Patent Publication Number: US-7913754-B2

Title: Wellhead assembly and method for an injection tubing string

Description:
PRIORITY 
     This application is a continuation-in-part of application Ser. No. 11/972,399, filed Jan. 10, 2008, entitled “WELLHEAD ASSEMBLY AND METHOD FOR AN INJECTION TUBING STRING,” which claims the benefit of U.S. Provisional Application No. 60/880,251, filed Jan. 12, 2007, entitled “WELLHEAD ASSEMBLY FOR AN INJECTION TUBING STRING,” which is hereby incorporated by reference in its entirety. 
    
    
     BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     The present invention relates generally to a wellhead assembly for an oil and gas well. More particularly, the present invention relates to a wellhead assembly or hanger for a coiled tubing string which has annular communication. 
     2. Description of the Related Art 
     It is often desirable in the oilfield industry to insert a string of coiled tubing into the production tubing of a completed oil and gas well. The coiled tubing may be used for a number of purposes such as chemical injection, gas injection, cross sectional area reduction, or for carrying downhole equipment such as sensors, gauges, and pumps. Traditional coiled tubing is a continuous length of spoolable pipe, ranging in size from ¾″ to 3″ OD. Smaller diameters, such as ¼ ″ or ⅜″ OD, are sometimes referred to as a capillary string or an injection tubing string. As used hereinafter, such tubing will be referred to as an injection tubing string, although such use is not intended to limit the scope of the invention or exclude other comparable tubing strings. 
     It is also desirable to leave the injection tubing string in the wellbore for extended periods of time. This allows an operator, for example, to inject chemicals into the wellbore, on a continual basis, to enhance production or to inhibit corrosion, scale, hydrate or paraffin buildup in the well bore. U.S. Pat. No. 6,851,478 discloses a Y-body Christmas tree for use with an injection tubing string, thereby allowing for the essentially permanent installation of the injection tubing string. The Y-body Christmas tree provides convenient access for injecting coiled tubing into a tubing string without necessarily adding height to the wellhead or tree. The Y-body Christmas tree includes a vertical fluid flow bore for passage and containment of the production of oil and gas from the wellbore. The tree includes upper and lower master valves for controlling the passage of well flow through the tree and to an adjoining flow line. The Y-body Christmas tree also includes an independent angular coiled tubing bore that intersects the vertical flow bore of the tree between the upper and lower master valves, allowing the upper master valve to be cycled without being obstructed by a coil string. 
     The Y-body Christmas tree has at least three drawbacks. First, the tree is more expensive than a conventional Christmas tree. Secondly, when the injection tubing string is installed in the production tubing, the lower master valve cannot be closed without severing the injection tubing string and requiring an expensive fishing job to remove the severed tubing string. Furthermore, when the tubing injection string is installed in the production tubing, the back pressure valve preparation in the tubing hanger is no longer available for installing a back pressure valve, without first removing the injection tubing string. In the event that the upper master valve begins to leak and needs to be repaired or replaced, an operator cannot obtain a double barrier required in many locations throughout the world by closing the lower master valve or installing a back pressure valve in the production tubing. As a result, an operator would have to mobilize a workover rig and/or lift boat so that the injection tubing string can be removed from the production tubing to allow the lower master valve to be closed and/or a back pressure valve to be installed. This is obviously a time consuming and expensive proposition. 
     Thus, there is a need for an alternative method for suspending an injection tubing string in production tubing that addresses the problems discussed above. 
     SUMMARY OF THE INVENTION 
     According to embodiments of the present invention, a wellhead assembly and method for an injection tubing string is provided herein. An exemplary embodiment of a wellhead assembly comprises a flange adapted to be connected to a wellhead, the flange having a longitudinal bore therethrough and an injection port extending radially through the flange and communicating with the longitudinal bore. The assembly includes a mandrel adapted to be inserted into the longitudinal bore of the flange, the mandrel having a longitudinal bore therethrough and a port for communicating with the injection port of the flange. The assembly further includes a hanger adapted to be connected to the upper end of an injection string, the hanger being further adapted to land in the longitudinal bore of the mandrel wherein the hanger includes a communication passageway for facilitating fluid communication between the port of the mandrel and the injection tubing string. 
     According to one embodiment, at least a portion of the mandrel&#39;s longitudinal bore serves as a polished bore receptacle. At least a portion of the flange&#39;s longitudinal bore also serves as a polished bore receptacle. The mandrel preferably includes seals for sealing the annular area between the flange&#39;s polished bore and the outer diameter of the mandrel. The seals seal the annular space above and below the injection port in the flange and the port extending through the mandrel. The injection tubing string hanger preferably includes seals for sealing the annular space between the mandrel&#39;s polished bore and the outer diameter of the hanger. The seals seal the annular space above and below the fluid passageway extending laterally through the hanger and the port extending through the mandrel. 
     In a preferred embodiment, the flange is inserted between the top of the production tubing head spool and the bottom of the Christmas tree. More particularly, the flange is connected beneath the lower master valve of the Christmas tree. 
     According to one embodiment, the injection tubing string is connected to the hanger by a ferrule fitting. A live swivel is preferably installed between the ferrule fitting and the injection string to allow rotation of the hanger without imparting rotation to the injection tubing string. 
     According to one embodiment, external threads are provided proximate to the lower end of the mandrel for connecting the mandrel to the back pressure valve thread profile in the production tubing hanger. The mandrel may also include an external seal for sealing the annular space between the mandrel and the production tubing hanger. The mandrel may include internal threads for receiving a back pressure valve in the longitudinal bore of the mandrel above the injection tubing string hanger. The hanger is preferably threadedly attached to the internal diameter of the mandrel to lock the hanger in place. Alternatively, the hanger may have a keyed connector which may be locked in place with minimal turning of the hanger relative to the mandrel. The hanger may also be locked in place with one or more snap rings which snap into mating recesses in the internal diameter of the mandrel. When locked in place, the hanger provides a straddled seal across the communication port with the mandrel. The hanger further provides a profile for connecting to a running tool. The hanger also provides annular flow area for production of oil and gas past the hanger and into the Christmas tree. Once installed, chemicals for treating the wellbore may be injected through the injection port of the flange, through the port in the mandrel, through the communication passageway of the hanger and into the injection tubing string. 
     In an alternative embodiment, a wellhead assembly for an injection tubing string is provided which comprises a wellhead apparatus having a longitudinal bore therethrough and an injection port extending through the wellhead apparatus and communicating with the longitudinal bore of the wellhead apparatus. The wellhead assembly also includes a mandrel adapted to be inserted into the longitudinal bore of the wellhead apparatus, the mandrel comprising a longitudinal bore therethrough and a port, the port extending through the mandrel for communicating with the injecting port of the wellhead apparatus. The assembly further comprises a hanger connected to the injection tubing string, the hanger being adapted to land in the longitudinal bore of the mandrel, wherein the hanger includes a communication passageway which facilitates fluid communication between the port of the mandrel and the injection tubing string. The wellhead apparatus may be a tubing head adapter, a master gate valve, a multi block Christmas tree, or a spacer, such as a spacer spool, a tubing bonnet, a bleed ring, a bleed ring gasket or an instrument flange. 
     In a preferred embodiment, the mandrel is adapted to land and lock in the back pressure valve profile in the production tubing hanger. The mandrel may also include an internal profile for receiving a back pressure valve. 
     Another embodiment of the invention is directed to a method for injecting fluid through a wellhead assembly and into an injection tubing string comprising the step of mounting a wellhead assembly to a wellhead, the wellhead assembly comprising a wellhead apparatus adapted to be connected to the wellhead and having a longitudinal bore therethrough and a fluid injection port, a mandrel adapted to be inserted into the longitudinal bore of the wellhead apparatus, the mandrel having a bore therethrough and a port, and a hanger connected to the injection tubing string, the hanger adapted to land inside the bore of the mandrel, the hanger having a communications passageway facilitating fluid communication between the port of the mandrel and the injection tubing string. The method further comprising the steps of injecting fluid through the fluid injection port of the wellhead apparatus, through the port of the mandrel, through the communication passageway of the hanger and through the injection tubing string. 
     A preferred embodiment of a method for injecting fluids into a well comprises the steps of replacing a first wellhead apparatus on a wellhead with a second wellhead apparatus having substantially the same dimensions as the first wellhead apparatus, the second apparatus having a longitudinal bore extending therethrough and providing the second wellhead apparatus with an injection port that communicates with the longitudinal bore of the second wellhead apparatus. The method further includes the steps of installing a mandrel in the longitudinal bore of the second wellhead apparatus, the mandrel having a longitudinal bore therethrough and a port, connecting an injection tubing string to a hanger and landing the hanger in the longitudinal bore of the mandrel, the hanger having a passageway to facilitate fluid communication between the port of the mandrel and the injection tubing string. The method further comprises injecting fluid through the injection port of the wellhead apparatus, through the port in the mandrel, through the passageway of the hanger and into the injection tubing string. By using a second wellhead apparatus having substantially the same dimensions as the first wellhead apparatus, the overall height of the wellhead and Christmas tree is kept the same so that existing flow lines leading from the tree can be utilized without extensive modification. The present invention is particularly well-suited for adding a chemical injection line to an existing offshore well where raising the height of the wellhead or tree is undesirable in light of cost, space and other restraints related to modifications to existing flow lines for the well. 
     Injected fluids may include gas, foamers, acids, surfactants, miscellar solutions, corrosion inhibitors, scale inhibitors, hydrate inhibitors, paraffin inhibitors, or any other chemicals that may increase the quality and/or quantity of production fluids flowing to the surface. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a cross-sectional view of an exemplary embodiment of the injection string wellhead assembly; 
         FIGS. 2A-C  are sectional views of an exemplary embodiment of a flange of the injection string wellhead assembly; 
         FIG. 3  is a cross-sectional view of an exemplary embodiment of a mandrel of the injection string wellhead assembly; 
         FIGS. 4A-C  are sectional views of an exemplary embodiment of an injection string hanger for the injection string wellhead assembly; 
         FIG. 5  is a side view of an exemplary embodiment of the flange positioned between a conventional dual master valve Christmas tree and a conventional tubing head; 
         FIG. 6  is a cross-sectional view of an exemplary embodiment of the injection string wellhead assembly; 
         FIG. 7  is a sectional top-side view of an exemplary embodiment of a flange of the injection string wellhead assembly; 
         FIG. 8  is a cross-sectional view of an exemplary embodiment of the injection string wellhead assembly; 
         FIG. 9A  is a cross-sectional view of an exemplary embodiment of the injection wellhead assembly having multiple strings hung from the hanger; and 
         FIG. 9B  is a sectional top-side view of the exemplary embodiment of  FIG. 9A . 
         FIGS. 10A and 10B  are cross-sectional views of a well before and after installation of an exemplary embodiment of the injection string wellhead assembly. 
         FIGS. 11A and 11B  are cross-sectional views of a well before and after installation of an exemplary embodiment of the injection string wellhead assembly. 
         FIGS. 12A and 12B  are cross-sectional views of a well before and after installation of an exemplary embodiment of the injection string wellhead assembly. 
     
    
    
     While the invention is susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and will be described in detail herein. However, it should be understood that the invention is not intended to be limited to the particular forms disclosed. Rather, the intention is to cover all modifications, equivalents and alternatives falling within the spirit and scope of the invention as defined by the appended claims. 
     DETAILED DESCRIPTION OF THE INVENTION 
     Illustrative embodiments of the invention and related methods are described below as they might be employed in the use of a wellhead assembly for an injection tubing string that extends into a production tubing string. In the interest of clarity, not all features of an actual implementation or related method are described in this specification. It will of course be appreciated that in the development of any such actual embodiment or method, numerous implementation-specific decisions must be made to achieve the developers&#39; specific goals, such as compliance with system-related and business-related constraints, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time-consuming, but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure. 
     Referring to  FIG. 1 , one embodiment of a wellhead assembly  10  for an injection tubing string is illustrated. The injection tubing string wellhead assembly  10  includes flange  15 , mandrel  20  and tubing hanger  25 . Flange  15 , as more clearly illustrated in  FIGS. 2A-2C . Flange  15  includes a longitudinal bore  17  extending through the center of the flange. Injection port  18  extends radially through the flange and into longitudinal bore  17 . As will be understood by one of skill in the art, chemicals for treating a wellbore may be injected via a surface injection line (not shown) through injection port  18 . Flange  15  is preferably inserted between the existing wellhead and the tubing head adapter for a given well. More particularly, the flange is adapted to be inserted between and connected to the upper flange of the production tubing head adapter spool and the lowermost flange of the lower master valve of the Christmas tree. One of skill in the art will appreciate that flange  15  may be inserted at the time that the injection tubing string is to be installed, or it may be installed with the initial Christmas tree installation. In the latter case, the remaining components of assembly  10  could then be installed at a subsequent time when chemical injection is required. 
     A plurality of bolt holes  24  are included about the outer circumference of the flange which will align with corresponding holes in the flanges of the production tubing spool (or tubing spool adapter if the latter is required) and lower master valve flange. By way of example, flange  15  includes 8 bolt holes for receiving bolts (not shown) to securely connect flange  15  between the production tubing head spool and the bottom of the lower master valve. Flange  15  includes an upper annular groove  22  and a lower annular groove  23  for receiving ring gasket seals (not shown), to seal the flange to the lower master valve and production tubing head spool. 
     Preferably, longitudinal bore  17  extending through the flange has the same diameter as the internal bore of the Christmas tree. For example, with 3½ inch production tubing, the Christmas tree will have a 3 1/16 inch internal bore extending therethrough and flange  15  will have a similar 3 1/16 inch inner diameter, or slightly less to accommodate easier insertion of the mandrel. At least a portion of internal bore  17  will serve as a polished bore receptacle to provide a sealing surface for mandrel  20 . 
     Referring to  FIGS. 1 and 3 , the injection tubing string wellhead assembly includes mandrel  20 . Mandrel  20  has a generally cylindrical shape with a longitudinal bore  30  extending therethrough. Mandrel  20  includes external threads on its lowermost end which are adapted to mate with a threaded profile on the internal diameter of the production tubing hanger in a set of threads known as “back pressure threads” (not shown). Threads  32  mate with the threaded profile in the tubing hanger that is conventionally used to receive a back pressure valve for the production tubing. One of skill in the art will appreciate that the back pressure valve thread profile in the production tubing hanger may differ depending on the supplier of the hanger. The profile for threads  32  on the mandrel will be selected to match the thread profile of the back pressure valve threads. Threads  32  provide a downward anchoring and compression means to compress an elastomer seal  48  when mandrel  20  is properly made up into the threaded profile or back pressure threads of the tubing hanger. When properly made up, threads  32  lock mandrel  20  to the tubing hanger. Mandrel  20  may also include an annular groove  34  for receiving a seal ring  48  which also seals the annular space between the lower end of mandrel  20  and the production tubing hanger. 
     Mandrel  20  includes a flow port  40  for communicating with injection port  18 . Mandrel  20  also includes upper annular recess  38  and lower annular recess  36  for receiving seal rings  52  and  54 , respectively. Ring seals  52  and  54  seal the annular area between mandrel  20  and bore  17  of flange  15 . Seals  52  and  54  keep injection chemicals from leaking between mandrel  20  and flange  15 . 
     Bore  30  of the mandrel includes a threaded profile  42  for receiving the mating threads on injection tubing string hanger  25 . One of skill in the art will appreciate that various types of thread profiles  42  may be used to attach and lock hanger  25  to mandrel  20 . Alternatively, the mandrel may include one or more recesses for receiving snap ring(s) on the external decimeter of hanger  25  to lock the hanger to the mandrel. External keys on the outer diameter of hanger  25  and mating profiles on the internal diameter of the mandrel could also be used to attach and lock the hanger to the mandrel. The mandrel may include an upper profile  44  for receiving a conventional back pressure valve (not shown). Mandrel  20  includes a polished bore section  55  that provides a sealing surface for tubing hanger  25 . 
     Referring to FIGS.  1  and  4 A- 4 C, one embodiment of the tubing hanger  25  of the present invention is shown in more detail. Hanger  25  includes an internal communications passageway  60  for communicating with mandrel flow port  40 , injection port  18  and the injection tubing string. In a preferred embodiment, passageway  60  extends radially from its opening on the outer periphery of hanger  25  to the center of the hanger, where a portion of passageway  60  extends axially into the profile  62 , thereby allowing communication with the top of the injection tubing string (not shown). In an alternative embodiment (such as shown in  FIGS. 10B ,  11 B, and  12 B), profile  62  is located closer to one side of the hanger instead of in the center of the hanger, thus shortening the length of passageway  60 . In a preferred embodiment, hanger  25  includes an annular channel  75  which extends about the opening to passageway  60  to facilitate communications with flow port  40 . Channel  75  allows communication between passageway  60  and flow port  40  even though passageway  60  is not radially aligned with port  40 . In a similar manner, an annular channel (not shown) between mandrel  20  and flange  15  may be used to facilitate communications between injection port  18  and flow port  40 . This annular channel may, for example, extend about bore  17  of the flange and/or the outer diameter of mandrel  20  (between recesses  36  and  38 ). 
     Hanger  25  includes annular grooves  72  and  74  for receiving seal rings  76  and  78  respectively to seal the annular space between hanger  25  and mandrel  20  above and below flow port  40 , flow channel  75  and passageway  60 . Thus, injected chemicals can be injected through injection port  18 , through flow port  40  and into channel  75  where the chemicals will flow until it reaches passageway  60 , whereafter the chemicals can pass into the injection tubing string connected to hanger  25 . 
     The injection tubing string (not shown) is preferably attached to hanger  25  with a ferrule connector, which fits inside profile  62  of hanger  25 . Hanger  25  may include an enlarged profile  65  for receiving a live tubing swivel which allows hanger  25  to be rotated relative to mandrel  20  without imparting rotation to the tubing string. During installation, hanger  25  will preferably be rotated into locking engagement with mandrel  20 . Live tubing swivels (not shown) are well known and are not described herein. In embodiments using snap rings to lock the hanger to the mandrel, rotation of the hanger is not necessary and therefore, live tubing swivels may be omitted. Seals  76  and  78  on the hanger preferably seal inside polish bore  55  of mandrel  20 . 
       FIG. 4B  illustrates a top view of hanger  25 , which provides a C-shaped flow area  80  for the production of oil and gas and other wellbore fluids up through the production tubing, past hanger  25  and into the Christmas tree and out surface production lines for the well. Hanger  25  also includes an internal profile  68  on its upper end for receiving a running tool. 
     To install the injection tubing string wellhead assembly on an existing well, the Christmas tree is disconnected from the production tubing head spool. Flange  15  is then inserted on top of the production tubing head spool (or tubing head adapter if present) and the tree is re-installed. Once the tree is re-installed, flange  15  will be connected to the bottom flange of the lower master valve. The mandrel is sized so that it can be run through the bore of the Christmas tree. 
     Hanger  25  and the injection tubing string suspended therefrom is run into the well after the Christmas tree has been nippled up to flange  15  and the tubing head spool. In one embodiment of the invention, the injection tubing string wellhead assembly is used with BJ Services&#39; InjectSafe™ System which includes upper and lower injection strings, the lower injection string extends from a wireline retrievable surface controlled subsurface safety valve. The subsurface safety valve may be either a tubing retrievable safety valve or be a wireline insert safety valve installed, for example, inside a production subsurface safety valve. The upper injection string will sting into the InjectSafe™ downhole safety valve and will communicate with the lower injection string through a bypass which bypasses the valve mechanism of the safety valve. In a preferred embodiment, hanger  25  is run with the upper portion of the injection string. Once the downhole safety valve and lower injection string have been set in the well, the upper string is spaced-out and cut and connected to hanger  25  via a ferrule connector. A live tubing swivel may extend between the ferrule connector and the injection tubing string. A running tool is connected to profile  68  of hanger  25  and the injection string and hanger are lowered into the well through the Christmas tree until the hanger lands in profile  42  of mandrel  20 . After the mandrel is connected to profile  42  of the mandrel, the running tool is disconnected from the hanger and removed from the wellbore. 
       FIG. 5  illustrates one embodiment of the present invention used with a conventional dual master valve Christmas tree. As shown in  FIG. 5 , flange  15  is installed beneath lower master gate valve  115 . Flange  15  is installed on top of tubing head adapter  110 , which is connected to the top of tubing head  105 . Upper master gate valve  120  is connected to the upper end of lower master gate valve  115 . Studded cross  125  is mounted to the top of upper master gate valve  120 . Top connector  140  is connected to the top of studded cross  125 . Flow line gate valve  130  and kill line gate valve  135  are attached on opposite sides of studded cross  125 . As can be seen from  FIG. 5 , flange  15  is located beneath both master valves of the Christmas tree. 
     The height of mandrel  20  is selected such that it will extend into the lower bore of the lower master valve but will not interfere with the operation (i.e., closing) of the lower master valve. Thus, both mater valves remain functional after installation of injection wellhead assembly  10 , thereby allowing the master valves to be closed without cutting or damaging the injection tubing string suspended from hanger  25 . 
     Referring to  FIGS. 6 and 7 , an alternative exemplary embodiment of wellhead assembly  10  is illustrated. The wellhead assembly  10 A includes flange  15 A, mandrel  20 A and tubing hanger  25 A. Flange  15 A includes longitudinal bore  17 A extending through the center of flange  15 A. Injection port  18 A extends radially through flange  15 A into the longitudinal bore. In general, each component works are previously discussed with some added features which will be outlined below. 
     In the exemplary embodiments of  FIGS. 6 and 7 , flange  15 A operates the same as discussed in relation to previous embodiments. However, in this embodiment, an integral needle valve  19 , as well known in the art, also extends radially through flange  15 A and into port  18 A, thereby regulating fluid communication through port  18 A. A grease fitting  21  may also be used to seal port  18 A when desired. As will be understood by one of skill in the art, chemicals for treating a wellbore may be injected via a surface injection line (not shown) through injection port  18 A. 
     Further referring to the exemplary embodiment of  FIG. 6 , flange  15 A is mounted between lower master valve  115 , which is above flange  15 A, and tubing head adapter  110 , which is below flange  15 A. One of skill in the art will appreciate that flange  15 A may be mounted at the time the injection tubing string is installed or it may be mounted with the initial Christmas tree installation. In the latter case, the remaining components of assembly  10 A could then be installed at a subsequent time when chemical injection is required. Flange  15 A also includes seals  27  in order to seal flange  15 A to lower master valve  115  and tubing head adapter  110 . Seals  27  may be, for example, ring gaskets seals. 
     A test port  26 , as known in the art, extends radially through flange  15 A in order to test the integrity of seals  27 ,  28  (uppermost seal) and  48 . A plurality of bolt holes (not shown) are spaced about the other circumference of flange  15 A which align with corresponding holes in the flanges of the lower master valve  115  and tubing head adapter  110 . Any number of bolt holes may be included as desired. 
     As discussed in relation to previous embodiments, preferably, longitudinal bore  17 A has the same diameter as the internal bore of the Christmas tree. However, flange  15 A may have a slightly smaller diameter than that of the Christmas tree bore in order to accommodate easier insertion of the mandrel  20 A. At least a portion of bore  17 A will serve as a polished bore receptacle to provide a sealing surface for mandrel  20 A. 
     Further referring to the exemplary embodiment of  FIG. 6  and as previously discussed in other embodiments, mandrel  20 A has a generally cylindrical shape with a longitudinal bore extending therethrough. Mandrel  20 A includes external threads  32 A on its lowermost end which are adapted to mate with a threaded profile on the internal diameter of the production tubing hanger  29  in a set of threads known as “back pressure threads” (not shown). Threads  32 A mate with the threaded profile in the tubing hanger that is conventionally used to receive a back pressure valve for the production tubing. One of skill in the art will appreciate that the back pressure valve thread profile in the production tubing hanger  29  may differ depending on the supplier of the hanger. The profile for threads  32 A will be selected to match the thread profile of the back pressure valve threads. Threads  32 A provide a downward anchoring and compression means to compress elastomer seals  48  which also seal the annular space between the lower end of mandrel  20 A and production tubing hanger  29 . Seals  28  are used to seal the annular space between tubing hanger  29  and tubing head adapter  110 . 
     As also discussed in previous embodiments, mandrel  20 A includes flow port  40 A for communicating with injection port  18 A. Mandrel  20 A includes annular seals  52 A and  54 A (and their corresponding recesses) for sealing the annular space between mandrel  20 A and bore  17 A of flange  15 A. Seals  52 A and  54 A keep injection chemicals from leaking between mandrel  20 A and flange  15 A. Mandrel  20 A may also include upper threaded profile  44 A for receiving a convention back pressure valve (not shown). Mandrel  20 A also includes a polished bore section  55 A that provides a sealing surface for tubing hanger  25 A. 
     In general, hanger  25 A operates the same as discussed in relation to the previous embodiments. Therefore, chemicals can be injected through injection port  18 A, through flow port  40 A and into channel  75 A (not shown in  FIG. 6 ) where the chemicals will flow until it reaches passageway  60 A, whereafter the chemicals can pass into the injection tubing capillary string  31  connected to hanger  25 A. Injection tubing string  31  is preferably attached to hanger  25 A with a connector  33 , such as for example, a ferrule or swivel connector, which fits inside hanger  25 A. 
     In the exemplary embodiment of  FIG. 3 , the longitudinal bore of mandrel  20  included a threaded profile  42  for receiving mating threads on hanger  25 . However, one of skill in the art will appreciate that various types of connectors, such as for example, snap rings, may be used to attach and lock hanger  25  to mandrel  20 . For example, in the alternative exemplary embodiment of  FIG. 6 , hanger  25 A includes annular recess  35  on its upper end for receiving a C-ring  41 , such as, for example, a snap ring or spring-loaded dog. C-ring  41  is used to lock hanger  25 A into place within mandrel  20 A and prevents hanger  25 A from moving uphole during operation. Once installed, C-ring  41  will mate with corresponding annular profiles within the longitudinal bore of mandrel  20 A, thereby locking hanger  25 A into position for fluid communication. Although disclosed as a C-ring at the upper end of hanger  25 A, those of skill in the art will realize that any variety of locking mechanisms, as well as placements along hanger  25 A, may be utilized to secure hanger  25 A in place. An internal threaded profile  45  is located at the upper end of hanger  25 A for receiving a running tool  47 . However, those of skill in the art will understand that any variety of connectors could be used for this purpose. 
     Referring to  FIG. 8 , an alternative embodiment of flange  15 B is illustrated. Here, flange  15 B operates as discussed in the previous embodiments; however, in this embodiment, flange  15 B has a taller vertical profile, thereby preventing the need to replace the stud bolts of the tubing head adapter. As shown, flange  15 B has an upper portion  90  and lower portion  92 . Upper portion  90  is taller than lower portion  92 , with lower portion  92  being a height which allows the existing stud bolts  96  of tubing head adapter  110  to be used to connect flange  15 B to adapter  110 . 
     An annular groove  94  is located around flange  15 B in between upper portion  90  and lower portion  92 . Lower portion  92  has bolt holes (not shown) for receiving bolts  96  of tubing head adapter  110 . Since lower portion  92  is short enough to receive existing bolts  96 , there is no need to replace bolts  96  with longer bolts. As such, flange  15 B can be readily applied to existing tubing head adapters. Integral needle valve  19  is located within upper portion  90 , while test port  26  is located within lower portion  92 . The design and operation of these components are identical to those embodiments previously discussed. Please note, however, that one ordinarily skilled in the art will appreciate that other flange profiles may be utilized depending on the bolt length and/or design of the head adapter. 
     The present invention may also be used with multi-completion wellbores (e.g., dual completions having two or more production tubing strings). For a multi-completion well, the flange would include two or more internal bores with each bore adapted to receive a mandrel and injection tubing hanger within the mandrel. The plurality of internal production bores through the flange may be of different diameters to correspond to different size production tubing (e.g., a 3½×2⅞ inch dual completion). 
     Referring to the exemplary embodiment of  FIGS. 9A and 9B , the present invention may also comprise multiple injection tubing strings hung from the hanger. In this embodiment, each tubing string has its own individual fluid flow path as discussed in previous embodiments and may encompass any combination of those features. Those skilled in the art will appreciate that the present disclosure encompasses such alternative embodiments. There are, however, a few modifications which will be discussed below in relation to  FIGS. 9A and 9B . 
     Referring to  FIG. 9A , the wellhead assembly of this exemplary embodiment includes two capillary strings  31 , each having respective fluid communication pathways as described in previous embodiments. Flange  15 C includes two injection ports  18 C (although only one is shown) and their corresponding needle valves  19 , which also operate as discussed in previous embodiments. Here, one injection port  18 C is located above the other lower injection port  18 C. However, those skilled in the art will appreciate that the exact location of the ports and their corresponding flow paths could be varied as desired. 
     Mandrel  20 C includes two flow ports  40 C; each port  40 C communicating with its respective injection port  18 C. In addition to seal rings  52  and  54  used to seal the annular space above and below single flow port  40  of previous embodiments, the present embodiment utilizes one additional seal ring  56 C. Seal ring  56 C is used to seal the annular space below the lower flow port  40 C, while seal ring  54 C is used to seal the annular space above lower port  40 . Ring seals  52 C,  54 C and  56 C keep injection chemicals from leaking between mandrel  20 C and flange  15 C as previously discussed. 
     Hanger  25 C also operates as previous discussed in relation to other embodiments. In this embodiment, however, in addition to seal rings  76  and  78  used to seal the annular space between hanger  25 C and mandrel  20 C above flow port  40 C, two additional seal rings  86 , 88  are used to seal the annular space above and below the lower flow port  40 C, respectively. Therefore, chemicals can be injected through each injection port  18 C, through each corresponding flow port  40 C and into each corresponding channel  75  ( FIG. 4A ) where the chemicals will flow until they reach each corresponding passageway  60  ( FIG. 4A ), whereafter the chemicals can pass into the respective tubing string  31 . 
     The injection tubing strings  31  of  FIG. 9A  are each attached to hanger  25 C with a connector  33 , which operates are discussed in relation to previous embodiments. Here, of course, instead of a single profile including profiles  62  and  65  (discussed in relation to FIG.  4 A), hanger  25 C will comprise dual profiles  99  (each comprising profile  62 , 65  and their corresponding communication passageways  60  and channels  75 ) for allowing fluid communication to tubing strings  31 . The exemplary embodiment of  FIG. 9B  illustrates a top view of hanger  25 C also having C-shaped flow area  80  as discussed in previous embodiments. Here, however, hanger  25 C includes dual profiles  99  for communicating with tubing strings  31 . 
     In other applications, particularly in offshore platforms, it may be difficult, impractical, or prohibitively expensive to raise the height of the wellhead and/or Christmas tree due to existing flow lines extending from the individual wells on the platform. In such situations, embodiments of the present invention may be used by replacing an existing wellhead apparatus with a similar apparatus having identical, or substantially identical, dimensions and having an injection port in communication with the longitudinal bore of the wellhead apparatus. By substituting a similar wellhead apparatus that has the same, or substantially the same dimensions, the height of the wellhead and/or Christmas tree will remain the same so that existing flow lines may be utilized. 
       FIGS. 10B ,  11 B, and  12 B illustrate exemplary embodiments of various wellhead apparatuses that have been substituted for original wellhead apparatuses in order to maintain the height of the wellhead and/or Christmas tree. Examples of wellhead apparatuses that may be modified to include an injection port in accordance with the invention include tubing head adapters, flange by flange single gate valves, multi block valve Christmas trees, composite Christmas trees, spacer spools, instrument flanges, bleed rings and bleed ring gaskets, essentially covering any individual Christmas tree apparatus which could be used, to comprise a vertical bore portion of a Christmas tree. Such apparatuses are well known in the art. 
       FIG. 10A  shows a wellhead prior to installation of an injection tubing string. The wellhead includes tubing head  205 , tubing head adapter  210 , tubing hanger  229  and lower master valve  215 . Tubing head adapter  210  includes test port  226 . Production tubing (not shown) is suspended from the wellhead via tubing hanger  229 . Wellbore fluids are produced up the production tubing, through hanger  229 , through the longitudinal bores extending through tubing head adapter  210  and valve  215 , and out a flowline (not shown) connected to the upper Christmas tree above valve  215 . Such an arrangement is well known in the art. 
       FIG. 10B  illustrates the wellhead after the wellhead assembly for an injection tubing string has been installed. The wellhead assembly includes tubing head adapter  210 A, mandrel  20  and injection tubing hanger  25 . Tubing head adapter  210 A has been substituted for tubing head adapter  210  of  FIG. 10A . Tubing head adapter  210 A includes injection port  218  and grease fitting  221 . Injection port  218  extends through the tubing head adapter and is in communication with the longitudinal bore through adapter  210 A. Tubing head  205 , tubing hanger  229  and lower master valve  215  remain the same. Since tubing head adapter  210 A has substantially the same dimensions as adapter  210 , the overall height of the wellhead and Christmas tree is substantially the same. Accordingly, existing flow lines may be utilized with the wellhead assembly shown in  FIG. 10B . 
     As with earlier embodiments, mandrel  20  is landed and locked into the back pressure valve profile in tubing hanger  229 . The length of mandrel  20  is selected so that it does not interfere with the operations of valve  215  (i.e., the mandrel does not prevent the valve from being opened or closed). Preferably, mandrel  20  includes an internal profile for receiving a back pressure valve. Injection tubing hanger  25  and the injection tubing string (not shown in  FIG. 10B ) are lowered through the Christmas tree until hanger  25  lands inside mandrel  20 . In a preferred embodiment, a snap ring on the external surface of hanger  25  snaps into a mating profile on the internal surface of mandrel  20  to lock the hanger to the mandrel. Mandrel  20  includes upper and lower external seals,  52  and  54 , which seal the annular space between mandrel  20  and tubing head adapter  210 A and between mandrel  20  and tubing hanger  229 , respectively. Hanger  25  includes seals on its external surface to seal the annular space above and below passageway  60 . Chemicals may be injected through injection port  218 , through the annular space between mandrel  20  and tubing hanger  229 , through flow port  40  in mandrel  20 , through passageway  60  and into the injection tubing string, which communicates with passageway  60 . 
       FIG. 11B  illustrates another embodiment of this invention. In this embodiment, master gate valve  215 A is substituted for original gate valve  215 . Gate valve  215 A has substantially the same dimensions of original gate valve  215 . Since the remaining wellhead and Christmas tree equipment are used with the wellhead assembly in  FIG. 11B , existing flow lines may be utilized. Gate valve  215 A includes injection port  218 A which extends through the lower flange, between the bolt holes in the flange (not shown), and communicates with the longitudinal bore of the valve. Injection port  218 A may include grease fitting  221 A. 
     Mandrel  20  is landed in the back pressure profile in tubing hanger  229  and extends into the lower end of longitudinal bore  235  of valve  215 A. The upper end of mandrel  20  does not interfere with operation of valve  215 A. Chemicals may be injected through injection port  218 A, through the annular space between mandrel  20  and the longitudinal bores of gate valve  215 , tubing head adapter  210  and tubing hanger  229  between upper seal  52  and lower seal  54 , through flow port  40  in mandrel  20 , through passageway  60  in hanger  25  and into the injection tubing string. 
       FIG. 12A  illustrates a well having a multi block Christmas tree  250  mounted on top tubing head adapter  210  and tubing head  205 . Multi block tree  250  includes upper and lower master gate valves  255  and  260 . Longitudinal bore  265  extends through the entire length of tree  250 , including through the upper and lower master gate valves. The components of valves  255  and  260  are not shown but construction and operations of such valves are well known in the art. 
     The wellhead assembly for an injection tubing string as illustrated in  FIG. 12B  includes a modified multi block tree  250 A, mandrel  20  and injection string hanger  25 . As with the modified wellhead apparatuses illustrated in  FIGS. 10B and 11B , tree  250 A is built to substantially the same dimension as the wellhead apparatus it replaces, in this embodiment tree  250 , to permit use of existing flow lines. Modified tree  250 A includes injection port  218 A which extends through the lower flange of the tree and communicates with longitudinal bore  265 . Mandrel  20  is landed in the back pressure profile of tubing hanger  229  and includes upper external seal  52  to seal the annular space between the upper end of mandrel  20  and longitudinal bore  265  above injection port  218 A. Similarly, mandrel  20  includes lower seals  54  to seal the annular space between the lower end of mandrel  20  and tubing hanger  229 . 
     The injection tubing string (not shown) is attached to hanger  25  and hanger  25  is landed and locked as described above inside mandrel  20 . Mandrel  20  preferably includes an internal profile for receiving a back pressure valve. The height of mandrel  20  is selected so that it does not prevent operations of master valves  255  or  260 . Chemicals may be injected through port  218 A through the annular space surrounding mandrel  20  between seals  52  and  54 , through flow port  40  in mandrel  20 , through passage  60  of hanger  25  and into the injection tubing string. 
     In an alternative embodiment, the injection port may be drilled through an existing wellhead apparatus on the well site to establish communication with the longitudinal bore extending through the apparatus. Thereafter, mandrel  20 , hanger  25  and an injection tubing string may be installed in the well as described above. The onsite drilling of the injection port may be necessary where logistic, timing, costs, supply or other constraints prevent the installation of a substitute wellhead apparatus. 
     As with earlier embodiments, hanger  25  of the wellhead assembly of  FIGS. 10B ,  11 B and  12 B may include an annular channel extending around an outer surface of the hanger, the annular channel intersecting communication passageway  60  of the hanger to allow fluid communication when port  40  of the mandrel is not radially aligned with passageway  60 . 
     Although various embodiments have been shown and described, the invention is not so limited and will be understood to include all such modifications and variations as would be apparent to one skilled in the art, as well as related methods. For example, a wellhead assembly having three or more tubing strings and their respective flow paths can be envisioned within the scope of the present disclosure. Accordingly, the invention is not to be restricted except in light of the attached claims and their equivalents.