Patent Publication Number: US-9903172-B2

Title: Subsea slanted wellhead system and BOP system with dual injector head units

Description:
BACKGROUND 
     This disclosure relates to the field of drilling extended reach lateral wellbores in formations below the bottom of a body of water. More specifically, the invention relates to drilling such wellbores where a sub-bottom depth of a target formation is too shallow for conventional directional drilling techniques to orient the wellbore trajectory laterally in the target formation. 
     Lateral wellbores are drilled through certain subsurface formations for the purpose of exposing a relatively large area of such formations to a well for extracting fluid therefrom, while at the same time reducing the number of wellbores needed to obtain a certain amount of produced fluid from the formation and reducing the surface area needed to drill wellbores to such subsurface formations. 
     Lateral wellbore drilling apparatus known in the art include, for example and without limitation, conventional drilling using segmented drill pipe supported by a drilling unit or “rig”, coiled tubing having a drilling motor at an end thereof and various forms of directional drilling apparatus including rotary steerable directional drilling systems and so called “steerable” drilling motors. In drilling such lateral wellbores, a substantially vertical “pilot” wellbore may be drilled at a selected geodetic position proximate the formation of interest, and any known directional drilling method and/or apparatus may be used to change the trajectory of the wellbore to approximately the geologic structural direction of the formation. When the wellbore trajectory is so adjusted, drilling along the geologic structural direction of the formation may continue either for a selected lateral distance from the pilot wellbore or until the functional limit of the drilling apparatus and/or method is reached. It is known in the art to drill multiple lateral wellbores from a single pilot wellbore to reduce the number of and the cost of the pilot wellbores and to reduce the surface area needed for pilot wellbores so as to reduce environmental impact of wellbore drilling on the surface. 
     Some formations requiring lateral wellbores are at relatively shallow depth below the ground surface or the bottom of a body of water. In such cases using conventional directional drilling techniques may be inadequate to drill a lateral wellbore because of the relatively limited depth range through which the wellbore trajectory may be turned from vertical to the dip (horizontal or nearly so) of the formation of interest. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  shows a subsea injector for a drilling system based on a spoolable tube, umbilical, rod or jointed drill pipe, landed on wellhead e.g. with standard H4 type wellhead connector. 
         FIG. 2  shows deployment or retrieval of a wellbore intervention tool assembly from a live (pressurized) wellbore situation, where blowout preventer (BOP) seal rams are closed. 
         FIG. 3  shows deployment or retrieval of a wellbore intervention tool assembly in a live wellbore situation, where upper seals are closed around an umbilical, coiled tubing or spoolable rod while the upper injector is pushing or pulling on the umbilical. When the wellbore intervention tool assembly is below the BOP, the lower injector is also utilized. 
         FIG. 4  shows an example slant-entry wellhead system. 
         FIG. 5  shows how a conductor pipe can be installed subsurface, where the conductor is jetted down using water. 
         FIG. 6  shows the conductor jetted to a required depth. 
         FIG. 6A  shows attachments at the end of hydraulic cylinders on a support. 
         FIG. 7  shows a subsea wellhead (landed into the conductor) and template, where a BOP system is lowered by cables or the like from a surface vessel. 
         FIG. 8  shows the subsea BOP being stabilized and guided by an hydraulic guide support system. 
         FIG. 9  shows the subsea BOP assembly landed and latched onto the wellhead. 
         FIG. 10  shows the upper injector and sealing system guided onto the wellhead and BOP by the hydraulic guide support system. 
         FIG. 11  shows the upper injector and sealing system guided and latched onto the wellhead and BOP, assisted by the hydraulic guide support system. 
         FIG. 12  shows a pipe such as a spoolable rod, coiled tubing or jointed pipe deployed into the wellbore, where injectors, seals and wipers have been activated. 
     
    
    
     DETAILED DESCRIPTION 
     Example methods and apparatus described herein are related to drilling wells below the bottom of a body of water such as a lake or the ocean, using a water-bottom located template onto which a wellhead and injector assembly is mounted at an angle inclined from vertical. An inclined wellhead and injector assembly enables reaching a horizontal (lateral) trajectory at relatively shallow sub-bottom depths, for example, for exploiting hydrocarbon reservoirs that are located very shallow below the seafloor. There are a number of geographic locations worldwide where such drilling technique is relevant, where ordinary vertical entry drilling methods are inadequate to drill a horizontal wellbore due to the need for longer distance to reorient the wellbore from vertical to horizontal. In addition, the deployment of wellbore devices, for example, electrical submersible pumps that have a substantial length and outer diameter to achieve required fluid lift rates can be impractical if a wellbore build angle is too steep. invention system and method as described herein alleviates that problem by substantially reducing the wellbore deviation build rate (or “dog leg severity”). 
     Also described herein is a dual injector head system, where the lower injector is primarily for inserting a drill string into the wellbore, while the upper injector is primarily for retrieving a drill string from the wellbore. The drill string can be based on jointed drill pipe, a spoolable rod, a spoolable tube (like for example coiled tubing) or similar. 
       FIG. 1  shows a subsea wellhead and pipe injector system  10  (hereinafter “system”) mounted to a template  52  disposed on the bottom  11  of a body of water. The system  10  may be used for any form of well intervention, including without limitation, drilling, running casing or liner and workover of completed wells. Such intervention may be performed using a spoolable tube such as coiled tubing, an umbilical cable or semi-stiff spoolable rod, or jointed (threadedly connected) pipe. The system  10  may comprise an upper injector assembly  14  landed on a spacer spool  13  and supported by a frame  14 A that transmits the weight of the upper injector assembly  14  to the template  52 . Connections between a surface casing  61  in a wellbore  63  may be made, e.g., with industry standard H4 type wellhead connectors. A lower injector and blowout preventer assembly  12  may be coupled to the wellhead  16  at one longitudinal end and at the other longitudinal end to one longitudinal end of the spacer spool  13 . The spacer spool  13  may be coupled at its other longitudinal end to the upper injector assembly  14 . 
     The upper injector assembly  14  may comprise a housing  24  having a suitably shaped entry guide  24 A to facilitate entry of a well intervention assembly  20  into the wellbore. The housing  24  may comprise internally an upper pipe injector  28  of types well known in the art. A wiper  26  may be disposed above the upper pipe injector  28  so that any contamination on the exterior of the well intervention assembly  20  is removed before the well intervention assembly leaves the upper injector assembly  14  and is exposed to the surrounding water. Upper  30  and lower  32  stuffing box seals may be provided below the upper pipe injector  28  so that wellbore fluids cannot escape as the well intervention assembly is moved into and out of the wellbore  63 . A lower wiper  26  may be disposed below the lower stuffing box seal  32  to prevent contaminants from entering the wellbore  63  as the wellbore intervention assembly  20  is moved into the wellbore  63 . 
     The lower injector assembly  12  may also be supported by the frame  14 A. The lower injector assembly  12  may include a lower pipe injector  17 , a lower wiper  18  below the lower pipe injector  17  and blowout preventer elements, e.g., pipe rams  16 A, shear rams  16 B and blind rams  16 C as may be found in conventional blowout preventers (BOPs). Operation of the lower pipe injector  17  and the respective rams  16 A,  16 B,  16 C may be performed by a control module  17 A. The control module  17 A may comprise any form of BOP operating telemetry system known in the art, or may be connected to a vessel on the surface ( FIG. 12 ) using an umbilical cable (not shown in  FIG. 1 ). Operation of the stuffing boxes  30 ,  32  and the upper pipe injector  28  may be performed by a corresponding control module  26 A. 
     The upper  28  and lower  17  pipe injectors may be activated individually or simultaneously to push or pull, as the case may be, an umbilical cable, semi-stiff spoolable rod, coiled tubing or jointed pipe. Two simultaneously operated pipe injectors  28 ,  17  may be integrated for deployment into, and retrieval of a well intervention tool assembly from the wellbore  63 . 
     The pipe injectors  28 ,  17  in the present embodiment may be integrated into a lubricator and BOP system, in contrast with coiled tubing injector apparatus known in the art where there would be one only pipe injector located externally of the lubricator. Having the injector located “externally” in the present context means that the intervention umbilical, rod, coiled tubing and the like must be pushed through seals that are normally exposed to a much higher pressure within the wellbore than the ambient pressure outside the wellbore. The differential pressure may result in more wear on seals and the intervention umbilical, rod or coiled tubing. More clamping force may also be required by the injector not to slip on the intervention umbilical, rod or coiled tubing. Thus, placement of the injectors inside the wellbore pressure containment system may reduce clamping forces required by the injectors and may reduce wear on the tubing and seals. 
     The principle of operation of the system  10  is based on placing the upper pipe injector  28  that is used for pulling the wellbore intervention tool assembly out of the wellbore  63  at a location above the wellbore pressure seals, i.e., the stuffing box seals  30 ,  32  and the BOP rams  16 A,  16 B,  16 C. The lower pipe injector  17  may be used to urge the wellbore intervention tool assembly into the well and may be located below the above described wellbore pressure seals, where the lower pipe injector  17  pulls the umbilical, rod or coiled tubing through the wellbore pressure seals and pushes the umbilical, rod or tubing into the wellbore with no friction increasing seals located below the lower pipe injector  17 . Both the upper  28  and lower  17  pipe injectors can be used simultaneously for increased efficiency and speed, if required. 
     Although the above description is made in terms of a drilling method based on a spoolable umbilical, rod or coiled tubing, it should be understood that also jointed pipes or tubing may be utilized in other embodiments. 
       FIG. 2  shows deployment or retrieval of a wellbore intervention tool assembly  20  from a live (pressurized) wellbore, where blowout preventer (BOP) seal rams  16 A,  16 C are closed while the wellbore intervention tool assembly  20  is removed from the system  10  or is inserted into the system  10 . In the present example embodiment, the wellbore intervention tool assembly comprises a drilling tool assembly coupled to a coiled tubing  20 A. The drilling tool assembly may comprise a drill bit  42 , a drilling motor  40  such as an hydraulic motor to rotate the drill bit  40 , and anchor  44  to transfer reactive torque from the drilling motor  42  to the wellbore wall or internal pipe and measuring instruments  46 ,  48  such as logging while drilling (LWD) and measurement while drilling (MWD) instruments. Other forms of wellbore intervention tool assembly may be used in different embodiments. 
       FIG. 3  shows deployment or retrieval of the wellbore intervention tool assembly  20  in a live wellbore, where the stuffing box seals  30 ,  32  are closed around the wellbore intervention tool assembly  20  while the upper pipe injector  28  is pushing or pulling on the wellbore intervention tool assembly  20 . When the wellbore intervention tool assembly  20  extends below the BOP  16 A,  16 B,  16 C, the lower injector  17  is also used to move the wellbore intervention tool assembly  20 . 
       FIG. 4  shows an example slant-entry wellhead system. One aspect of the slant-entry wellhead system is a movable support  50  having hydraulic cylinders  56 ,  56 A affixed thereto. The movable support  50  is mounted to the subsea template  52 . Having a movable support  50  for modules landed onto the template  52  facilitates setting a conductor pipe and assembling the injector and wellhead assembly to the wellhead ( 16  in  FIG. 1 ). Although the following description is made in terms of using an upper injector assembly and a lower injector assembly as explained with reference to  FIG. 1 , it should be understood that the scope of the present disclosure in constructing a slant-entry wellbore is not limited to the use of the two above-described injector assemblies. 
     Wellheads of types known in the art can be utilized, but will be installed on the subsea template at an angle as illustrated in  FIG. 4 . Such angle may be at least ten degrees inclined from vertical, and will depend on the depth below the water bottom at which the wellbore is required to be drilled substantially horizontal. A pilot wellbore and necessary conductor pipe will need to be drilled or jetted through the template  52 , where a guide funnel system may be used to facilitate installing the conductor pipe. Such a guide funnel can be retrieved prior to installing the wellhead. Jacks with guides  54 ,  54 A can also be used to assist the operation. These jacks, shown as hydraulic cylinders  56  and  56 A may function like robotic arms, that can also perform other operations as securing the entry angle of conductor pipe, casing, and the like, in addition to being able to adapt to various handling tools, inspection tools, visualization tools, etc. The jacks  56 ,  56 A may each be rotatable such that its longitudinal axis may be oriented at any selected angle with respect to vertical. The system illustrated in  FIG. 4  may comprise all the components described above with reference to  FIGS. 1 through 3 , with the inclusion of the movable support  50  and it associated components. 
       FIG. 5  shows how a conductor pipe  60  can be installed subsurface, where the conductor pipe  60  is jetted down using water. A deployment tool  62  with one or more packing elements  62 A may be used to lower the conductor into the sea, as well as being coupled to a hose from the water surface (whereon a vessel having a pump is disposed) being able to jet the conductor into the sub-bottom using high pressure water supplied from the surface or from a pump system placed on the seafloor.  FIG. 5  shows water being pumped into the conductor pipe  60 , where the conductor pipe  60  is then jetted into the sub-bottom. Also shown are two lifting wires  57  for deploying and supporting the conductor pipe  60  during jetting. The two hydraulic cylinders  56 ,  56 A shown may be used to support the conductor pipe  60  at the required angle when driving the conductor pipe  60  into the sub-bottom. A larger and longer temporary support (e.g. a longitudinal cut large bore tube (“tray”)) can be mounted to both hydraulic cylinders  56 ,  56 A, where the angle of the support would be set to the required conductor pipe  60  entry angle. In the present embodiment, a guide funnel  55  may be coupled to the upper end of the conductor pipe  60  to facilitate entry of various tools therein for jetting and/or drilling the sub-bottom to place the conductor pipe  60  at a required depth. 
     For those skilled in the art of offshore drilling, it will be appreciated that an alternative to jetting the conductor pipe  60  as illustrated, is that the conductor pipe  60  can be drilled into the seabed with a motor placed on top of the conductor or coupled to the exterior of the conductor. Also a jet drilling system can be deployed into the lower end of the conductor pipe  60 , where such jet drilling system is retrieved after conductor has been placed to the required depth. 
     Another method for setting the conductor pipe  60  is to hammer the conductor pipe  60  into the sub-bottom, which is common for vertical conductor installations. For both the latter methods, the support system  50  may hold the conductor pipe  60  at the required angle during the hammering procedure.
     1.  FIG. 6  shows the conductor pipe  60  disposed to a required depth. Now, the wellbore can be drilled deeper with any known drilling system, followed by the installation and cementing of a first (surface) casing string. In some embodiments a drillable material or a material that will gradually dissolve by time by being exposed to certain fluids, for example sea water, may be coupled to the lower end of the conductor pipe  60 . Any remaining material may be removed using the wellbore intervention tool assembly ( 20  in  FIG. 1 ) when such wellbore intervention tool assembly is a drilling system powered by fluid pumped from the surface or from a subsurface located pumping system, or if so equipped by an electric or hydraulic motor if such is used as the motor ( 42  in  FIG. 1 )   

     The wellhead will be mounted on the upper end of the surface casing. The wellhead may be landed onto the conductor pipe, whereafter the BOP can be connected to the wellhead when required.  FIG. 6A  shows one or both the hydraulic jacks can be equipped with various handling tools  54 A, as for example a gripper as illustrated. Such a gripper  54 A can take hold of, support the weight of and guide equipment landed on the support system  50  or into the wellbore. A gripper may also contain a motor system for rotation of e.g. conductor pipe, casing strings and the like, as well as a function to drive a module (conductor, casing, valve system, etc.) up and down. A solution may be envisaged where one of the hydraulic cylinders  56  spins a large bore tube, while the other hydraulic cylinder  56 A pushes same tube into the wellbore. 
       FIG. 7  shows the lower injector assembly  12  being lowered onto the conductor pipe  60  and the template  52 , where the wellhead  12  is lowered by cables  57  or the like from a surface vessel ( FIG. 12 ). The hydraulic cylinders  56 ,  56 A, for example, may be used for guiding and supporting the lower injector assembly  12  onto the template  52 . 
       FIG. 7  also shows the lower injector assembly  12  being stabilized and guided by the support  50  and the hydraulic cylinders  56 ,  56 A using supports  54 ,  54 A at the end of each hydraulic cylinder  56 ,  56 A 
       FIG. 8  shows the lower injector assembly  12  landed and latched onto the wellhead  16 . 
       FIG. 9  shows the upper injector assembly  14  being lowered by cables  57  from the vessel ( FIG. 12 ) for coupling to the lower injector assembly.  FIG. 10  shows the upper injector assembly being guided onto the wellhead and the lower injector assembly  12  by the hydraulic cylinders  56 ,  56 A and the support  50  on the template  52 . 
       FIG. 11  shows a pipe such as a spoolable rod, coiled tubing or jointed pipe deployed into the wellbore, where injectors, seals and wipers have been activated for wellbore intervention purposes. 
       FIG. 12  shows a vessel  70  on the water surface from which may be deployed all of the above described apparatus. In  FIG. 12 , the wellbore intervention tool system  20  is extended from the vessel through the system  10  and into the wellbore  63  below. Fluid may be supplied from pumps (not shown) on the vessel  70  through the wellbore intervention tool system  20  for any intervention purpose known in the art. In some embodiments, the need for a riser or similar conduit extending from the system  10  to the vessel  70  may be eliminated by using a riserless mud return system RMR such as may be obtained from Enhanced Drilling, A. S., Karenslyst allé 4, P.O Box 444, Skøyen, 0213 Oslo, Norway and as more fully described in U.S. Pat. No. 7,913,764 issued to Smith et al. 
     Using a system as shown in  FIG. 1 , either with or without the RMR system shown in  FIG. 12 , in some embodiments, it is possible to replace wellbore fluid inside the space between the upper pipe injector housing to any selected depth in the wellbore. Such fluid replacement may be performed by inserting the wellbore intervention tool assembly  20  into the wellbore ( 63  in  FIG. 1 ) to any selected depth while the seals  30 ,  32  are closed so as to sealingly engage the wellbore intervention tool assembly  20 . Fluid, such as seawater may be pumped into the wellbore intervention tool assembly  20  from the surface (e.g., from the vessel  70 ). As fluid is pumped into the wellbore  63  through the wellbore intervention tool assembly  20 , existing fluid in the wellbore  63  may be displaced and discharged through a fluid outlet ( 29  in  FIG. 1 ). The fluid outlet may be connected to a fluid line  72  that returns the discharged fluid to the vessel  70  or to any other storage container. 
     Possible benefits of a system and method according to the present disclosure may include any one or more of the following: 
     a) placing a wellhead at an angle under water to enable drilling horizontal wells in shallow sub-bottom formations; 
     b) placing a BOP and/or lubricator and seal stack system at an angle deviating from vertical on a subsea template; 
     c) jetting in a conductor pipe at an angle. Alternatively, drilling the conductor in by a motor connector to the conductor; 
     d) placing a lubricator and a seal stack system deviating from vertical on a subsea wellhead; 
     e) using an injector built into a pressure containing housing, where injector will be exposed to wellbore fluids and pressure; 
     f) using an injector located on the elevated pressure side of a sealing system preventing wellbore fluids from escaping to the outside environment; 
     g) combining two injectors, where one is primarily for inserting a drill string into the wellbore, while the other is primarily for retrieving a drill string from a wellbore. 
     h) combining two injectors, where both can be simultaneously operated at same speed to insert or retrieve a drill string from a wellbore; 
     i) combining two injectors, where each of these can be adjusted according to the outer diameter (OD) of an object passing through the injectors, so that a tool system can be inserted or retrieved from the lubricator while pushing in or pulling out by the injectors. An example can be that a bottom hole tool assembly is pushed in by the upper injector against the drilling umbilical, coil or drill pile with the lower injector not engaging the bottom hole tool assembly. Thereafter, as soon as the bottom hole assembly has passed through the lower injector, the lower injector is engaged towards the drill string (coil, umbilical or drill pipe) driving this string into the wellbore, while the upper injector are no longer responsible for pushing the string into the wellbore; 
     j) using a wiper seal to remove wellbore clay and the like from the drill string, before the drill string protrudes through the main seals in a BOP system. 
     k) using a wiper seal to remove wellbore clay and the like from the drill string, before the drill string protrude through the main seals in a lubricator stuffing box system; 
     l) providing capability to change out wellbore fluids with clean sea water in a lubricator prior to opening an upper stuffing box to insert or retrieve wellbore intervention tools or tool strings. This can be achieved by pumping in seawater and taking discharge to the surface for cleaning; 
     m) using an adjustable support system to guide and support weight of components engaging onto and landing into a seabed template; 
     n) using a sea bed lubricator system with a sealing system on a top end thereof, where a well intervention tool assembly on a pipe or pipe string can be inserted or retrieved in a safe manner without the need for a riser to surface. The foregoing is performed by individually closing and opening the upper or lower sealing system as well as displacing wellbore fluids with clean seawater prior to retrieval of the wellbore intervention tool assembly through the upper seal system; 
     o) mounting a drillable (for example manufactured in a material easy to drill out after use, or a material that will gradually dissolve by time by being exposed to certain fluids, like for example sea water) drilling system on the lower end of a conductor, where the drilling system is powered by fluid pumped from the surface or from a subsurface located pumping system; 
     p) deploying a drill string from a surface semisubmersible drilling rig or vessel, where the drill string enters a sea bed wellbore at an angle higher than 10 degrees from vertical; 
     q) increasing axial force (“weight on bit”) on a subsurface drill string, by using one or two injectors integrated in a sea bed located BOP and/or lubricator system. 
     r) replaceable modules that can be mounted on hydraulic jacks, where such modules can perform tasks as lifting, guiding, rotating, etc. 
     s) increasing length of external sealing, by e.g. cement, of casing strings by placing wellbore at an angle instead of vertical, which is critical with respect to very shallow reservoirs 
     t) introducing a submerged “goose neck” system to support and guide a drill string deployed from a surface vessel or drilling rig 
     While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims.