
                 Isolation Tool 
                   
               
               
                   
                 Prior Art 
                   
                 In Accordance 
               
               
                 Production 
                 Isolation Tool 
                   
                 With Invention 
               
            
           
           
               
               
               
               
               
            
               
                 Tubing I.D. 
                 I.D. 
                 Flow Rate 
                 I.D. 
                 Flow Rate 
               
               
                   
               
               
                 2⅜″ 
                 1.25″ 
                 18 bpm 
                 1.5″  
                 26 bpm 
               
               
                 2⅞″ 
                 1.5″  
                 26 bpm 
                 1.75″ 
                 36 bpm 
               
               
                 3½″ 
                 1.75″ 
                 36 bpm 
                 2.0″  
                 48 bpm 
               
               
                   
               
            
           
         
       
     
     As is apparent, flow rates are significantly improved and the time required to stimulate a well is correspondingly reduced. 
     The hydraulic setting tool is remounted to the wellhead after the well treatment to stimulate production is completed. The hydraulic setting tool is then operated to stroke the assembled mandrel upward out of the top of the valve  104 . The valves  104 ,  102  and  100  are closed to prevent well fluids from escaping to the atmosphere. After the valves  104 ,  102  and  100  are closed, the entire assembly of the wellhead isolation tool  55  and the high pressure valve  106  as well as the hydraulic setting tool are removed from the top of the valve  104 . The sequence of steps described above may be changed to adapt to specific circumstances, as will be apparent to persons skilled in the art. 
     Although a hydraulic setting tool as described above with reference to FIG. 5 has been used to illustrate the use of the preferred embodiment of the invention, as noted above other types of setting tool may be used for inserting the assembled mandrel through the wellhead to the operative position. For example, a setting tool described by McLeod in U.S. Pat. No. 4,632,183, entitled INSERTION DRIVE SYSTEM FOR TREE SAVERS which issued on Dec. 5, 1984, the entire specification of which is incorporated herein by reference, may be used. Another type of setting tool which may also be used to insert the assembled mandrel is described by Bullen in U.S. Pat. No. 4,241,786, entitled WELL TREE SAVER, which issued on May 2, 1979 and is also incorporated herein by reference. 
     Modifications and improvements to the above-described embodiments of the invention may become apparent to those skilled in the art. The foregoing description is intended to be exemplary rather than limiting. The scope of the invention is therefore intended to be limited solely by the scope of the appended claims.