Patent Publication Number: US-11035193-B2

Title: Tubing hanger assembly with wellbore access, and method of supplying power to a wellbore

Description:
CROSS REFERENCE TO RELATED APPLICATIONS 
     This application claims the benefit of U.S. Ser. No. 62/611,490 filed Dec. 28, 2017. That application is entitled “Tubing Hanger Assembly With Wellbore Access, and Method of Supplying Energy to a Wellbore,” and is incorporated herein in its entirety by reference. 
    
    
     STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
     Not applicable. 
     THE NAMES OF THE PARTIES TO A JOINT RESEARCH AGREEMENT 
     Not applicable. 
     BACKGROUND OF THE INVENTION 
     This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art. 
     FIELD OF THE INVENTION 
     The present disclosure relates to the field of hydrocarbon recovery operations. More specifically, the present invention relates to an assembly for providing line power from a power box at the surface, and down to an electrical submersible pump. The invention also relates to a method of accessing a wellbore through a tubing hanger using a series of protective discs. 
     Technology in the Field of the Invention 
     In the drilling of oil and gas wells, a wellbore is formed using a drill bit that is urged downwardly at a lower end of a drill string. The drill bit is rotated while force is applied through the drill string and against the rock face of the formation being drilled. After drilling to a predetermined depth, the drill string and bit are removed and the wellbore is lined with a string of casing. 
     It is common to place several strings of casing having progressively smaller outer diameters into the wellbore. In this respect, the process of drilling and then cementing progressively smaller strings of casing is repeated several times until the well has reached total depth. The final string of casing, referred to as a production casing, is typically cemented into place. 
     As part of the completion process, the production casing is perforated at a desired level. Alternatively, a sand screen may be employed at a lowest depth in the event of an open hole completion. Either option provides fluid communication between the wellbore and a selected zone in a formation. In addition, production equipment such as a string of production tubing, a packer and a pump may be installed within the wellbore. 
     During completion, a wellhead is installed at the surface. Fluid gathering and processing equipment such as pipes, valves and separators are also provided. Production operations may then commence. 
     In typical land-based production operations, the wellhead includes a tubing head and a tubing hanger. The tubing head seals the wellbore at the surface while the tubing hanger serves to gravitationally support the long string of production tubing. The tubing hanger is landed along an internal shoulder of the tubing head while the tubing string extends down from the tubing hanger proximate to a first pay zone. 
     In connection with hanging the tubing in the wellbore, it is sometimes desirable to run an electric line to provide power to downhole components. Such components may include a resistive heater or an electric submersible pump (or “ESP”). To provide such access, a plug-in joint has been provided along the wellhead wherein a power cable at the surface is spliced and placed in electrical communication with a power cable in the wellbore leading down to the equipment to be powered. The plug-in joint is exposed to high pressure fluids, which are also frequently corrosive. 
     U.S. Pat. No. 4,583,804 entitled “Electric Feedthrough System,” sought to provide a wellhead arrangement for running a power cable at the surface through a wellhead. Such a wellhead arrangement offered a rigid housing adapter along the tubing head to accommodate and to isolate the electric line. However, the housing utilized conductive copper rods that required the three wires of an armored electrical cable to be stripped of their insulating casing and separated, and then further exposed to be spliced to the copper rods. The spliced wires leave the wellhead vulnerable to volatile production fluids and shorting. 
     Accordingly, a need exists for an improved tubing hanger that provides access to the wellbore during well completion. Further, a need exists for a tubing hanger assembly that enables the pass-through of electrical conduit through the wellhead without exposing uninsulated conductive wires. Still further, a need exists for an improved tubing hanger that offers a port that is offset from but parallel with the tubing string for receiving conduit, such as electrical wiring that provides power to an electrical submersible pump, without splicing and connecting conductive wires along the wellhead. 
     SUMMARY OF THE INVENTION 
     A tubing hanger assembly for gravitationally supporting a production tubing string within a wellbore is provided herein. The tubing hanger assembly generally comprises a tubing head and a tubing hanger. Beneficially, the tubing hanger assembly allows the operator to install an insulated power cable through the wellhead and into the wellbore without the splicing of conductive wires along the wellhead or completely removing insulation. 
     The tubing head has an upper end and a lower end, and defines a central bore having a conical surface. The upper end comprises a flange having a plurality of radially disposed holes. The holes permit the wellhead to be bolted to other components that make up a so-called Christmas Tree at the surface. 
     The tubing hanger is configured to reside along the central bore of the tubing head and over the wellbore. The tubing hanger comprises a central bore that extends from its upper end to its lower end. The tubing hanger includes a beveled surface along an outer diameter. This beveled surface lands on the conical surface of the tubing head to provide gravitational support for the production tubing. 
     The tubing hanger defines a tubular body. The tubular body has an upper threaded end and a lower threaded end. The lower threaded end is configured to threadedly mate with the upper end of a joint of production tubing. Specifically, the joint of production tubing is the uppermost joint of tubing in a long tubing string that extends down into the wellbore. Those of ordinary skill in the art will know that the upper end of a joint of tubing string is referred to as the “box end.” A male-to-male pup joint may be used to connect the tubing hanger to the uppermost joint of tubing. 
     Beneficially, the tubing hanger provides an auxiliary port that is offset from, but that is co-axial with, the central bore. The auxiliary port also extends from the upper end to the lower end of the tubular body. 
     The tubing hanger assembly also comprises:
         at least one elastomeric disc configured to reside within the auxiliary port and to receive separated conductive wires of an electric power cable; and   at least one rigid disc also configured to reside within the auxiliary port and to receive separated conductive wires of an electric power cable.       

     In addition, the tubing hanger assembly comprises a bottom plate. The bottom plate resides along the lower end of the tubular body and gravitationally supports the at least one elastomeric disc and the at least one rigid disc. Preferably, the elastomeric discs and the rigid discs are stacked in series, in alternating arrangement, to form a disc stack. 
     Preferably, the elastomeric discs are fabricated from neoprene, while the rigid discs are fabricated from a polycarbonate material such as so-called PEEK. The at least one elastomeric disc is configured to expand within the auxiliary port when compressed in order to seal the conductive wires and the auxiliary port from reservoir fluids. At the same time, the at least one rigid disc is configured to retain rigidity within the auxiliary port during installation and during production operations to keep the conductive wires separated from the steel material making up the tubular body. 
     Preferably, the at least one elastomeric disc comprises at least two elastomeric discs and the at least one rigid discs comprises at least two rigid discs. The elastomeric discs and the rigid discs are alternatingly stacked, in series, within the auxiliary port to form the disc stack. 
     In one embodiment: 
     each of the at least two elastomeric discs comprises three central through-openings for receiving respective conductive wires of the power cable; 
     each of the at least two rigid discs also comprises three central through-openings for receiving respective conductive wires of the power cable; 
     the central through-openings of the elastomeric discs and the central through-openings of the rigid discs are aligned along the disc stack; and 
     each of the conductive wires retains its own plastic insulation along the auxiliary port. 
     In a preferred embodiment, the bottom plate comprises a central through-opening for receiving the conductive wires below the disc stack en route to the wellbore. The bottom plate is secured to the bottom end of the tubular body, such as by means of bolts. Preferably, sufficient discs are placed along the disc stack so that when the bottom plate is secured, the operator must apply compression to force the elastomeric discs to expand and to fill the auxiliary port. In this way, a fluid seal is formed by causing the elastomeric discs to extrude around the conductive wires. At the same time, the rigid discs provide separation of the conductive wires from the metal body of the tubing hanger, preventing arcing or shorting. 
     In one aspect: 
     each of the at least two elastomeric discs is cut in half along the central through-openings to receive respective conductive wires; and 
     each of the at least two rigid discs is also cut in half along the central through-openings to receive respective conductive wires. 
     This permits each of the respective disc halves to be placed back together before loading into the auxiliary port. 
     In one embodiment, the tubing hanger further comprises a pair of elongated alignment pins. In this instance, each of the at least two elastomeric discs and each of the at least two rigid discs comprises a pair of opposing through-openings configured to receive a respective alignment pin along the disc stack. This keeps the three central through openings aligned. 
     In one arrangement, the tubing hanger further comprises a rigid, non-conductive sleeve residing at a top of the disc stack. The sleeve accommodates space along the auxiliary port, reducing the number of discs required. The sleeve lands on an upper shoulder along the auxiliary port and provides a smooth transition into the auxiliary port. In another arrangement, an uppermost disc and a lowermost disc of the rigid discs along the disc stack have a thickness that is greater than a thickness of the intermediate rigid discs. 
     In operation, the tubing head is placed over the wellbore as part of a well head. The tubing head seals the wellbore in order to isolate wellbore fluids during production operations. 
     A power cable is run into the wellbore. Typically, the power cable is run with the joints of production tubing and is periodically clamped. Once the production string has been run into the wellbore, the uppermost joint of tubing is threadedly connected to the tubing hanger. At this point, the outer conductive sheath is removed from a length of the power cable, revealing three insulated conductive wires. 
     The conductive wires are laid out separately along the disc stack. More specifically, the conductive wires are placed along disc halves of the stack, with each wire being placed along one of the three central through-openings. Once the wires are in place, the mating disc halves are put back in place and the disc stack is inserted into the auxiliary port from the bottom end. Preferably, the non-conductive rigid sleeve is placed above the disc stack. 
     The operator installs the bottom plate onto the bottom of the tubing hanger. The conductive wires pass through a central through-opening in the bottom plate en route to the wellbore. The disc stack is now held in place and the power cable is able to pass through the wellhead without splicing. Once the wires have extended below the auxiliary port, they are once again in their sheathed state. 
     As part of the installation procedure, the operator will make a determination as to how many elastomeric discs and rigid discs will make up the disc stack. Ideally, the disc stack will be longer than the space available within the auxiliary port, taking into account the length of the non-conductive sleeve (if used). The operator will use the bottom plate to push on the disc stack, compressing the elastomeric discs so that a series of annular seals is provided along the auxiliary port. Pushing on the disc stack reduces its length, allowing the full stack to fit within the auxiliary port. 
     It is noted that the present tubing hanger assembly may also be used in running other communications lines into the wellbore. For example, fiber optic cable may be passed through the auxiliary port, either in addition to or in lieu of the power cable. In one aspect, the communications line is a power cable that provides power to a downhole resistive heater element as opposed to an ESP. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       So that the manner in which the present inventions can be better understood, certain illustrations are appended hereto. It is to be noted, however, that the drawings illustrate only selected embodiments of the inventions and are therefore not to be considered limiting of scope, for the inventions may admit to other equally effective embodiments and applications. 
         FIG. 1  is a partial cut-away view of a tubing head and a tubing hanger. The tubing hanger has landed on a conical inner surface of the tubing head, and is gravitationally supporting a string of production tubing from the surface. The tubing hanger includes an auxiliary port parallel with but offset from a vertical axis of the tubing string. 
         FIG. 2  is a cross-sectional view of the tubing hanger of the present invention, in one embodiment. The auxiliary port for receiving a communications line (such as a power cable) is shown in cut-away view. 
         FIG. 3  is a partial perspective view of the tubing hanger of the present invention, in one embodiment. Here, the tubing hanger is connected to an uppermost joint of a production tubing string. The tubing hanger and tubing string are being lowered into the tubing head. 
         FIG. 4  is a perspective view of the tubing hanger of  FIG. 3 , without the tubing head. Parts of the tubing hanger are shown in exploded apart relation. 
         FIG. 5A  is a bottom view of a tubular body making up the tubing hanger of  FIG. 3 . 
         FIG. 5B  is a side view of the tubing hanger. 
         FIG. 5C  is a perspective view of the tubing hanger. 
         FIG. 6A  is an end view of an alignment pin as may be used to align discs for receiving the power cable along the auxiliary port. 
         FIG. 6B  is a side view of the alignment pin of  FIG. 6A . 
         FIG. 6C  is a perspective view of the alignment pin of  FIG. 6A . 
         FIG. 7A  is an end view of an optional rigid, non-conductive sleeve of the tubing hanger of  FIG. 2 . 
         FIG. 7B  is a side view of the non-conductive sleeve of  FIG. 7A . 
         FIG. 7C  is a perspective view of the non-conductive sleeve. 
         FIG. 8A  is a top view of a bottom plate of the tubing hanger of  FIG. 2 . The bottom plate is used to support and to compress elastomeric discs for sealing the auxiliary port. 
         FIG. 8B  is a side view of the bottom plate of  FIG. 8A . 
         FIG. 8C  is a perspective view of the bottom plate of  FIG. 8A . 
         FIG. 9A  is a top view of an elastomeric disc to be placed within the auxiliary port, in one embodiment. The elastomeric disc responds to compressive force supplied through the bottom plate. 
         FIG. 9B  is a side view of the elastomeric disc of  FIG. 9A . 
         FIGS. 9C and 9D  are perspective views of the elastomeric disc of  FIG. 9A , taken from opposing ends. 
         FIG. 10A  is a top view of a “thick” disc fabricated from a rigid, non-conductive material as used in the tubing hanger of  FIG. 2 . The thick disc may be used as part of a stack of discs wherein elastomeric and rigid discs alternate in series within the auxiliary port. 
         FIG. 10B  is a side view of the thick disc of  FIG. 10A . 
         FIGS. 10C and 10D  are perspective views of the thick disc of  FIG. 10A , taken from opposing ends. 
         FIG. 11A  is a top view of a “thin” disc fabricated from a rigid, non-conductive material as used in the tubing hanger of  FIG. 2 . The thin disc is also used as part of a stack of discs wherein conductive and rigid discs alternate in series within the auxiliary port. 
         FIG. 11B  is a side view of the thin disc of  FIG. 11A . 
         FIGS. 11C and 11D  are perspective views of the thin disc of  FIG. 11A , taken from opposing ends. 
         FIG. 12  is a cut-away view of a wellbore as may receive the tubing hanger assembly and connected tubing string of  FIG. 1 . 
     
    
    
     DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS 
     Definitions 
     For purposes of the present application, it will be understood that the term “hydrocarbon” refers to an organic compound that includes primarily, if not exclusively, the elements hydrogen and carbon. Hydrocarbons may also include other elements, such as, but not limited to, halogens, metallic elements, nitrogen, oxygen, and/or sulfur. 
     As used herein, the term “hydrocarbon fluids” refers to a hydrocarbon or mixtures of hydrocarbons that are gases or liquids. For example, hydrocarbon fluids may include a hydrocarbon or mixtures of hydrocarbons that are gases or liquids at formation conditions, at processing conditions, or at ambient condition. Hydrocarbon fluids may include, for example, oil, natural gas, coalbed methane, shale oil, pyrolysis oil, pyrolysis gas, a pyrolysis product of coal, and other hydrocarbons that are in a gaseous or liquid state. 
     As used herein, the terms “produced fluids,” “reservoir fluids” and “production fluids” refer to liquids and/or gases removed from a subsurface formation, including, for example, an organic-rich rock formation. Produced fluids may include both hydrocarbon fluids and non-hydrocarbon fluids. Production fluids may include, but are not limited to, oil, natural gas, pyrolyzed shale oil, synthesis gas, a pyrolysis product of coal, oxygen, carbon dioxide, hydrogen sulfide and water. 
     As used herein, the term “fluid” refers to gases, liquids, and combinations of gases and liquids, as well as to combinations of gases and solids, combinations of liquids and wellbore fines, and combinations of gases, liquids, and fines. 
     As used herein, the term “wellbore fluids” means water, hydrocarbon fluids, formation fluids, or any other fluids that may be within a wellbore during a production operation. 
     As used herein, the term “gas” refers to a fluid that is in its vapor phase. 
     As used herein, the term “subsurface” refers to geologic strata occurring below the earth&#39;s surface. 
     As used herein, the term “formation” refers to any definable subsurface region regardless of size. The formation may contain one or more hydrocarbon-containing layers, one or more non-hydrocarbon containing layers, an overburden, and/or an underburden of any geologic formation. A formation can refer to a single set of related geologic strata of a specific rock type, or to a set of geologic strata of different rock types. 
     As used herein, the term “communication line” or “communications line” refers to any line capable of transmitting signals or data. The term also refers to any insulated line capable of carrying an electrical current, such as for power. The term “conduit” may be used in lieu of communications line. 
     As used herein, the term “wellbore” refers to a hole in the subsurface made by drilling or insertion of a conduit into the subsurface. A wellbore may have a substantially circular cross section, or other cross-sectional shapes. The term “well,” when referring to an opening in the formation, may be used interchangeably with the term “wellbore.” 
     Description of Selected Specific Embodiments 
     An improved tubing hanger assembly is provided herein. The tubing hanger assembly is used to suspend a tubing string within a wellbore. The tubing hanger assembly includes a tubing hanger configured to gravitationally land on a beveled surface along the inner diameter of a tubing head, and to suspend a string of production tubing from the surface. Beneficially, the tubing hanger assembly is arranged to receive a continuous power cable from a power source at the surface and through the tubing hanger assembly, without the conductive wires being spliced. 
       FIG. 1  is a cut-away view of a tubing head  100 . The tubing head  100  is a known tubing head (sometimes referred to as a “tubing spool”) that is configured to reside over a wellbore (see, e.g., wellbore  1200  in  FIG. 12 ). The tubing head helps in sealing production fluids from the wellbore at the surface. The “surface” may be a land surface; alternatively, the surface may be an ocean bottom or a lake bottom, or a production platform offshore. 
     The tubing head  100  defines a generally cylindrical body  110  having an outer surface (or outer diameter) and an inner surface (or inner diameter). The inner surface forms a bore  105  which is dimensioned to receive a tubing hanger  200 . Features of the tubing hanger  200  are described further below in connection with  FIGS. 2 through 4 . 
     The tubing head  100  and the tubing hanger  200  together may be referred to as a tubing hanger assembly. The purpose of the tubing hanger assembly is to support a string of production tubing  50  from the surface. It is understood that the tubing hanger assembly is a part of a larger wellhead (not shown, but well-familiar to those of ordinary skill in the art) used to control and direct production fluids from the wellbore and to enable access to the “back side” of the tubing string  50 . 
     As seen in  FIG. 1 , the tubing hanger  200  has landed on a conical surface  107  of the tubing head  100 . The conical surface  107  is dimensioned to receive a matching beveled surface (shown at  207  of  FIG. 2 ) of the tubing hanger  200 . In this way, the tubing hanger  200  (and connected tubing string  50 ) is gravitationally supported by the tubing head  100 . 
     The tubing head  100  comprises an upper flange  112 . The upper flange  112  includes a series of holes  114  radially disposed and equidistantly place along the upper flange  112 . The holes  114  are configured to receive bolts (not shown) having ACME threads. The bolts secure the upper flange  112  to a separate flanged body (not shown) that makes up a portion of a “Christmas Tree.” 
     The upper flange  112  includes opposing through-openings  116 . The through openings  116  threadedly receive respective lock pins  320 . The lock pins  320  help secure the tubing hanger  200  in place. The lock pins  320  include a distal end that may be translated into engagement with the tubing hanger  200 . More specifically, the distal end of the lock pins  320  engage a reduced inner diameter portion (shown at  203  in  FIG. 2 ) of the tubing hanger  200 . When engaged, the locking pins  320  prevent relative rotation of the tubing hanger  200  and connected tubing string  50  within the bore  105  of the tubing head  100 . 
     In the view of  FIG. 1 , a tubing hanger  200  has been placed within the inner surface  105  of the tubing head  100 . The tubing hanger  200  comprises a generally tubular body  210  having a central bore  205 . The tubing hanger  200  is configured to be closely received within the inner surface (or bore)  105  of the tubing head  100 . 
       FIG. 2  is a cross-sectional view of the tubing hanger  200  of the present invention, in one embodiment. The tubular body  210  making up the tubing hanger  200  is shown along with the central bore  205 . The tubular body  210  includes an upper end  212  and a lower end  214 . Each of the upper  212  and lower  214  ends comprises female threads within the bore  205 , representing upper threads and lower threads. The lower threads are configured to connect to the upper pin end of a joint of tubing  50 , making up a tubing connection  216 . That joint of tubing  50  becomes the uppermost tubing joint in a string of production tubing that is run into a wellbore during completion. 
     The tubular body  210  of the tubing hanger  200  defines an outer surface (or outer diameter). As shown in  FIG. 1 , the outer surface of the tubing hanger  200  is dimensioned to be closely received within the inner diameter of the tubing head  100 . As noted, the tubing hanger  200  includes a beveled surface  207 . In the preferred arrangement, the beveled surface  207  resides proximate the lower end  214  of the tubing hanger  200 . The beveled surface  207  is configured to land on the matching conical surface  107  of the tubing head  100 . In this way, the tubing hanger  200  and connected tubing string  50  are gravitationally supported at the top of the wellbore. 
     The tubing hanger  200  includes a series of o-rings  215 . The o-rings  215  provide a fluid seal between the outer surface of the tubing hanger  200  and the inner surface of the tubing head  100 . 
     Of interest, the tubing hanger  200  also includes an auxiliary port  220 . The auxiliary port  220  runs parallel with the central bore  205  of the tubing hanger  200 . The auxiliary port  220  includes a top end  222  and a bottom end  224 . The auxiliary port  220  defines a bore  225  from the top end  222  to the bottom end  224 . The bore  225  slidably receives separated (but still insulated) conductive wires from a power cable (seen in  FIG. 1  at  310 ). 
     Returning to  FIG. 1 , the power cable  310  is shown as three wires  305 . These represent a traditional positive wire, a negative wire and a ground. Each of the positive, negative and ground wires is separated along the auxiliary port  220 . This is done by removing the thick, insulating sheath from the power cable  310 . Each of the conductive wires  305  will still have at least its own thin plastic insulation, but the thick, insulating sheath for the power cable  310  is removed along the auxiliary port  220 . 
     For purposes of the present disclosure, the power cable  310  is designed to supply power from a power box  300  to an electrical submersible pump (or “ESP,” not shown) downhole. The power cable  305  extends from the electrical box  300 , through an NPT connection at the auxiliary port  220 , through the auxiliary port  220 , down the wellbore and then to the ESP. 
     A shoulder  228  is machined into the upper end of the auxiliary port  220 . A thin but rigid, non-conductive sleeve  230  is placed along the auxiliary port  220  against the shoulder  228 . The sleeve  230  provides a smooth entrance for the wires  305  into the auxiliary port  220  while also providing electrical insulation between the unsheathed wires  305  and the tubular metal body  210 . 
     The non-conductive sleeve  230  defines a cylindrical body and is preferably fabricated from a rigid plastic material such as PEEK. “PEEK” is an acronym for polyetheretherketone. PEEK is a high-performance engineering plastic known for its mechanical strength and dimensional stability. PEEK is also known for its resistance to harsh chemicals. PEEK material offers hydrolysis resistance and can maintain stiffness at high temperatures, such as up to 330° F. The non-conductive sleeve  230  may be, for example, four inches in length and have an inner diameter of 0.5 inches. 
     In addition to the rigid sleeve  230 , a series of discs is provided for the bore  225 . These preferably represent alternating rigid  240  and elastomeric  250  discs. As described further below in connection with  FIGS. 9, 10 and 11 , the discs  240 ,  250  maintain the electrical wires associated with the power cable  305  suitably separated, both from each other and from the conductive tubular body  210 . 
     In one optional aspect, an uppermost rigid disc  240 ′ has a thickness that is greater than the other rigid discs  240 . Optionally, four to eight rigid discs  240  fabricated from PEEK are provided, with an uppermost and a lowermost rigid disc  240 ′ having a thickness that is greater than the intermediate discs  240 . In any event, the elastomeric discs  250  are preferably spaced in alternating arrangement between the rigid discs  240 , forming a disc stack  255 . The disc stack  255  may also be referred to as packing. 
     Below the series of discs  240 ,  250  is a bottom plate  260 . The bottom plate  260  is used to secure the disc stack  255  within the auxiliary port  220 . At least some degree of compression is applied onto the bottom plate  260  and through the disc stack  255  in order to “energize” the elastomeric discs  250 . In this way, the bore  225  of the auxiliary port  220  is fluidically sealed from the wellbore below. 
     In a preferred embodiment, “energizing” means that the operator applies mechanical compression to the disc stack  255  in order to cause the neoprene material making up the elastomeric discs  250  to expand. However, in one aspect the material making up the elastomeric discs  250  is reactive to wellbore fluids, causing the discs  250  to still further expand. 
     The bottom plate  260  may include a central through-opening, designated as element  265  in  FIG. 8A . The through-opening  265  is dimensioned to receive the conductive wires  305  as they exit the tubing hanger  200 . Below the bottom plate  260 , the conductive wires  305  have their thick, insulating sheath, again forming a power cable  310  that will extend down the wellbore and to the ESP. A portion of the cable  310  is shown in  FIG. 2 , exiting the tubing hanger  200  with the three wires  305  bundled therein. 
     Finally, the tubing hanger  200  includes a bolt  270 . More specifically, and as shown in the exploded view of  FIG. 4 , a pair of bolts  270  is provided. The bolts  270  reside on opposing sides of the through-opening  265  and are used to secure the bottom plate  260  to the lower end  224  of the tubing hanger body  210  using, for example, ACME threads. 
       FIG. 3  is a perspective view of the tubing hanger  100  of the present invention, in one embodiment. Here, the tubing hanger  200  is connected to an uppermost joint of a production tubing string  50 . In addition, a power cable  305  is shown extending through the tubing hanger  200  and down into the tubing head  100 . 
     At a top of  FIG. 3  is a landing tubing joint  55 . This is a joint of tubing that is simply a working joint. The tubing joint  55  is threadedly connected to the upper threads of the tubing hanger  200  at the upper end  212 . The tubing joint  55  and connected tubing hanger  200  may then be lowered into the tubing head  100  and into the wellbore using the draw works of the rig (not shown). 
     Also at the top of  FIG. 3  is seen the power cable  310 . The thick, outer sheath of the power cable  305  is removed as it enters the auxiliary port  220 , and then down through the non-conductive sleeve  230  and the various discs  240 ,  250 . Below the alternating discs  240 ,  250 , the conductive wires  305  pass through the bottom plate  260  and down into the wellbore. It is understood that the power cable  310  is clamped to selected joints of production tubing  50  en route to the ESP. 
       FIG. 3  also shows a fuller view of the tubing head  100 . Here, it is observed that the cylindrical body  110  of the tubing head  100  comprises three primary portions. These represent the upper flange  112 , a central body portion  120 , and a lower flange  130 . It can again be seen that the upper flange  112  includes a series of holes  114  radially disposed and equidistantly place along the upper flange  112 . The upper flange  112  also includes a plurality of through-openings or ports  116  configured to threadedly receive the respective lock pins  320 . 
     The lower flange  130  also includes a series of holes  134  radially disposed and equidistantly place along the lower flange  130 . The holes  134  are used to secure the tubing head to a lower plate (not shown) disposed over the wellbore, using ACME-threaded bolts. 
       FIG. 4  is a perspective view of the tubing hanger  200  of  FIG. 3 , without the tubing head  100 . Both the central bore  205  and the auxiliary port  220  are shown in perspective. Additional parts of the tubing hanger  200  are shown in exploded apart relation including illustrative stacked discs  240 ′,  240 ,  250 . 
     In  FIG. 4 , each of the stacked discs  240 ′,  240 ,  250  may contain three separate through-openings, with each opening being arranged to receive a respective wire  305  from the power cable  310 . The through-openings for the elastomeric disc  250  are shown in  FIG. 9A  at  902 ,  904  and  906 ; the through-openings for the “thick” rigid disc  240 ′ are shown in  FIG. 10A  at  1002 ,  1004  and  1006 ; and the through-openings for the “thin” rigid disc  240  are shown in  FIG. 11A  at  1102 ,  1104  and  1106 . 
     Also noted from  FIG. 4  is that each of the stacked discs  240 ′,  240 ,  250  contains two opposing through-openings. The pair of through-openings for the elastomeric disc  250  are shown in  FIG. 9A  at  905 ; the through-openings for the large rigid disc  240 ′ are shown in  FIG. 10A  at  1005 ; and the opposing pair of through-openings for the small rigid disc  240  are shown in  FIG. 11A  at  1105 . Each of these openings is arranged to receive a respective alignment pin (seen at  275  in  FIGS. 4 and 6C ). 
     Also visible in  FIG. 4  are the two bolts  270 . The bolts  270  are shown extending through through-openings in the bottom plate  260 . The through openings are shown at  264  in  FIG. 8A . The bolts  270  secure the bottom plate  260  and the discs  240 ′,  240 ,  250  in place along the auxiliary port  220 . 
       FIG. 5A  is a bottom view of the tubular body  210  defining the linger hanger  200  of  FIG. 3 . The central bore  205  for receiving production fluids (through production tubing  50 ) is shown. Also shown is the auxiliary port  220  through which the conductive wires  305  of the power cable  310  pass. 
       FIG. 5B  is a side view of the tubing hanger  200  of  FIG. 2 . The opposing top  212  and bottom  214  ends are indicated. Of interest, the recessed outer diameter portion  203  that receives the lock pins  320  is visible. Also seen is the lower beveled edge  207 . 
       FIG. 5C  is a perspective view of the tubing hanger  200  of  FIG. 2 . The view is taken from the bottom end  214 . A pair of bolt openings  274  is seen at the bottom end  214 . In addition, female threads are seen along the bore  205  for receiving a pup joint that connects the tubing hanger  200  with the uppermost joint of production tubing  50 . 
       FIG. 6A  is an end view of an alignment pin  275 . The alignment pin  275  is used to align the discs  240 ′,  240 ,  250  within the auxiliary port  220 . This allows the discs  240 ′,  240 ,  250  to slidably receive the conductive wires  305  en route to the wellbore. Preferably, the alignment pins  275  are fabricated from a polycarbonate material or from PEEK. 
       FIG. 6B  is a side view of the alignment pin  275  of  FIG. 6A .  FIG. 6C  is a perspective view of the alignment pin  275  of  FIG. 6A . In one embodiment, the alignment pins  275  are 10 inches in length and 0.25 inches in diameter. The alignment pins  275  are dimensioned to pass through the through-openings  905 ,  1005  and  1105  of discs  240 ′,  240  and  250 , respectively. The length of the alignment pins  275  is less than a length of the bore  225 . 
       FIG. 7A  is an end view of the non-conductive sleeve  230  of the tubing hanger  200  of  FIG. 2 . The non-conductive sleeve  230  defines a tubular body having a wall  232  and a through opening  235 . The non-conductive sleeve  230  is preferably fabricated from a plastic material such as PEEK. 
       FIG. 7B  is a side view of the non-conductive sleeve  230 .  FIG. 7C  is a perspective view of the non-conductive sleeve  230 . In one embodiment, the sleeve  230  is 4 inches in length and has an inner diameter of 0.5 inches. The sleeve  230  is dimensioned to reside within the auxiliary port  220  near the top end  212  of the tubing hanger  200 . 
       FIG. 8A  is a top view of a bottom plate  260  of the tubing hanger  200  of  FIG. 2 . The bottom plate  260  resides below the auxiliary port  220  at the bottom end  214  of the tubing hanger  200 . 
       FIG. 8B  is a side view of the bottom plate  260  of  FIG. 8A .  FIG. 8C  is a perspective view of the bottom plate  260 . 
     The bottom plate  260  contains a pair of opposing through openings  264 . The through openings  264  are dimensioned to receive respective bolts  270 . The bolts  270  are threaded into openings  274  at the bottom end  224  of the tubing hanger  220  to secure the bottom plate  260  to the tubing hanger  220 . The bolts  270  have been removed for illustrative purposes. 
     The bottom plate  260  also contains a central through opening  265 . The central through opening  265  is dimensioned to receive the power cable  310  (or at least the unsheathed conductive wires  305  before they are re-sheathed) en route to the wellbore. Of interest, the central through opening  265  has a diameter that is smaller than the outer diameter of the discs  240 ′,  240 ,  250 . In this way, the bottom plate can retain the discs  240 ,  250  within the auxiliary port  220 . 
       FIG. 9A  is a top or end view of an elastomeric disc  250 . The elastomeric disc  250  is designed to be placed within the bore  225  of the auxiliary port  220 . More specifically, a series of two, three, four, or more elastomeric discs  250  are aligned in series within the auxiliary port  220  as part of the disc stack  255 . 
       FIG. 9B  is a side view of the elastomeric disc  250  of  FIG. 9A .  FIGS. 9C and 9D  are perspective views of the elastomeric disc  250  of  FIG. 9A , taken from opposing ends. 
     The elastomeric disc  250  is fabricated from a pliable and electrically non-conductive material such as neoprene. The elastomeric disc  250  defines a cylindrical body  910 . The disc  250  comprises a pair of opposing through openings  905  placed through the body  910 . The through openings  905  are dimensioned to receive respective alignment pins  275 . 
     The elastomeric disc  250  also comprises a series of central through openings  902 ,  904 ,  906 , aligned in series along the body  910 . Each central through opening  902 ,  904 ,  906  is intended to receive a respective wire  305  from the power cable  310 . 
     It is observed that the elastomeric disc  250  may be split in half. A dividing line is shown at  915  indicating the split. This allows each elastomeric disc  250  to capture the respective wires  305  of the power cable  310  without having to run the individual wires separately through the disc  250 . 
       FIG. 10A  is a top view of a “thick” disc fabricated from a non-conductive material as used in the tubing hanger  200  of  FIG. 2 . The thick disc  240 ′ may be used as part of a stack of discs wherein conductive  250  and non-conductive  240  discs alternate in series within the auxiliary port  220 . 
       FIG. 10B  is a side view of the thick disc  240 ′ of  FIG. 10A .  FIGS. 10C and 10D  are perspective views of the thick disc  240 ′ of  FIG. 10A , taken from opposing ends. 
       FIG. 11A  is a top or end view of a “thin” disc  240  fabricated from a non-conductive material as used in the tubing hanger  200  of  FIG. 2 . The thin disc  240  is also used as part of a stack of discs wherein conductive  250  and non-conductive  240  discs alternate in series within the auxiliary port  220 . 
       FIG. 11B  is a side view of the thin disc  240  of  FIG. 11A .  FIGS. 11C and 11D  are perspective views of the thin disc  240  of  FIG. 11A , taken from opposing ends. 
     The conductive discs  240 ′ and  240  are fabricated from the same material and have the same design. The only difference between the two is that the disc  240 ′ of  FIGS. 10A and 10B  has a greater thickness than the disc  240  of  FIGS. 11C and 11D . Each of the rigid discs  240 ′,  240  is preferably fabricated from a polycarbonate material such as PEEK. 
     Each of the rigid discs  240 ′,  240  defines a cylindrical body  1010 ,  1110 . Each of the rigid discs  240 ′,  240  comprises a pair of opposing through openings  1005 ,  1105  placed through the respective body  1010 ,  1110 . The through openings  1005 ,  1105  are dimensioned to receive respective alignment pins  275 . 
     As with the elastomeric disc  250 , each of the rigid discs  240 ′,  240  also comprises a series of central through openings. The central through openings for the thick disc  240 ′ are shown at  1002 ,  1004  and  1006  while the central through openings for the thick disc  240  are shown at  1102 ,  1104  and  1106 . The central through openings are aligned in series along their respective bodies  1010  or  1110 . Each central through opening  1002 ,  1004 ,  1006  or  1102 ,  1104 ,  1106  is intended to receive a respective wire  305  from the power cable  310 . 
     As with the elastomeric disc  250 , each of the rigid discs  240 ′,  240  is split in half. A dividing line for body  1010  is shown at  1015  indicating the split. Similarly, a dividing line for body  1110  is shown at  1115 . This allows each disc  240 ′,  240  to capture the respective wires  305  of the power cable  310  without having to run the individual wires  305  separately through the discs  240 ′,  240 . 
     As shown best in  FIGS. 2 and 4 , the conductive  250  and non-conductive  240  discs are spaced in alternating arrangement, forming a disc stack  255 . Optionally, the thick discs  240 ′ are placed at the top and/or bottom ends of the disc stack  255 . During assembly, the discs  240 ′,  240 ,  250  are opened into their respective halves. The three individual wires (having thin plastic insulation)  305  from the power cable  310  are separated and laid out in parallel along respective half-discs. The conductive wires  305  are (i) laid along the central through openings  902 ,  904 ,  906  for the elastomeric discs  250 , (ii) laid along the central through openings  1002 ,  1004 ,  1006  for the thick rigid disc(s)  240 ′, and are (iii) laid along the central through openings  1102 ,  1104 ,  1106  for the thin rigid discs  240 . The half discs  240 ′,  240 ,  250  are then put together to capture the unsheathed wires  305 . Alignment pins  275  are run through the through openings  905 ,  1005 ,  1105  in the order in which the discs  240 ′,  240 ,  250  are stacked to help maintain the half-discs in order and proper relation. 
     After the disc stack  255  is assembled and all wires  305  are in place, the disc stack and wires  305  are pushed up into the auxiliary port  220  from the bottom end  224 . The operator will make a determination as to how many elastomeric discs  250  and rigid discs  240 ′,  240  will make up the disc stack  255 . Ideally, the disc stack  255  will be longer than the space available within the auxiliary port  220 , taking into account the amount of space consumed by the non-conductive sleeve  230 . The operator will then use the bottom plate  260  to push on the disc stack  255 , compressing the elastomeric discs  250  so that a series of annular seals is provided along the auxiliary port  220 . 
     When the elastomeric (neoprene) discs  250  are compressed, they expand outwardly and inwardly. Outwardly, the discs  250  expand into the wall of the auxiliary port  220  to provide a fluid seal. Inwardly, the discs  250  expand around the electrical wires  305 , protecting the wires  305  from reservoir fluids during production. More importantly, the elastomeric discs  250  prevent the conductive electrical wires  305  from shorting out due to the loss of the outer insulating sheath and their proximity to the metal tubular body  210  of the tubing hanger  200 . At the same time, the rigid (PEEK) plastic material of the rigid discs  240  helps centralize and separate the conductive wires  305  within the auxiliary port  220 , keeping the wires  305  from contacting each other or the metal body  210  of the steel tubing hanger  200 . 
     It is understood that during operation the disc stack  255  is exposed to wellbore pressures that may exceed 1,200 psi. Accordingly, the shoulder  228  is provided to help hold the sleeve  230  and the disc stack  255  in place. 
       FIG. 12  is a cross-sectional view of a wellbore  1200  as may receive the tubing hanger assembly (indicated as  150 ) and connected tubing string (as indicated at  1220 ) of  FIG. 1 . The wellbore  1200  defines a bore  1205  that extends from a surface  1201 , and into the earth&#39;s subsurface  1210 . The wellbore  1200  has been formed for the purpose of producing hydrocarbon fluids for commercial sale. A string of production tubing  1220  is provided in the bore  1205  to transport production fluids from a subsurface formation  1250  up to the surface  1201 . In the illustrative arrangement of  FIG. 12 , the surface  1201  is a land surface. 
     The wellbore  1200  includes a wellhead. Only the tubing hanger assembly  150  of  FIG. 1  is shown (with the tubing hanger  200  therein). However, it is understood that the wellhead will include a production valve that controls the flow of production fluids from the production tubing  1220  to a flow line, and a back side valve that controls the flow of gases from a tubing-casing annulus  1208  up to the flow line. In addition, a subsurface safety valve (not shown) is typically placed along the tubing string  1220  below the surface  1201  to block the flow of fluids from the subsurface formation  1250  in the event of a rupture or catastrophic event at the surface  1201  or otherwise above the subsurface safety valve. 
     The wellbore  1200  will also have a pump  1240  at the level of or just above the subsurface formation  1250 . In this view, the pump  1240  is an ESP. The pump  1240  is used to artificially lift production fluids up to the tubing head  100 . Since an ESP is used, no reciprocating sucker rods are required or shown. However, a power cable such as cable  310  will be run from the surface  1201  down to the ESP  1240 . 
     The wellbore  1200  has been completed by setting a series of pipes into the subsurface  1210 . These pipes include a first string of casing  1202 , sometimes known as surface casing. These pipes also include at least a second string of casing  1204 , and frequently a third string of casing (not shown). The casing string  1204  is an intermediate casing string that provides support for walls of the wellbore  1200 . Intermediate casing strings may be hung from the surface  1201 , or they may be hung from a next higher casing string using an expandable liner or a liner hanger. It is understood that a pipe string that does not extend back to the surface is normally referred to as a “liner.” 
     The wellbore  1200  is completed with a final string of casing, known as production casing  1206 . The production casing  1206  extends down to the subsurface formation  1250 . The casing string  1206  includes perforations  1215  which provide fluid communication between the bore  1205  and the surrounding subsurface formation  1250 . In some instances, the final string of casing is a liner. 
     Each string of casing  1202 ,  1204 ,  1206  is set in place through cement (not shown). The cement is “squeezed” into the annular regions around the respective casing strings, and serves to isolate the various formations of the subsurface  1210  from the wellbore  1200  and each other. In some cases, an intermediate string of case or the production casing will not be cemented all the way up to the surface  1201 , leaving a so-called trapped annulus. 
     As noted, the wellbore  1200  further includes a string of production tubing  1220 . The production tubing  1220  has a bore  1228  that extends from the surface  1201  down into the subsurface formation  1250 . The bore  1228  receives the ESP  1240 . Thus, the production tubing  1220  serves as a conduit for the production of reservoir fluids, such as hydrocarbon liquids. An annular region  1208  is formed between the production tubing  1220  and the surrounding tubular casing  1206 . 
     It is understood that the present inventions are not limited to the type of casing arrangement used. The wellbore  1200  is presented as an example of a wellbore arrangement where a power cable or digital cable or fiber optic cable may be utilized. In such an instance, the improved tubing hanger  200  of the present invention may be used. 
     Using the wellbore  1200 , a method of hanging a string of production tubing within a wellbore is also provided. The method first comprises providing a tubing hanger assembly. The tubing hanger assembly includes a tubing head and a separate tubing hanger. 
     The tubing head has an upper end and a lower end. The upper end comprises a flange having a plurality of radially disposed through openings. The tubing head also includes a conical surface along an inner bore. 
     The tubing hanger defines a generally tubular body having an upper end, a lower end, and an outer diameter. A central bore extends from the upper end to the lower end of the tubular body. A beveled surface along the outer diameter lands on the conical surface of the tubing head. 
     The tubing hanger also includes an auxiliary port. The auxiliary port extends through the tubular body from the upper end to the lower end and is parallel to the central bore within the tubular body. 
     At least one elastomeric disc is placed within the auxiliary port. In addition, at least one rigid disc is also placed within the auxiliary port. Each of the elastomeric discs and the rigid discs is configured to receive conductive wires of a communications line, such as an electric power cable. 
     The method also includes the steps: 
     placing the tubing head over a wellbore; 
     running a string of production tubing into the wellbore; 
     clamping the communications line to joints of the production tubing as the string of production tubing is run into the wellbore; 
     securing the tubing hanger to an upper joint of the production tubing; and 
     removing an outer insulating sheath from a length of the communications line, leaving at least one insulated conductive wire. 
     The method also includes the steps: 
     running the unsheathed communications line through the auxiliary port in the tubing hanger, wherein the unsheathed portion of the communications line resides along the auxiliary port; 
     placing the at least one elastomeric disc and the at least one rigid disc along the unsheathed portion of the communications line within the auxiliary port, forming a disc stack; 
     compressing the disc stack so that the at least one elastomeric disc seals the auxiliary port; and 
     landing the beveled surface residing along the outer diameter of the tubing hanger on the conical surface along the inner diameter of the tubing head, whereby the tubing hanger resides within the tubing head over the wellbore and gravitationally supports the string of production tubing by means of a threaded connection with the tubing hanger. 
     In the preferred embodiment, the communications line is a power cable, and the power cable is in electrical communication with a downhole electrical submersible pump. The tubing hanger is arranged to receive the continuous power cable from a power source through the auxiliary port and into the wellbore, without the power cable being spliced. “Spliced” means exposing the copper wires. 
     The at least one elastomeric disc is configured to expand within the auxiliary port when compressed in order to seal the conductive wires and the auxiliary port from reservoir fluids. In addition, the at least one rigid disc is configured to retain rigidity within the auxiliary port during production operations to separate the conductive wires from the tubular body. 
     In one aspect, the tubing head further comprises two or more lock pins disposed equi-radially about the tubing head flange and passing through the through openings in the flange. The method further comprises rotating the lock pins into engagement with the tubing hanger to lock the tubing anger and supported tubing string in place within the tubing head. 
     Preferably, the at least one elastomeric disc comprises at least two elastomeric discs and the at least one rigid disc comprises at least two rigid discs. The elastomeric discs and the rigid discs are alternatingly stacked in series within the auxiliary port to form a disc stack. 
     The method may also include selecting a number of elastomeric discs to be included in the disc stack. The method then includes placing the disc stack into the auxiliary port through the bottom end, compressing the disc stack, and then securing the bottom plate to the bottom end of the tubing hanger in order to secure the disc stack and the conductive wires within the auxiliary port. 
     Preferably, the bottom plate comprises a central through-opening for receiving the conductive wires below the disc stack en route to the wellbore. The bottom plate is bolted to the bottom end of the tubular body. 
     In one aspect, 
     the tubing hanger further comprises a pair of elongated alignment pins; 
     each of the elastomeric discs and each of the rigid discs comprises a pair of opposing through-openings configured to receive a respective alignment pin along the disc stack; 
     each of the at least two elastomeric discs is cut in half along the central through-openings to receive a respective conductive wire; and 
     each of the at least two rigid discs is also cut in half along the central through-openings to receive a respective conductive wire. 
     This arrangement permits each of the respective disc halves to be placed back together before loading into the auxiliary port. 
     As can be seen, an improved tubing hanger assembly is provided that allows the operator to connect a power cable to a downhole tool such as an electrical submersible pump, without splicing conductive wires along the wellhead. While it will be apparent that the inventions herein described are well calculated to achieve the benefits and advantages set forth above, it will be appreciated that the inventions are susceptible to modification, variation and change without departing from the spirit thereof.