Patent Publication Number: US-9890607-B2

Title: Independent guide string hanger

Description:
CROSS REFERENCE TO RELATED APPLICATION 
     This application claims priority to U.S. Non-Provisional patent application Ser. No. 14/035,892, entitled “Independent Guide String Hanger”, filed on Sep. 24, 2013, which is herein incorporated by reference in its entirety, and which claims priority to and benefit of U.S. Non-Provisional patent application Ser. No. 12/868,469, entitled “Independent Guide String Hanger”, filed on Aug. 25, 2010, which is herein incorporated by reference in its entirety. 
     BACKGROUND 
     This section is intended to introduce the reader to various aspects of art that may be related to various aspects of the present invention, which are described and/or claimed below. This discussion is believed to be helpful in providing the reader with background information to facilitate a better understanding of the various aspects of the present invention. Accordingly, it should be understood that these statements are to be read in this light, and not as admissions of prior art. 
     As will be appreciated, oil and natural gas have a profound effect on modern economies and societies. Indeed, devices and systems that depend on oil and natural gas are ubiquitous. For instance, oil and natural gas are used for fuel in a wide variety of vehicles, such as cars, airplanes, boats, and the like. Further, oil and natural gas are frequently used to heat homes during winter, to generate electricity, and to manufacture an astonishing array of everyday products. 
     In order to meet the demand for such natural resources, companies often invest significant amounts of time and money in searching for and extracting oil, natural gas, and other subterranean resources from the earth. Particularly, once a desired resource is discovered below the surface of the earth, drilling and production systems are often employed to access and extract the resource. These systems may be located onshore or offshore depending on the location of a desired resource. Further, such systems generally include a wellhead assembly through which the resource is extracted. These wellhead assemblies may include a wide variety of components, such as various casings, hangers, valves, fluid conduits, and the like, that control drilling and/or extraction operations. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       Various features, aspects, and advantages of the present invention will become better understood when the following detailed description is read with reference to the accompanying figures in which like characters represent like parts throughout the figures, wherein: 
         FIG. 1  is a block diagram that illustrates an exemplary mineral extraction system; 
         FIG. 2  is a top view of an exemplary wellhead that may be used in the mineral extraction system of  FIG. 1 ; 
         FIG. 3  is a cross-sectional view of the wellhead, taken along line  3 - 3  of  FIG. 2 , having a tubing hanger and an independent guide string hanger; 
         FIG. 4  is a detailed cross-sectional view of the independent guide string hanger, taken within line  4 - 4  of  FIG. 3 ; 
         FIG. 5  is a cross-sectional view of the wellhead, taken along line  5 - 5  of  FIG. 2 , showing an electrical feed-through mandrel passing through the tubing hanger; 
         FIG. 6  is a perspective view of an embodiment of the independent guide string hanger, as shown in  FIG. 2 ; 
         FIG. 7  is a top view of the independent guide string hanger of  FIG. 6 ; and 
         FIG. 8  is a cross-sectional side view of the independent guide string hanger and guide string, taken along line  8 - 8  of  FIG. 7 . 
     
    
    
     DETAILED DESCRIPTION OF SPECIFIC EMBODIMENTS 
     One or more specific embodiments of the present invention will be described below. These described embodiments are only exemplary of the present invention. Additionally, in an effort to provide a concise description of these exemplary embodiments, all features of an actual implementation may not be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions must be made to achieve the developers&#39; specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure. 
     When introducing elements of various embodiments of the present invention, the articles “a,” “an,” “the,” and “said” are intended to mean that there are one or more of the elements. The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements. Moreover, the use of “top,” “bottom,” “above,” “below,” and variations of these terms is made for convenience, but does not require any particular orientation of the components. 
     Certain regions of the world include geologic formations which contain a mixture of heavy, viscous oil mixed with sand, known as oil sands or tar sands. Due to the thickness of the oil and the sand contamination, the oil may not be extracted through conventional production techniques. Instead, a steam assisted gravity drain (SAGD) system may be employed to separate the oil from the sand and to reduce the oil viscosity prior to extraction. In certain SAGD systems, steam is injected through a wellhead into the geologic formation containing the oil sands. The well is then shut in for a period of time (e.g., several months) allowing the oil to “heat soak.” After the soaking period, the well is opened such that the heated oil and condensed steam may be extracted. Such a configuration may facilitate economically feasible oil production from oil sands. 
     Certain SAGD wellheads are configured to support multiple strings within a casing head. For example, a production tubing string and a guide string may be supported by a single hanger disposed within the casing head. The production tubing may extend into the oil formation and convey extracted oil to the surface, while the guide string may be used to run coiled tubing through the well casing. As will be appreciated, the hanger will include seals configured to block a flow of high pressure and high temperature steam from exiting the wellhead. Specifically, the hanger generally includes a large radial seal area for sealing both the production tubing string and the guide string. As a result, sufficient radial area may not be available for sealing additional components passing through the hanger (e.g., an electrical feed-through mandrel). Consequently, the additional components may be sealed within other areas of the wellhead (e.g., a tubing head adapter). Unfortunately, such configurations typically result in large, complex and expensive wellhead assemblies. 
     Embodiments of the present disclosure may significantly reduce the size, cost and complexity of wellhead assemblies used for steam assisted gravity drain (SAGD) operations. For example, in certain embodiments, a wellhead includes a casing head having a first retaining feature configured to support a tubing hanger, and a second retaining feature configured to support a guide string hanger independently of the tubing hanger. In certain embodiments, the first retaining feature includes a tapered portion of a bore of the casing head and the second retaining feature includes a shoulder. In such embodiments, the guide string hanger may be secured to the casing head by a plug that extends through the body of the casing head into a recess within the guide string hanger, while the tubing hanger is suspended by fluid pressure above the tapered portion. To block rotation of the tubing hanger, the guide string hanger may include a neck that extends axially into a recess within the tubing hanger. In this configuration, rotation of the tubing hanger is blocked by contact between the neck and the recess, while the tubing hanger is free to translate in an axial direction. Further embodiments include a tubing head adapter secured to the casing head, and a feed-through mandrel substantially sealed to the tubing head adapter and extending through the tubing hanger and the guide string hanger. Because the tubing hanger and the guide string hanger have a sufficient radial area to facilitate passage of the mandrel, the tubing head adapter may be secured to the casing head directly adjacent to the tubing hanger and guide string hanger, thereby providing a compact wellhead. In further embodiments, the guide string hanger includes an opening having a sufficient diameter to facilitate passage of an electric submersible pump (ESP), thereby enabling the guide string hanger to be run prior to running the tubing string. 
       FIG. 1  is a block diagram that illustrates an embodiment of a mineral extraction system  10 . The illustrated mineral extraction system  10  can be configured to extract various minerals and natural resources, including hydrocarbons (e.g., oil and/or natural gas), or configured to inject substances into the earth. In some embodiments, the mineral extraction system  10  is land-based (e.g., a surface system). As illustrated, the system  10  includes a wellhead  12  coupled to a mineral deposit  14  via a well  16 , wherein the well  16  includes a surface conductor pipe  18  and a well-bore  20 . The surface conductor pipe  18  provides for the connection of the wellhead  12  to the well  16 . 
     The wellhead  12  typically includes multiple components that control and regulate activities and conditions associated with the well  16 . For example, the wellhead  12  generally includes bodies, valves and seals that route produced minerals from the mineral deposit  14 , provide for regulating pressure in the well  16 , enable monitoring conditions in the well  16  and provide for injecting chemicals into the well-bore  20  (down-hole). In the illustrated embodiment, the wellhead  12  includes a production tree  22 , a casing head  24  and a tubing head adapter  26 . The system  10  may include other devices that are coupled to the wellhead  12 , and devices that are used to assemble and control various components of the wellhead  12 . For example, as discussed in detail below, a tubing hanger and a guide string hanger may be disposed within the casing head  24  and configured to support a production tubing string and a guide string, respectively. 
     The tree  22  generally includes a variety of flow paths (e.g., bores), valves, fittings, and controls for operating the well  16 . For instance, the tree  22  may include a frame that is disposed about a tree body, a flow-loop, actuators, and valves. Further, the tree  22  may provide fluid communication with the well  16 . For example, the tree  22  includes a tree bore which provides for completion and workover procedures, such as the insertion of tools into the well  16 , the injection of steam and various chemicals into the well  16  (down-hole), and the like. Further, minerals extracted from the well  16  (e.g., oil and natural gas) may be regulated and routed via the tree  22 . For instance, the tree  22  may be coupled to a jumper or a flowline that is tied back to other components, such as a manifold. Accordingly, produced minerals flow from the well  16  to the manifold via the wellhead  12  and/or the tree  22  before being routed to shipping or storage facilities. A blowout preventer (BOP) may also be included, either as a part of the tree  22  or as a separate device. The BOP may consist of a variety of valves, fittings and controls to prevent oil, gas, or other fluid from exiting the well in the event of an unintentional release of pressure or an overpressure condition. 
     In the present configuration, the well-bore  20  includes a surface casing  28  extending vertically downward from the surface conductor pipe  18 . As illustrated, production tubing  30  extends through the surface casing  28  from the wellhead  12  to the mineral deposit  14 . The production tubing  30  includes a substantially vertical portion  32  and a substantially horizontal portion  34 . The substantially vertical portion  32  extends from the surface to the approximate depth of the mineral deposit  14 , while the substantially horizontal portion  34  engages the mineral deposit  14 . As a result of this geometry, the production tubing  30  includes a heel  36  which forms an approximately 90 degree bend between the substantially vertical portion  32  and the substantially horizontal portion  34 . In addition, a toe  38  is positioned at the opposite end of the substantially horizontal portion  34  from the heel  36 . As illustrated, the toe  38  engages the mineral deposit, thereby enabling product to flow into the well-bore  20 . In addition, the horizontal portion  34  of the production tubing  30  which engages the mineral deposit  14  includes a pickup liner  39  having multiple slots configured to facilitate increased product flow into the production tubing  30 . 
     The present mineral extraction system  10  may be utilized for SAGD operations. In such operations, steam is injected through the wellhead  12  into the geologic formation containing the mineral deposit  14 , such as oil sands. The well is then shut in for a period of time (e.g., several months) allowing the oil to “heat soak.” After the soaking period, the well is opened such that the heated oil and condensed steam may be extracted. However, because the oil may still be substantially viscous, an artificial lift pump, such as the illustrated electric submersible pump (ESP)  40 , may be employed to transfer oil from the mineral deposit  14  to the wellhead  12 . In certain SAGD configurations, the ESP  40  is positioned within the production tubing  30  adjacent to the heel  36 . 
     As will be appreciated, an ESP conduit  42  may extend through the surface casing  28  to provide electrical power to the ESP  40 . As discussed in detail below, the ESP conduit  42  passes through the wellhead  12 , from an electrical feed-through connector  44  to the well-bore  20 . In the present configuration, the electrical feed-through connector  44  includes a mandrel configured to mount directly to the tubing head adapter  26 , thereby establishing a seal between the conduit  42  and the wellhead  12 . Because the present guide string hanger includes an opening configured to accommodate the diameter of the electrical feed-through connector  44 , the present wellhead  12  may have a smaller vertical extent than configurations in which the mandrel is positioned above the guide string hanger. 
     For example, certain hangers are configured to support and seal the production tubing  30  and guide string. Due to the high pressures and temperatures associated with SAGD production, the seals may utilize a relatively large radial area of the hanger. For example, the seals may be configured to resist a pressure of greater than approximately 2000, 2500, 3000 psi, or more, and a temperature of greater than approximately 550, 600, 650 degrees Fahrenheit, or more. Consequently, due to the large radial area of the seals, insufficient area may remain to accommodate the diameter of the mandrel. As a result, the mandrel may be positioned above the hanger such that only the conduit  42  extends through the hanger. Because the entire mandrel is positioned above the hanger, the wellhead may have a large vertical extent. In certain embodiments of the present disclosure, separate hangers are employed to support and seal the production tubing  30  and the guide string, thereby increasing the available radial area of each hanger. As a result, the mandrel may pass through the tubing hanger and the guide string hanger. Consequently, the mandrel may be secured directly to the tubing head adapter  26 , thereby decreasing the vertical extent of the wellhead  12  and substantially reducing wellhead manufacturing costs. 
     In addition to the production tubing  30  and the ESP conduit  42 , a guide string  46  may extend through the surface casing  28 . As will be appreciated, the guide string  46  may be configured to facilitate running coiled tubing through the wellhead  12  and into the surface casing  28 . The coiled tubing may be utilized for gas lift, catalyst injection, temperature and/or pressure monitoring, among other uses. Based on the application, the coiled tubing and guide string  46  may extend to the heel  36 , the toe  38 , or other region adjacent to the production tubing  30 . The coiled tubing also passes through the wellhead  12  and couples to a valve  48  configured to regulate flow of various fluids through the coiled tubing. As illustrated, the valve  48  is directly coupled to the tubing head adapter  26 . As previously discussed, the vertical extent of the wellhead  12  may be reduced due to the increased radial seal area generated by employing an independent guide string hanger. Consequently, the “toad stool” or extension utilized to couple the valve to the tubing head adapter employed in other wellhead configurations due to geometric limitations may be obviated. 
     As discussed in detail below, certain embodiments of the present wellhead configuration employ a guide string hanger that is independent of the tubing hanger. In such embodiments, the tubing hanger may be supported within the casing head  24  by a first retaining feature, and the guide string hanger may be supported by a second retaining feature of the casing head  24 . For example, the guide string hanger may be supported by a shoulder, while the tubing hanger is suspended above the guide string hanger by a tapered portion of the casing head  24  or a second shoulder. In certain embodiments, the guide string hanger may include a recess disposed in an outer radial surface and configured to interface with a plug removably coupled to the casing head  24 . Contact between the plug and the recess may block axial translation and circumferential rotation of the guide string hanger. Furthermore, circumferential rotation of the tubing hanger may be blocked by contact between a neck extending axially upward from the guide string hanger and a corresponding recess within the tubing hanger. Moreover, due to the length of the neck, the tubing hanger may translate in the axial direction without disengaging the guide string hanger. In further embodiments, the guide string hanger may have openings sufficiently large to facilitate passage of the production tubing  30  with the ESP conduit  42  attached. In such embodiments, the guide string  46  may be run prior to running the production tubing  30 . In addition, the guide string hanger may include a threaded connection that enables the guide string hanger to be run with a segment of guide string, thereby decreasing the operational costs associated with the running process. 
       FIG. 2  is a top view of an exemplary wellhead  12  that may be used in the mineral extraction system  10  of  FIG. 1 . As illustrated, both the valve  48  and the electrical feed-through connector  44  are coupled to the tubing head adapter  26 . In addition, a tubing bore  50  extends through the tubing head adapter  26  and the casing head  24 . As discussed in detail below, the tubing bore  50  is configured to establish fluid communication between the production tubing  30  and the tree  22 . In the present configuration, the bore  50 , the valve  48  and the electrical feed-through connector  44  are offset relative to a geometric center  52  of the casing head  24 . Specifically, the components  44 ,  48  and  50  are offset in a radial direction  54  relative to the geometric center  52 , and a circumferential direction  56  relative to one another. As discussed in detail below, this radial and circumferential offset is particularly configured to facilitate passage and sealing of the production tubing  30 , the ESP mandrel, and guide string  46 . Furthermore, an annulus valve  58  is coupled to an outer surface of the casing head  24  to facilitate passage of fluid between the annulus and an exterior of the wellhead  12 . 
       FIG. 3  is a cross-sectional view of the wellhead  12 , taken along line  3 - 3  of  FIG. 2 , having a tubing hanger  60  and an independent guide string hanger  62  disposed within the casing head  24 . As illustrated, the casing head  24  is configured to facilitate passage of the production tubing  30 , the ESP conduit  42  and the guide string  46 . In the present embodiment, the wellhead  12  includes a tubing hanger  60  and an independent guide string hanger  62 . The tubing hanger  60  is configured to support the production tubing  30 , and the guide string hanger  62  is configured to support the guide string  46 . As illustrated, the tubing hanger  60  and the guide string hanger  62  are aligned along an axial direction  64  within a bore  66  of the casing head  24 . In addition, the tubing hanger  60  and the guide string hanger  62  are vertically stacked, with the tubing hanger  60  above the guide string hanger  62 . As discussed in detail below, the guide string hanger  62  is supported by a shoulder  68  of the casing head bore  66 . Furthermore, the tubing hanger  60  is supported by a tapered portion  70  of the casing head  24 . Specifically, a tapered portion  72  of the tubing hanger  60  is configured to interface with the tapered portion  70  of the casing head  24 , thereby supporting the tubing hanger  60  in the axial direction  64 . It should be appreciated that the tubing hanger  60  may be supported by other retaining features in alternative embodiments. For example, in certain embodiments, the casing head bore  66  may include a shoulder configured to support the tubing hanger  60 . In the present embodiment, a pair of seals  74  (e.g., rubber o-rings) is disposed between the tubing hanger  60  and the bore  66  to block a flow of fluid between the hanger  60  and casing head  24 . While two seals  74  are employed in the present embodiment, it should be appreciated that alternative embodiments may employ more or fewer seals  74 , such as 1, 2, 3, 4, 5, 6, or more. 
     In certain configurations, the production tubing  30  includes a threaded end  76  configured to interface with corresponding threads  78  of the tubing hanger  60 . The threaded connection enables the tubing hanger  60  to support the production tubing  30 , and serves to substantially block fluid from flowing out of the production tubing  30  and into an annulus  80 . Consequently, fluid from the mineral deposit  14  may be directed through the production tubing  30 , and into a bore  82  of the tubing hanger  60 . The fluid may then flow through the bore  50  of the tubing head adapter  26 , and into a conduit  84  which couples the tubing head adapter  26  to the production tree  22 . As a result of this configuration, fluid may be directed from the mineral deposit  14  to the tree  22  without significant leakage. 
     Similar to the threaded connection described above, the guide string  46  may include a threaded end  86  configured to interface with corresponding threads  88  of the guide string hanger  62 . The threaded connection enables the guide string hanger  62  to support the guide string  46 , while substantially blocking fluid flow between the guide string  46  and the annulus  80 . As previously discussed, the guide string  46  is configured to facilitate running coiled tubing  90  through the wellhead  12  and into the surface casing  28 . The coiled tubing  90  may be utilized for gas lift, catalyst injection, temperature and/or pressure monitoring, among other uses. As illustrated, the coiled tubing  90  extends through the guide string  46 , and passes through an opening  92  within the guide string hanger  62 . The coiled tubing  90  then extends through an opening  94  within the tubing hanger  60 , and an opening  96  within the tubing head adapter  26 . Finally, the coiled tubing  90  couples to the valve  48  configured to regulate fluid flow through the coiled tubing  90 . 
     As illustrated, the opening  94  within the tubing hanger  60  includes a substantially straight portion  98  aligned with the axial direction  64 , and an angled portion  100 , extending between the substantially straight portion  98  and the valve  48 . In the present configuration, the valve  48  is directly mounted to the tubing head adapter  26  at an angle configured to provide clearance between the conduit  84  and the valve  48 /coiled tubing slip assembly  102 . Consequently, the angle of the angled portion  100  is selected to substantially correspond to the angle of the valve  48  and slip assembly  102 . For example, the angle may be approximately between 0 to 15, 2 to 10, or typically about 3 to 8 degrees. 
     In certain wellhead configurations which employ a single production tubing/guide string hanger, a tubing head body adapter is positioned between the casing head and the tubing head adapter. As will be appreciated, the tubing head body adapter is configured to provide clearance between the electrical feed-through mandrel and the hangers, and to align the ESP conduit, the production tubing and the guide string. In such configurations, the coiled tubing valve is mounted to the tubing head body adapter by an angled extension or “toad stool.” The toad stool serves to offset the valve and slip assembly from the tubing head body adapter. As discussed in detail below, the present embodiment obviates the tubing head body adapter because the electrical feed-through connector  44  mounts directly to the tubing head adapter  26  due to the additional radial seal area provided by the independent guide string hanger  62 . As a result, the toad stool which serves to offset the valve and slip assembly from the tubing head body adapter is obviated. Consequently, the valve  48  may be mounted directly to the tubing head adapter  26 , thereby decreasing the size, complexity and manufacturing costs associated with the present wellhead  12 . 
     As illustrated, the annulus valve  58  is mounted to a first radial side of the casing head  24 . As previously discussed, the valve  58  is configured to regulate a flow of fluid between the annulus  80  and external conduits, pipes and/or downstream components. In the present configuration, a fluid passage  104  within the casing head  24  extends between the valve  58  and the bore  66 . In addition, a passage  106  within the guide string hanger  62  is aligned with the casing head passage  104  such that fluid may flow between the annulus  80  and the valve  58  via the passages  104  and  106 . A plug  108  is secured to the opposite radial side of the casing head  24  by a flanged connection  110 . The plug  108  is configured to interface with the guide string hanger  62  to block movement of the hanger  62  in the axial direction  64 , and to block rotation of the hanger  62  in the circumferential direction  56 . As discussed in detail below, the guide string hanger  62  includes a neck  112  configured to interface with the tubing hanger  60  to block rotation of the hanger  60  in the circumferential direction  56  and/or to establish a seal with the hanger  60 . 
     As discussed in detail below, the guide string hanger  62  includes openings sufficiently large to facilitate passage of the production tubing  30  with the ESP conduit  42  attached (e.g., strapped to the production tubing  30 ). In this configuration, the guide string  46  may be run prior to running the production tubing  30 . In addition, the guide string hanger  62  may include a threaded connection that enables the guide string hanger to be run with a segment of guide string, thereby decreasing the operational costs associated with the running process. Moreover, because the guide string hanger  62  and the tubing hanger  60  include openings sufficiently large to facilitate passage of the electrical feed-through mandrel, the mandrel may be sealed to the tubing head adapter  26 , thereby substantially decreasing the vertical extent of the wellhead  12  compared to configurations in which the mandrel is positioned above the tubing hanger and guide string hanger. 
       FIG. 4  is a detailed cross-sectional view of the independent guide string hanger  62 , taken within line  4 - 4  of  FIG. 3 . As illustrated, the guide string hanger  62  is supported by the shoulder  68  of the casing head  24 . As will be appreciated, the shoulder  68  is configured to support a wear bushing which may be present during drilling operations. By utilizing the existing shoulder  68  to support the guide string hanger  62 , the present embodiment may be implemented with substantially no modifications to the casing head  24 . In the present configuration, the guide string hanger  62  includes an angled (e.g., tapered) portion  114  configured to substantially match the contour of the shoulder  68 . In this manner, movement of the guide string hanger  62  in the axial and radial directions  64  and  54  will be blocked by contact between the angled portion  114  and the shoulder  68 . 
     To facilitate running (e.g., lowering) the guide string hanger  62  into the illustrated installed position, the opening  92  includes an upper threaded end  116 . Similar to the lower threaded end  88 , the upper threaded end  116  is configured to interface with corresponding threads of a guide string segment. In such a configuration, prior to installation, a guide string segment may be secured to the guide string hanger  62  via the upper threaded end  116 . Next, the guide string hanger  62  may be run into the casing head bore  66  by lowering the guide string segment until the angled portion  114  of the guide string hanger  62  contacts the shoulder  68 . At that point, the guide string segment may be uncoupled from the guide string hanger  62  and removed from the casing head bore  66 . In this manner, the present guide string hanger  62  may be run without special tools, thereby decreasing the operational costs associated with the running process. 
     As previously discussed, once the guide string hanger  62  has been lowered into position, the hanger  62  may be secured by the plug  108 . As illustrated, the plug  108  includes a larger diameter end  118  coupled to the flanged connection  110 , and a smaller diameter end  120  configured to engage the guide string hanger  62 . Specifically, the guide string hanger  62  includes a recess  122  located at one circumferential position along an outer radial surface of the guide string hanger  62 . The recess  122  is shaped to substantially correspond to the shape of the smaller diameter end  120 . Consequently, after the guide string hanger  62  has been lowered into position, the recess  122  may be aligned with a passage  124  within the casing head  24 . The plug  108  may then be inserted into the passage  124  such that the smaller diameter portion  120  engages the recess  122 . After engagement, the plug  108  may be secured to the casing head  24  by the flanged connection  110 . As a result of this configuration, movement of the guide string hanger  62  in the axial direction  64  and rotation of the hanger  62  in the circumferential direction  56  are blocked by contact between the smaller diameter portion  120  and the recess  122 . 
     Furthermore, the guide string hanger  62  is configured to block rotation of the tubing hanger  60  in the circumferential direction  56 . As previously discussed, the guide string hanger  62  includes a neck  112  located at one circumferential position along an upper axial surface of the guide string hanger  62 . In addition, the tubing hanger  60  includes a recess  126  located at one circumferential position along a lower axial surface of the tubing hanger  60 . In this configuration, as the tubing hanger  60  is run into the casing head bore  66 , the recess  126  may be aligned with the neck  112  such that the neck  112  engages the recess  126 . Once the tubing hanger  60  is in the illustrated installed position, rotation of the hanger  60  in the circumferential direction  56  is blocked by contact between the neck  112  and the recess  126 . Because rotation of the guide string hanger  62  is blocked by the plug  108 , the tubing hanger  60  may not rotate relative to the casing head  24 . As discussed in detail below, the neck  112  may include a seal which contacts the recess  126  to block fluid flow between the annulus  80  and the opening  94 . 
     As previously discussed, movement of the tubing hanger  60  in an axially downward direction  125  is blocked by contact with the bore  66  of the casing head  24 . Specifically, the tapered portion  72  of the tubing hanger  60  is configured to interface with the tapered portion  70  of the casing head  24 , thereby supporting the tubing hanger  60  in the axial direction  64 . In addition, the pair of seals  74  (e.g., rubber o-rings or graphite yarn) disposed between the tubing hanger  60  and the bore  66  substantially block flow fluid between the hanger  60  and casing head  24 . In this configuration, the tubing hanger  60  may “float” or move in an axially upward direction  127  due to hydraulic fluid pressure between the hanger  60  and the casing head  24 . As illustrated, the neck  112  is positioned a distance  128  within the recess  126 . Consequently, the tubing hanger  60  may translate in the axially upward direction  127  a distance substantially equal to the overlap  128  between the neck  112  and the recess  126 , while blocking rotation of the tubing hanger  60 . 
     While the tubing hanger  60  is supported by the tapered portion  70  of the casing head  24  in the present embodiment, it should be appreciated that the tubing hanger  60  may be supported by other retaining features in alternative embodiments. For example, in certain embodiments, the casing head bore  66  may include a shoulder configured to support the tubing hanger  60 . In such embodiments, the tubing hanger  60  may be locked into the lowered position by pins, for example. As a result, movement of the tubing hanger  60  in the axially upward direction  127  will be blocked, thereby substantially reducing or eliminating the float described above. 
     As discussed in detail below, the guide string hanger  62  includes openings sufficiently large to facilitate passage of the production tubing  30  with the ESP conduit  42  attached (e.g., strapped to the production tubing  30 ). In this configuration, the guide string  46  may be run prior to running the production tubing  30 . In addition, because the guide string hanger  62  and the tubing hanger  60  include openings sufficiently large to facilitate passage of the electrical feed-through mandrel, the mandrel may be sealed to the tubing head adapter  26 , thereby substantially decreasing the vertical extent of the wellhead  12  compared to configurations in which the mandrel is positioned above the tubing hanger  60  and guide string hanger  62 . 
       FIG. 5  is a cross-sectional view of the wellhead  12 , taken along line  5 - 5  of  FIG. 2 , showing an electrical feed-through mandrel passing through the tubing hanger  60 . As illustrated, the electrical feed-through connector  44  includes an electrical conduit  130  configured to deliver electrical power to the ESP  40  via the down-hole conduit  42 . The electrical feed-through connector  44  also includes a substantially rigid, cylindrical housing  132  configured to block a flow of high pressure and high temperature steam from exiting the wellhead  12 . In the present embodiment, the cylindrical housing  132  includes an upper connection  134  having an angled neck  136 , a mandrel  138  extending through the tubing head adapter  26  and tubing hanger  60 , and a lower connector  140  extending through the guide string hanger  62 . In certain embodiments, the electrical feed-through connector  44  may include a BIW connector manufactured by ITT Corporation of White Plains, N.Y. 
     In certain embodiments, the upper connector  134  and the lower connector  140  may be coupled to the mandrel  138  via respective threaded connections. For example, external threads may be disposed on each axial side of the mandrel  138 . The upper connector  134  and the lower connector  140  may include corresponding internal threads configured to interface with the external threads of the mandrel  138 . In such a configuration, the upper connector  134  and the lower connector  140  may be coupled to the mandrel  138  via rotation of the respective connector  134  and/or  140 , or rotation of a sleeve coupled to the respective connector  134  and/or  140  and including the internal threads. The upper connector  134  and/or the lower connector  140  may include electrical stabs or prongs configured to engage corresponding receptacles in the mandrel  138 , thereby establishing an electrical connection between the external electrical conduit  130  and the down-hole conduit  42 . 
     As illustrated, the mandrel  138  extends through an opening  142  within the tubing head adapter  26  and an opening  144  within the tubing hanger  60 . Similarly, the lower connector  140  extends through an opening  146  within the guide string hanger  62 . In the present configuration, the outer diameter of the mandrel  138  is substantially equal to the inner diameter of the openings  142  and  144 . In addition, a first seal (e.g., multiple rubber o-rings)  148  may be disposed between the mandrel  138  and the tubing head adapter  26 , and a second seal (e.g., multiple rubber o-rings)  150  may be disposed between the mandrel  138  and the guide string hanger  60 . Consequently, the mandrel  138  may serve to substantially block a flow of steam out of the wellhead  12 , while establishing an electrical connection with the ESP  40 . 
       FIG. 6  is a perspective view of the independent guide string hanger  62 , as shown in  FIG. 2 . As illustrated, the guide string hanger  62  includes the passage  106  configured to establish fluid communication between the valve  58  and the annulus  80 . In addition, the guide string hanger  62  includes the recess  122  configured to interface with the plug  108  to block rotation and translation of the guide string hanger  62  relative to the casing head  24 . While a substantially round recess  122  is employed in the present embodiment, it should be appreciated that alternative embodiments may employ other recess shapes (e.g., square, hexagonal, etc.) which correspond to the shape of the plug  108 . Furthermore, because the recess  122  does not extend through the structure of the guide string hanger  62 , fluid may not pass through the recess  122 . As previously discussed, because the recess  122  is disposed on an opposite radial side of the guide string hanger  62  from the passage  106 , rotating the guide string hanger  62  such that the recess  122  aligns with the plug  108  aligns the passage  106  with the passage  104  in the casing head  24 . In this manner, when the plug  108  is inserted into the recess  122 , the passage  106  is aligned with the passage  104 , thereby establishing a fluid path between the annulus  80  and the valve  58 . 
     In the present embodiment, the guide string hanger  62  includes an opening  152  configured to facilitate passage of the production tubing  30 . As previously discussed, the production tubing  30  is coupled and sealed to the tubing hanger  60 , which is vertically stacked above the guide string hanger  62  in the present embodiment. Consequently, the present guide string hanger  62  is configured to accommodate the production tubing  30  without sealing or supporting the tubing  30 . The guide string hanger  62  also includes the opening  146  configured to facilitate passage of the electrical feed-through connector  44 . As illustrated, the openings  146  and  152  adjoin one another without any hanger material positioned between the openings  146  and  152 . Consequently, the production tubing  30  and the electrical conduit  42  may be run together without interference from the guide string hanger  62 . For example, the electrical conduit  42  may be strapped to the production tubing  30  as the tubing  30  is lowered into the well-bore  20 . Because the openings  152  and  146  may accommodate the combined tubing and conduit assembly, the guide string  46  may be run prior to running the tubing  30 . 
       FIG. 7  is a top view of the independent guide string hanger  62 , as shown in  FIG. 2 . As illustrated, the tubing opening  152 , the electrical conduit opening  146  and the coiled tubing opening  92  are offset from a geometric center  154  of the guide string hanger  62  along the radial direction  54 . In addition, the openings  152 ,  146  and  92  are offset from one another along the circumferential direction  56 . Such a configuration may accommodate passage of the production tubing  30 , the electrical conduit  42  and the coiled tubing  90  through the present guide string hanger  62 . As previously discussed, the production tubing  30  and the electrical conduit  42  may be run simultaneously. Consequently, the combined area of the openings  152  and  146  may facilitate passage of the tubing/conduit assembly. In the present embodiment, a diameter  156  of the opening  152  is sufficient to accommodate passage of the ESP  40 , and a diameter  158  of the opening  146  is sufficient to accommodate the electrical feed-through connector  44 . As will be appreciated, the ESP  40  may be run along with the production tubing  30 , and a diameter of the ESP  40  may be larger than a diameter of the production tubing  30 . Because the diameter  156  of the production tubing opening  152  is larger than the diameter of the ESP, the guide string hanger  62  may be run (i.e., lowered into position) prior to running the production tubing  30 . 
     While the guide string hanger  62  is configured to facilitate passage of the ESP  40 , production tubing  30  and electrical conduit  42  through the openings  152  and  146 , the present guide string hanger  62  includes sufficient remaining radial area to seal the guide string  46 . As previously discussed, the guide string  46  includes outer threads  86  configured to interface with inner threads  88  of the guide string hanger  62 . Once coupled, the threaded connection serves to support the guide string  46  and provides a seal between the interior of the guide string  46  and the annulus  80 . Because the production tubing  30  is sealed to the tubing hanger  60  and the feed-through mandrel  138  is sealed to the tubing hanger  60  and tubing head adapter  26 , each fluid passage extending down-hole is substantially sealed at the wellhead  12 . Because the opening  146  is configured to accommodate the diameter of the electrical feed-through connector  44 , the present wellhead  12  may have a smaller vertical extent than configurations in which the mandrel is positioned above the guide string hanger. 
       FIG. 8  is a cross-sectional side view of the independent guide string hanger  62  and guide string  46 , taken along line  8 - 8  of  FIG. 7 . As previously discussed, the external threads  86  of the guide string  46  may be secured to the inner threads  88  of the guide string hanger  62 , thereby establishing a seal between the guide string  46  and the hanger  62 . Furthermore, the neck  112  of the guide string hanger  62  includes a seal  160  (e.g., rubber o-ring) configured to block fluid from flowing out of the guide string hanger  62 /tubing hanger  60  connection. As previously discussed, the neck  112  of the guide string hanger  62  is configured to interface with a recess  126  in the tubing hanger  60 , thereby blocking rotation of the tubing hanger  60  in the circumferential direction  56 . In addition, due to the length of the neck  112 , the tubing hanger  60  may float or rise in the axially upward direction  127  a distance substantially equal to the overlap  128  between the neck  112  and the recess  126 . In this configuration, the seal  160  substantially blocks fluid flow into the annulus  80  despite variations in separation distance between the tubing hanger  60  and the guide string hanger  62 . 
     While the invention may be susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and have been described in detail herein. However, it should be understood that the invention is not intended to be limited to the particular forms disclosed. Rather, the invention is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the invention as defined by the following appended claims.