A hybrid wellhead system is assembled using a plurality of threaded unions, such as spanner nuts or hammer unions, for securing respective tubular heads and a flanged connection for securing a flow control stack to a top of a tubing head spool. The tubing head spool is secured by a threaded union to an intermediate head spool. The intermediate head spool is secured by another threaded union to a wellhead. Each tubular head secures and suspends a tubular string in the well bore. The hybrid wellhead system is capable of withstanding higher fluid pressures than a conventional independent screwed wellhead, while providing a more economical alternative to a flanged, or ranged, wellhead system because it is less expensive to construct and faster to assemble.

This application claims the benefit of priority under 35 U.S.C. §119(e) to U.S. Provisional Patent Application Ser. No. 60/513,142 filed Oct. 21, 2003. 


   MICROFICHE APPENDIX 
   Not Applicable. 
   TECHNICAL FIELD 
   The present invention relates generally to wellhead systems for the extraction of subterranean hydrocarbons and, in particular, to a hybrid wellhead system employing both threaded unions and flanged connections. 
   BACKGROUND OF THE INVENTION 
   Wellhead systems are used for the extraction of hydrocarbons from subterranean deposits. Wellhead systems include a wellhead and, optionally mounted thereto, various Christmas tree equipment (for example, casing and tubing head spools, mandrels, hangers, connectors, and fittings) The various connections joints and unions needed to assemble the components of the wellhead system are usually either threaded or flanged. As will be elaborated below, threaded unions are typically used for low-pressure wells where the working pressure is less than 3000 pounds per square inch (PSI), whereas flanged unions are used in high-pressure wells where the working pressure is expected to exceed 3000 PSI. 
   Independent screwed wellheads are well known in the art. The American Petroleum Institute (API) classifies a wellhead as an “independent screwed wellhead” if it possesses the features set out in API Specification  6 A entitled “Specification for Wellhead and Christmas Tree Equipment.” The independent screwed wellhead has independently secured heads for each tubular string supported in the well bore. The pressure within the casing is controlled by a blowout preventer (BOP) typically secured atop the wellhead. The head is said to be “independently” secured to a respective tubular string because it is not directly flanged or similarly affixed to the casing head. Independent screwed wellheads are widely used for production from low-pressure production zones because they are economical to construct and maintain. Independent screwed wellheads are typically utilized where working pressures are less than 3000 pounds per square inch (PSI). Further detail is found in U.S. Pat. No. 5,605,194 (Smith) entitled “Independent Screwed Wellhead with High Pressure Capability and Method” which provides an apt summary of the features, uses and limitations of independent screwed wellheads. 
   Flanged wellheads, as noted above, are employed where working pressures are expected to exceed 3000 PSI. Wellhead systems with flanged connections are frequently designed to withstand fluid pressures of 5000 or even 10,000 PSI. The downside of flanged wellheads (also known in the art as ranged wellheads) is that they are heavy, time-consuming to assemble, and expensive to construct and maintain. As noted in U.S. Pat. No. 5,605,194 (Smith), a 5000PSI ranged wellhead may cost two to four times that of an independent screwed wellhead with a working pressure rating of 3000 PSI. While oil and gas companies prefer to employ independent screwed wellheads rather than flanged wellheads, the latter must be used for high-pressure applications. Oil and gas companies are thus faced with a tradeoff between pressure rating and cost. 
   U.S. Pat. No. 5,605,194 (Smith) discloses an apparatus and method for temporarily reinforcing a low-pressure independent screwed wellhead with a high-pressure casing nipple so as to give it a high-pressure capability. The casing nipple described by Smith permits high-pressure fracturing operations to be performed through an independent screwed wellhead. Fracturing operations may achieve fluid pressures in the neighborhood of 6000 PSI, which the casing nipple is able to withstand even though the wellhead is only rated for 3000 PSI. 
   One of the disadvantages of the Smith casing nipple and method of use is that the casing nipple must be installed prior to fracturing and then removed prior to inserting the tubing string. As persons skilled in the art will readily appreciate, the steps of installing and removing the casing nipple generally entail killing the well, resulting in uneconomical downtime for the rig and potentially reversing beneficial effects of the fracturing operation. It is thus highly desirable to provide an apparatus and method which overcomes these problems. 
   There therefore exists a need for a wellhead system which withstands elevated fluid pressures and permits the extraction of subterranean hydrocarbons at less cost for the wellhead equipment. 
   SUMMARY OF THE INVENTION 
   It is therefore an object of the invention to provide a hybrid wellhead system which optimally combines the high-pressure rating of a flanged wellhead with the relative ease-of-use and low cost of an independent screwed wellhead. The hybrid wellhead is easier and more economical to manufacture and assemble, minimizes rig downtime, and is nonetheless able to withstand high fluid pressures (e.g., at least 5000 PSI). 
   The hybrid wellhead system is capable of withstanding elevated fluid pressures when subterranean hydrocarbon formations are stimulated in a well. The hybrid wellhead system has a plurality of tubular heads, each tubular head suspending a respective tubular string in the well, the tubular heads being connected to the hybrid wellhead system by threaded unions; and a tubing head spool mounted to the wellhead system having a top end that is flanged for connection to a flow-control stack. 
   The invention further provides a method of installing a wellhead for stimulating a well for the extraction of hydrocarbons therefrom, where the pressure may spike above a working pressure rating of an independent screwed wellhead, the method comprising the steps of: securing each successive tubular head to the wellhead using a threaded union; and securing a flow-control stack to the wellhead using a flanged connection. 


   
     BRIEF DESCRIPTION OF THE DRAWINGS 
     Further features and advantages of the present invention will become apparent from the following detailed description, taken in combination with the appended drawings, in which: 
       FIG. 1  is a cross-sectional elevation view of a conductor assembly having a conductor window fastened with a quick-connector to a conductor pipe that is, in turn, dug into the ground; 
       FIG. 2  is a cross-sectional elevation view of the conductor assembly shown in  FIG. 1  after a surface casing has been run in and a wellhead has been landed onto a conductor bushing; 
       FIG. 3  is a cross-sectional elevation view illustrating the removal of the conductor window, leaving behind the exposed wellhead; 
       FIG. 4  is a cross-sectional elevational view showing a drilling flange and a blowout preventer secured to the wellhead by a threaded union; 
       FIG. 5  is a cross-sectional elevation view of a test plug locked into place by locking pins in the drilling flange prior to retraction of the landing tool; 
       FIG. 6  is a cross-sectional elevational view illustrating a drill bushing locked in place inside the drilling flange; 
       FIG. 7  is a cross-sectional elevational view of an intermediate casing being run through the stack until an intermediate casing mandrel is landed onto the wellhead; 
       FIG. 8  is a cross-sectional elevational view illustrating the raising of the drilling flange and blowout preventer and the mounting of an intermediate head spool, or “B Section”, onto the wellhead and intermediate casing mandrel; 
       FIG. 9  is a cross-sectional elevational view showing a B Section test plug locked in place by locking pins in the drilling flange; 
       FIG. 10  is a cross-sectional elevational view of another drill bushing locked in place in the drilling flange; 
       FIG. 11  is a cross-sectional elevational view of a production casing being run through the stack until a production casing mandrel is landed in the intermediate head spool; 
       FIG. 12  is a cross-sectional elevational view depicting the removal of the blowout preventer and drilling flange from the intermediate head spool; 
       FIG. 13  is a cross-sectional elevational view of a tubing head spool secured by a nut to the intermediate head spool; 
       FIG. 14  is a cross-sectional elevational view of a tubing head pressure test tool inserted into the production casing for pressure-integrity testing; 
       FIG. 15  is a cross-sectional elevational view of slips attached to the intermediate casing to be used where the intermediate casing cannot be run to its predicted depth; 
       FIG. 16  is a cross-sectional elevational view of the slips seated in the casing bowl of the wellhead, showing a packing nut which is used to secure a seal plate on top of the slips; 
       FIG. 17  is a cross-sectional elevational view showing an intermediate head spool and drop sleeve being lowered onto the packing nut and wellhead; 
       FIG. 18  is a cross-sectional elevational view of the intermediate head spool secured to the wellhead with a drop sleeve above the packing nut, seal plate and slips; 
       FIG. 19  is a cross-sectional elevational view of a second embodiment of the intermediate casing mandrel which has been elongated to replace the drop sleeve and the slips; and 
       FIG. 20  is a cross-sectional elevational view of an assembled hybrid wellhead system showing a flow control stack flanged to the top of a tubing head spool, and threaded unions securing the tubing head spool to the intermediate head spool and securing the intermediate head spool to the wellhead. 
   


   It will be noted that throughout the appended drawings, like features are identified by like reference numerals. 
   DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS 
   For the purposes of this specification, the expressions “wellhead system”, “tubular head”, “tubular string”, “mandrel”, and “threaded union” shall be construed in accordance with the definitions set forth in this paragraph. The expression “wellhead system” shall denote a wellhead (also known as a “casing head” or “surface casing head”) mounted atop a conductor assembly which is dug into the ground and which has, optionally mounted thereto, various Christmas tree equipment (for example, casing head housings, casing and tubing head spools, mandrels, hangers, connectors, and fittings). The wellhead system may also be referred to as a “stack” or as a “wellhead-stack assembly”. The expression “tubular head” shall denote a wellhead body such as a tubing head spool used to support a tubing mandrel, intermediate head spool (also known as a “B Section”) or a wellhead (also known as a casing head). The expression “tubular string” shall denote any casing or tubing, such as surface casing, intermediate casing, production casing or production tubing. The expression “mandrel” shall denote any generally annular mandrel body such as a production casing mandrel, intermediate casing mandrel or a tubing hanger (also known as a tubing mandrel or production tubing mandrel). The expression “threaded union” shall denote any threaded connection such as a nut, sometimes also referred to as a wing-nut, spanner nut, or hammer unions. 
   Prior to boring a hole into the earth for the extraction of subterranean hydrocarbons such as oil or natural gas, it is first necessary to “build the location” which involves removing any soil, sand, clay or gravel to the bedrock. Once the location is “built”, the next step is to “dig the cellar” which entails digging down approximately 40–60 feet, depending on bedrock conditions. The “cellar” is also known colloquially by persons skilled in the art as the “rat hole”. 
   As illustrated in  FIG. 1 , a conductor  12  is inserted (or, in the jargon, “stuffed”) into the rat-hole that is dug into the ground or bedrock  10 . The upper portion of the conductor  12  that protrudes above ground level is referred to as a “conductor nipple”  13 . A conductor ring  14  (also known as a conductor bushing) is fitted atop the upper lip of the conductor nipple  13 . The conductor ring  14  has an upper beveled surface defining a conductor bowl  14   a.    
   A conductor window  16 , which has discharge ports  15 , is connected to the conductor nipple  13  via a conductor pipe quick connector  18 , which uses locking pins  19  to fasten the conductor window  16  to the conductor nipple  13 . When fully assembled, the conductor window  16 , the conductor ring  14  and the conductor  12  constitute a conductor assembly  20 . At this point, a drill string (not shown, but well known in the art) is introduced to bore a hole that is typically 600–800 feet deep with a diameter large enough to accommodate a surface casing. 
   As depicted in  FIG. 2 , after drilling is complete, a surface casing  30  is inserted, or “run”, through the conductor assembly  20  and into the bore. The surface casing  30  is connected by threads  32  at an upper end to a wellhead  36  in accordance with the invention. The wellhead  36  has a bottom end  34  shaped to rest against the conductor bowl  14   a . The surface casing  30  is run into the bore until the bottom end  34  of the wellhead contacts the conductor bowl  14   a , as illustrated in  FIG. 2 . 
   As shown in  FIG. 2 , the surface casing  30  is a tubular string having an outer diameter less than the inner diameter of the conductor  12 , thereby defining an annular space  33  between the conductor and the surface casing. The annular space  33  serves as a passageway for the outflow of mud when the surface casing is cemented in, a step that is well known in the art. Mud flows back up through the annular space  33  and out the discharge ports  15  located in the conductor window  16 . The annular space  33  is eventually filled up with cement during the cementing stage so as to set the surface casing in place. 
   A wellhead  36  (also known as a “surface casing head”) in accordance with the invention is connected to the surface casing  30  by threads  32  to constitute a wellhead-surface casing assembly. The wellhead  36  has side ports  37  (also known as flow-back ports) for discharging mud during-subsequent cementing operations (which will be explained below). As illustrated in  FIG. 3 , the wellhead  36  also has a casing bowl  38 , which is an upwardly flared bowl-shaped portion that is configured to receive a casing mandrel, as will be further explained below. As illustrated in  FIG. 2 , the wellhead  36  is connected by threads to a landing tool  39  via a landing tool adapter  39   a . The landing tool  39  is used to insert the wellhead-surface casing assembly and to guide this assembly down into the bore until the wellhead contacts the conductor bowl. The casing bowl  38  of the wellhead  36  is set as soon as cementing is complete (to minimize rig down time). Once the surface casing  30  is properly cemented into place, the landing tool  39  and landing tool adapter  39   a  is unscrewed from the wellhead  36  and removed. 
   As depicted in  FIG. 3 , the conductor window  16  is then detached from the conductor  12  by disengaging the locking pins  19  of the quick connector  18 . After the conductor window  16  has been removed, as shown, what remains is the wellhead-surface casing assembly, i.e., the wellhead  36  sitting atop the conductor ring  14  and the conductor  12  with the surface casing  30  suspended from the wellhead. 
     FIG. 4  depicts a drilling flange  40  in accordance with the invention, and a blowout preventer  42 , together constituting a pressure-control stack, secured to the wellhead  36  by a threaded union  44 , such as a lockdown nut or hammer union. The drilling flange  40  and blowout preventer  42  can be installed while waiting for the cement to set, further reducing rig down time. The wellhead  36  has upper pin threads for engaging box threads of the threaded union  44 . The blowout preventer (BOP) is secured to the top surface of the drilling flange  40  with a flanged connection. A metal ring gasket  41  is compressed between the drilling flange  40  and the wellhead  36  to provide a fluid-tight seal. The metal ring gasket is described in detail in the applicant's co-pending U.S. patent application Ser. No. 10/690,142 filed Oct. 21, 2003, the specification of which is incorporated herein by reference. The ring gasket ensures a fire-resistant, high-pressure seal. The drilling flange  40  also optionally has two annular grooves  41   a  in which O-rings are seated for providing a backup seal between the wellhead and the drilling flange. 
   The drilling flange  40  further includes locking pins  46  which are located in transverse bores in the drilling flange  40 , and which are used to lock in place plugs and bushings as will be described below in more detail. The drilling flange  40  and blowout preventer  42  are mounted to the wellhead  36  in order to drill a deep bore into or adjacent to one or more subterranean hydrocarbon formation(s). But before drilling can be safely commenced, the pressure-integrity of the wellhead system, or “stack”, should be tested. 
     FIG. 5  illustrates the insertion of a test plug  50  in accordance with the invention for use in testing the pressure-integrity of the stack. The pressure-integrity testing is effected by plugging the stack with the test plug  50 , closing all valves and ports (including a set of pipe rams and blinds rams on the BOP) and then pressurizing the stack. The test plug is described in detail in Applicant's co-pending U.S. patent application. 
   As illustrated in  FIG. 5 , the test plug  50  has a bull-nosed bottom portion  51  which has an annular shoulder for supporting above it a metal gauge ring  52 , an elastomeric backup seal  53  and an elastomeric cup  54 , which is preferably made of nitrile rubber, although other elastomers or polymers may be used. The cup  54  includes a pair of annular grooves  54   a  into which O-rings may be seated to provide a fluid-tight seal between the cup  54  and the bull-nosed bottom portion  51 . The test plug  50  further includes a tubular extension  55  which is threaded at a bottom end to support the bull-nosed end portion  51 . A top end of the tubular extension  55  is integrally formed with an upper shoulder  56 . The upper shoulder  56  abuts an annular constriction in the drilling flange  40  as shown in  FIG. 5 . When the upper shoulder  56  has abutted the annular constriction, the locking pins  46  in the drilling flange  40  are screwed inwardly to engage an upper surface of the upper shoulder  56 , thereby securing the test plug inside the stack. The upper shoulder  56  further includes a plurality of fluid passages  57  through which fluid may flow during pressurization of the stack. 
   The test plug  50  is inserted and retracted using a test plug landing tool  59  which is threaded to the test plug  50  inside an internally threaded socket  58 , which extends upwardly from the upper shoulder  56 . After the test plug landing tool  59  has been removed, the stack is pressurized to an estimated operating pressure. Due to the design of the test plug  50 , the pressure-integrity of the joint between the wellhead and the surface casing is tested, as well as the pressure-integrity of all the joints and seals in the stack above the wellhead. 
   A typical test procedure begins with shutting the BOP pipe rams for testing of the pipe rams to at least the estimated operating pressure. The test plug  50  is then locked with the locking pins  46  and the landing tool  59  is removed. The BOP blind rams are then shut and tested to at least the estimated operating pressure. If all seals and joints are observed to withstand the test pressure, the test plug can be removed to make way for the drill string. 
   As shown in  FIG. 6 , after the pressure-integrity of the stack is confirmed, preparations for drilling are commenced. This involves the insertion of a wear bushing  60  using a wear bushing insertion tool  62 . The wear bushing insertion tool  62  includes a landing joint  64  which is used to insert the wear bushing  60  to the correct location inside the drilling flange  40 . The wear bushing insertion tool  62  also includes a bushing holder  66  threadedly connected to a bottom end of the landing joint  64  for holding the wear bushing  60 . The wear bushing  60  is landed in the drilling flange  40 , and is then locked in place by the locking pins  46 . A head  46   a  of each locking pin  46  engages an annular groove  68  in the wear bushing, thereby locking the wear bushing  60  in place. 
   Once the wear bushing  60  is locked in place, the wear bushing insertion tool  62  is retracted, leaving the wear bushing  60  locked inside the drilling flange  40 . The stack is thus ready for drilling operations. A drill string (not illustrated, but well known in the art) is introduced into the stack so that it may rotate within the wear bushing. The wear bushing is installed to protect the casing bowl and surface casing from the deleterious effects of a phenomenon known in the art as “Kelley Whip”. With the wear bushing in place, drilling of a bore (to the intermediate casing depth) may be commenced. 
   The drilling rig runs the drilling string into the well bore and stops a safe distance above a cement plug. After an appropriate cement curing time, drilling resumes. When a desired depth for an intermediate casing is reached, the drilling string is removed from the well bore. 
   As illustrated in  FIG. 7 , the intermediate casing  70  is run through the stack and into the well bore. In certain jurisdictions, industry regulations require that intermediate casing be run when exploiting a deep, high-pressure well. The intermediate casing serves to ensure that the deep production zone is isolated from porous shallower zones in the event that a production casing is ruptured. 
   As depicted in  FIG. 7 , the intermediate casing  70  is secured and suspended in the well bore by an intermediate casing mandrel  72 . The intermediate casing mandrel  72  is threaded to the intermediate casing  70  at a lower threaded connection  71 . The intermediate casing mandrel  72  is threaded to a landing tool  74  at an upper threaded connection  73 . The intermediate casing mandrel  72  has a lower frusta-conical end  75  shaped to be seated in the casing bowl  38  of the wellhead  36 . The lower frusta-conical end  75  of the intermediate casing mandrel  72  has a pair of annular grooves  76  in which O-rings are seated to provide a fluid-tight seal between the intermediate casing mandrel and the wellhead. The intermediate casing  70  is cemented into place by flowing back mud through the side ports  37  of the wellhead  36 , in a manner well known in the art. 
   As illustrated in  FIG. 8 , after the landing tool  74  is detached and removed from the intermediate casing mandrel  72 , the drilling flange  40  and the blowout preventer  42  are raised to accommodate an intermediate head spool  80  in accordance with the invention. The intermediate head spool  80  is secured by threaded unions between the drilling flange  40  at the top and the wellhead  36  at the bottom. 
   As shown in  FIG. 8 , the intermediate head spool  80  has a pair of flanged side ports  81 . The intermediate head spool  80  also has a set of upper pin threads  82  for engaging a set of box threads on the threaded union  44 . A metal ring gasket, as described in the Applicant's co-pending application referenced above, is seated in an annular groove  83  atop the intermediate head spool  80 . The drilling flange  40  is secured to the intermediate head spool  80  by the threaded union  44  which compresses the metal ring gasket between the drilling flange  40  and the intermediate head spool  80  to form a fire-resistant, high-pressure seal. 
   As further shown in  FIG. 8 , the intermediate head spool  80  also has a bowl-shaped seat  84  for seating a tubing hanger, as will be described below. Below the side ports  81 , the intermediate head spool  80  has a pair of injection ports  85  for injecting plastic injection seals  86 . Adjacent to the injection ports are test ports  87 . The intermediate head spool  80  further includes a lower annular shoulder  88  which has an annular groove  89 . The intermediate head spool  80  is secured to the well-head  36  by a lockdown nut  90 . The top surface of the wellhead  36  has an annular groove  36   a  which aligns with the annular groove  89  in the bottom surface of the intermediate head spool  80 . A metal ring gasket is located in the annular grooves  36   a ,  89  and is compressed to form a fluid-tight seal when the intermediate head spool  80  is secured to the wellhead  36 . Finally, as shown in  FIG. 8  and  FIG. 9 , a seal ring  92 , having four annular grooves  94  for O-rings provides a spacer and a seal beneath the intermediate head spool  80 , between the top of the wellhead and the intermediate casing mandrel. 
   Illustrated in  FIG. 9  is a “B Section test tool”  100  (also known as the intermediate head test tool) which is secured inside the stack for use in pressure-integrity testing as described above with reference to  FIG. 5 . As explained, bull-nosed bottom portion  101  which has an annular shoulder for supporting above it a metal gauge ring  102 , an elastomeric backup seal  103  and an elastomeric cup  104 , which is preferably made of nitrile rubber, although other elastomers or polymers may be used. The cup  104  includes a pair of annular grooves  104   a  into which O-rings may be seated to provide a fluid-tight seal between the cup  104  and the bull-nosed bottom portion  101 . The test plug  100  further includes a tubular extension  105  which is threaded at a bottom end to support the bull-nosed end portion  101 . A top end of the tubular extension  105  is integrally formed with an upper shoulder  106 . The upper shoulder  106  abuts an annular constriction in the drilling flange  40  as shown. When the upper shoulder  106  has abutted the annular constriction, the locking pins  46  in the drilling flange  40  are screwed inwardly to engage an upper surface of the upper shoulder  106 , thereby securing the test plug inside the stack. The upper shoulder  106  further includes a plurality of fluid passages  107  through which fluid may flow during pressurization of the stack. 
   The B section test plug  100  is inserted and retracted using the test plug landing tool  59 , which is threaded to the test plug  100  inside an internally threaded socket  108 , which extends upwardly from the upper shoulder  106 , as described above. After the test plug landing tool  109  has been removed, the stack is pressurized to at least an estimated operating pressure. Due to the design of the B section test plug  100 , the pressure-integrity of the joint between the intermediate casing and the intermediate casing mandrel (as well as the pressure-integrity of all the joints and seals above it in the stack) are pressure tested. 
   A typical test procedure begins with shutting the BOP pipe rams for testing of the pipe rams to the estimated operating pressure. The B section test plug  100  is then locked with the locking pins  46  and the landing tool  59  is removed. The BOP blind rams are then shut and tested to the estimated operating pressure. After a satisfactory test, the blind rams are opened and the landing tool is reinstalled. Finally, if all seals and joints are observed to withstand the estimated operating pressure, the locking pins  46  are released and the B section test plug  100  is removed. 
     FIG. 10  shows the installation of an intermediate wear bushing  110  in the drilling flange  40 . The intermediate wear bushing  110  is installed using an insertion tool  112 , which is very similar to the insertion tool  62  described above with reference to  FIG. 6 . The insertion tool  112  includes a landing joint  114 , which is used to insert the intermediate wear bushing  110  to the correct location inside the drilling flange  40 . The insertion tool  112  also has a bushing holder  116  threadedly connected to a bottom end of the landing joint  114  for holding the intermediate wear bushing  110 . The intermediate wear bushing  110  is aligned with the drilling flange  40  and is then locked in place by the locking pins  46 . A head  46   a  of each locking pin  46  engages an annular groove  118  in the wear bushing thereby locking the intermediate wear bushing  110  in place. 
   Once the intermediate wear bushing  110  is locked into place, the insertion tool  112  is retracted, leaving the wear bushing  110  locked inside the drilling flange  40 . The stack is thus ready for drilling operations. A drill string (not shown) is run into the stack and rotates within the intermediate wear bushing, as described above. 
   After the desired bore is drilled, the drill string and associated collars and wear bushing are removed from the stack. As shown in  FIG. 11 , a production casing string  120  is then run and a production casing mandrel  122  is staged for cementing. 
     FIG. 11  illustrates how, after cement is run, the production casing mandrel  122  is landed onto the B section, or intermediate head spool  80 , using a landing tool  124 . The production casing mandrel  122  is secured by a box thread  121  to the production casing  120 . The production casing mandrel  122  is secured to the landing tool  124  by a box thread  123 . The production casing mandrel  122  has a frusta-conical bottom end  126  that sits in the bowl-shaped seat  84  of the intermediate head spool  80 . The frusta-conical bottom end  126  has a pair of annular grooves  128  in which O-rings are received for providing a fluid-tight seal between the production casing mandrel  122  and the intermediate head spool  80 . 
   After the production casing mandrel  122  is landed in the intermediate head spool  80 , the landing tool  124  is disconnected from the production casing mandrel and removed. Next, the drilling flange  40  and the blowout preventer  42  are removed as a unit (along with the threaded union  44 ) as illustrated in  FIG. 12 . The production casing mandrel  122  sits exposed atop the remainder of the stack. 
     FIG. 13  depicts a tubing head spool  130  secured by a lockdown nut  140  to the intermediate head spool  80 . The tubing head spool  130  includes a pair of flanged side ports  131  and a top flange  132 . The top flange  132  has an annular groove  133  for receiving a standard metal ring gasket (not shown), which is well known in the art. The top flange  132  also has transverse bores for housing locking pins  134 . The tubing head spool  130  has a stepped central bore  130   a.    
   As shown in  FIG. 13 , the tubing head spool  130  further includes a inner shoulder  135  which has a bowl-shaped seat  135   a . The inner shoulder  135  abuts a top surface of the production casing mandrel  122 . Below the inner shoulder  135  is a bottom annulus  136 , which includes an outer shoulder  136   a  that is engaged by the threaded union  140  when the threaded union  140  is tightened. Beneath the outer shoulder  136   a  is an annular groove  136   b  which aligns with the matching annular groove  83  in a top of the intermediate head spool  80 . As shown in  FIG. 13 , the outer shoulder  136   a  abuts the top surfaces of the seal ring  92  and the intermediate head spool  80 . A metal ring gasket is seated in the annular grooves  136   b ,  83 . The metal ring gasket is described in detail in Applicant's co-pending application referenced above. 
   The bottom annulus  136  has two injection ports  137  through which two plastic injection seals  138  are injected. The bottom annulus  136  also has a pair of test ports  139  for use in pressure-integrity testing. 
     FIG. 14  illustrates a tubing head test plug  150  installed inside the bore of the stack for pressure-integrity testing. Landed in the position shown, the test plug  150  permits pressure-integrity testing of the joint between the production casing  120  and the production casing mandrel  122 , as well as all the joints and seals above that joint. 
   The test plug  150  has a solid bull-nosed end piece  151  which has an upper annular shoulder upon which is supported a metal gauge ring  152 , an elastomeric backup seal  153 , and an elastomeric cup  154 . The gauge ring  152 , backup seal  153  and cup  154  provide a fluid-tight seal between the test plug  150  and the production casing  120 . The cup  154  includes two annular grooves  154   a  in which O-rings may be seated for providing a fluid-tight seal between the bull-nosed end piece  151  and the cup  154 . At an upper portion of the bull-nosed end piece are threads for connecting to a tubular extension  155 . The tubular extension  155  has an opening  155   a  through which pressurized fluid flows during pressurization of the stack. The tubular extension has a flared section  156  with three O-ring grooves  156   a . The flared section  156  has a lower beveled shoulder  157  which sits in the bowl-shaped seat  135   a  of the tubing head spool  130 . A top end of the tubular extension  155  has a pin thread  158  and a sealing end section  159  for sealed connection to a Bowen union  160 . 
   The Bowen union  160  includes a bottom flange  161 , a Bowen adapter  162 , and a ring gasket groove  163  which aligns with the annular groove  133  in the tubing head spool  130  for receiving a standard metal ring gasket. The Bowen union  160  further includes a pair of annular grooves  164  in which O-rings are seated for providing a fluid-tight seal between the Bowen union  160  and the sealing end section  159  of the tubular extension  155 . The Bowen union  160  further includes a set of box threads  165  for engaging the threads  158  on the tubular extension  155 . 
   For pressure-integrity testing of the stack, the Bowen union  160  is connected to a high-pressure line (which is not shown, but is well known in the art). Pressurized fluid is pumped through the central bore of the stack, through the opening  155   a  in the tubular extension  155  and into the annular space  150   a  between the tubular extension  155  and the production casing mandrel  122  and product-ion casing  120 . 
   After the pressure-integrity testing has been satisfactorily completed, the high-pressure line is disconnected from the Bowen union  160  and the test plug  150  and Bowen union  160  are then removed from the stack. The hybrid wellhead system is then ready for completion. 
   In some cases, the intermediate casing string  70  cannot be run to the desired depth because of debris or some other blockage at or near the bottom of the well bore, or because the string length was miscalculated. In that case, slips  170  are affixed to the intermediate casing  70 , as illustrated in  FIG. 15 . The slips  170  are frusta-conically shaped to be seated in an upwardly flared casing bowl  38 ′ of a wellhead  36 ′. As shown, the wellhead  36 ′ is a variant of the wellhead  36 . The wellhead  36 ′ has a modified casing bowl  38 ′, i.e., the casing bowl  38 ′ provides more angle with respect to the vertical and has a longer contact surface than the standard casing bowl  38 . The casing bowl  38 ′ is thus designed to support a tubular string using the slips  170 . The casing bowl  38 ′ includes side ports  37 ′. The casing bowl  38 ′ is thus designed to support a tubular string using the slips  170 . 
   Ordinarily, if the intermediate casing  70  can be fully run to the desired depth, the drilling flange  40  and the BOP  42  remain installed while the intermediate casing mandrel  72  is landed, as was shown in  FIG. 7 . However, as shown in  FIG. 15 , to permit the attachment of the slips  170 , it is necessary to remove the drilling flange  40  and the BOP  42 . 
   As illustrated in  FIG. 16 , the slips  170  are seated in the casing bowl  38 ′ of the wellhead  36 ′. The intermediate casing  70  is thus suspended in the well bore. An annular seal plate  172  having four annular grooves  174  for accommodating O-rings is seated on a top surface  171  of the slips  170  and on an annular ledge  171   a  of the wellhead  36 ′. As illustrated, the top surface  171  and the annular ledge  171   a  are not horizontally flush. Accordingly, the underside of the annular seal plate  172  has an annular recess  173  for accommodating the annular ledge  171   a.    
   A packing nut  176  is secured atop the annular seal plate  172 . The packing nut  176  has external threads  178 , which engage internal threads  31 ′ on an upper annular extension  35 ′ of the wellhead  36 ′. The upper annular extension  35 ′ also has external threads for meshing with a lockdown nut as will be described below. 
   As shown in  FIG. 17 , an intermediate head spool  80 ′ (also known as a B section) is installed atop the wellhead  36 ′ and the packing nut  176 . The intermediate head spool  80 ′ is almost identical to the intermediate head spool  80  shown in  FIGS. 8–14  except for the lower annular shoulder  88 ′ which further includes a lower annular protrusion  88   a ′ to accommodate the upper annular extension  35 ′ of the wellhead  36 ′. 
   As illustrated in  FIG. 17 , the intermediate head spool  80 ′ is secured to the wellhead  36 ′ by a threaded union  90 ′. A drop sleeve  180  is inserted as a spacer between the intermediate casing  70  and the intermediate head spool  80 ′, backing against the plastic injection seals  86  and test ports  87 . The drop sleeve  180  fits beneath an annular shoulder in the intermediate head spool and above the packing nut  176 . The drop sleeve  180  has four annular grooves  182  in which O-rings are seated for providing a fluid-tight seal between the drop sleeve  180  and the intermediate casing  70 . 
     FIG. 18  illustrates the intermediate head spool  80 ′ secured to the wellhead  36 ′ by the threaded union  90 ′. The intermediate casing string  70  is secured and suspended in the well by the slips  170  which are seated in the casing bowl  38 ′ of the wellhead  36 ′. The annular seal plate  172  (with O-rings in the grooves  174 ) provides a seal while the packing nut  176  secures the seal plate  172  and the slips  170  to the wellhead  36 ′. The drop sleeve  180  (with four O-rings in the grooves  182 ) acts as a spacer and seal between the intermediate head spool  80 ′ and the intermediate casing  70 , above the packing nut  176 . As shown in  FIG. 18 , a drilling flange  40  (with a BOP mounted thereto, but not shown) is then secured to the intermediate head spool  80 ′ using the threaded union  44 . The threaded union  44  has a box thread that engages the upper pin thread  82  on the intermediate head spool  80 ′. A metal ring gasket is seated in the annular groove  83 . Along with two adjacent O-rings, the metal ring gasket provides a fluid-tight seal between the drilling flange  40  and the intermediate head spool  80 ′. 
     FIG. 19  illustrates a second embodiment of the intermediate casing mandrel  72 ′ which is designed for use in conjunction with the wellhead  36 ′. The intermediate casing mandrel  72 ′ has a box thread  71  for securing and suspending the intermediate casing  70  in the well. The intermediate casing mandrel  72 ′ includes a frusta-conical bottom end  75 ′ that is contained at the same level as the slips  170  shown in  FIG. 18 . The frusta-conical bottom end  75 ′ has a larger contact surface with the wellhead  36 ′, and is thus well suited for supporting a long intermediate casing string required in a particularly deep well. 
   As illustrated in  FIG. 19 , the frusta-conical bottom end  75 ′ has three annular grooves  77  in which O-rings are seated to provide a fluid-tight seal between the intermediate casing mandrel  72 ′ and the wellhead  36 ′. The intermediate casing mandrel  72 ′ has a top end  79  that acts as a spacer, and replaces the drop sleeve  180  shown in  FIG. 18 . A thinner seal plate  172 ′ and a thinner packing nut  176 ′ accommodate the top end  0 . 79 . The seal plate  172 ′ also has four annular grooves  174  in which O-rings are seated to provide a fluid-tight seal between the intermediate casing mandrel  72 ′ and the wellhead  36 ′. The plastic injection seals  85  also provide a fluid-tight seal with the top end  79  of the intermediate casing mandrel  72 ′. 
   The intermediate head spool  80 ′ is secured by the threaded union  90 ′ to the wellhead  36 ′. The intermediate head spool  80 ′ abuts the top end  79  of the intermediate casing mandrel  72 ′. The outer shoulder  88 ′ abuts the top of the wellhead  36 ′. The bottom annulus  88   a ′ abuts the top of the packing nut  176 ′. 
     FIG. 20  illustrates a completed hybrid wellhead system which includes wellhead  36 , an intermediate head spool  80 , a tubing head spool  180 , and a flow-control stack  200 . As illustrated and described above, the wellhead  36  is secured to the surface casing  30 , the intermediate casing mandrel  72  is connected to the intermediate casing  70 , and the production casing mandrel  122  is connected to the production casing  120 . The tubing head spool  180  supports a tubing hanger  182  that is locked down by locking pins  184 . The tubing hanger  182  has a box thread  188  for securing and supporting a production tubing string  190  within the production casing  120 . The tubing head spool  180  is secured to the intermediate head spool  80  by a threaded union  195 . 
   The flow-control stack  200  is flanged to a top flange  185  of the tubing head spool  180 . The top flange  185  includes a ring gasket groove  186  which aligns with an annular groove  202  in the flow control stack  200  for receiving a standard metal ring gasket. The flow-control stack  200  may include any one or more of a flow tee, choke, master valve or production valves. These flow-control devices are well known in the art and are not described in further detail. The tubing hanger  182  also has a pair of annular grooves  183  in which O-rings are seated for providing a fluid-tight seal between the tubing head spool  180  and the tubing hanger  182 . 
     FIG. 20  illustrates threaded unions for securing the intermediate head spool to the wellhead and for securing the tubing head spool to the intermediate head spool. A flanged connection is used for securing the flow-control stack to the tubing head spool, to permit a standard flow control stack to be used for hydrocarbon production. This hybrid wellhead system is capable of withstanding higher fluid pressures than independent screwed wellheads (which are typically rated at no more than 3000 PSI). The wellhead has a working pressure rating of 3000–5000 PSI. The intermediate head spool has a working pressure rating of 10,000 PSI. The tubing head spool has a working pressure rating of 10,000–15,000 PSI and higher working pressures can be accommodated, if required. 
   Persons skilled in the art will appreciate that other combinations of heads, fittings and components may be assembled in the manner described above to form a hybrid wellhead system. The embodiments of the invention described above are therefore intended to be exemplary only. The scope of the invention is intended to be limited solely by the scope of the appended claims.