Abstract:
Apparatus for inserting a tubing hanger into a tubing head spool on a live well includes a landing spool and a landing joint that reciprocates through a top end of the landing spool. The landing joint is connected to the tubing hanger. The landing spool is connected to a top flange of a blowout preventer on the live well. The blowout preventer is then opened and the tubing hanger is injected into the tubing head spool. A lifting spool is also provided to permit the tubing hanger to be injected without the use of a service rig. Safety is improved, costs reduced and production is facilitated because the well does not have to be killed.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This is the first application filed for the present invention. 
     MICROFICHE APPENDIX 
     Not Applicable. 
     TECHNICAL FIELD 
     The present invention relates in general to methods and apparatus for installing wellhead equipment in live wells, and, in particular, to a method and apparatus for inserting a tubing hanger into a tubing head spool installed on a live well. 
     BACKGROUND OF THE INVENTION 
     Production tubing is commonly used in oil wells for production purposes after an oil well has been completed or recompleted. Wells are frequently stimulated during the completion and recompletion processes. During well stimulation, high pressure fluids are pumped at high rates into one or more production zones of the well in order to fracture the hydrocarbon bearing formations to release trapped hydrocarbons. After the well has been completed or recompleted, fluid pressures in the well are typically greater than atmospheric pressure, and must be contained in order to prevent the loss of hydrocarbons to atmosphere. 
     In many cases, after a well is stimulated, well operators prefer to prepare the well for production without “killing” the well. A well is killed by pumping overbearing fluids into the well to contain fluid pressures in the well. Killing the well is generally considered undesirable because the kill fluids can potentially hinder production by disturbing the affects of the well treatment procedure. Consequently, production tubing is generally run into the live well using injection methods that are well known in the art. When the production tubing is run into a live well, a retrievable plug is first inserted into the bottom end of the tubing. This prevents hydrocarbons from escaping through the production tubing as it is run into the well. Jointed tubing or coil tubing may be used for production. In either case, tubing rams on blowout preventers (BOPs) are used to seal around the tubing while the tubing is being run into the well. If jointed tubing is used, the tubing is generally run through a snubbing unit, as is well understood in the art. 
     After the production tubing string has been run into the well, however, a tubing hanger must be set in the tubing head spool to suspend the production tubing string in the well. The tubing hanger is connected to a top end of the tubing string, and special equipment is required to run the tubing hanger into the tubing spool. 
     FIG. 1 is a schematic diagram of equipment that is frequently used to install a tubing hanger on a live well, generally indicated by reference  10 . The live well includes a casing spool  12 , to which a tubing head spool  14  is mounted. Tubing head spool  14  generally includes one or more tubing head valves  16 , which communicate with an annulus of the well in a manner well known in the art. Mounted to a top of the tubing head spool is a ram-type blowout preventer (BOP)  18  having a set of opposed tubing rams  20 , which are used to close an annulus of the well bore around a production tubing of a known diameter, and a set of opposed blind rams  22  which are used to completely block the annulus but cannot be used to close around tubing or other components. Mounted to the top of the ram-type BOP is an annular BOP  24 , available, for example, from Hydril Company, Houston, Tex. The annular BOP  24  employs a flexible rubber packing unit to provide pressure seal-off at the wellhead. The annular BOP can contain annulus pressure on an open hole or around tubular elements inserted into the well, such as production tubing  30  and tubing hanger  32 . The production tubing  30  and the tubing hanger  32  are inserted into the well using a landing joint  34  controlled by blocks  36  of a service rig, the remainder of which is not shown. Service rigs are well known in the art. 
     The paired BOPs shown in FIG. 1 are capable of sealing around the production tubing  30 , a tubing collar (not shown), the tubing hanger  32 , and the landing joint  34  as they are respectively run into the live well bore. These respective components run through the BOPs to the tubing head spool  14  in the order specified. The landing joint  34  is screwed into a top of the tubing hanger  32  and is connected to the blocks  36  of the service rig. The respective components are then stepped through the BOPs  24 ,  18  as the pipe rams  20  and the annular BOP  24  are opened and closed in sequence to permit the tubing hanger to be inserted into the tubing head spool while the live well is under pressure. Although this procedure is known to work reliably and has been approved by regulatory authorities, it has several disadvantages. First, the respective BOPs  18 ,  24  add significantly to the height over the well, thus making the floor of the rig (not shown) very high and a potentially dangerous place to work. Furthermore, in certain jurisdictions safety laws require that a completion rig be moved away from the well before and during a well stimulation treatment, in order to provide adequate working space in the case of emergency. After well stimulation is completed, the rig must be moved back over the well, usually for the sole purpose of landing the tubing hanger and installing the wellhead after the tubing hanger has been landed in the live well. This is a costly operation, and it would be more cost-effective and beneficial if the well operator were able to release the service rig after the tubing is run into the well, to clear valuable work area and to reduce expense by releasing the service rig as early as possible. 
     Consequently, there exists a need for a method and apparatus for setting a tubing hanger in a tubing head spool on a live well which is easier and more cost-effective than the known method described above. 
     SUMMARY OF THE INVENTION 
     It is an object of the invention to provide an apparatus for setting a tubing hanger in a tubing head spool on a subterranean well in which a fluid pressure in the well is greater than atmospheric pressure. 
     It is a further object of the invention to provide a method of setting a tubing hanger in a tubing head spool on a subterranean well in which a fluid pressure in the well is greater than atmospheric pressure. 
     It is yet a further object of the invention to provide a method and apparatus for setting a tubing hanger in a tubing head spool on a live well without the use of a service rig. 
     The invention therefore provides an apparatus for setting a tubing hanger in a tubing head spool in a subterranean well in which a fluid pressure is greater than atmospheric pressure. Such wells are commonly referred to as “live wells”. The apparatus comprises a landing spool which is mounted to a ram-type blowout preventer (BOP). The BOP is in turn mounted to the tubing head spool. The landing spool includes a flange for sealing attachment to the BOP and a top end through which a landing joint is reciprocated. The top end of the landing spool provides a high-pressure seal to prevent an escape of hydrocarbons as all the landing joint is reciprocated therethrough. A sidewall of the landing spool preferably includes a pressure bleed port to permit an equalization of pressure between the landing spool and the well, or an equalization of pressure between the landing spool and atmosphere. Lifting hooks or eyes are also provided on the sidewall of the landing spool, to permit the connection of flexible members, such as chains or cables, to support the landing spool before it is connected to a top flange of the BOP. 
     The top end of the landing spool through which the landing joint is reciprocated includes a packing cavity that receives high-pressure packing, such as Chevron packing. The high-pressure packing is retained in the packing cavity by a packing nut, such as a gland nut, well known in the art. The packing nut is preferably reinforced by a safety nut that engages a threaded outer perimeter of the top end of the landing spool. The safety nut has an inwardly-extending top wall that closely surrounds the landing joint and covers the gland nut to ensure that the high-pressure packing is not ejected by fluid pressures in the live well. 
     In accordance with a further embodiment of the invention, the apparatus further includes a lifting spool adapted to be mounted between the landing spool and the BOP. The lifting spool includes a bottom flange adapted to be mounted to a top of the BOP and a top flange to which the landing spool is mounted. Both the top and bottom flanges of the lifting spool are adapted to accommodate high-pressure gaskets to provide a high-pressure fluid seal between adjacent components. The lifting spool includes at least two attachment points for the connection of lift mechanisms for supporting and vertically displacing a lifting beam to which a top end of the landing joint is connected. By actuating the lift mechanisms, the landing joint and the attached tubing hanger and production tubing string may be lifted to release slips supporting the tubing, or lowered to inject the tubing hanger into the tubing spool. The lift mechanisms are preferably hydraulic cylinders, although other lift mechanisms such as ball jacks, or the like, may be used. The attachment points are, for example, slots formed in a top of respective lift arms of the lifting spool. Transverse bores pierce the slots. The slots receive mounting lugs which are likewise pierced by a transverse bore. Pins pass through the transverse bores in the lift arms and the mounting lugs to secure the lift mechanisms to the lifting spool. 
     The lifting beam is attached to the rams to support the landing joint as described above. The landing joint is preferably connected to the lift beam by a swivel joint or a hydraulic motor. If a swivel joint is used, the landing joint may be rotated using a wrench, to connect the landing joint to a top of the tubing hanger, as well as to swivel the production tubing if a downhole packer, hanger, plug or some other downhole attachment must be set. A hydraulic motor is used for the same purpose and is beneficial if the well is deep and long runs of tubing must be manipulated in order to seat a downhole packer, or the like. 
     The lifting beam preferably further includes pulleys, winches or come-alongs mounted adjacent the lift mechanisms. The pulleys, winches or come-alongs control the cables or chains used to support the landing spool before it is connected to a top flange of the lifting spool. After the landing joint is connected to the tubing hanger and slips supporting the tubing are removed, the landing spool is lowered, using the pulleys, winches or come-alongs, onto a top flange of the lifting spool and the landing spool is connected to the lifting spool to provide a fluid-tight seal around the landing joint. 
     The invention further provides a method of setting a tubing hanger in a tubing head spool of a subterranean well in which a fluid pressure in the well is higher than atmospheric pressure. The method comprises steps of supporting a plugged tubing string run into the well through a BOP. The tubing string is supported using slips to inhibit the tubing string from falling into the well, so that a tubing hanger can be connected to a top end of the tubing string. The landing spool and landing joint are hoisted into vertical alignment with the tubing hanger and the landing joint is connected to the tubing hanger. A lift mechanism is connected to a top end of the landing joint and the landing joint and the tubing string are raised to free the slips. After the slips are removed, the tubing hanger is lowered into a top of the BOP and the landing spool is lowered and connected to a top flange of the BOP. Fluid pressure between an annulus of the well and the landing spool is equalized. Fluid pressure is equalized using, for example, a bleed hose connected between a valve on the tubing head spool and a bleed port on the landing spool. After pressure is equalized, pipe rams on the BOP are opened and the tubing hanger is injected into the tubing head spool. Lockdown nuts on the tubing head spool are used to lock the tubing hanger in the tubing head spool and the landing joint is disconnected from the tubing hanger. The landing joint is then withdrawn and blind rams on the BOP are closed. Thereafter, pressure is bled from the landing spool and the landing spool is removed. Once the tubing hanger is secured in the tubing head spool, the BOP can be removed from the well. A wellhead can then be mounted to the tubing head spool in order to complete preparation of the well for production of hydrocarbons. 
     Thereafter, pressure between the wellhead and the annulus of the well can be equalized and the plug in the bottom end of the tubing removed using, for example, a wireline run down through the production tubing. 
     The invention further provides a method of installing a tubing hanger in a tubing head spool in a well in which fluid pressure exceeds atmospheric pressure without the use of a service rig. In accordance with the method, a lifting spool is mounted to a top of a BOP that is mounted above a tubing head spool of the live well. A plugged tubing is run into the well through the lifting spool on the BOP. The plugged tubing is supported with slips at a top flange of the lifting spool to inhibit the tubing string from falling into the well. A landing spool with a landing joint and lift mechanisms adapted for connection to the lifting spool are hoisted into vertical alignment with the tubing hanger. The lift mechanisms are connected to the lifting spool and the landing joint is connected to the tubing hanger. The lift mechanisms are actuated to lift the tubing hanger to release the slips. The slips are removed and the tubing hanger is lowered into the lifting spool. The landing spool is then lowered and sealingly connected to a top of the lifting spool. Pressure is equalized between an annulus of the well and the lifting spool. Thereafter, the BOPs are opened and the lift mechanisms are actuated to lower the tubing hanger into the tubing head spool. 
     After the tubing hanger has been lowered into the tubing head spool, the tubing hanger is locked in the tubing head spool using the lockdown screws. The landing joint is then disconnected from the tubing hanger and raised above blind rams of the BOPs. The blind rams are closed, pressure is bled from the landing spool and the landing spool and the lifting spool are removed from the wellhead along with the lift mechanisms. Thereafter, the BOPs may be removed and a wellhead installed as described above. 
    
    
     DESCRIPTION OF THE DRAWINGS 
     The invention will now be explained by way of example only, and with reference to the following drawings, in which: 
     FIG. 1 is a schematic elevational view of a prior art arrangement of BOPs used to inject a tubing hanger into a tubing head spool of a live well; 
     FIG. 2 is a schematic elevational view of a live well with a production tubing supported by slips at a top of a BOP, showing a landing spool in accordance with the invention in cross-section; 
     FIG. 2 a  is a detailed schematic view of a fluid seal provided between the landing spool shown in FIG. 2 and a landing joint that reciprocates through a passage in a top end of the landing spool; 
     FIG. 3 is a cross-sectional view of the live well shown in FIG. 2, illustrating pressure equalization between an annulus of the well and the landing spool in accordance with the invention; 
     FIG. 4 is a cross-sectional view of the live well shown in FIG. 3 with the tubing hanger installed in the tubing head spool, the landing joint disconnected from the tubing hanger and the blind rams of the BOP in a closed condition; 
     FIG. 5 is a schematic elevational view of a lifting spool in accordance with a further aspect of the invention; and 
     FIG. 6 is a cross-sectional view of the lifting spool shown in FIG. 5 with a lift mechanism connected to the lifting spool and the landing spool suspended above the tubing hanger in preparation for inserting the tubing hanger into the tubing head spool. 
    
    
     It will be noted that throughout the appended drawings, like features are identified by like reference numerals. 
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS 
     This invention provides apparatus and methods for setting a tubing hanger into a tubing head spool of a live well without the use of multiple blowout preventers and, optionally, without the use of a service rig. 
     FIG. 2 is a schematic elevational view of a live well  10  which includes a casing spool  12  to which a tubing header spool  14  is mounted. Mounted to a top of the tubing header spool  14  is a ram-type BOP  18 , which is well known in the art. The BOP  18  includes tubing rams  20  and blind rams  22 . As is well known in the art, the tubing rams may be equipped with tubing slips to accommodate jointed or coiled tubing of different diameters. The blind rams  22  are used to seal an annulus of the well in the event that a production tubing string  30  is dropped into the well. 
     As is well understood in the art, the completion of a well for production includes a step of perforating a casing of the well to permit hydrocarbons to flow into an annulus of the well from production zones (not shown). Completion of the well also frequently includes stimulation procedures in which high-pressure fluids are pumped down through the tubing string  30  and/or the well casing to stimulate production zones prior to placing the well into productive service. Subsequent to stimulation, may well operators prefer to inject tubing into the live well without flowing drilling mud, or the like, into the well to “kill” the well, in order to ensure that kill fluids do not reverse any of the benefits of the stimulation process. As is well understood, however, a tubing hanger cannot be safely inserted through a single BOP mounted to a live well. 
     The apparatus in accordance with the invention permits a tubing hanger to be rapidly and safely inserted into a tubing head spool of a live well using only one BOP. The apparatus in accordance with the invention includes a landing spool, generally indicated by the reference  40 , and a landing joint  42  which is connected to a top end of the tubing hanger  32 . A bottom of the landing joint  42  is preferably machined with an “EUE” thread for this purpose. The landing joint  42  is inserted through a passage  44  in a top end of the landing spool  40 . The passage  44  includes a packing cavity  46 . 
     The packing cavity  46  is shown in more detail in FIG. 2 a . The packing cavity  46  retains a steel packing washer  48  over which a high-pressure packing  50 , such as a Chevron packing, is positioned. The packing  50  closely surrounds and provides a high-pressure seal around the landing joint  42  to ensure that well fluids do not escape to atmosphere when the tubing hanger  32  is inserted into the tubing head spool  14 . The high-pressure packing  50  is retained in the packing cavity  46  by a gland nut  52 . A safety nut  54  threadedly engages a spiral thread on a outer periphery of the top end of the landing spool  40 . A top wall of the safety nut  54  projects inwardly to cover the gland nut  52  to ensure that the gland nut  52  is not stripped by fluid pressures exerted on the high-pressure packing  50 . A sidewall of the landing spool  40  includes at least two eyes or hooks  56 . The eyes or hooks  56  receive chain or cable  58  used to suspend the landing spool  40  while the landing joint  42  is connected to a top end of the tubing hanger  32 . The landing spool  40  is also suspended while slips  60 , well known in the art, that suspend the production tubing  30  are removed to permit the tubing hanger  32  to be inserted down through the BOP  18 . The landing joint  42  is typically supported by blocks  62  of a service rig (not shown). The slips  60  are likewise generally slips of the service rig. 
     After the landing joint  42  is connected to a top end of the tubing hanger  32 , the blocks  62  are operated to bear the weight of the production tubing  30  and the slips  60  are removed. Thereafter, the landing joint  42  is lowered to lower the tubing hanger  32  into a top of the BOP  18 , as shown in FIG.  3 . As will be noted, the tubing ram  20  of the BOP  18  is closed around the production tubing  30 . As is also well understood by those skilled in the art, a bottom of the production tubing  30  is sealed by a retrievable plug  64 , which prevents well fluids from escaping through an open end of the tubing string  30 . After the slips  60  are removed and the tubing hanger  32  is lowered, the cables  58 , connected, for example, to a sand line of the service rig, are used to lower the landing spool  40  onto a top flange of the BOP  18 . A high-pressure gasket  66  is inserted into a ring gasket groove  68  provided in the respective flanges of the landing spool  40  and the BOP  18  to provide a high-pressure fluid seal between those components. 
     After the landing spool  40  is mounted to the BOP  18 , pressure is equalized between an annulus of the live well and the landing spool  40 . A pressure bleed hose  70  is connected between a pressure bleed port  72  on the landing spool and a corresponding port or valve  74  in fluid communication with an annulus of the live well  10  to permit fluid pressure to equalize between the annulus and the landing spool  10 . After the pressure is equalized and it has been verified that there are no leaks at the ring gasket  66  or the high-pressure packing  50 , the respective valves are closed and the bleed hose  70  may be removed, as shown in FIG.  4 . Thereafter, the tubing rams  20  are opened which opens the annulus through the BOP  18  to permit the tubing hanger  32  to be lowered into the tubing head spool  14 , as shown in FIG.  4 . After the tubing hanger is seated in the tubing head spool, lock bolts  78  of the tubing head spool  14  are adjusted to lock the tubing hanger  32  in the tubing head spool. 
     The landing joint  34  is then rotated to disconnect the landing joint from the tubing hanger  32 , and the landing joint is raised until it is above the blind rams  22  of the BOP  18 . After the blind rams are closed, pressure is vented from the landing spool  40  by, for example, opening the pressure bleed port  72 . Subsequently, the landing spool is removed by, for example, reconnecting the cables  58  to the eyes  56  (see FIG. 2) and removing the landing spool using the sand line of the service rig. Once the landing spool is removed, the BOP  18  can be removed from the tubing head spool. Thereafter, a wellhead (not shown) can be mounted to the tubing head spool  14  using methods well known in the art. Pressure between the wellhead and the annulus beneath the tubing hanger  32  is balanced using a pressure bleed hose  70  as described above. A wireline lubricator (not shown) or the like may be used to run a wireline into the hole to remove the plug  64  (FIG. 3) sealing the bottom end of the production tubing  30 . After the plug  64  is removed, production from the well can commence. 
     FIG. 5 is a schematic view of a lifting spool that may be used in conjunction with the apparatus, in accordance with a further aspect of the invention. The lifting spool  80  is mounted to a BOP on a live well  10 . The lifting spool  80  permits the tubing hanger  32  to be inserted into the live well  10  without the use of a service rig. This has economic advantages by permitting the service rig to be released from the well as soon as the production tubing string  30  is run into the well, and before well stimulation is performed. In accordance with the invention, the lifting spool  80  is mounted to a top of the BOP  18  and the tubing string  30  is run into the well through an annulus of the lifting spool  80 . Tubing string  30  is supported by slips  82 , which are well known in the art. The service rig may then be released. After the service rig is released and the area is clear, the well may be stimulated using, for example, a blowout preventer protector as described in Applicant&#39;s U.S. Pat. No. 5,819,851, which issued on Oct. 13, 1998. The blowout preventer protector permits well stimulation fluids to be pumped down an annulus of the well, while the production tubing string  30  is used as a “dead string” to monitor fluid pressures in the stimulation zone. Alternatively, production tubing string  30  can also be used for the pumping of high-pressure stimulation fluids, for example, into a separate production zone to permit simultaneous stimulation of two production zones. 
     After the live well  10  has been stimulated and the fracturing stack or the blowout preventer protector (neither of which are shown) are removed from the lifting spool  80 , a tubing hanger  32  is connected to a top of the tubing string  30 . Thereafter, a lifting mechanism in accordance with this aspect of the invention is hoisted over the lifting spool  80  as shown in FIG.  6 . Since the service rig has been released from the well, the lift mechanism is preferably hoisted into position using a boom truck  90 , partially shown in ghost lines. A boom  92  of the boom truck is connected to the lift mechanism to hoist it in position over the lifting spool  80 . The lift mechanism includes a lifting beam  84  supported by at least two lift rams  86  which are, for example, hydraulic cylinders, ball jacks, or the like. The lift rams  86  are connected to opposite ends of the lifting beam  84 . The bottom ends of the lift rams  86  include mounting lugs  88  which are received in sockets  94  formed in the top of the lifting spool  80 . Pins  96  are inserted through transverse bores  98  (FIG. 5) in sidewalls of the sockets  94  and corresponding bores through mounting lugs  88 , to secure the lift rams  86  to the lifting spool  80 . 
     The lifting beam  84  serves a dual function of supporting the landing spool  40  as well as the landing joint  34 , which is used to raise and lower the production tubing string  30  connected to the tubing hanger  32 . The landing spool  40  is preferably supported by flexible lifting members such as cables  100 . The cables  100  are in turn supported by rotatable support members such as pulleys  102 , or winches or come-alongs  104 . The landing joint  42  may be connected at its top end to a hydraulic motor  106  to permit the production tubing string  30  to be rotated as required to set downhole attachments such as packers, plugs or hangers (not shown) connected to the production tubing string  30 . After the lift mechanism shown in FIG. 6 is hoisted into position and locked in place using pins  96 , the lift rams  86  are operated to lift the tubing string  30  to an extent required to free the slips  82  (FIG.  5 ). After the slips are removed, the tubing hanger  32  is lowered to an extent required to permit the landing spool  40  to be connected to a top of the lifting spool  80 . Once the landing spool  40  is connected to a top of the lifting spool  80 , pressure is equalized between the landing spool  40  and the annulus of the live well by connecting a bleed hose between the landing spool  40  and the tubing head spool  14 , as shown in FIG.  3 . After the pressure is equalized, tubing rams  20  of the BOP  18  are opened and the lift rams  86  are operated to lower the tubing hanger  32  into the tubing head spool  14 , as shown in FIG.  4 . The lock bolts  78  on the tubing head spool  14  are then adjusted to lock the tubing hanger  32  in the tubing head spool  14 . 
     Thereafter, the landing joint  42  is disconnected from the top of the tubing hanger  32  and the landing joint  42  is raised until the bottom end is above the blind rams  22 , which are closed as shown in FIG.  4 . After the blind rams are closed, pressure is bled from the landing spool  40 , the landing spool  40  is disconnected from the lifting spool  80  and the lift mechanism is removed from the lifting spool  80 . The lifting spool  80  is then removed from the BOP  18 . The BOP  18  may then be removed from the tubing head spool  14  after pressure is released, because the tubing hanger seals the annulus of the live well. After the BOP  18  is removed, the boom truck  90  can be used to hoist a wellhead (not shown) onto a top of the tubing head spool  14 . After the wellhead is connected to a top of the tubing head spool  14 , pressure is equalized between the wellhead and the annulus of the live well using a pressure bleed hose, in a manner similar to that shown in FIG.  3 . Thereafter, a lubricator and a wireline, well known in the art, may be used to retrieve the retrievable plug  64  in the bottom end of the production tubing string  30  to enable production from the live well to commence. 
     The embodiments of the invention described above are intended to be exemplary only. The scope of the invention is therefore limited solely by the scope of the appended claims.