Patent Publication Number: US-2023151709-A1

Title: Method and apparatus for aligning a subsea tubing hanger

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
     This application is a non-provisional application which claims benefit under 35 USC §119(e) to U.S. Provisional Application Ser. No. 63/264249 filed November 18 th , 2021 entitled “ METHOD AND APPARATUS FOR ALIGNING A SUBSEA TUBING HANGER ,” which is incorporated herein in its entirety. 
    
    
     STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH 
     None. 
    
    
     FIELD OF THE INVENTION 
     This invention relates to the installation of a tubing hanger in a Xmas Tree of a subsea installation for the production of hydrocarbons. 
     BACKGROUND OF THE INVENTION 
     Establishing a subsea hydrocarbon production well involves locating a template on the seafloor with a number of slots. Drilling into the seafloor is performed through a slot and then a wellhead is installed, and casing suspended from the wellhead. Operations are performed through a marine high pressure riser (HP riser) extending to the surface, with a blow out preventer (BOP) installed either at the subsea wellhead or at the surface. The riser is connected at the subsea end via a riser connector to either the BOP or, if the BOP is at the surface, to the wellhead. 
     Once the well is fully cased, it is necessary to install production tubing. Production tubing is suspended from a tubing hanger (TH); the tubing hanger being landed on previously installed casing hanger within the wellhead and then locked in place. The orientation of the TH around the vertical well axis is set in this step. A pressure test of the tubing hanger is then performed, and the production packer is set. 
     With the TH locked in place and tested, the work string including tubing hanger running tool is withdrawn. The BOP and HP riser may then be removed. A subsea vertical Xmas tree system (VXT) is then installed on the wellhead. 
     The template contains a number (e.g. 4) of slots/wellheads and it is necessary to go through the above steps for each wellhead. Each wellhead will receive a VXT. Located in the template between the VXTs is a production manifold whose purpose is to receive production flow from each VXT once the wells are producing, and to combine these flows into a single line to the host platform. 
     Each VXT includes a connector known as a production outboard wing hub which, when the VXT and manifold are in place in the template, extends towards the manifold and connects with a corresponding inboard hub on the manifold. Since these hubs comprise steel conduit rigidly connected to the VXT or manifold, respectively, precise alignment between the VXTs and the manifold is critical to ensure a sound connection between the hubs. This alignment is achieved by the VXT and the manifold both being located on template guide posts so that both VXTs and manifold are aligned with respect to the template. 
     When a VXT is installed, it also interfaces with the tubing hanger to connect with production tubing in the respective slot/wellhead so that it aligns precisely with the production bore and also additional channels/bores/lines around the main bore, in order that the connections are sound and leak-free. The orientation of the TH (around the vertical well axis) is therefore critical since it effectively determines the orientation of the VXT required for a leak-free connection with the production tubing (main bore together with ancillary bores/lines adjacent the main more). The tolerances here are very tight. 
     Since the orientation of the VXT is determined by the template guide posts, if the TH orientation is not sufficiently precise then the required leak-free connection between VXT and production tubing may not be made. With strict orientation requirements +/- 1,5-2 degree from reference point, there is a fairly high risk that the TH can be installed outside given tolerances. If the TH is found to have been installed outside the manufacture’s tolerances, the well must be re-worked, and a new completion must be installed. 
     Currently, orientation checks of the TH can only be done after the HP riser and the Blowout Preventer (BOP) have been removed from the well. Prior to removal of the BOP and riser, the completion needs to be fully set, tested and the well must be suspended with two individual suspension barriers. All these things must be done before any test can be carried out. The estimated duration for such work-over activity is approximately 7 to 10 days with a drilling rig. The estimated cost impact for this activity is around 75 to 100 million Norwegian Kroner (about 7.5 to 10 million US Dollars) at today’s prices. 
     There is therefore a need to improve the precision with which the tubing hanger is installed. 
     BRIEF SUMMARY OF THE DISCLOSURE 
     The invention more particularly includes a process for installing a production tubing hanger in a subsea wellhead in a subsea template, the process comprising:
     a) running a tubing hanger and tubing hanger running tool through a riser to install the tubing hanger in the wellhead;   b) using a sensor to detect the orientation of the tubing hanger around a vertical axis with respect the template;   c) adjusting the orientation of the tubing hanger with respect to the template;   d) installing the tubing hanger.   

     The invention also includes a system for sensing alignment around a vertical well axis of a tubing hanger with respect to a subsea template, the system comprising: 
     (a) A sensor pair comprising complementary first and second sensor components;   (b) The said first sensor element located on a riser orientation spool or blowout preventer, the orientation spool including supports for engaging with the template to locate the orientation spool;   (c) The said second sensor element located on a wellhead running tool or wellhead orientation tool;   (d) Said first and/or second sensors being in communication with a display apparatus on the surface, whereby positive confirmation of correct alignment of the tubing hanger running tool may be displayed at the surface.   

     Various optional features of the invention are described in the dependent claims appended to this document. 
     Examples and various features and advantageous details thereof are explained more fully with reference to the exemplary, and therefore non-limiting, examples illustrated in the accompanying drawings and detailed in the following description. Descriptions of known starting materials and processes can be omitted so as not to unnecessarily obscure the disclosure in detail. It should be understood, however, that the detailed description and the specific examples, while indicating the preferred examples, are given by way of illustration only and not by way of limitation. Various substitutions, modifications, additions and/or rearrangements within the spirit and/or scope of the underlying inventive concept will become apparent to those skilled in the art from this disclosure. 
     As used herein, the terms “comprises,” “comprising,” “includes,” “including,” “has,” “having” or any other variation thereof, are intended to cover a non-exclusive inclusion. For example, a process, product, article, or apparatus that comprises a list of elements is not necessarily limited only those elements but can include other elements not expressly listed or inherent to such process, process, article, or apparatus. Further, unless expressly stated to the contrary, “or” refers to an inclusive or and not to an exclusive or. For example, a condition A or B is satisfied by any one of the following: A is true (or present) and B is false (or not present), A is false (or not present) and B is true (or present), and both A and B are true (or present). 
     The term substantially, as used herein, is defined to be essentially conforming to the particular dimension, shape or other word that substantially modifies, such that the component need not be exact. For example, substantially cylindrical means that the object resembles a cylinder, but can have one or more deviations from a true cylinder. 
     Additionally, any examples or illustrations given herein are not to be regarded in any way as restrictions on, limits to, or express definitions of, any term or terms with which they are utilized. Instead these examples or illustrations are to be regarded as being described with respect to one particular example and as illustrative only. Those of ordinary skill in the art will appreciate that any term or terms with which these examples or illustrations are utilized encompass other examples as well as implementations and adaptations thereof which can or cannot be given therewith or elsewhere in the specification and all such examples are intended to be included within the scope of that term or terms. Language designating such non-limiting examples and illustrations includes, but is not limited to: “for example,” “for instance,” “e.g.,” “In some examples,” and the like. 
     Although the terms first, second, etc. can be used herein to describe various elements, components, regions, layers and/or sections, these elements, components, regions, layers and/or sections should not be limited by these terms. These terms are only used to distinguish one element, component, region, layer or section from another. Thus, a first element, component, region, layer or section discussed below could be termed a second element, component, region, layer or section without departing from the teachings of the present inventive concept. 
     While preferred examples of the present inventive concept have been shown and described herein, it will be obvious to those skilled in the art that such examples are provided by way of example only. Numerous variations, changes, and substitutions will now occur to those skilled in the art without departing from the disclosure. It should be understood that various alternatives to the examples of the disclosure described herein can be employed in practicing the disclosure. It is intended that the following claims define the scope of the disclosure and that methods and structures within the scope of these claims and their equivalents be covered thereby. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       A more complete understanding of the present invention and benefits thereof may be acquired by referring to the following description taken in conjunction with the accompanying drawings in which: 
         FIG.  1    shows prior art and is a highly schematic plan view of a subsea template with four Xmas trees and a manifold; 
         FIG.  2    shows prior art and is a highly schematic sectional view from the side of a wellhead with tubing hanger and Xmas tree installed; 
         FIG.  3   a    is a highly schematic sectional view from the side of a wellhead with a tubing hanger in the process of being installed, also showing tubing hanger running tool and orientation system together with high pressure riser orientation spool; and 
         FIG.  3   b    is a highly schematic view of a monitoring unit located on the surface. 
     
    
    
     DETAILED DESCRIPTION 
     Turning now to the detailed description of the preferred arrangement or arrangements of the present invention, it should be understood that the inventive features and concepts may be manifested in other arrangements and that the scope of the invention is not limited to the embodiments described or illustrated. The scope of the invention is intended only to be limited by the scope of the claims that follow. 
       FIG.  1    shows prior art and provides background to the invention. On a subsea template  1  are located four vertical Xmas trees (VXTs)  2 . Each VXT is located on the template by template guide posts  3 . Extending from each VXT is an inboard wing hub  4  (for clarity, this is only shown on the bottom left VXT in  FIG.  1   ) which carries produced oil and gas from the wellhead  6  and terminates in a connector  5 . 
     At the center of the template  1  is a manifold  7 . Extending from the manifold  7  are four outboard wing hubs  8  each terminating in a respective outboard wing hub connector  9 . In the assembly, the outboard and inboard connectors  5 ,  9  are secured together such that produced oil and gas flows from all four VXTs to the manifold  7 . An output line  10  from the manifold  7  carries produced oil and gas from all four VXTs to a nearby production platform. 
     The inboard and outboard hubs  4 ,  8  comprise steel tubing with a large central bore for produced oil and gas and smaller channels and lines (not shown in  FIG.  1   ), e.g. for control or managing pressure in annuli in the producing well. The alignment of the inboard and outboard hub connectors  5 ,  9  is critical and is ensured by the VXT and manifold both being located by features of the template  1 . 
     Turning now to  FIG.  2   , which also shows prior art and provides background to the invention, a wellhead  11  is installed in a slot  12  of a template  1 . Installed in the wellhead is a casing hanger  13  and, mounted in the wellhead on the casing hanger, is a tubing hanger  14 . Mounted on the wellhead  11  a vertical Xmas tree (VXT)15. The VXT is located with respect to the template  1  by template guide posts  3 . 
     As with the other components, the VXT  15  is shown in highly schematic form and omitting the majority of the features of this complex piece of equipment. Connected to the side of the VXT  15  is an inboard wing hub  4  with connector  5  for interfacing with an outboard wing hub of a manifold (not shown). 
     The VXT  15  interfaces with the tubing hanger  14  and makes a seal  17  with a main production bore  16  of the tubing hanger  14 , such that the main production bore is continued through a VXT main bore  18  and then via a further seal  19  through an inboard hub main bore  20 . 
     Alongside the main production bore  16  are one or more smaller bores, conduits or control lines (hydraulic, electrical, optical, etc.). There may be a number of these located around the main production bore  16  but for clarity only one exemplary TH secondary conduit  21  is shown in  FIG.  2   . The conduit  21  is continued into a VXT secondary conduit  22  via a seal  23 . The VXT secondary conduit  22  is then continued via a seal  24  into an inboard hub secondary conduit  25 . 
     The orientation of the VXT  15  around the vertical axis  26  of the system is clearly critical in order that the secondary conduit seal  23  is not compromised, along with any other conduit seals or connections, e.g. for electrical or optical cable, arranged around the main bore seal  17 . Since the VXT’s orientation around axis  26  is set with respect to the template  1  by the template guide posts  3  in order that the inboard and outboard hub connectors  5 ,  9  mate correctly, it is important that the TH  14  is installed in the correct orientation in the wellhead  11  so that the various seals and connections between the VXT and TH are correctly made. In practice, the tolerance here can be as little as 1.5 degree. 
       FIG.  3    shows the current standard system for orienting the TH, as well as illustrating the invention. In  FIG.  3   , the VXT has not yet been installed and the TH  14  is in the process of being installed. 
     The template  1 , template slot  12 , wellhead  11  and casing hanger  13  are in place. A high pressure riser assembly  30  extends between the wellhead  11  and a blow out preventer (not shown) on a rig (not shown) at the surface. The riser assembly  30  comprises a high pressure riser  31  and a riser orientation spool  32 . The orientation spool  32  connects the riser  31  to the wellhead  11 , and also includes part of a mechanism, described more fully below, for orienting the tubing hanger  14 . The orientation spool  32  includes locating arms  33  which fit onto the template guide posts  3  which will later secure the orientation of the VXT  15 . 
     Within the riser assembly is shown a tubing hanger running tool  34  temporarily secured to the tubing hanger  14 , above which is a tubing hanger orientation tool  35 . The running tool  34  and orientation tool  35  are suspended from drill string  36 . 
     The TH orientation tool  35  includes a locating groove  37 , a helical groove or cam surface which is engaged with a sprung locating pin  38  on the interior surface of the riser orientation spool  32 . The purpose of these components will be discussed more fully below. 
     Located on the interior surface of the riser orientation spool  32  are upper and lower inductive sensors  39   a ,  39   b . Complementary elements  40   a ,  40   b  are located on the exterior surface of the tubing hanger orientation tool  35  and running tool  34 , respectively. The elements  40   a ,  40   b  are inserts made from a different metal to that of the tubing hanger running tool  34  and orientation tool  35 . The sensors and complementary elements are precisely located at points on the circumferences of the riser orientation spool  32  and tubing hanger running tool  34  and TH orientation tool  35  such that the orientation of the running tool and orientation tool can be precisely determined with respect to the riser orientation spool, which itself located with respect to the template  1 . Lines (not shown) running up the riser or drill string communicate signals from the sensors to monitoring apparatus (not shown) at the surface. 
     The locations of the inductive sensors  39  and complementary elements  40  may be varied. For example, the sensors  39  may be located on the TH running tool  34  and/or orientation tool  35  and the complementary elements on the inside of the riser orientation spool  32 . It may be possible to have both the inner elements located on one or the other of the running tool  34  and orientation tool  35 . If a subsea blowout preventer (BOP) is used, then the outer elements may be located on the BOP. Other possibilities may become apparent to the skilled person depending on the details of the work string and riser; the precise location of the sensors in a vertical direction is not critical. The type of sensor is not critical and other types of sensors, e.g. radioactive emitters and complementary absorbers, may be employed. 
     A simple display unit  50  on the surface, including red and green lights  52 , is provided to indicate to the operator that the correct alignment has been achieved and the TH can be locked in place (see  FIG.  3   b   ). The display unit  50  communicates with the sensors  39 ,40 via a line  51  In this way, the orientation of the TH is subject to a positive confirmation based on live sensed data before the TH is set and before conducting the lengthy procedures of removing the BOP and riser and installing the XMT. 
     The current standard procedure (prior art) is to rely on the locating pin  38  and groove  37  to achieve correct orientation of the tubing hanger  14 . The running tool, orientation tool and TH assembly is calibrated on the surface with a dummy wellhead and riser to help ensure the components will be correctly aligned when they are installed on the real wellhead. 
     As the TH running tool string is lowered into the wellhead  14 , the pin  38  on the riser orientation spool  32  engages with the groove  37  and rotates the work string until the tubing hanger is in the correct orientation around axis  26  and the various lines and channels (e.g.  21 ) are correctly located around the axis  26 . 
     Following installation of the tubing hanger, the HP riser  30  and blow out preventer (not shown) are removed and the wellhead prepared to receive a VXT. The rig is then moved away and a VXT installed normally using a vessel. These processes are complex and time consuming, taking up a number of days of expensive rig time. When the VXT is installed and tested it may become apparent that the TH is not properly aligned around the vertical axis  26  for some reason, and one or more of the connections between the various ancillary channels and lines (e.g.  21 ) adjacent the production bore  16  has not been securely made. The only way to remedy this is to remove the VXT, bring the rig back in and re-install the HP riser assembly  30 , run the TH running tool  34  and orientation tool  35  again and adjust the position of the tubing hanger  14 . This takes many days of expensive rig time and may even need to be repeated if the alignment is still not correct. Unfortunately, the need for this remedial process is not uncommon. 
     In the apparatus shown in  FIG.  3   , the probability of having to perform this extensive remedial process is reduced by having the proximity sensors  39  a,b to provide feedback about the orientation of the TH running tool and orientation tool  34 ,  35  with respect to the riser orientation spool  32  and hence the template  1 . If the orientation of the TH running string appears to be incorrect then the string may be withdrawn slightly and reinserted until the sensors indicates that the orientation is correct. This is a simple and inexpensive procedure which may easily be repeated many times until the correct orientation is confirmed. The HP riser assembly  30  may then be removed and the VXT installed. 
     With sensors in place, there may be no need to use a TH orientation tool  35  and alignment pin  38 , thus saving cost. There may also be no need to have a calibration process and dummy wellhead on the surface, thus saving time and cost. Instead, the TH running string may simply be rotated from the surface until the sensors indicate that the tubing hanger is correctly oriented before securing the TH and removing the running string. 
     In modifications of this embodiment more or fewer sensors may be used and the sensors may be of different type. The lower down the sensor, i.e. the nearer the tubing hanger itself, the better since the sensor reading will be less subject to error due to tolerances in connections between components. Clearly if the TH orientation tool  35  is omitted then a sensor on the orientation tool would not be required. Sensors may be provided at more than one location around the circumference. The sensors may be capable of transmitting data to the surface by radio transmission, thereby avoiding the need to run lines down the riser. 
     In closing, it should be noted that the discussion of any reference is not an admission that it is prior art to the present invention, especially any reference that may have a publication date after the priority date of this application. At the same time, each and every claim below is hereby incorporated into this detailed description or specification as a additional embodiments of the present invention. 
     Although the systems and processes described herein have been described in detail, it should be understood that various changes, substitutions, and alterations can be made without departing from the spirit and scope of the invention as defined by the following claims. Those skilled in the art may be able to study the preferred embodiments and identify other ways to practice the invention that are not exactly as described herein. It is the intent of the inventors that variations and equivalents of the invention are within the scope of the claims while the description, abstract and drawings are not to be used to limit the scope of the invention. The invention is specifically intended to be as broad as the claims below and their equivalents.