Patent Publication Number: US-9835009-B2

Title: Method and apparatus for managing annular fluid expansion and pressure within a wellbore

Description:
The present application is a U.S. National Stage patent application of International Patent Application No. PCT/US2014/031756, filed on 25 Mar. 2014, the benefit of which is claimed and the disclosure of which is incorporated herein by reference in its entirety. 
     TECHNICAL FIELD 
     The present disclosure relates generally to oilfield equipment, and in particular to wells, drilling and completion systems, and techniques for completion of wells and production of hydrocarbons from drilled wellbores in the earth. More particularly still, the present disclosure relates to an improvement in systems and methods for managing annular pressure buildup and fluid expansion between successive casing strings within a wellbore. 
     BACKGROUND 
     Systems for producing hydrocarbons from wellbores typically employ a well head, which includes a well head housing, connected atop surface casing extending into the earth from the top of the wellbore and cemented into place within the wellbore. During drilling and completion operations, a blowout preventer may be included atop the well head housing. 
     Generally, as a wellbore is drilled, successively smaller diameter casing strings are concentrically installed in the well bore at deeper depths, suspended from casing hangers landed, seated, and locked within the well head housing. The casing strings isolate the wellbore from the surrounding formation. The area between any two adjacent casings defines a casing annulus. Similarly, production tubing is typically concentrically installed within the inner casing, suspended from a tubing hanger landed and seated within the well head housing. The production tubing provides a conduit for producing the hydrocarbons entrained within the formation. An inner casing annulus is defined between the inner casing and the production tubing. Moving outward from the production tubing to the outermost casing, these various annuli are conventionally identified alphabetically as the A-annulus, B-annulus, C-annulus, etc. 
     Typically, each casing hanger is sealed within the well head housing by a mechanical seal assembly. Accordingly, the upper end of each casing is sealed from the adjacent casing. Likewise, cement is typically deposited about the lower end of each casing string to form a casing shoe, thereby sealing the annulus at the lower end of a casing string, with the result being that any fluid located within a casing annulus may become trapped. If fluid constrained within an annulus becomes pressurized, such as from a leak or thermal expansion, a pressure differential may overstress and/or rupture a casing or tubing wall. The phenomenon of trapped annulus pressure or annular pressure buildup is traditionally addressed by overdesigning casing strings and production tubing, with a concomitant cost penalty. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       Embodiments are described in detail hereinafter with reference to the accompanying figures, in which: 
         FIG. 1  is an elevation view in partial cross section of a well and an offshore drilling system according to an embodiment, showing a subsea well head serviced by an offshore platform via a riser; 
         FIG. 2  is an axial cross section of a portion of the well head of  FIG. 1 , showing three casings and a production tubing in a coaxial arrangement, casing hangers, a tubing hanger, and a pressure relief system according to an embodiment; 
         FIGS. 3A and 3B  are an exploded diagram of the well head of  FIG. 2  in axial cross section; 
         FIG. 4A  is an axial cross section of a pressure relief valve assembly for use within the well head of  FIG. 2  according to an embodiment, showing a pressure relief valve assembly with an adjustable spring-loaded seat in a shut position; 
         FIG. 4B  is an axial cross section of a pressure relief valve assembly of  FIG. 4A , showing a relief flow path through the pressure relief valve assembly when in an open position; and 
         FIGS. 5A-5C  are a flow chart of a method for producing hydrocarbons according to an embodiment that uses the well and drilling system of  FIGS. 1-4 . 
     
    
    
     DETAILED DESCRIPTION 
     The foregoing disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed. Further, spatially relative terms, such as “beneath,” “below,” “lower,” “above,” “upper,” “uphole,” “downhole,” “upstream,” “downstream,” and the like, may be used herein for ease of description to describe one element or feature&#39;s relationship to another element(s) or feature(s) as illustrated in the figures. The spatially relative terms are intended to encompass different orientations of the apparatus in use or operation in addition to the orientation depicted in the figures. 
       FIG. 1  is an elevation view in cross-section of a drilling system  10  according to an embodiment. Drilling system  10  includes a drilling rig  22 , which may include a rotary table  26 , a top drive unit  28 , a hoist  29 , and other equipment necessary for drilling a wellbore in the earth. Drilling system  10  may include an offshore platform  20 , such as a tension leg platform, spar, semi-submersible, or drill ship. However, drilling system  10  may be a land drilling system or any other drilling system capable of forming a wellbore extending through one or more downhole formations. 
     Drilling rig  22  may be located generally above a well head  24 , which in the case of an offshore location is located at the sea bed and is connected to drilling rig  22  via a riser  25 . Riser  25  allows drill pipes, casing, tubing, and other tools or devices to be run into and out of the wellbore  27 . Blowout preventers  30  and/or a Christmas tree assembly (not illustrated) may be provided atop well head  24 . 
       FIG. 2  is an axial cross section of a portion of well head  24  of  FIG. 1  according to an embodiment.  FIGS. 3A and 3B  combined are an exploded view of  FIG. 2 . Referring to  FIGS. 2, 3A and 3B , well head  24  includes a well head housing  40 , which may be mounted atop a surface casing (not illustrated) that is run and cemented into an earthen foundation. In some embodiments, the surface casing may be a commercially available 26 inch or 20 inch surface casing, for example. Well head housing  40  may be formed of several discrete commercially available components, including a casing head housing that mounts atop the surface casing, a casing spool that mounts atop the casing head housing, and a tubing spool that mounts atop the casing spool. However, other combinations, including a unitary well head housing, may be used as appropriate. In an embodiment, well head housing may be an American Petroleum Institute (API) standard 13⅝ inch housing. 
     An outer casing  45  is run and cemented into an upper portion of wellbore  27  ( FIG. 1 ), and the upper end of outer casing  45  is received within well head housing  40 . In some embodiments, outer casing  45  may be a 13⅜ inch diameter casing, while in other embodiments; outer casing  45  may have a different diameter. 
     An intermediate casing  50  is run into outer casing  45 . An upper end of intermediate casing  50  is connected to an intermediate casing hanger  55 , and intermediate casing hanger  55  is seated on a shoulder  56  within the interior of well head housing  40 , thereby suspending intermediate casing  50  within outer casing  45 . In some embodiments, intermediate casing  50  may be a 9⅝ inch diameter casing, while in other embodiments, intermediate casing  50  may have a different diameter. 
     The region between the interior of outer casing  45  and the exterior of intermediate casing  50  defines an outer annulus  48 . A lower cavity  49  is defined within the interior of well head housing  40  between the top end of outer casing  45  and the bottom of intermediate casing hanger  55 . Lower cavity  49  is in fluid communication with outer annulus  48 . 
     An intermediate annular seal bushing  60  is received within well head housing  40  above intermediate casing hanger  55 . Intermediate annular seal bushing  60  includes O-rings or other seals that seal intermediate annular seal bushing  60  between an interior wall of well head housing  40  and an exterior wall of intermediate casing  50 , intermediate casing hanger  55 , or both, thereby sealing outer annulus  48  and lower cavity  49 . In some embodiments, radial locking pins  61  may be set through apertures  62  formed in well head housing  40  and recesses  63  formed in intermediate annular seal bushing  60  to ensure proper rotative alignment and lock intermediate annular seal bushing  60  into place within well head housing  40 . 
     An inner casing  70  is run into intermediate casing  50 . An upper end of inner casing  70  is connected to an inner casing hanger  75 , and inner casing hanger  75  is seated on a shoulder  76  formed by a top end of intermediate annular seal bushing  60 , thereby suspending inner casing  70  within intermediate casing  50 . In some embodiments, inner casing  70  may be a 7 inch diameter casing, while in other embodiments, intermediate casing  50  may have a different diameter. 
     The region between the interior of intermediate casing  50  and the exterior of inner casing  70  defines an intermediate annulus  58 . Intermediate annular seal bushing  60  defines an intermediate annular cavity  59  at its upper end. Intermediate annular cavity  59  is in fluid communication with intermediate annulus  58 . 
     According to an embodiment, intermediate casing hanger  55  has an outer annular pressure relief conduit  47  formed therethrough. Similarly, intermediate annular seal bushing  60  has an intermediate bushing pressure relief conduit  67  formed therethrough. The lower end of outer annular pressure relief conduit  47  opens to lower cavity  49  so that it is in fluid communication with outer annulus  48 . The upper end of outer annular pressure relief conduit  47  aligns with and is in fluid communication with the lower end of intermediate bushing pressure relief conduit  67 . Intermediate bushing pressure relief conduit  67  opens to intermediate annular cavity  59  so that it is in fluid communication with intermediate annulus  58 . 
     According to some embodiments, an outer annular pressure relief valve  44  may be disposed along the fluid communication path of conduits  47  and  67 . In one embodiment, outer annular pressure relief valve  44  is disposed along outer annular pressure relief conduit  47 , while in another embodiment, outer annular pressure relief valve  44  is located within intermediate bushing pressure relief conduit  67 . Outer annular pressure relief valve  44  is designed and arranged to selectively open and/or shut, based on pressure, temperature, and/or time as described in greater detail below, thereby selectively venting outer annulus  48 . 
     An inner annular seal bushing  80  is received within well head housing  40  above inner casing hanger  75 . Inner annular seal bushing  80  includes O-rings or other seals that seal inner annular seal bushing  80  between an interior wall of well head housing  40  and an exterior wall of inner casing  70 , inner casing hanger  75 , or both, thereby sealing intermediate annulus  58  and intermediate annular cavity  59 . In some embodiments, radial locking pins  81  may be set through apertures  82  formed in well head housing  40  and recesses  83  formed in inner annular seal bushing  80  to ensure proper rotative alignment and lock inner annular seal bushing  80  into place within well head housing  40 . 
     A production tubing  90  is run into inner casing  70 . An upper end of production tubing  90  is connected to a tubing hanger  95 , and tubing hanger  95  is seated on a shoulder  96  formed by a top end of inner annular seal bushing  80 , thereby suspending production tubing  90  within inner casing  70 . 
     The region between the interior of inner casing  70  and the exterior defines an inner annulus  78 . Inner annular seal bushing  80  defines an inner annular cavity  79  at its upper end. Inner annular cavity  79  is in fluid communication with inner annulus  78 . 
     According to an embodiment, inner casing hanger  75  has an intermediate annular pressure relief conduit  57  formed therethrough. Similarly, inner annular seal bushing  80  has an inner bushing pressure relief conduit  87  formed therethrough. The lower end of intermediate annular pressure relief conduit  57  aligns with and is in fluid communication with the upper end of intermediate bushing pressure relief conduit  67 . The upper end of intermediate annular pressure relief conduit  57  aligns with and is in fluid communication with the lower end of inner bushing pressure relief conduit  87 . However, in another embodiment (not illustrated), the upper end of intermediate annular pressure relief conduit  57  and the lower end of inner bushing pressure relief conduit  87  could both open to intermediate annular cavity  59 , thereby establishing fluid communication between the respective conduits. The upper end of inner bushing pressure relief conduit  87  opens to inner annular cavity  79  so that it is in fluid communication with inner annulus  78 . 
     According to some embodiments, an intermediate annular pressure relief valve  54  may be disposed along the fluid communication path of conduits  57  and  87 . In one embodiment, intermediate annular pressure relief valve  54  is disposed along intermediate annular pressure relief conduit  57 , while in another embodiment, intermediate annular pressure relief valve  54  could also be located within inner bushing pressure relief conduit  87 . Intermediate annular pressure relief valve  54  is designed and arranged to selectively open and/or shut, based on pressure, temperature, and/or time as described in greater detail below, thereby selectively venting intermediate annulus  58  and/or outer annulus  48 . 
     According to an embodiment, tubing hanger  95  has a central bore extending between an upper end and a lower end of hanger  95 , and tubing hanger  95  further has an inner annular pressure relief conduit  77  formed therein. The lower end of inner annular pressure relief conduit  77  opens to inner annular cavity  79  so that it is in fluid communication with inner annulus  78 . The upper end of inner annular pressure relief conduit  77  is in fluid communication with the central bore of hanger  95  and thus, the interior of production tubing  90 . 
     According to some embodiments, inner annular pressure relief conduit  77  includes an inner annular pressure relief valve  74  disposed therein. Inner annular pressure relief valve  74  is designed and arranged to selectively open and/or shut, based on pressure, temperature, and/or time as described in greater detail below, thereby selectively venting inner annulus  78 , intermediate annulus  58  and/or outer annulus  48 . 
     Although those foregoing embodiments employing a pressure relieve valve(s) are not limited to a particular type of relive valve,  FIGS. 4A and 4B  are axial cross sections of an exemplar pressure relief valve, shown in the shut and open positions respectively, which in an embodiment may be used for each of outer annular pressure relief valve  44 , intermediate annular pressure relief valve  54 , and/or inner annular pressure relief valve  74 . Referring to  FIGS. 4A and 4B , annular pressure relief valve  44 ,  54 ,  74  may be disposed within annular pressure relief conduit  47 ,  57 ,  77  formed within hanger  55 ,  75 ,  95 , respectively. 
     In an embodiment, annular pressure relief valve  44 ,  54 ,  74  may be a poppet valve, which may include a movable poppet  100  that engages and seals against a seat ring  102 . Poppet  100  is formed at the distal end of an axially travelling stem  101 . Poppet  100  is urged against scat ring  102  by an adjustable spring  104  that is disposed between poppet  100  and a stop screw  106 . The axial position of stop screw  106  determines the compressive preload on spring  104  and, as a result, the pressure set point at which poppet  100  will move off of seat ring  102  against the spring force to relieve pressure. When fluid pressure bearing against poppet  100  is less than the lifting set point, poppet  100  is seated and sealed against seat ring  102  by spring  104 . When fluid pressure bearing against poppet  100  is greater than the lifting set point, poppet  100  is lifted away from seat ring  102 , allowing fluid flow through annular pressure relief valve  44 ,  54 ,  74  as indicated by the flow arrows in  FIG. 4B . 
     In an embodiment, annular pressure relief valve  44 ,  54 ,  74  is located within hanger  55 ,  75 ,  95  so that stop screw  106  may be easily accessed for set point adjustment and valve maintenance and/or repair. 
     According to another embodiment, annular pressure relief valve  44 ,  54 ,  74  may be adapted to selectively open and shut based on fluid pressure, temperature, and or elapsed time, for example. Such valves are commercially available. For instance, an electronic remote equalizing device (eRED®) available from Red Spider Technology, Ltd. is a battery-operated computer controlled ball valve that can be repeatedly opened and closed remotely. An eRED® ball valve includes integrated pressure and temperature sensors and a clock circuit, and it may be preprogrammed to open or shut whenever a specified condition—temperature, pressure, time, or combination thereof,—is detected. This process may be repeated without any form of intervention. 
     Accordingly, during drilling and completion operations, annular pressure relief valve  44 ,  54 ,  74  may be set to open at a predetermined pressure to allow fluid pressure be released in a controlled manner and prevent loss of casing integrity. The flow stream through annular pressure relief valve  44 ,  54 ,  74  may provide an indication of when the maximum wellbore surface temperature has been reached. After the wellbore temperature and annulus pressure have stabilized during production operations at the maximum temperature, annular pressure relief valve  44 ,  54 ,  74  may be programmed to shut, thereby sealing all casing annuli until a subsequent predetermined pressure activates the valve(s) again. It will be appreciated that not all relief valves need be activated at the same predetermined pressure. The predetermined pressure may be selected, in some embodiments, based on the sizing or other characteristics of the casing or tubing forming the annulus serviced by the pressure relief valve. 
       FIGS. 5A-5C  are a flowchart for a method of producing hydrocarbons according to an embodiment, using the well and offshore drilling system of  FIG. 1-4 . The method is equally adaptable for on-shore wells. Referring primarily to  FIGS. 5A-5C , with reference to  FIGS. 1-4 , at  200 , a surface casing (not illustrated) is run, typically by drilling, jetting, or driving, and then cemented at the selected well location on the seabed. At step  204 , well head housing  40  is run and connected atop the surface casing. At step  208 , marine riser  25  and blowout preventer  30  are connected to the top of well head housing  40 . Marine riser  25  extends upward to offshore platform  20 . 
     Wellbore  27  is drilled and cased in segments, with each subsequent segment having a smaller diameter. In steps  212  and  216 , the uppermost portion of wellbore  27  is drilled and cased with outer casing  45 , respectively. In an embodiment, outer casing  45  is 13⅜ inch casing, although other sizes may be used as appropriate. Outer casing  45  may be cemented within the uppermost portion of wellbore  27 . The top end of outer casing  45  terminates within well head housing  40 . 
     Next, in step  220 , an upper portion of wellbore  27  is drilled through well head housing  40  and outer casing  45 . In step  224 , intermediate casing  50  is run through well head housing  40  and outer casing  45  into the upper portion of wellbore  27 . In steps  228  and  232 , intermediate casing  50  is connected to and suspended within well head housing  40  by intermediate casing hanger  55 . Intermediate casing hanger  55  includes outer annular pressure relief conduit  47 , which is arranged to selectively vent outer annulus  48 , defined by the region between outer casing  45  and intermediate casing  55 . In an embodiment, intermediate casing  50  is a 9⅝ inch casing. 
     Likewise, in step  236 , an intermediate portion of wellbore  27  is drilled through well head housing  40  and intermediate casing  50 . In step  240 , inner casing  70  is run through well head housing  40  and intermediate casing  50  into the intermediate portion of wellbore  27 . In steps  244  and  248 , inner casing  70  is connected to and suspended within well head housing  40  by inner casing hanger  75 . Inner casing hanger  75  includes intermediate annular pressure relief conduit  57 , which is arranged to selectively vent both intermediate annulus  58 , defined by the region between intermediate casing  50  and inner casing  70 , and outer annulus  48 . In an embodiment, inner casing  70  is a 7 inch casing. 
     Production tubing  90  is installed in a substantially similar manner. In step  252 , a lower portion of wellbore  27  is drilled through well head housing  40  and inner casing  70 . In step  256 , production tubing  90  is run through well head housing  40  and inner casing  70  into the lower portion of wellbore  27 . In steps  260  and  264 , production tubing  90  is connected to and suspended within well head housing  40  by tubing hanger  95 . Tubing hanger  95  includes inner annular pressure relief conduit  87 , which is arranged to selectively vent inner annulus  78 , defined by the region between inner casing  70  and production tubing  90 , intermediate annulus  58 , and outer annulus  48 . 
     Finally, in step  268 , one or more of the casing annuli—inner annulus  78 , intermediate annulus  58 , and outer annulus  48 —are selectively vented to the interior of production tubing  90  via inner annular pressure relief conduit  87 , intermediate annular pressure relief conduit  57 , and/or outer annular pressure relief conduit  47 . The casing annuli maybe selectively vented based on pressure, temperature, time, or a combination thereof. 
     Although well head  24  is illustrated and described as having an outer, intermediate and inner casing, it may include few or more casings defining various casing annuli, which may be vented in a similar manner as described herein. Moreover, more than one coaxial production tubing may be included, defining one or more annuli therebetween. Accordingly, a routineer in the art will recognize that the present disclosure and claims cover embodiments with coaxial arrangements of piping strings and resultant annuli, regardless of whether a particular piping string is considered to be production tubing or casing. 
     The system and method disclosed herein provide a mechanically straightforward and reliable way to vent trapped pressurized fluid under controlled conditions at the well head without operator intervention. The pressure relief mechanism is entirely independent, opening and shutting based on flexible predetermined parameters. Accordingly, without the need to compensate for annulus pressure buildup, casing specifications may be relaxed. 
     In summary, a hanger system, a well and a method of producing hydrocarbons have been described. Embodiments of the hanger system may generally have: A first piping hanger having an upper end and a lower end with a first pressure relief conduit formed within the first piping hanger and extending between the upper and lower ends of the first piping hanger; a first piping string carried by the first piping hanger; a second piping hanger having an upper end and a lower end with a second pressure relief conduit formed within the second piping hanger and extending between the upper and lower ends of the second piping hanger; and a second piping string carried by the second piping hanger; wherein the first piping hanger and the second piping hanger are positioned in proximity to one another so that the first pressure relief conduit is in fluid communication with the second pressure relief conduit. Embodiments of the well may generally have: A wellbore formed in the earth; a well head housing disposed atop of the wellbore; an outer casing disposed in the wellbore, a top end of the outer casing connected to and in fluid communication with the well head housing; an intermediate casing disposed within the outer casing, a region between the outer casing and the intermediate casing defining an outer annulus; an intermediate casing hanger connected to a top end of the intermediate casing and seated with the well head housing above the top end of the outer casing, the intermediate casing hanger suspending the intermediate casing; a production tubing disposed in the intermediate casing; a tubing hanger connected to a top end of the production tubing and seated within the well head housing above the intermediate casing hanger, the tubing hanger suspending the production tubing; an outer annular pressure relief conduit formed within the intermediate casing hanger, the outer annular pressure relief conduit forming at least part of a pressure relief flow path from the outer annulus to an interior region of the production tubing; and an outer annular pressure relief valve disposed within the pressure relief flow path. Embodiments of the method of producing hydrocarbons may generally include: Installing a first piping string in a wellbore by suspending the first piping string from a first piping string hanger; installing a second piping string in the wellbore by suspending the second piping string from a second piping string hanger so as to form an annulus between a portion of the first piping string and the second piping string; and selectively venting a pressure through a first pressure relief conduit formed through the first piping string hanger and through a second pressure relief conduit formed through the second piping string hanger. 
     Any of the foregoing embodiments may include any one of the following elements or characteristics, alone or in combination with each other: A pressure relief valve disposed along the first pressure relief conduit or the second pressure relief conduit; a third piping hanger having an upper end and a lower end with a third pressure relief conduit formed within the third piping hanger and extending between the upper and lower ends of the third piping hanger; a third piping string carried by the third tubing hanger; the second piping hanger and the third piping hanger are positioned in proximity to one another so that the second pressure relief conduit is in fluid communication with the third pressure relief conduit; a first pressure relief valve disposed along the first pressure relief conduit or the second pressure relief conduit; a second pressure relief valve disposed along the third pressure relief conduit; the first piping string is an outer casing; the second piping string is an intermediate casing disposed within the outer casing; a production tubing hanger having an upper end and a lower end with a central bore extending therebetween and a pressure relief conduit formed within the production tubing hanger extending from the lower end of the production tubing hanger to the central bore; a production tubing string carried by the production tubing hanger; a seal bushing disposed between the first and second piping hangers; the seal bushing having an upper end and a lower end with a third pressure relief conduit formed within the seal bushing and extending between the upper and lower ends of the seal bushing so that the third pressure relief conduit is in fluid communication with the first and second pressure relief conduits; the seal bushing defines a cavity; the third pressure relief conduit is in fluid communication with the cavity; at least the first or the second pressure relief conduit is in fluid communication with the cavity, the outer annular pressure relief valve is disposed within the outer annular pressure relief conduit; an inner annular pressure relief conduit formed within the tubing hanger, the inner annular pressure relief conduit forming at least part of the pressure relief flow path; an inner annular pressure relief valve disposed within the pressure relief flow path downstream of the outer annular pressure relief valve; the inner annular pressure relief valve is disposed within the inner annular pressure relief conduit; an inner casing disposed between the intermediate casing and the production tubing, a region between the intermediate casing and the inner casing defining an intermediate annulus, a region between the inner casing and the production tubing defining an inner annulus; an inner casing hanger connected to a top end of the inner casing and seated within the well head housing above the intermediate casing hanger and below the tubing hanger; an intermediate annular pressure relief conduit formed within the inner casing hanger and forming at least part of the pressure relief flow path; an intermediate annular pressure relief valve disposed within the pressure relief flow path downstream of the outer annular pressure relief valve and upstream of the inner annular pressure relief valve; the intermediate annular pressure relief valve is disposed within the intermediate annular pressure relief conduit; the inner annular pressure relief conduit is fluidly coupled to the inner annulus upstream of the inner annular pressure relief valve; the intermediate annular pressure relief conduit is fluidly coupled to the intermediate annulus upstream of the intermediate annular pressure relief valve; an intermediate annular seal bushing disposed within the well head housing between the intermediate casing hanger and the inner casing hanger, the intermediate annular seal bushing including an intermediate annular cavity that is fluidly coupled to the intermediate annulus; an intermediate bushing pressure relief conduit formed within the intermediate annular seal bushing, fluidly coupled to between the outer annular pressure relief conduit and the intermediate annular pressure relief conduit, and forming at least a portion of the pressure relief flow path; an inner annular seal bushing disposed within the well head housing between the inner casing hanger and the tubing hanger, the inner annular seal bushing including an inner annular cavity that is fluidly coupled to the inner annulus; an inner bushing pressure relief conduit formed within the inner annular seal bushing, fluidly coupled to between the intermediate annular pressure relief conduit and the inner annular pressure relief conduit, and forming at least a portion of the pressure relief flow path; an intermediate annular seal bushing disposed within the well head housing between the intermediate casing hanger and the tubing hanger; an intermediate bushing pressure relief conduit formed within the intermediate annular seal bushing, fluidly coupled to between the outer annular pressure relief conduit and the inner annular pressure relief conduit, and forming at least a portion of the pressure relief flow path; the well head housing is disposed at a location on a seabed; the well further comprises a marine riser coupled between an offshore platform and an upper end of the well head housing; at least one from the group consisting of the outer annular pressure relief valve and the inner annular pressure relief valve is designed and arranged to open at a predetermined pressure; at least one from the group consisting of the outer annular pressure relief valve and the inner annular pressure relief valve is designed and arranged to shut based on at least one from the group consisting of an elapsed time and a temperature; installing an outer casing in the wellbore; the first piping string is an intermediate casing at least partially disposed within the outer casing; the second piping string is an inner casing at least partially disposed within the intermediate casing; installing a well head housing at a location on the surface of the earth; running a first drill string through the well head housing; drilling using the first drill string an uppermost portion of a wellbore; installing an outer casing in the uppermost portion of the wellbore; running a second drill string through the well head housing and the outer casing; drilling using the second drill string an upper portion of the wellbore below the uppermost portion; running an intermediate casing through the well head housing and outer casing into the upper portion of the wellbore; providing an intermediate casing hanger having an outer annular pressure relief conduit formed therethrough; connecting a top end of the intermediate casing to the intermediate casing hanger; suspending the intermediate casing by seating the intermediate casing hanger within the well head housing, a region between the outer casing and the intermediate casing defining an outer annulus; running a third drill string through the well head housing and intermediate casing; drilling using the third drill string a lower portion of the wellbore below the upper portion; running a production tubing through the well head housing into the lower portion of the wellbore; providing a tubing hanger having an inner annular pressure relief conduit formed therein; connecting a top end of the production tubing to the tubing hanger; suspending the production tubing by seating the tubing hanger within the well head housing; and selectively venting the outer annulus to an interior of the production tubing via the outer annular pressure relief conduit and the inner annular pressure relief conduit; running a fourth drill string through the well head housing and intermediate casing; drilling using the fourth drill string an intermediate portion of the wellbore below the upper portion and above the lower portion of the wellbore; running an inner casing through the well head housing and the intermediate casing into the intermediate portion of the wellbore; providing an inner casing hanger having an intermediate annular pressure relief conduit formed therethrough; connecting a top end of the inner casing to the inner casing hanger; suspending the inner casing by seating the inner casing hanger within the well head housing, a region between the intermediate casing and the inner casing defining an intermediate annulus; selectively venting the intermediate annulus to the interior of the production tubing via the intermediate annular pressure relief conduit and the inner annular pressure relief conduit; selectively venting the outer annulus to the interior of the production tubing via the intermediate annular pressure relief conduit; the production tubing is disposed within the inner casing; a region between the inner casing and the production tubing defines an inner annulus; selectively venting at least one of the group consisting of the outer annulus, the intermediate annulus and the inner annulus to the interior of the production tubing based on a pressure; preventing venting of at least one of the group consisting of the outer annulus, the intermediate annulus and the inner annulus based on at least one from the group consisting of an elapsed time and a temperature; the well head housing is located at a subsea location; and the method further comprises coupling a marine riser between an offshore platform and an upper end of the well head housing. 
     The Abstract of the disclosure is solely for providing the patent office and the public at large with a way by which to determine quickly from a cursory reading the nature and gist of technical disclosure, and it represents solely one or more embodiments. 
     While various embodiments have been illustrated in detail, the disclosure is not limited to the embodiments shown. Modifications and adaptations of the above embodiments may occur to those skilled in the art. Such modifications and adaptations are in the spirit and scope of the disclosure.