Abstract:
A tubing hanger apparatus and method for installing coiled tubing in oil and gas wells utilizes a tubing head assembly having a vertical flow passage therethrough, a hydraulically operated piston in an upper portion of the flow passage; a double tapered slip cup and an annular packoff assembly in a lower portion of the flow passage, and a contractible double tapered slip assembly disposed between the piston and slip cup. The piston, in a normally raised position and the slip in a normally radially expanded position allows coiled tubing to be lowered or raised therethrough and through the slip cup and packoff assembly. The piston is lowered by hydraulic pressure to apply a vertical force that radially contracts the slip assembly to grip the tubing and support the weight thereof and the weight is transferred through the slip cup to expand the packoff assembly and seal the tubing.

Description:
CROSS REFERENCE TO RELATED APPLICATION 
   This application claims priority of U.S. Provisional Application Ser. No. 60/706,500 filed Aug. 8, 2005. 

   BACKGROUND OF THE INVENTION 
   1. Field of the Invention 
   This invention relates generally to methods and apparatus for installing and suspending coiled tubing in an oil and/or gas well, and more particularly to a method and apparatus for installing and suspending coiled tubing utilizing a tubing hanger with a hydraulically actuated slip and sealing assembly. 
   2. Description of the Prior Art 
   Coiled tubing has gained widespread acceptance in the last decade due to its many advantages over conventional jointed tubing, including time and labor savings, pumping flexibility, elimination of leakage and leak testing, reduced formation damage, safety, etc. The operational concept of a coiled tubing system involves running a continuous string of smaller coiled tubing into a well to perform specific well servicing operations without disturbing existing completion tubulars and equipment. When servicing is complete, the small diameter tubing may be retrieved from the well and spooled onto a large reel for transport to and from work locations. 
   The typical procedure for hanging or suspending coiled tubing from the surface as a production or an injection string utilizes a tubing head installed above the lower master valve in which an annular tubing hanger with slips and seals is supported and blowout preventers connected above the tubing head. The typical wellhead assembly also includes an access window assembly disposed above the blowout preventers and requires that the distance from the bottom flange of the access window assembly to the tubing head lockdown screws be measured to insure that the annular hanger assembly sets completely in its hanger profile. In wraparound style hanger assemblies the hanger (with slips and seals) is placed around the coiled tubing and slowly lowered to the top of the lower set of blowout preventers rams. The hanger assembly is lowered into the hanger bowl of the tubing head and the weight of the tubing is landed on the hanger. Lockdown screws are then engaged to actuate the seal of the hanger, and the coiled tubing is rough cut through the window of the access window assembly and the blowout preventers and access window assembly are removed. A final or smooth cut is then made on the coiled tubing and it is beveled to fit an adapter and to avoid damaging adapter seals. The remaining wellhead equipment is then installed and flow lines connected. The coiled tubing is pressured up to shear out the bottom plug and the well is placed in service. 
   In installations having an access window assembly, it is necessary to open the access window assembly for placement of the slip and seal assembly around the coiled tubing so that it may be lowered into the tubing head, which potentially opens the annular space surrounding the coiled tubing to the pressure in the well. Also, the fact that the hanger assembly must be lowered around the coiled tubing from a point near the bottom of the access window assembly to the seating area in the tubing head, without being seen, provides a potential for improper seating of the hanger seal and actuation of its slips. Furthermore, the wrap-around slip and sealing assemblies of the hangers are inherently more likely to create sealing or slip engagement problems than seal or slip assemblies that are continuous. 
   There are several types of tubing hanger assemblies for suspending coiled tubing that utilize mechanical means for actuating slips or clamping jaws to hold the tubing rigidly at a predetermined position in the annulus of a wellbore. These types of hanger assemblies typically include semi-circular gripping and support members which are clamped about the tubing at a designated position and maintained clamped with a circular array of threaded rods or set screws that maintain clamping pressure to retain the tubing, and are accessible from outside of the hanger assembly. In many of these tubing hanger assemblies, the threaded rods, actuator rods, or set screws, when rotated, move the slips downward and inward to a position adjacent the tubing in gripping relationship and simultaneously, as the slips move downward and inward, they bear against a slip support cup adjacent the central bore which, in turn, compresses a packer element to expand inward into contact with the tubing thereby to seal off the annulus immediately around the coiled tubing. 
   Cobb, U.S. Pat. Nos. 4,554,971 and 4,646,827 discloses a tubing anchor assembly for seating and supporting coiled tubing in a tubing head, which includes as a first element, a slip assembly characterized by multiple slip segments inserted in the slip bowl of the tubing head and each provided with a beveled top face and a vertically oriented dove tail slot. As a second element, slip retainer screws are radially threaded in the tubing head body at spaced intervals, each of the slip retainer screws provided with a frustro conical tip having a beveled tip base, and each tip extending into the slip bowl of the tubing head and engaging a dove tail slot in one of the slip segments. The slip segments are maintained in open configuration inside the upper portion of the slip bowl when the tips of the slip retainer screws are in engagement with the dove tail slots and when the slip retainer screws are threadedly retracted in the tubing head body. A retainer ring located in a groove provided in each of the slip segments serves to maintain the slip segments in a desired alignment as a slip assembly inside the slip bowl and the slip segments are permitted to drop in concert by the influence of gravity from the frustro conical tips of the slip retainer screws as the slip retainer screws are caused to threadedly travel toward the center of the slip bowl. The slip segments are secured in functional position in the slip bowl after release by engagement of the frustro conical tips with the beveled top faces of the slip segments. 
   Boychuk, U.S. Pat. Nos. 5,515,925 and 5,515,926 disclose an apparatus and method for suspending coiled tubing in a well which utilizes a tubing head having a vertical flow passage therethrough, an annular sealing assembly carried in a lower counterbored portion of the flow passage, and a slip assembly carried in an upper counterbored portion of the flow passage, and a plurality of circumferentially spaced threaded slip activators carried by the tubing head and connected with the slip assembly. The slip activators are manipulated externally of the tubing head to move the slip assembly from passive positions to active positions. The activators move the slip assembly between an outwardly expanded passive position in which the slip assembly does not interfere with the flow passage and an inwardly contracted active position in which gripping surfaces carried on the slip assembly engages the coiled tubing to support the weight thereof, and the weight of the tubing is transferred from the slip assembly to the sealing assembly. 
   Piper, U.S. Pat. No. 5,522,464 discloses a hanger assembly for use with coiled tubing, which provides separate hydraulic actuation of slip positioning and setting of a dual packer element. The hanger assembly includes a body member having an axial bore that intersects at an intermediate position with a frusto conical slip bowl wherein a spaced array of upwardly toothed slips is slidably positioned. Plural hydraulic actuators are mounted in the body member and have actuator rods pivotally connected to respective slips to be driven downward and inward into contact with the tubing at a designated position. The lower part of the body member includes a central, cylindrical cavity which receives inner and outer packers in a concentric array with the inner packer defining the central bore such that application of hydraulic fluid under pressure expands the packer inward into sealing relationship around the tubing passing therethrough. 
   Baker et al, U.S. Pat. No. 5,727,631 discloses a coiled tubing hanger including a hanger bowl, a slip bowl supported in the hanger body, a plurality of slip segments disposed in the slip bowl so as to be movable between a retracted position wherein the tubular member is able to pass through the coiled tubing hanger and an extended position wherein a serrated surface of the slip segments engages the coiled tubing and forces the slip segments along the slip bowl so as to wedge the slip segments between the slip bowl and the coiled tubing to hold the coiled tubing. The slip segments are biased in the retracted position with a pair of slip retaining rings and the slip segments are moved between the retracted portion and the extended position with a plurality of spring-loaded pins disposed through the hanger body and engagable against the outer side of the slip segments such that the slip segments are disposed in the extended position when the pins are urged inwardly and such that the slip segments are biased in the retracted position when the pins are urged outwardly. 
   Card et al, U.S. Pat. No. 6,588,510 discloses a coil tubing hanger system and method of installation utilizing a tubing hanger body having an axial opening therethrough. A slip bowl having a base and housing a slip that can be retained in a first position spaced apart from bowl base and a second position proximate the bowl base is fitted within the opening. Tubing is fitted within the slip and through the bowl while the slip is retained in the first position. The slip is then allowed to drop to the second position such that the slip teeth bite onto the outer surface of the tubing. 
   The present invention is distinguished over the prior art in general, and these patents in particular by a tubing hanger apparatus and method for installing coiled tubing in an oil and/or gas well which utilizes a tubing head assembly having a vertical flow passage therethrough, a hydraulically operated activation piston carried in an upper portion of the flow passage, a double tapered slip cup and an annular packoff sealing assembly carried in a lower portion of the flow passage, and a contractible double tapered slip assembly disposed between the piston and the slip cup. The piston is in a normally raised position and the slip assembly is normally radially expanded to allow and coiled tubing to be lowered or raised therethrough and through the slip cup and packoff sealing assembly. The piston is lowered by hydraulic pressure to apply a vertical force and radially contract the slip assembly to grip the tubing and support the weight thereof and the weight of the tubing is transferred through the slip cup to the packoff sealing assembly which expands inwardly to seal the tubing exterior. 
   In the installation method, the coiled tubing hanger assembly, which includes the tubing head and components described above, is installed on the wellhead prior to lowering the coiled tubing into the well. A blowout preventer stack and coiled tubing injector apparatus is installed above the tubing hanger apparatus. The coiled tubing is run through the blowout preventer stack and coiled tubing head until the string of coiled tubing reaches a desired depth in the well. The activation piston is subjected to hydraulic fluid pressure, such as via a hand pump, sufficient to engage and contract the slip assembly radially inwardly to engage and grip the exterior of the coiled tubing. The coiled tubing is lowered such that the weight of the tubing string is totally supported by the slip assembly, and the slip assembly is engaged with the annular packoff sealing assembly such that the weight of the tubing is transferred through the slip cup to the packoff sealing assembly which expands inwardly to form a sealing relation on exterior of the coiled tubing. 
   Once all the weight has been set on the slip assembly, the hydraulic pressure is increased sufficient to set and maintain the slip assembly and packoff sealing ring engaged on the tubing. The blowout preventer stack is disconnected from the tubing hanger assembly and lifted with the coiled tubing injector head, and the tubing is cut off above the tubing hanger assembly. A positive lock mandrel/reentry guide threadedly engaged in the top of the tubing head is screwed down to engage the piston and lock the piston and slip assembly in their engaged position on the tubing. The rest of the wellhead is then connected on top of the tubing hanger assembly, and the hydraulic pressure is bled off. To pull the coiled tubing string, hydraulic pressure is applied, and the positive lock mandrel/reentry guide is removed. When the coiled tubing has been re-established to the pulling coiled tubing string and a pressure test has been carried out, then the pressure is bled off to release the slips and packoff seal. 
   In the present invention, the slips are held in the open position via a set of expansion rings that can be collapsed when hydraulic pressure has been applied via the hydraulically activated piston and have a “controlled makeup” to control the amount of pressure applied to the tubing so they will not crush the coiled tubing, which would otherwise “neck the tubing down” and weaken it at the suspension point. 
   The apparatus and method of the present invention allows the use of coiled tubing for production applications without requiring removal of the tubing injector apparatus or blowout preventers and without requiring the use of an access window assembly. The present apparatus and method also provides complete pressure control of the well at all times. The slip and seal assemblies are contained within the coiled tubing head but are activated by an external source of hydraulic pressure, and may be easily expanded and contracted to allow the coiled tubing to be repositioned, lower or higher in the well, without pulling the tubing. 
   SUMMARY OF THE INVENTION 
   It is therefore an object of the present invention to provide a method and apparatus for installing and suspending coiled tubing in an oil and/or gas well that allows the use of coiled tubing for production applications without requiring disconnection of the tubing injector apparatus or blowout preventers and without requiring the use of an access window assembly. 
   It is another object of this invention to provide a method and apparatus for installing and suspending coiled tubing in an oil and/or gas well that provides complete pressure control of the well at all times. 
   Another object of this invention is to provide a method and apparatus for installing and suspending coiled tubing in an oil and/or gas well which utilizes internal slip and seal assemblies that are contained within the coiled tubing head but are activated externally via hydraulic pressure. 
   A further object of this invention is to provide a method and apparatus for installing and suspending coiled tubing in an oil and/or gas well which allows the slip assembly to be retracted to an active position for allowing the coiled tubing to be repositioned, lower or higher in the well, without pulling the tubing. 
   A still further object of this invention is to provide an apparatus for installing and suspending coiled tubing in an oil and/or gas well which is simple in construction, inexpensive to manufacture and is rugged and reliable in operation. 
   Other objects of the invention will become apparent from time to time throughout the specification and claims as hereinafter related. 
   The above noted objects and other objects of the invention are accomplished by the present method and apparatus for installing coiled tubing in an oil and/or gas well, particularly for production of hydrocarbon fluids therefrom. The tubing hanger apparatus includes a tubing head assembly having a vertical flow passage therethrough, a hydraulically operated activation piston carried in an upper portion of the flow passage, a double tapered slip cup and an annular packoff sealing assembly carried in a lower portion of the flow passage, and a contractible double tapered slip assembly disposed between the piston and the slip cup. The piston is in a normally raised position and the slip assembly is normally radially expanded to allow and coiled tubing to be lowered or raised therethrough and through the slip cup and packoff sealing assembly. The piston is lowered by hydraulic pressure to apply a vertical force and radially contract the slip assembly to grip the tubing and support the weight thereof and the weight of the tubing is transferred through the slip cup to the packoff sealing assembly which expands inwardly to seal the tubing exterior. 
   In the installation method, the coiled tubing hanger assembly, which includes the tubing head and components described above, is installed on the wellhead prior to lowering the coiled tubing into the well. A blowout preventer stack and coiled tubing injector apparatus is installed above the tubing hanger apparatus. The coiled tubing is run through the blowout preventer stack and coiled tubing head until the string of coiled tubing reaches a desired depth in the well. The activation piston is subjected to hydraulic fluid pressure, such as via a hand pump, sufficient to engage and contract the slip assembly radially inwardly to engage and grip the exterior of the coiled tubing. The coiled tubing is lowered such that the weight of the tubing string is totally supported by the slip assembly, and the slip assembly is engaged with the annular packoff sealing assembly such that the weight of the tubing is transferred through the slip cup to the packoff sealing assembly which expands inwardly to form a sealing relation on exterior of the coiled tubing. 
   Once all the weight has been set on the slip assembly, the hydraulic pressure is increased sufficient to set and maintain the slip assembly and packoff sealing ring engaged on the tubing. The blowout preventer stack is disconnected from the tubing hanger assembly and lifted with the coiled tubing injector head, and the tubing is cut off above the tubing hanger assembly. A positive lock mandrel/reentry guide threadedly engaged in the top of the tubing head is screwed down to engage the piston and lock the piston and slip assembly in their engaged position on the tubing. The rest of the wellhead is then connected on top of the tubing hanger assembly, and the hydraulic pressure is bled off. To pull the coiled tubing string, hydraulic pressure is applied, and the positive lock mandrel/reentry guide is removed. When the coiled tubing has been re-established to the pulling coiled tubing string and a pressure test has been carried out, then the pressure is bled off to release the slips and packoff seal. 
   Many other objects and advantages of the apparatus and method of the present invention will be apparent from reading the description which follows in conjunction with the accompanying drawings. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
       FIG. 1  is a longitudinal cross section of a coiled tubing hanger apparatus in accordance with a preferred embodiment of the invention showing the components in a disengaged non-sealing condition to allow coiled tubing to be lowered or raised therethrough. 
       FIG. 2  is a longitudinal cross section of the coiled tubing hanger apparatus similar to  FIG. 1 , but having an alternate lower body portion, with the components in a disengaged non-sealing condition to allow coiled tubing to be lowered or raised therethrough. 
       FIG. 3A  and  FIG. 3B  are partial longitudinal cross sections, showing the slip assembly in the open position, and in the engaged position, respectively. 
       FIG. 4  is a longitudinal cross section of the coiled tubing hanger apparatus, showing the components in their engaged sealing condition on the coiled tubing and locked in that position by a positive lock mandrel/reentry guide installed in the top of the hanger apparatus. 
       FIG. 5  is a block diagram illustrating the steps in a typical procedure for running and suspending coiled tubing using the present tubing hanger assembly. 
   

   DESCRIPTION OF THE PREFERRED EMBODIMENTS 
   Referring to the drawings by numerals of reference, there is shown in  FIGS. 1 ,  2  and  4 , a coiled tubing hanger assembly  10  in accordance with a preferred embodiment of the invention. The coiled tubing hanger assembly  10  includes a tubing head having an upper body member  11  and a lower body member  30  ( FIGS. 1 and 4 ) or  30 A ( FIG. 2 ) releasably connected together. The upper body member  11  has a generally cylindrical main body portion  12  with radial flange  13  at its top end. The interior of the upper body member  11  has a first or larger bore  14  extending inwardly a distance from its bottom end and terminating in a first flat annular shoulder  15 , a second intermediate bore  16 , smaller in diameter than the first bore, extending inwardly a distance from the first shoulder and terminating in a second annular shoulder  17 , and a third smaller bore  18 , smaller in diameter than the intermediate bore, extending upwardly from the second shoulder. 
   The first or larger bore  14  has internal threads  19  extending upwardly a distance from its bottom end and terminating a distance below the first shoulder  15 . An annular groove  20  is formed in the side wall of the larger bore  14  between the threaded portion  19  and the shoulder  14  and receives a sealing member  21 , such as a polypak seal, an O-ring, or other suitable seal element. The upper end of the third or smaller bore  18  is provided with internal threads  22  that extend downward a distance from the top end of the upper body member  11 . An O-ring groove  23  is formed in the side wall of the smaller bore  18  between the threaded portion and the shoulder  17  and receives an O-ring  24 , an O-ring with backup ring, or other suitable seal element. A fluid port  25  disposed between the shoulder  17  and the O-ring groove and seal  23 ,  24 , extends through the side wall of the upper body member  11  in fluid communication between the smaller bore  18  and the exterior of the upper body member. 
   A first check valve  26 , shown schematically, is installed in the fluid port  25  to allow one-way fluid flow from a hydraulic fluid source H through the port into the interior of the upper body member  11 , and, in a preferred embodiment a second check valve  27  is disposed exterior of the port between the hydraulic fluid source and the first valve to provide a double barrier from well pressure. 
   The exterior of the lower body member  30  has a generally cylindrical main body portion  31  with a reduced diameter neck portion  32  at its upper end and an externally threaded portion  33  extending a distance downward from the neck portion. In the embodiment of  FIG. 1 , the bottom end of the lower body member  30  is provided with a radial flange  34 . Alternatively, as shown in  FIG. 2 , the lower end of the lower body member  30 A is provided with a reduced diameter externally threaded portion  35 . The interior of both lower body members  30  and  30 A are essentially the same, and the internal features are identified by the same numerals of reference. 
   The interior of the lower body member  30 ,  30 A, has a larger upper bore  36  extending inwardly a distance from its top end and terminating in an annular shoulder  37 , and a smaller lower bore  38 , smaller in diameter than the upper bore, extending downwardly from the shoulder  37  and terminating at the bottom end of the lower body member. An outlet port  39  disposed beneath the shoulder  37  extends through the side wall of the lower body member to provide fluid communication between the lower bore  38  and the exterior of the lower body member when the coiled tubing is supported therein. 
   In the assembled condition, the externally threaded portion  33  of the lower body member  30  is threadedly engaged in the internal threads  19  in the lower end of the upper body member  11  with its reduced diameter neck portion  32  engaged in sealing relation with the seal member  21 . 
   A generally cylindrical activation piston  40  is slidably disposed in the upper body member  11 . The activation piston  40  has a smaller diameter upper portion  41  engaged in a sliding seal relation with the seal member  24 , and a larger diameter lower portion having a circumferential groove  43  containing a sealing element  44 , such as a polypak seal or other suitable seal, engaged in a sliding seal relation with the interior of the intermediate bore  16 . The interior of the activation piston  40  has a longitudinal bore  45  that extends downwardly from its top end and terminates in a downward and outward tapered conical bottom portion  46 . 
   A packoff seal assembly  47  is disposed at the bottom of the larger upper bore  36  of the lower body member  30 ,  30 A. The packoff seal assembly  47  has a metal base ring  48  supported on the shoulder  37  and a rubber seal ring  49  secured to the base ring. The exterior of the rubber seal ring  49  has an upward and inwardly tapered truncated conical upper portion  49 A. A central bore  50  extends through the packoff assembly, through which the coiled tubing is lowered or raised. 
   A slip support cup  51  is slidably received in the larger upper bore  36  of the lower body member  30 ,  30 A and supported on the top of the packoff assembly  47 . The interior of the slip support cup  51  has a lower conical surface  51 A that tapers upward and inwardly from its bottom end and terminates in a radial shoulder  52 , and an upper conical surface  51 B that tapers downward and inwardly from its top end and terminates in a central bore  53  that extends through the radial shoulder  52  and through which the coiled tubing passes. The lower conical surface  51 A surrounds the tapered conical upper portion  49 A of the rubber seal ring  49  of the packoff assembly  47  in a mating relation and the radial shoulder  52  is supported on the top surface of the seal ring. 
   Referring additionally to  FIG. 3A , a contractible double tapered segmented slip assembly  54  having at least two separate slip segments  54 A is disposed in the tubing hanger assembly  10  between the slip support cup  51  and the activation piston  40 . Each slip segment  54 A has an arcuate or semi-circular radial flange  55  intermediate its top and bottom ends, a lower frusto-conical surface  56  that tapers upward and outwardly from its bottom end and terminates in a radial shoulder  57  at the bottom of the flange, and an upper conical surface  58  that tapers downward and outwardly from its top end and terminates in a radial shoulder  59  at the top of the flange. The interior surface of each slip segment  54 A is provided with an arcuare inner surface that is toothed to provided a gripping surface  60  and a pair of vertically spaced recessed grooves  61 . An expansion ring  62  is installed in each groove  61  to maintain them in a normally radially expanded open position, as shown in  FIGS. 1 ,  2  and  3 A. 
   As shown in  FIGS. 1 ,  2  and  3 A, when the piston  40  is raised and the slip assembly  54  is in the expanded position, the lower frusto-conical surfaces  56  of the slip segments  54 A are supported in the upper portion of the upper conical surface  51 B of the slip cup  51 , and their upper frusto-conical surfaces  58  are received in the lower portion of the conical bottom portion  46  of the raised piston  40 . In this position, the gripping surfaces  60  of the slip segments  54 A are spaced apart a sufficient distance to allow the coiled tubing string to run through the hanger assembly without engaging the slips and setting the slips accidentally. 
   As shown in  FIGS. 1 ,  2  and  4 , an externally threaded tubular positive lock mandrel/reentry guide  63  is threadedly engaged in the threads  22  at the upper end of the upper body member  11 , and is partially retracted to be spaced above the top end of the raised piston  40  when the slip assembly  54  is in the expanded position, and the tubing is being run. 
     FIG. 3B  and  FIG. 4  show the coiled tubing T in the vertical flow passage defined by the bores in the positive lock mandrel/reentry guide  63 , the piston  40 , slip cup  51 , packoff assembly  47 , and the lower body member  30 ,  30 A. The slip assembly  54  and sealing ring  49  of the packoff assembly  47  are shown engaged on the coiled tubing T, and the positive lock mandrel/reentry guide  63  is shown screwed down to lock the piston and slip assembly in their engaged position, as described hereinafter. 
   The activation piston  40  is activated by a hydraulic hand pump or other hydraulic power source H connected to the fluid port  25  and the hydraulic fluid passes through the check valve  26  in the fluid port. Preferably a second check valve  27  is disposed between the hydraulic power source and the first check valve  26  to provide a double barrier from well pressure. When sufficient hydraulic pressure is applied to the activation piston  40 , it moves down, and the upper and lower frusto-conical surfaces  58  and  59  of the slip segments  54 A are engaged between the conical bottom portion  46  of the piston and the upper conical surface  51 B of the slip cup  51 , and they contract radially inward against the force of the expansion rings  62  to close around the coiled tubing T such that their gripping surfaces  60  bite into and firmly grip the tubing. 
   It should be noted that, as shown in  FIG. 3B , the radial shoulders  57  and  59  of the slip segments  54 A are engaged between the flat bottom surface of the piston  40  and the flat top surface of the slip cup  51 , and thus, control the amount of squeeze that can be put on the coiled tubing. This feature prevents the slip segments from imposing stress risers and compressive forces larger than needed to grip and hold the coiled tubing, and thereby prevents necking down of the coiled tubing, and weakening it at the suspension point. This feature is called a “controlled make-up” of the slips. The opposed double taper on the exterior of the slip segments  54 A facilitates engagement of the gripping surfaces along the full length of the slips, and thus reduces the overall length required to hold the tubing weight. 
   The mating conical surfaces of the piston  40 , the slip assembly  54 , the slip cup  51  and the sealing ring  49  of the packoff assembly  47  are correlated such that when the slip assembly is contracted and engaged on the tubing, the weight of the tubing is transferred through the slip cup to the sealing ring of the packoff assembly to compress the sealing ring such that it deforms to form a sealing relation between the exterior of the coiled tubing and the surrounding surfaces of the lower body member  30 ,  30 A of the tubing head assembly. Because the slip assembly is hydraulically set from an external source (such as a hydraulic hand pump), the slips can be set and sealed anytime it is required, and can be expanded and contracted to allow the coiled tubing to be repositioned, lower or higher in the well, without pulling the tubing. 
   In order to retract (raise) the piston  40 , all hydraulic pressure and fluid is released from the pump or hydraulic power source connected with the fluid port so that the piston will retract (be raised) when the coiled tubing is pulled (removed). When the coiled tubing is pulled, the piston  40  is raised and the expansion rings  62  expand the slip segments  54 A such that the slip segments are reset and the slips and piston resume their original positions. The cross sectional surface areas of the piston are of a balanced design such that it is not affected, or moved, by internal pressure, due to the differential in surface area. 
   Operation 
   Having described the components of the system, and referring additionally to  FIG. 5 , the steps in a typical procedure for running and suspending coiled tubing using the tubing hanger assembly will be described. 
   The tubing hanger assembly  10  is installed onto the wellhead, making sure that the correct, preferably new, ring gaskets are installed in the top and bottom flanges; or if installing a threaded hanger assembly, that an acceptable thread dope is applied. 
   If a bottom hole assembly is required and is not the same O.D. as the coiled tubing string, it may be necessary to install the coiled tubing through the hanger assembly, and then install the bottom hole assembly. The tubing hanger assembly  10  is nippled up (connected) onto the lower master valve that is installed on the wellhead. 
   The bore from the striper rubber (sealing element used for the coiled tubing) to the closed valve upon which the tubing hanger is seatedis pressure tested to the pressure required. 
   Once the pressure test has been accepted, the lowermost valve is opened and the coiled tubing is run thru the wellhead, and running is stopped when the required depth has been reached. 
   To set the slip assembly  54  and activate the packoff assembly  47 , a hydraulic hand pump is connected to the fluid port  25  on the tubing hanger assembly. The activation piston  40  is pressured up to approximately 1,000 PSI and the coiled tubing is allowed to roll into the well as the pressure builds up on the port. There should be a slow transfer of weight from the existing injector head to the internal slip assembly  54  in the tubing hanger assembly. Once all the weight has been set on the slip assembly  54 , the hydraulic pressure is increased to approximately 5,000 PSI. The increased pressure will hydraulically set the slip assembly  54  and engage packoff assembly sealing ring  49 . The internal one-way check valve  26  in the fluid port  25  maintains the pressure on the slip assembly and the packoff seal so that it cannot accidentally be bled off. 
   The blowout preventer (BOP) is nippled down (disconnected) from the top of the tubing hanger assembly  10 . The BOP and the coiled tubing injector head is lifted to a sufficient distance to where a rough cut can be made through the tubing approximately 6″ above the tubing hanger assembly  10 . Once the injector head and BOP have been moved out of the way, a final cut of 4″ (or whatever length may be required) above the tubing hanger assembly is made. The positive lock mandrel/reentry guide  63  is screwed down to engage the top end of the activation piston  40  and lock the piston and slip assembly  54  in their engaged position on the tubing. The rest of the wellhead is then nippled up (connected) on top of the tubing hanger assembly. 
   Since the activation piston  40  is mechanically locked down, the pressure on the fluid port  25  should be bled off. This will eliminate any possibility that heat generated by friction flow will cause an increase in the pressure of the fluid in the closed cavity used to set the slips and packing. 
   To pull the coiled tubing string, a pressure of approximately 5,000 PSI is applied through the fluid port of the tubing hanger assembly for approximately three minutes. Only after this step can the positive lock mandrel/reentry guide  63  be removed. When the coiled tubing has been re-established to the pulling coiled tubing string and the pressure test has been carried out, then the fluid port pressure should be bled off to release the slips and packoff. 
   The present coiled tubing hanger assembly has minimum leak paths, whereas other hangers have three or six external activation methods via activation screws or hold down screws, which are all potential leak paths. The present hanger assembly can also be set without having any service personnel underneath the blowout preventers (BOPS) which would be nippled up (connected) on top of the tubing hanger. The reduced leak paths and the ability to hydraulically set the slips provide significant advantages of the present coiled tubing hanger over conventional coiled tubing hanger apparatus and installation methods used in the coiled tubing industry. 
   While this invention has been described fully and completely with special emphasis upon preferred embodiments, it should be understood that within the scope of the appended claims the invention may be practiced otherwise than as specifically described herein.