巴西专利BR112012029411B1 apparatus for supplying coiled tubing to a subsea hydrocarbon production well and method of supplyin

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专利摘要:
APPLIANCES AND METHODS TO PROVIDE PIPING WITHIN A SUBMARINE WELL. In some embodiments, the apparatus useful for supplying piping to an underwater well includes at least one surface injector configured to control the movement of the pipe in and out of the well and at least one underwater injector configured to apply pushing and pulling forces to the pipe.
公开号:BR112012029411B1
申请号:R112012029411-3
申请日:2011-05-18
公开日:2020-12-01
发明作者:Lance Nigel Portman
申请人:Baker Hughes Incorporated；
IPC主号:

专利说明:

[0001] [001] Some modalities of the present description refer to the use of a pipeline injection system in connection with an underwater well, such as an underwater hydrocarbon production well. FUNDAMENTALS
[0002] [002] In various phases of hydrocarbon recovery operations, a pipe injector is normally used to insert a pipe into the well to perform different downhole services. Conducting pipeline intervention in subsea wells or under water normally guarantees the use of a piping injector in the subsea wellhead. The submerged layout of the injector, and the significant distance that may exist to the seabed, pose challenges in the effective and efficient conduct of subsea pipeline intervention operations.
[0003] [003] Several presently known injection systems and techniques for underwater pipeline intervention are believed to have one or more drawbacks. For example, in some existing known systems, the seabed injector is used as the main injector to move the piping in and out of the well. In such cases, the operation of the seabed injector will have to be controlled from the surface. Therefore, the underwater injector typically requires substantial control and valve components, instrumentation that can be monitored from the surface, and significant umbilical support (communication / control lines) from the surface. As such, the underwater injector is likely to be heavy and cumbersome, requiring special equipment for the deployment and processing of difficult or impractical recovery. In addition, many components, which are subject to failure, malfunction and maintenance will be underwater or located in the injector under the sea. Remotely accessing, repairing or replacing these components will be time-consuming, expensive and difficult or impossible.
[0004] [004] It should be understood that the discussion described above is provided for illustrative purposes only and is not intended to limit the scope or purpose of this description or any related patent or patent application. Thus, none of the attached claims or claims of any patent application or related patent should be limited by the above discussion, or required to respond to, include or exclude the aforementioned examples, features and / or disadvantages merely because of their mention above.
[0005] [005] Thus, there is a need for improved systems, devices and methods capable of producing a submerged pipe in a well with one or more of the attributes, capacities or characteristics described below or evident from the attached drawings.
[0006] [006] BRIEF SUMMARY OF THE DISCLOSURE
[0007] [007] In some embodiments, the present disclosure involves an apparatus for injection of piping from a structure located in the vicinity of the surface of a body of water in a well extending into the earth below the water. At least one surface injector is associated with the structure, engaged with the piping and positioned close to the water surface. The surface injector is configured to control the movement of the pipe in and out of the well. At least one underwater injector is engaged with the tubing, deliverable to the tubing from the frame to the well, releasably engaging with the well and configured and used to apply downward pushing forces and upward pulling forces to the pipeline without control the movement of the pipe. The piping and underwater injector are delivered to the well without the use of one or more risers extending from the structure to the well.
[0008] [008] Several modalities of the present description involve an apparatus for supplying coiled piping to an underwater hydrocarbon production well from a marine vessel on the sea surface. At least one main injector is transported by the ship, engaged with the coiled tubing and positioned close to the water surface. The main injector is configured and used to control the movement of the coiled pipe in and out of the well during normal operations. At least one slave injector is engaged with the coiled pipe, deliverable in the coiled pipe from the vessel to the well, controlled independently from the main injector (s) and configured to be repeatedly deployable to and from the well. The weight of the slave injector is less than the weight of each main injector. The coiled tubing and slave injector (s) are supplied to the well without the use of one or more risers extending from the vessel to the well.
[0009] [009] There are modalities of the present description that involve an apparatus for supplying coiled piping to a submarine hydrocarbon production well from a marine vessel on the sea surface. At least one main injector is transported by the ship, engaged with the coiled tubing and positioned close to the water surface. The main injector is configured and used to control the movement of the coiled pipe in and out of the well during normal operations. At least one slave injector is engaged with the coiled pipe, deliverable in the coiled pipe from the vessel to the well, controlled independently from the main injector (s) and configured to be repeatedly deployable to and from the well. The slave injector applies only for pushing force directed downward onto the coiled pipe when it is needed during operations to overcome the wellhead pressure and well friction that occurs when inserting the coiled pipe into the well and to maintain tension on the coiled tubing above the slave injector.
[0010] [0010] Several modalities of the present description involve an apparatus for supplying coiled piping to a submarine hydrocarbon production well from a marine vessel on the sea surface. At least one main injector is transported by the vessel, hooked up with the coiled tubing and positioned close to the water surface. The main injector is configured and used to control the movement of the coiled tubing in and out of the well. At least one slave injector is engaged with the coiled tubing, delivered in the coiled tubing from the vessel to the well and configured to be used at a power level that is less than about half the operating power level of each injector main. The coiled tubing and slave injector (s) are supplied to the well without the use of one or more risers extending from the vessel to the well.
[0011] [0011] Many modalities of the present description involve a method of supplying piping to an underwater well from a floating structure. A first end of the pipeline is extended through at least one main injector transported over the structure. At least one slave injector having a weight less than each main injector is suspended at the first end of the pipeline. The slave injector is delivered to the well by lowering the pipe to the water without the use of one or more risers extending from the well structure, and is engaged with the well. The main injector is selectively operated to control the movement of the pipe up and down the well. The slave injector can apply pushing forces directed downwards and pulling forces directed upwards towards the pipe without controlling the movement of the pipe.
[0012] [0012] Consequently, the present disclosure includes features and advantages that are believed to advance the underwater pipeline intervention technology. Potential features and advantages of the present disclosure described above and other potential features and benefits will be readily apparent to those skilled in the art after considering the detailed description that follows of various modalities and referring to the accompanying drawings.
[0013] [0013] BRIEF DESCRIPTION OF THE DRAWINGS
[0014] [0014] The following figures are part of the present specification, included to demonstrate certain aspects of various modalities of the present description and referenced here in the detailed description:
[0015] [0015] Figure 1 is a side view of a marine vessel carrying a piping intervention system that includes at least one surface injector and at least one subsurface injection shown arranged on top of a mast set transport that can stand upright according to an embodiment of the present description;
[0016] [0016] Figure 2 is a side view of the maritime vessel and piping intervention system of Figure 1, which shows the exemplary transport in an implanted position and the exemplary underwater injector submerged in the water according to one embodiment of the present description;
[0017] [0017] Figure 3 is an exploded view of the exemplary underwater injector and the associated equipment of Figure 2;
[0018] [0018] Figure 4 is a side view of an embodiment of an underwater injector shown coupled to an umbilical coil with a pair of hydraulic control lines according to an embodiment of the present description, and
[0019] [0019] Figure 5 is a partial schematic and partial cross-sectional view of an embodiment of an ambient pressure compensation system for energizing an underwater injector chain pull cylinder according to an embodiment of the present description.
[0020] [0020] DETAILED DESCRIPTION OF THE PREFERRED MODALITIES
[0021] [0021] The characteristics and advantages of the present disclosure and additional characteristics and advantages will be evident to those skilled in the art after considering the following detailed description of exemplary modalities of the present disclosure and referring to the attached figures. It is to be understood that the present description and accompanying drawings, which are examples of modalities, are not intended to limit the claims of the present patent application, any patent granted hereinafter or any patent application or patent claiming priority of the present application. On the contrary, the intention is to cover all modifications, equivalences and alternatives falling within the spirit and scope of the claims. Many changes can be made to the particular modalities and the details disclosed here, without departing from that spirit and scope.
[0022] [0022] Showing and describing preferred modalities, common or similar elements are referenced in the attached figures with similar or identical reference numbers, or are evident from the figures and / or the description here. Figures are not necessarily to scale and certain features and views of figures may be shown exaggerated in scale or schema in the interest of clarity and conciseness.
[0023] [0023] As used herein, and throughout various portions (and positions) of this patent application, the terms "invention", "present invention" and their variations are not intended to mean any possible modality encompassed by this disclosure or any particular claim (s). Thus, the purpose of each such reference should not be considered necessary for, or part of, any modality thereof, or any particular claim (s) merely because of such reference. The terms "coupled "," connected "," engaged "," transported "and the like, and variations thereof, as used herein and in the appended claims are intended to mean a direct or indirect connection or relationship. For example, if a first device couples to a second device, this connection can be through a direct connection or through an indirect connection through other devices and connections.
[0024] [0024] Some terms are used here and in the appended claims to refer to particular components. As a person skilled in the art will appreciate, different people may refer to a component by different names. This document is not intended to distinguish between components that differ in name, but not function. In addition, the terms "including" and "comprising" are used here and in the appended claims in an open manner, and therefore must be interpreted to mean "including, but not limited to ...". In addition, the reference here and in the appended claims for components and aspects of a singular time does not necessarily limit the present description or appended claims to a single component, or aspect, but should be interpreted to generally mean one or more, as is convenient and desirable in each particular case.
[0025] [0025] With reference initially to Figure 1, a piping intervention system 10 according to one embodiment of the present description is made with a structure 16, such as a sea ship 18, shown deployed in a body of water 20. In other embodiments, the structure 16 can be a floating platform (not shown) or any other desired conveyor or arrangement of conveyors. The body of water 20 can be an ocean, sea or bay, or take any other form. Thus, the shape and other characteristics of the water body 20 are not limiting in the present specification or appended claims. For simplicity, the "sea" is used here to refer to the body of water 20 (in any form) and should not be considered as limiting.
[0026] [0026] The illustrated system 10 includes at least one surface injector 22 and at least one underwater injector 28. The surface injector 22 remains on or near the frame 16 during normal operations, while the underwater injector 28 is lowered to the water in a wellhead (not shown) at the bottom of the sea. In some embodiments, one or more surface injectors 22 may remain mounted or suspended from the structure 16 above the water surface during operations. Other modalities may involve submerging one or more surface injectors 22 into the water, generally at a desired shallow depth near the water surface (for example, up to 50 meters of water), at some point during operations. Thus, the expression "in the vicinity of the water surface" and its variations, when used in reference to the position of a surface injector 22 means located somewhere above the water surface or suspended from the ship 16 or submerged at a depth usually shallow of water during normal operations.
[0027] [0027] The injectors 22, 28 are engaged with a pipe 32 and are useful for inserting and removing the pipe 32 and all the equipment (for example, downhole assembly) that can be transported through the pipe 32 in and out an underground well accessible through the wellhead on the seabed (not shown). In this example, tubing 32 is conventional coiled tubing 34, which is useful for performing downhole assembly (not shown) for well maintenance operations, as they are and become even better known. However, the present disclosure is not limited to use with coiled tubing 34 and can be used with any other type of suitable tubing 32 and other equipment.
[0028] [0028] In the present embodiment, it is generally desirable to maintain substantial tension on the pipeline 32 between the injectors 22, 28 during operations. For example, in some situations, maintaining tension on the coiled tubing 34 can prevent undesirable bending of tubing 34 near the seabed and can help make system 10 and / or tubing 32 more tolerant of marine chains. As used herein, the term "substantial" and its variations means completely, but allowing for some variation thereof, which can be expected or encountered during typical operations, depending on the particular use or application being referenced. However, there may be modalities or cases in which it is not desirable or possible to maintain tension in the pipeline 32.
[0029] [0029] Still with reference to Figure 1, the surface injector 22 is configured, arranged and powered as the "master" or "primary" injector of system 10 to control the up and down movement, position, movement speed and automatic breaking of the pipeline 32 during normal operations, as they are and will become still known. Any suitable piping injector can be used as the surface injector 22. The illustrated surface injector 22 is generally operated and controlled in a manner similar to a standard sand injection unit, as it is and will become known. Some examples of piping injectors currently available commercially that can be configured and adapted for use as the surface injector 22 in relation to some modalities of the present description are the HR 580 models of Hydra-Rig ® or HR 680.
[0030] [0030] Still with reference to Figure 1, the illustrated system 10 includes two substantially identical surface injectors 22, referred to herein as the first and second surface injectors 23, 24. In this embodiment, the second surface injector 24 is provided for redundancy 100%, runs in parallel with the first injector 23 and is always engaged. Thus, if one injector 23, 24 fails, the other injector 23, 24 will take over to provide the necessary injector functions. In some applications, for example, each of the injectors 23, 24 can be a standard sand injection unit having a pull rating of 36287.39 kg. It should be understood, however, that multiple surface injectors 22 may not be included. In addition, when multiple surface injectors 22 are included, any desired amounts can be used and they need not be identical. It should also be noted that system 10 may also include one or more identical or non-identical underwater injectors 28, if desired.
[0031] [0031] The underwater injector 28 is configured, arranged and powered to provide limited functions. For example, the illustrated underwater injector 28 is a "slave" or "secondary" injector of system 10, which is configured and used to apply downward driving forces and upward pulling forces to pipeline 32 without controlling the tubing movement 32. Underwater injector 28 of this modality has relatively low power to push / pull tubing and provides relatively low tensile strength in tubing 32. Therefore, the illustrated injector 28 is relatively simple and light and easy to move upwards and down from frame 16 to the well. The term "relatively", as used herein with respect to the underwater injector 28 or its components or capacities, means, in comparison with the standard or conventional full capacity sand injection unit or the surface injector 22. However , in other embodiments, the underwater injector 28 may not be limited as described above.
[0032] [0032] If desired, underwater injector 28 can be configured and used to apply such an approximate downward pushing force to pipeline 32, as may be necessary during operations to overcome wellhead pressure and well friction that occur during the insertion of piping 32 into the well and maintaining the tension in piping 32 above the underwater injector 28. The exemplary underwater injector 28 is thus instrumental in smashing or stabbing high pressure wells, changing subsurface safety valves (not shown) or other equipment or other activities at shallow depths in the well (for example, up to 1828.8 meters in the well for some applications). In addition, if desired, underwater injector 28 can be configured and used to apply only such an approximate upward pulling force to tubing 32, as may be necessary to overcome the weight of tubing 32 above injector 28, when removing the pipe 32 from the well.
[0033] [0033] Still with reference to Figure 1, the underwater injector 28 can have and / or be operated at any desired power level. In the illustrated embodiment, injector 28 is operated at low power. For example, the operating power or nominal power level of the underwater injector 28 may be less than that of each surface injector 22. In some arrangements, for example, the underwater injector 28 may operate at a power level or have a rated power that is less than approximately half that of each surface injector 22. There may even be situations where the power level or rated operating power of the injector 28 is less than about one-third that of each injector 22.
[0034] [0034] Any suitable injector can be used as the underwater injector 28 (sometimes referred to as the "sea bed" injector). For example, a standard sand injection unit designed to engage 1 ½ coiled pipe injector can be pulled down or modified to be used as the underwater injector 28 of the pipe intervention system 10 with 2 "or 2 3/8" coiled tubing. A particular example of a presently commercially available pipe injector that can be configured or modified to be used as the underwater injector 28 in connection with some modalities of the present description is the Hydra-Rig ® model HR 635. Additional information on the features or types of pipeline injectors and / or associated equipment that can be useful or modified for use in connection with the surface injector 22 and / or underwater injector 28 some of the modalities of the present disclosure are available in access documents the public, such as US Patent 4,655,291 to Cox, entitled "Injector for Coupled Tube" and issued on April 7, 1987, US Patent 4,899,823 to Cobb et al., entitled "Method and Apparatus for Conducting Pipe Rolled in Submarine Wells "and issued on February 13, 1990, US Patent 5,022,130 to Laky, entitled" Coiled Pipe Treatment System "and issued on March 26, 1991, and other documents cited herein, which are incorporated herein by reference in their entirety. However, the present description and appended claims are not limited to or by these examples of types of equipment or the information provided in the referenced documents.
[0035] [0035] Still with reference to Figure 1, the injectors 22, 28 can be used in connection with any equipment configuration suitable for their effective development and use. In this embodiment, the coiled tubing 34 is shown wound in and out of one or more reels of tube 36 mounted on the frame 16. At least one winding device 40, such as a level 42 winding assembly, can be included to wind the tubing coiled 34 in a circuit (or arc) inside and outside the spool 36. If desired, a pipe feeder 44 can be arranged between the spool 36 and the surface injector 22. The illustrated pipe feeder 44 grabs the pipe 32 and feeds it between the spool 36 and the surface injector 22. In this example, the feeder 44 is electronically controlled to administer the pipe 36 extending between itself and the surface injector 22 and to operate in timed operation with the surface injector 22. An in-line pipe inspection device 49 is also included in this modality to inspect / monitor the condition of the pipe 32 before being fed to the surface injector 22 and submerged in water. An example of a pipe inspection device 49 is the PipeCheck System currently commercially available from BJ Services Company.
[0036] [0036] Referring now to Figure 2, tubing 32 is shown passing through the surface injector 22 from the pipe spool 36 and into and through underwater injector 28. In this embodiment, a flexible tube 38 is included to support piping 32 in emergency situations. For example, flexible tube 38 may be useful if feeder 44 becomes unable to schedule payment for tubing 32 from reel 36 with the speed of surface injector 22. In such cases, it may be desirable to wrap tubing 32 along the flexible tube 38 when it is pulled out of the well and rewound on the reel 36. However, in other embodiments, the flexible tube 38, or other equipment can be used to support the pipe 32 during normal or other special operations. In some embodiments, a flexible tube 38 may not be included.
[0037] [0037] In another aspect independent of the present description, a pipe collector 50 may be included. The illustrated pipe catcher 50 is configured to engage or grab the pipe 32 if the pipe 32 loosens or otherwise becomes disengaged from the surface injector 22, preventing the pipe 32 from falling to the seabed. The pipe collector 50 can have any suitable configuration, components and operation. For example, pipe catcher 50 may include at least one conical slide 51 suspended from multiple wires 52. In this example, two slides 51 are included. The illustrated slides 51 are powered by an independent hydraulic load pressure system (not shown) and actuated electronically, such as through a rigid wire or an acoustic signal. If pipe 32 loosens above pipe collector 50, slips 51 will be triggered to catch pipe 32. In this example, pipe catcher 50 is designed to withstand up to about 150000 pounds of force. However, other arrangements may not include a pipe collector 50.
[0038] [0038] With reference also to Figure 2, the illustrated underwater injector 28 and equipment attached to it (as described below) are configured to be implanted in the subsea well through the pipe 32 and releasably coupled with equipment (not shown) located in the well. Tubing 32 thus serves as one for the exemplary underwater injector 28 and equipment deployed with it without the need for a separate cable winch, crane or the like. In the illustrated embodiment, piping 32, injector 28 and related equipment are shown to be deployed outside the rear of ship 18, but can instead be implemented on the side of structure 16, through a well (not shown), or in any another desired arrangement. In addition, piping 32 is implanted in the well without using tie rods extending from structure 16 to the well. However, piping 32, underwater injector 28 and related equipment can be configured to be deployed to the well in any other suitable way.
[0039] [0039] With reference now to Figure 3, in the present embodiment, the underwater injector 28 is housed in a frame 29 as part of an underwater injector assembly 30. Attached below the illustrated injector 28 is an extractor 31, which provides a seal dynamics around the pipe 32, as it runs in and out of the well during operations, as they are and will become known. A lubricator 35 is engaged below the extractor 31 and is removably connectable to the equipment (for example, rupture prevention) located in the well (not shown). Lubricator 35 serves as a pressure vessel when engaged with equipment in the well, as it is and will become known. In this embodiment, the lubricator 35 is short, such as 4.572 to 15.24 meters in length. However, lubricator 35 can be of any desired length, shape and configuration.
[0040] [0040] Still with reference to Figure 3, the pipeline 32 extends through the injector 28 and to the extractor 31. The well-bottom assembly or other equipment (not shown) that can be transported at the lower end 33 of the pipeline 32 it is positioned inside the lubricator 35 during transportation, delivery and implantation to / from the well. A first releasable coupling 45, such as a hydraulic quick connection 46, is shown arranged between the illustrated extractor 31 and lubricator 35. This can be useful, for example, to allow disengagement of the extractor 31 and lubricator 35 in the frame 16, so to allow access or change outside the downhole set (not shown), or other desired effect. A second releasable coupling 47 is shown disposed at the lower end of the lubricator 35 for engaging / releasing from equipment (e.g., rupture prevention) in the well. If desired, a flow T-shaped tube 48 can be coupled below the extractor 55, in order to allow the recovery or ventilation of fluids from the lubricator 35 after connection with the equipment in the well, as it is and will become still known . In this modality, the extractor 31, lubricator 35, couplings 45, 47 and flow T-shaped tube 48 are implanted and recovered with the underwater injector 28 through the pipe 32.
[0041] [0041] With reference again to Figure 1, in another aspect independent of the present description, the injectors 22, 28 of this modality are shown transported within a mast assembly 54. However, any other equipment suitable for transporting the injectors 22, 28 can be used. In this example, mast assembly 54 includes a conveyor 56 that houses the surface injector (s) 22 and carries the underwater injector 28. The surface injectors 22 are mounted on the conveyor 56, while the underwater injector 28 is movable inwardly. and out of transport 56. Exemplary transport 56 is self-erect and foldable between at least one "transport position" (for example, Figure 1) and at least one "implantation position" (for example, Figure 2).
[0042] [0042] In a transport position (for example, Figure 1), the illustrated transport 56 is shown substantially horizontal in relation to the ship deck 19. When the exemplary transport 56 is in this position, mast assembly 54 and all components carried by it have a low center of gravity, increasing the stability of the structure 16, such as during transport. The transport position can also allow for safe positioning and greater safety when handling injectors 22, 28 and other equipment on the structure 16, such as during transportation, maintenance, inspection, replacement, repair, etc. For example, the transport position of the transport 56 can improve the ease of and safety when accessing or changing the downhole assembly (not shown) engaged in the pipeline 32. In this transport position 56, the illustrated mast assembly 54 provides a height-sensitive work platform and eliminates the need for deck cranes or other equipment normally needed to replace the downhole assembly (not shown). The transport position of the exemplary transport 56 also ensures that no part of the piping intervention system 10 or related equipment is dragging in the water, for example, when system 10 is not deployed or the ship 18 (or other structure 16) is in Traffic.
[0043] [0043] In a deployment position (for example, Figure 2), the transport 56 of the present embodiment is shown substantially vertically in relation to the ship deck 19 with its lower end 57 submerged in the water. The deployment position illustrated allows the deployment of piping 32, underwater injector 28 and associated equipment for the well and operation of the piping intervention system 10. In this example, when the transport 56 is in this position, the mast assembly 54 and the components carried on it also have a low center of gravity, increasing the stability of the frame 16 during operation.
[0044] [0044] The exemplary transport 56 can be mobile between the transport and implantation positions in any suitable form. In this embodiment, transport 56 is articulated mobile in relation to ship 18. Referring to Figure 2, illustrated transport 56 is transported on a transport base 58, which rotates with respect to mast platform 62. For example, the transport base 58 may have a projecting arm 60 that articulates the mast platform 62 articulated, such as by means of an articulation shaft 66. The mast platform 62 is shown firmly attached to the ship deck 19, as by screws. A transport conductor 68 is shown extending between the mast platform 62 and the transport 56 (and / or transport base 58) and is selectively controlled to move the transport 56 between positions. For example, transport conductor 68 may include at least one hydraulic cylinder 70. It should be noted that there may be multiples of the above components as needed or desired in a particular embodiment to properly support mast assembly 54, pipeline 32, injectors 22, 28 and other equipment during transportation and operations. In addition, different or additional components can be included in the mast assembly 54.
[0045] [0045] In this modality, the transport 56 is also selectively mobile in relation to the transport base 58 between the multiple positions. For example, a lower (lateral) position of the transport 56 relative to the transport base 58 (for example, Figure 2) allows the lower end 57 of the transport 56 to be properly submerged in the water during the implantation of the underwater injector 28 and operation of the piping intervention system 10. An upper (lateral) position of the exemplary transport 56 in relation to the transport base 58 (for example, Figure 1) is useful for positioning transport 56 in the transport position, such as on top of a deck base 70, which extends upwards from mast platform 62. Transport 56 can be movable relative to transport base 58 in any suitable manner. For example, one or more manual or electronically controlled chain drive assemblies (not shown) can be used.
[0046] [0046] With reference again to figure 2, in another aspect independent of the present description, the piping intervention system 10 of the present modality is compensated in elevation, in order to effectively isolate the piping 32 from the movement of the structure 16 in the Water. This can be done in any suitable way. For example, transport 56 can be compensated for in elevation on mast assembly 54 to compensate for all movements of ship 18 in the water. In the illustrated embodiment, an active lift compensation system 74 includes at least one pulley 76 and winch 78 mounted on the conveyor 56. At least one conveyor line 80 extends from the winch 78, over the pulley 76 and the injector ( s) surface 22, suspending the surface injector 22 inside the transport 56, As the structure 16 moves up and down, side by side and in any other way in the water (in relation to the seabed) , the illustrated system 74 responsively varies the suspension height of the surface injector (s) 22 inside the conveyor 56, in general, maintaining the position of the pipe 32 in relation to the seabed. The exemplary elevation compensation arrangement can be useful, for example, to allow successful engagement / disengagement with the well and help prevent unwanted creaking on piping 32 and / or underwater injector assembly 30 during deployment to and from the well and then the coupling with the well. If desired, active or passive roller and pitch compensation can also be included.
[0047] [0047] In another example, the chains (not shown) of the surface injector (s) 22 can be configured to move up and down in antiphase with the movement of the structure 16. Thus, the surface injector 22 can be designed and operated to provide a lift compensation function directly compensating the movement of the structure 16. If desired, this arrangement can be used as a substitute for the said lift compensation system 74 or other lift compensation arrangement, in order to minimize the potential for additional fatigue on the pipeline 32 thus caused.
[0048] [0048] Figure 4 illustrates an underwater injector of example 28, which can be used in connection with some modalities of the present disclosure. In this example, injector 28 has a low piping push / pull power capability and provides low tensile strength in pipeline 32 compared to surface injector 22. Therefore, injector 28 is illustrated relatively simple and lightweight, smaller than the surface injector 22 and easy to move up and down and from the well. In addition, the underwater injector 28 may be arranged to have a piping pushing capacity that is greater than its maximum piping pulling capacity. In such cases, if desired, the underwater injector 28 may be a standard modified sand injection unit arranged essentially upside down. For example, in some embodiments, an underwater injector 28 with a maximum pull capacity of 6803, 886 kg and a maximum push capacity of 15875.73 kg can be used a surface injector 22 having a pull rating of 36287.39 kg . However, the present disclosure is not limited to any of the injector's suggested or exemplary power capabilities.
[0049] [0049] The illustrated injector 28 includes a pair of opposing chains 90, 92 and corresponding blocks 94 that cling to the pipe 32, as is yet to be known. Each associated chain / block combination 90, 94 and 92, 94 is sometimes referred to here as a chain, block set 95, 96, respectively. The exemplary chains 90, 92 are rotated by one or more chain rotation motors 98. When chains 90, 92 are in a suitable clamping engagement with piping 32, the rotation of chains 90, 92 by the motor (es) 98 it will apply pushing and pulling forces to the pipe 32, as is and will become still known.
[0050] [0050] In the embodiment of Figure 4, two in tandem rotating motors operating in parallel 98 maintain a predefined push / pull force on chains 90, 92. Chains 90, 92 will rotate in response to the speed of piping 32, as established by the surface injector 22 during normal operations. However, any desired number of (one or more) chain rotation motors 98 can be included.
[0051] [0051] The chain rotation motor 98 may have any suitable shape, configuration and power capacity. In some embodiments, for example, motors 98 may be electric. In the embodiment of Figure 4, chain rotation motors 98 are relatively low power hydraulic motors 100. The illustrated motors 100 are driven by a hydraulic fluid supplied from the surface by means of a fluid circuit having hydraulic lines 102, 104 extending from an umbilical coil 106 arranged on the frame 16. However, there may be more than two hydraulic lines 102, 104. For example, two pairs of hydraulic lines can be used.
[0052] [0052] Lines 102, 104 can form an umbilical dedicated to underwater injector 28, when implanted. Alternatively, lines 102, 104 can overlap the umbilical extending to other equipment in the well, such as rupture prevention (not shown) Lines 102, 104 of this mode are bidirectional, so that any of lines 102, 104 can be used as the hydraulic source or return line. In this example, because of the low power requirements of motors 100, lines 102, 104 can, if desired, be close, small, composite neutronically floating hydraulic lines.
[0053] [0053] Still with reference to Figure 4, the hydraulic fluid is supplied inside and ventilated from the hydraulic lines 102, 104 of this modality with one or more hydraulic pumps 108 arranged on the structure 16. If desired, one or more throttle valves (not shown) can be used in connection with pump 108. In this example, pump 108 is preset to drive hydraulic fluid at a desired speed to maintain the preset push / pull force on chains 90, 92 described above. If desired, the exemplary pump 108 can be manually adjusted in one or more additional stages of operation. For example, in this mode, the operator can move the pump 108 to the second position to increase the power for the engines 100, such as by smashing the pipe 32 into the well, and a third position off. Thus, the illustrated pump 108 and motors 98 are independently controlled from the surface injector 22. In addition, in this embodiment, the phase adjustment of the pump 108 is the only function of the implanted underwater injector 28 adjustable from the surface. Consequently, control of the exemplary underwater injector 28 is not linked to the control of the surface injector 22 and operates completely independently of it.
[0054] [0054] The underwater injector illustrated 28 also includes one or more pull cylinders 114 to hold blocks 94 in the desired tightening coupling with the tubing (not shown). This embodiment includes two traction cylinders 114. However, any desired number of traction cylinders 114 can be included. The illustrated traction cylinders 114 are energized to maintain the desired tightening coupling by means of an ambient pressure compensation system 116. If desired, system 116 can be self-energized and self-sufficient, without the need for any control from the surface or fluid , electrical or other communication with the surface. However, in other embodiments, the traction cylinders 114 can be energized in any suitable form.
[0055] [0055] Referring now to Figure 5, the ambient pressure compensation system 116 can have any desired components, configuration and operation. In this embodiment, system 116 includes a reservoir housing 118 associated with, or transported over, the underwater injector assembly (for example, assembly 30, Figure 3), and having no hydraulic fluid flow lines or other communication lines for the surface. The illustrated housing 118 includes a push cavity 119 fluidly isolated from a push cavity 120 by a reservoir piston 122. The reservoir piston 122 is spring-loaded into the exemplary push cavity 120 by one or more elements of pushing 124 arranged in the pushing cavity 119. The pushing element 124 can be one or more suitable spring or any other suitable pushing mechanism, as it is or will become still known.
[0056] [0056] Still referring to Figure 5, the illustrated pushing element 124 extends around an axis 126 of the reservoir piston 122 and applies a force to a non-sealing extension 128 of the axis 126. If desired, the end 127 of the axis 126 can extend out of reservoir housing 118 to indicate the position of piston 122 as can be detected by an ROV or other suitable equipment.
[0057] [0057] The exemplary reservoir cavity 120 contains hydraulic fluid in communication with a first sealed cavity 132 of the drive cylinder 114, through a sealed (pressurized) fluid circuit 130. Inside the illustrated drive cylinder 114, a drive piston 136 separates the first sealed cavity 132 from a second cavity 134. The pressurized fluid circuit 130 thus extends between the reservoir piston 122 and the traction piston 136.
[0058] [0058] With reference also to Figure 5, the axis 138 of the illustrated traction piston 136 engages an outer traction applicator 140, which effectively pulls the chain / block assembly 96 into a clamping engagement with the pipe 32. Therefore, pressure on the exemplary circuit 130 (caused by the pushing element 124 acting on the reservoir piston 122) is pushing the traction piston 136 away from the pipe 32, pulling the applicator 140 towards the pipe 32 and an internal traction applicator 142 Sufficient pressure in circuit 130 will cause the outer traction applicator 140 to effectively sandwich the pipeline 32 between the chain / block assemblies 95, 96, with the desired clamping forces. Thus, the illustrated pushing element (s) 124 can be preselected to cause the desired clamping forces on the pipeline 32. However, any other configuration of components to pressurize the circuit 130 and cause the pipe 32 clamping coupling can be used.
[0059] [0059] If desired, clamping forces on the pipeline 32 can be maintained in the underwater injector 28 regardless of the ambient fluid pressure (hydrostatic) in the surrounding water body 20. Any suitable component arrangement can be used to compensate for pressure changes environment. For example, in the illustrated embodiment, ambient pressure (sea water) is communicated to the push cavity 119 of the reservoir housing 118 and the second cavity 134 of the pull cylinder 114 through ports 121, 146, respectively. Thus, changes in ambient pressure are effectively carried to both sides of the traction piston 136, preserving the pressurized state of the circuit 130 caused by the pushing forces of the pushing element 124.
[0060] [0060] Still with reference to Figure 5, it may be desirable to maintain the tensile forces on the pipeline 32 in the underwater injector 28 regardless of changes in the outer diameter (OD) of the pipeline 32. Any suitable arrangement and techniques can be used to preserve the tightening coupling of the chain / block assemblies 95, 96 with the piping 32 on the variations in the outer diameter of the piping 32. In the illustrated mode, use the pushing element (s) 124 and vent on opposite sides of the system 116 (by means of of doors 121 in the push cavity 119 and doors 146 in the second cavity 134) can allow the displacement piston 136 to move in both directions in response to OD changes in the pipeline 32. For example, by increasing the outer diameter of the pipeline 32 as it passes through the chain / block assemblies 95, 96, the pull piston 136 can slide into the first cavity 132 of the pull cylinder 114, maintaining the pull pressure o suitable in the pipeline 32. This action can apply pressure to the reservoir piston 122, compress the pushing element 124 and / or force the sea water out of the pushing cavity 119 through port (s) 121. For another example, upon a decrease in the outer diameter of the pipe 32, the traction piston 136 can slide into the second cavity 134, forcing seawater out of the second cavity 134 through port (s) 146 and maintaining the tensile pressure piping 32.
[0061] [0061] The ambient pressure compensation system 116 may include an opening 150 in the fluid circuit 130, such as to allow pressure on the drive piston 136 to be released, supply additional hydraulic fluid within the reservoir cavity 120 or another purpose. For example, a valve 152 can be arranged in opening 150 and accessible via an ROV or other equipment. Valve 152 can be opened to the water body 20 or a hydraulic fluid receptacle or line (not shown), such as to release pressure in the ambient pressure compensation system 116 and disengage the chain / block assemblies 95, 96 and underwater injector 28 from the pipe 32. This sequence may be desirable, for example, in the case of equipment malfunction, total system failure, use of pipe, etc.
[0062] [0062] With reference again to Figure 4, the exemplary underwater injector 28 also includes one or more chain tension cylinders 160. Chain tension cylinders 160 can have any suitable configuration and operation, as is or will become known. In this embodiment, each chain 90, 92 has a dedicated chain tension cylinder 160, which maintains a desired tension in the corresponding chain 90, 92 by acting on top of a lower sprocket (not shown) coupled with the respective chain 90, 92 The chain tension cylinders 160 can be energized to maintain the desired chain tension in any desired manner. For example, an ambient pressure compensation system generally similar to system 116 as described above can be used to energize each chain tension cylinder 160. For another example, chain tension cylinders 160 can be energized mechanically or by spring, as it is or becomes still known. Underwater injector 28 can include other systems or functions, such as gearbox oil and gearbox drain, as they are and will become known. If desired, any of these systems can also be powered by a generally configured ambient pressure compensation system similar to system 116 as described above.
[0063] [0063] In some embodiments, water-based hydraulic fluids (WBHF) can be used with one or more of the hydraulic components of the underwater injector 28. For example, the use of WBHF with the underwater injector 28 may allow for a better hydrostatic balance between the water body 20 and the WBHF in the injector 28 and / or its associated components (compared to the use of oil-based hydraulic fluids). For another example, environmentally certified WBHF can be poured or vented into the water body 20 from underwater injector 28 or related equipment, reducing the risk of environmental damage and eliminating the need for an underwater housing drain line (not shown) ) extending to frame 16. For yet another example, the use of WBHF in connection with WBHF-compatible engines (eg engine 100) of the injector 28 can reduce the risk of engine failure pressure situations that may arise due to a potential pressure differential between the fluid in the engine and the ambient pressure in the water body 20, for example, when the engine is switched off.
[0064] [0064] If desired, the exemplary underwater injector 28 can be configured without any instrumentation requiring monitoring from the surface. For example, any necessary gauge (s) and / or sensor (s) (not shown) to monitor hydraulic pressure and flow rate on lines 102, 104 can be arranged at the top end of lines 102, 104 or on frame 16 Any other gauges, sensors or other instruments necessary for the injector 28, such as for use with engines 98, traction cylinders 114, chain tension cylinders 160, ambient pressure compensation system (s) 116, gearbox (not shown), box drain (not shown) or other components, can be configured to be monitored by an ROV or equipment. Therefore, the instrumentation associated with the underwater injector 28 can be relatively simple, reducing the complexity of the injector assembly 30, the potential for malfunction or the requirement for electrical or other communication from the surface. The exemplary piping intervention system 10 can therefore be performed by operators with minimal specific training.
[0065] [0065] In another independent aspect, the present invention includes methods of supplying piping 32 into an underwater well from a floating structure 16 without the use of one or more risers. An embodiment of a method will now be described in connection with the use of the piping intervention system 10 and example components of Figures 1 to 5. However, it should be understood that the illustrated system 10 is not necessary for the practice of this exemplary method or other methods of the present disclosure or appended claims. Any appropriate components can be used. In addition, the present disclosure is not limited to the specific method described below, but includes several methods in accordance with the principles of the present description.
[0066] [0066] With reference to the example of Figures 1 and 2, a first end 33 of the pipeline 32 extends through the surface injector (s) (master) 22 and into the underwater injector (slave) 28, which is suspended at from it. For example, referring to Figure 3, the end 33 of the pipe 32 can be extended to the extractor 31 and coupled to a downhole assembly (not shown) disposed in the lubricator 35. The extractor 31 and lubricator 35 can be removably connected, as with coupling 45. If the exemplary auto-upright mast assembly 54 is included, the conveyor 56 can be in a substantially horizontal position when attaching the equipment as described above (as well as during transport, maintenance, changing equipment etc. .). For implantation of the underwater injector 28 and piping 32 for the well, the illustrated transport 56 is moved to a substantially vertical position and partially submerged in the water. If desired, the mast assembly 54 or other component (s) (for example, the surface injector 22) can be configured to compensate in elevation for the movement of the structure 16 in the water.
[0067] [0067] The exemplary underwater injector 28 and related equipment (for example, Figure 3) are supplied to the well by lowering the pipe 32 into the water (for example, Figure 2). In this embodiment, the underwater injector 28 can be lowered into the well without the use of a crane, cable winch or crane on the structure 16. Furthermore, the illustrated structure 16 does not need to be a specialized vessel, as long as it is capable of holding and support system 10 and related equipment.
[0068] [0068] After the illustrated underwater injector 28 is engaged with the well, the surface injector 22 is selectively operated to control the movement of the pipe 32 up and down in the well, as desired. The underwater injector 28 applies downwardly directed pushing or upwardly pulling forces to the pipeline 32, as desired, without controlling the movement of the pipeline 32.
[0069] [0069] The exemplary underwater injector 28 is controlled independently of the surface injector 22 and can be pre-configured to operate substantially automatically. For example, injector 28 may have some operator control or adjustability from the surface to increase or decrease its ability to pull and / or push tubing, such as to facilitate piping 32 into the well, replacing a safety valve subsurface (not shown), etc. If desired, the underwater injector 28 can be configured without any gauges, sensors or other instrumentation requiring monitoring from the surface. In addition, if desired, the underwater injector 28 can be energized with water-based hydraulic fluid.
[0070] [0070] With reference now to Figure 4, in this method of operating example, a total of only two communication lines are extended between underwater injector 28 and structure 16. For example, hydraulic fluid control lines 102, 104 they are included to power the chain rotation motors 100 of the underwater injector 28. The lines 102, 104 can be connected to the injector 28 before implantation of the structure 16 or connected to the seabed with the remote equipment, such as an ROV. Underwater injector 28 can be equipped with at least one chain pull cylinder 114 that holds injector 28 in a tight fit with the tubing, regardless of changes in ambient pressure in seawater or the outer diameter of the tubing 32. If At least one self-contained, self-powered, spring-powered 116 ambient pressure compensation system (Figure 5, for example) can be included to provide at least one chain tension pressure control, chain tension control, drain and gearbox oil in underwater injector 28, without any control lines extending to the ship or surface.
[0071] [0071] With reference again to figure 2, in the present example of the operating method, the underwater injector 28 can be selectively released from the well, returned to the structure 16 by retraction of the pipe 32 in the structure 16, returned to the well by reimplantation of the pipe 32 and re-engaged with the well several times as desired, without the use of a cable winch, crane or crane.
[0072] [0072] Preferred modalities of the present disclosure, thus, offer advantages in relation to the previous technique and are well adapted to accomplish one or more of the objectives of the present disclosure. However, the present description does not require each of the components and steels described above and is in no way limited to the modalities described above, methods of operation, variables, values or ranges of values. Any one or more of the above components, characteristics and processes may be used in any suitable configuration, without including other such components, characteristics and processes. In addition, the present disclosure includes additional features, capabilities, functions, methods, uses and applications that have not been specifically mentioned here, but are, or will become apparent from this description, the attached drawings and claims.
[0073] [0073] The methods that are provided or evident from this description, or claimed here, and any other methods that may fall within the scope of the appended claims, can be performed in any suitable desired order and are not necessarily limited to any sequence described here, or as may be listed in the appended claims. In addition, the methods of the present disclosure do not necessarily require the use of particular modalities shown and described here, but they are equally applicable to any other appropriate structure, shape and configuration of the components.
[0074] [0074] While exemplary modalities have been shown and described, many variations, modifications and / or alterations to the system, apparatus and methods of the present specification, such as in the components, details of construction and operation, arrangement of the parts and / or methods of use , are possible, contemplated by the patent applicant, within the scope of the appended claims, and can be made and used by an ordinary person skilled in the art without departing from the spirit or teachings of the disclosure and scope of the appended claims. Thus, all matter exposed or shown in the attached drawings must be interpreted as illustrative, and the scope of the description and the attached claims should not be limited to the modalities described and shown here.

权利要求:
Claims (13)
[0001]
Apparatus for supplying coiled tubing (34) to a submarine hydrocarbon production well, from a marine vessel (18) on the sea surface, the apparatus comprising: at least one master injector (22) carried by the ship (18), having a known weight, positioned near the water surface and engaged with the coiled tubing (34), said at least one master injector (22) being configured and used to control the movement of the coiled pipe (34) into and out of the well during normal operation; and at least one slave injector (28) engaged with the coiled pipe, deliverable in the coiled pipe (34) from the vessel (18) to the well, independently controlled from said at least one master injector (22) and configured to be repeatedly implementable to and from the well, where the weight of said at least one slave injector (28) is less than the weight of each of said at least one master injector (22), through which the coiled tubing (34) and said at least one slave injector (28) are delivered to the well without the use of one or more risers extending from the vessel (18) to the well, characterized by the fact that said at least one master injector (22) includes at least one chain configured to directly compensate the movement of the ship (18) in relation to the seabed when said at least one slave injector (28) is implanted in the well.
[0002]
Apparatus according to claim 1, characterized by the fact that at least one slave injector (28) is configured to selectively release from the well, returning it to the ship (18) by retracting the pipe (34) under the ship (18), returning at least one slave injector (28) to the well by redeploying the pipe from the structure and reengaging at least one slave injector (28) with the well multiple times without the use of a cable winch (78), crane or crane.
[0003]
Apparatus, according to claim 2, characterized by the fact that it also includes a self-erecting mast (54) disposed on the ship (18) and within which said at least one master injector (22) is transported, at least part of said self-erecting mast (54) is movable between multiple positions, at least one said position allowing the implantation of said at least one slave injector (28) and coiled tubing (34) into the well and at least one other position allowing the handling, maintenance and changing said at least one slave injector (28) and related components.
[0004]
Apparatus according to claim 3, characterized by the fact that it also includes at least one transport (56) associated with the self-erecting mast (54), having at least one master injector (22) inside the transport (56) and compensating lifting the transport (56).
[0005]
Apparatus, according to claim 1, characterized by the fact that said at least one slave injector (28) is energized with the use of water-based hydraulic fluid allowing the improved hydrostatic balance between said water-based hydraulic fluid in said at least one slave injector (28) and sea water.
[0006]
Apparatus according to claim 5, characterized by the fact that said water-based hydraulic fluid is discharged to the sea without causing significant environmental damage and without the need for any box drain lines extending from said at least one injector slave (28) to the ship (18).
[0007]
Apparatus according to claim 1, characterized by the fact that said slave injector (28) includes at least one self-contained, self-powered and spring-powered ambient pressure compensation system to provide at least a chain tension pressure control, chain tension control, drain control and gearbox oil in it without any control lines extending to the ship (18).
[0008]
Apparatus according to claim 1, characterized by the fact that it also includes a coiled pipe collector (34) disposed below said at least one master injector (22) and configured to engage the coiled pipe (34) in cases where the coiled tubing (34) becomes disengaged or released from said at least one master injector (22).
[0009]
Apparatus according to claim 1, characterized by the fact that said at least one slave injector (28) has a maximum capacity to push the coiled pipe (34) down which is greater than its maximum capacity to pull the coiled pipe (34) upwards.
[0010]
Method of supplying piping into an underwater well from a floating structure (16), the method characterized by the fact that it comprises: extending a first end (33) of the tubing through at least one main injector carried over the frame (16); at the first end (33) of the pipe, suspend at least one slave injector (28) having a weight that is less than the weight of at least one master injector (22); deliver at least one slave injector (28) to the well by lowering the pipe into the water without using one or more risers extending from the structure (16) to the well; engage at least one slave injector (28) with the well; selectively operate at least one master injector (22) to control the movement of the pipe up and down in the well; and allowing at least one slave injector (28) to apply push downwardly directed and pull upwardly forced into the pipe without at least one slave injector (28) controlling the pipe movement; and providing at least one master injector (22) with at least one chain configured to directly compensate for the vessel's movement (18) in relation to the seabed when said at least one slave injector (28) is implanted in the well.
[0011]
Method according to claim 10, characterized by the fact that it also includes providing a self-erecting mast (54) in the structure and within which at least one main injector is transported, moving at least part of the self-erecting mast (54) between multiple positions, at least one position allowing the implantation of at least one slave injector (28) and piping to the well and at least one other position allowing the transport (56), handling, maintenance and change of at least one slave injector (28) , components referenced to it and equipment transported at the first end (33) of the pipe.
[0012]
Method according to claim 11, characterized by the fact that it also includes providing at least one transport (56) associated with the self-erecting mast (54), having at least one master injector (22) inside the transport (56) and compensate for the lift (56).
[0013]
Method, according to claim 12, characterized by the fact that it also includes selectively releasing at least one slave injector (28) from the well, returning it to the structure (16) by retracting the pipe on top of the structure ( 16), returning at least one slave injector (28) to the well by redeploying the pipe from the structure and reengaging at least one slave injector (28) with the well multiple times without using a cable winch (78 ), crane or crane.

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同族专利:

公开号 | 公开日

US20140216752A1|2014-08-07|

GB2494558A|2013-03-13|

GB2494558B|2018-08-22|

NO20121302A1|2012-12-04|

US20110284234A1|2011-11-24|

BR112012029411A2|2017-11-21|

US8720582B2|2014-05-13|

AU2011255632B2|2015-06-04|

SG185618A1|2012-12-28|

GB201220415D0|2012-12-26|

WO2011146623A3|2013-01-03|

AU2011255632A1|2012-11-29|

US9151123B2|2015-10-06|

NO345836B1|2021-08-30|

WO2011146623A2|2011-11-24|

MY167137A|2018-08-13|

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法律状态:
2018-12-26| B06F| Objections, documents and/or translations needed after an examination request according [chapter 6.6 patent gazette]|

2019-07-30| B06U| Preliminary requirement: requests with searches performed by other patent offices: procedure suspended [chapter 6.21 patent gazette]|

2019-12-17| B06A| Patent application procedure suspended [chapter 6.1 patent gazette]|

2020-11-10| B09A| Decision: intention to grant [chapter 9.1 patent gazette]|

2020-12-01| B16A| Patent or certificate of addition of invention granted [chapter 16.1 patent gazette]|Free format text: PRAZO DE VALIDADE: 20 (VINTE) ANOS CONTADOS A PARTIR DE 18/05/2011, OBSERVADAS AS CONDICOES LEGAIS. |

优先权:

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US61/346,323|2010-05-19|

US13/109,422|US8720582B2|2010-05-19|2011-05-17|Apparatus and methods for providing tubing into a subsea well|

US13/109,422|2011-05-17|

PCT/US2011/037005|WO2011146623A2|2010-05-19|2011-05-18|Apparatus and methods for providing tubing into a subsea well|

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