Techniques and systems to reduce deflection of a riser extending from an offshore platform. A device may include a main tube disposed along a length of the device. The device may also include a support member that may be coupled to the main tube, wherein the support member may surround the main tube. The device may include a buoyancy assembly that may at least partially surround the main tube, wherein the buoyancy assembly may have an elongated non-circular and non-cylindrical shape. The buoyancy assembly may also include buoyancy foam.

BACKGROUND

Advances in the petroleum industry have allowed access to oil and gas drilling locations and reservoirs that were previously inaccessible due to technological limitations. For example, technological advances have allowed drilling of offshore wells at increasing water depths and in increasingly harsh environments, permitting oil and gas resource owners to successfully drill for otherwise inaccessible energy resources. To drill for oil and gas offshore, it is desirable to have stable offshore platforms and/or floating vessels from which to drill and recover the energy resources. Techniques to stabilize the offshore platforms and floating vessels include, for example, the use of mooring systems and/or dynamic positioning systems. However, these systems may not always adequately stabilize components descending from the offshore platforms and floating vessels to the seafloor wellhead.

For example, a riser string or riser (e.g., a pipe or series of pipes, such as riser joints, that connects the offshore platforms or floating vessels to the floor of the sea) may be used to transport drill pipe, casing, drilling mud, production materials or hydrocarbons between the offshore platform or floating vessel and a wellhead. The riser is suspended between the offshore platform or floating vessel and the wellhead, and may experience forces, such as underwater currents, that cause deflection (e.g., bending or movement) or vortex induced vibrations (VIV) in the riser. Acceptable deflection can be measured by the deflection along the riser, and also at, for example, select points along the riser. These points may be located, for example, at the offshore platform or floating vessel and at the wellhead. If the deflection resulting from underwater current is too great, drilling must cease and the drilling location or reservoir may not be accessible due to such technological constraints. If the vibrations due to the currents are too great, the riser and/or the wellhead may experience accelerated fatigue damage.

DETAILED DESCRIPTION

Systems and techniques for stabilizing a riser (e.g., a riser string made up of a series of riser joints coupled to one another) extending from offshore platform, such as a drillship, a semi-submersible platform, a floating production system, or the like, are set forth below. During offshore drilling operations, high current or high loop current is sometimes occurred, and it may cause large drag force and/or deflection on the riser (e.g., especially for buoyancy joints of the riser, which may have diameters up to 55″ or more) and vortex induced vibrations (VIV), which can cause riser failure and, thus, require cessation of drilling and/or production operations. In some embodiments, fairings and/or helical strakes may be used along the riser. However, these helical strakes tend to aid in VIV suppression but not necessarily in reducing the drag force. Additionally, installation and removal of fairings and/or /helical strakes may be time consuming, thus slowing operations of the offshore platform.

Accordingly, additional embodiments herein may include specialty riser joints with weathervaning buoyancy (e.g., drilling and/or production specialty riser joints that may form a portion or all of the riser) that are designed to operate to greatly reduce the drag coefficient and drag force on the riser. By altering the shape of the specialty riser joints' buoyancy from a cylindrical or circular shape to that of an elongated shape (e.g., an elliptical or airfoil shape), the drag coefficient and drag force of the specialty riser joints can be greatly reduced. Also, the VIV may be greatly reduced and/or eliminated.

In some embodiments, the specialty riser joints may be fixed with respect to an axial, radial, and circumferential directions. In other embodiments, the elongated shape of the specialty riser joints may allow for the specialty riser joints to be fixed with respect to an axial and a radial direction, while capable of rotation in a circumferential direction. This circumferential motion may be in response to, for example, forces imparted to the specialty riser joints by currents. Through rotation of the specialty riser joints, the drag coefficient and drag force of specialty riser joints resulting from the shape thereof may be preserved even as currents change in the field.

With the foregoing in mind,FIG. 1illustrates an offshore platform includes an offshore vessel10. Although the presently illustrated embodiment of an offshore vessel10is a drillship (e.g., a ship equipped with a drill rig and engaged in offshore oil and gas exploration and/or well maintenance or completion work including, but not limited to, casing and tubing installation, subsea tree installations, and well capping), other offshore platforms such as a semi-submersible platform, a floating production system, or the like may be substituted for the drillship. Indeed, while the techniques and systems described below are described in conjunction with a drillship, the techniques and systems are intended to cover at least the additional offshore platforms described above.

As illustrated inFIG. 1, the offshore vessel10, with a derrick11thereon, includes a riser12extending therefrom. The riser12may include a pipe or a series of pipes (e.g., riser joints) that connect the offshore vessel10to the seafloor14via, for example, blow out preventer (BOP)16that is coupled to a wellhead18on the seafloor14. These riser joints may include one or more of, for example, drilling riser joints, slick joints, buoyancy joints, pup joints, telescopic joints, production joints, or other types of riser joints as part of the riser12. In some embodiments, the riser12may transport produced hydrocarbons and/or production materials between the offshore vessel10and the wellhead18, while the BOP16may include at least one valve with a sealing element to control wellbore fluid flows. In some embodiments, the riser12may pass through an opening (e.g., a moonpool) in the offshore vessel10and may be coupled to drilling equipment of the offshore vessel10. As illustrated inFIG. 1, it may be desirable to have the riser12positioned in a vertical orientation between the wellhead18and the offshore vessel10, for example, to allow a drill string made up of drill pipes19to pass from the offshore vessel10through the BOP16and the wellhead18and into a wellbore below the wellhead18. However, external factors (e.g., environmental factors such as currents) may disturb the vertical orientation of the riser12.

As illustrated inFIG. 2, the riser12may experience deflection, for example, from currents20. These currents20may apply forces on the riser12, which causes deflection (e.g., motion, bending, or the like) in riser12. Thus, when the offshore vessel10works under the existence of strong currents20, the riser12will have significant horizontal deflection due to the drag loads applied along the riser12. As a result, the angle24between the vertical axis26(e.g., an axis that is perpendicular to the seafloor14and extends vertically to the surface of the sea28) and the riser bottom flex joint30may exceed tolerance levels for the performance of, for example, drilling operations.

This angle24may be modified through the dynamic positioning of the offshore vessel10. That is, through the movement of the offshore vessel10in response to the currents20, the static angle24of the bottom flex joint30may be reduced and/or eliminated to meet any operational requirements associated with, for example, the blow out preventer16, the wellhead18, and/or the riser12. However, adjustment of the position of the offshore vessel10to reduce and/or eliminate the static angle24of the bottom flex joint30may also increase the the angle32of top flex joint34beneath drill floor36with respect to the vertical axis26. This may cause the portion of the riser12beneath the drill floor as it passes through the moonpool38to interfere with the hull39of the offshore vessel10. This interference between the riser12and the hull39is to be avoided.

Thus, force applied to the riser12from the currents20(or other environmental forces) may cause the riser12to stress the BOP16or cause key seating, as the angle24that the riser12contacts the BOP16may be affected via the deflection of the riser12. Likewise, the currents20and/or efforts to mitigate the force of the currents20(e.g., dynamic positioning of the offshore vessel) may cause the riser12to contact the edge of the moonpool38of the offshore vessel10. To reduce the deflection of the riser12, and to reduce the chances of occurrence of the aforementioned problems caused by riser12deflection, additional systems and techniques may be employed.

FIG. 3illustrates a system to mitigate the deflection of the riser12. In some embodiments, reduction of the angle32and, indeed, deflection of the riser12as a whole may be accomplished through the use of one or more elongated riser joints40of the riser12. These specialized riser joints (e.g., elongated riser joints40) may be disposed along an entire length of the riser12or, for example, along one or more predetermined portions of the riser12that cumulatively result in a length of elongated riser joints40less than an entire length of the riser12. In some embodiments, each elongated riser joint40may have a fixed geometry (e.g., a fixed shape and elongation). In other embodiments, at least one riser joint may be tapered such that the length of the elongation of the elongated riser joint40tapers along an axial distance of the elongated riser joint40. Likewise, a series of elongated riser joints40may be utilized whereby each elongated riser joint40has a fixed elongation length, but the elongation lengths between elongated riser joints40differs (e.g., to allow for net tapering of the elongation of the elongated riser joints40when taken as a group).

The elongated riser joints40may have an elongated shape such as an elliptical shape (which, may in some embodiments, include an offset of its center along a rotational axis, for example, axial direction42), an airfoil shape (e.g., a fin, a blade, or a vane), a shape with a leading edge that tapers to a trailing edge (e.g., a teardrop), or the like. The elongated riser joints40have also have a non-circular shape as well as a non-cylindrical shape as the elongated shape. For example, the elongated riser joints may have one or more streamline bodies as the elongated non-circular and non-cylindrical shape. Indeed, while circular shaped riser joints may have a drag coefficient to approximately 1.2 for laminar flow, the elongated riser joints40may have a reduced drag coefficient of approximately 0.2˜0.6 along with reduced and/or eliminated VIV with respect to circular riser joints. An elongated riser joint40may be, for example, a buoyancy joint and the elongated riser joint40may have an elliptical cross section may include a length to width ratio of approximately 2:1, which can reduce drag and drag coefficient to approximately 0.435 while also greatly reducing and/or eliminating VIV. As previously noted, the elliptical cross section of the elongated riser joints40may include a offset of their center to the rotation axis for example, axial direction42, so as to create weathervane movement, rotation, or the like. In some embodiments, the amount of offset from the center of the elongated riser joints40may be chosen dependent on, for example, desired amount of rotation, the environment in which the elongated riser joints40will be utilized, or the like. As illustrated inFIG. 3, and as will be discussed in greater detail below, the riser12with at least one elongated riser joint40may be disposed between the offshore platform10and the seafloor14, whereby the riser12includes at least one elongated riser joint40is disposed in an axial direction42(e.g., along a longitudinal axis). Also illustrated for reference is a radial direction44, which may be used to describe, for example, a width of the elongated riser joint40. Additionally, as will be discussed in greater detail below, at least one portion of the elongated riser joint40may rotate in a circumferential direction46, for example, in response to currents20, whereby the elongated riser joint40is elongated (e.g., may have an elongated shape) in the radial direction44(at a width of the elongated riser joint40).

FIG. 4Aillustrates a cross section top view48of the elongated riser joint40andFIG. 4Billustrates a side view50of the elongated riser joint40when the riser joint40has an elliptical shape (e.g., with a length52and a width equivalent to 2× length52, such that the length to width ratio is 2:1). As illustrated, the elongated riser joint40may include a buoyancy foam54that operates to provide buoyancy to the elongated riser joint40when submerged. The buoyancy foam54may be a single enclosure that operates as an outer (exterior) portion of the elongated riser joint40or the buoyancy foam54may be two or more distinct enclosures that may be affixed to one another via one or more fasteners56(e.g., screws, bolts, pins, locking mechanisms, or the like) or the two or more enclosures may be permanently affixed (e.g., welded) to one another to combine to form an outer (exterior) portion of the elongated riser joint40. As illustrated inFIGS. 4A and 4B, in some embodiments, the elongated riser joint40may be offset by a distance55away from its center57along the illustrated so that its rotational axis59is not along the center57, but rather, adjusted by distance55away from the center57, for example, to enhance the response of the elongated riser joint40with respect to changes to the directions of currents20(e.g., to aid in providing a weathervane effect).

The buoyancy foam54, in some embodiments, is rotatable around the main tube58, through which, for example, drill pipes19may pass. As illustrated, the main tube58may be circular in shape and terminate in a flange60or a connector (e.g., a slick joint designed to prevent damage to the riser12and restrict lateral movement of one or more lines passing along the riser12) with, for example, one or more apertures62through which choke and kill lines may pass, one or more apertures64through which a hydraulic line may pass, and one or more apertures66through which a booster line may pass. The flange60may allow for connection of the elongated riser joint40with another elongated riser joint40and/or a standard riser joint. The elongated riser joint40may also include fixed buoyancy foam68that, for example, directly surrounds the main tube58and one or more of the choke and kill lines, the hydraulic line, and the booster line. The material used for the buoyancy foam54and the fixed buoyancy foam68may be identical or, for example, the material used for the buoyancy foam54may be a non-absorbent (e.g., fluidly sealed) material while the material used for the fixed buoyancy foam68may not necessarily be a non-absorbent (e.g., fluidly sealed) material.

Furthermore, as illustrated inFIG. 4B, the buoyancy foam54may include one or more bands70disposed thereon and/or disposed between segments of buoyancy foam54. In some embodiments, the bands70may be metallic strips or strips or similar materials that allow for connection points by the one or more fasteners56along the length of the elongated riser joint40in an axial direction42. Additionally, a clamp72may be disposed beneath one or more of the bands70. The clamp72may be made of metal or a similar minimally deformable material and may include a groove (e.g., a “U” groove) or other mounting guide which may be used to mount a rotating buoyancy assembly to allow for rotation of the buoyancy foam54, for example, in a circumferential direction46about the main tube58, such that the portion of the elongated riser joint40including an elongated body (e.g., buoyancy foam54or the buoyancy foam54and the one or more bands70) is configured to rotate in a circumferential direction with respect to the flange60. The components of the rotating buoyancy assembly may are illustrated in greater detail with respect toFIG. 5.

FIG. 5illustrates an exploded view of the elongated riser joint40. As illustrated, a buoyancy assembly74may include a metal frame inclusive of the band70as well as the one or more fasteners56. The buoyancy assembly74may provide the elongated shape to the elongated riser joint40, as the buoyancy assembly74may be the external portion of the elongated riser joint40(e.g., via inclusion of the buoyancy foam54as a portion of the buoyancy assembly74). Thus, the buoyancy assembly74may have an elliptical shape (which may, in some embodiments, include a rotational axis59offset from center57by distance55), an airfoil shape (e.g., a fin, a blade, or a vane), a shape with a leading edge that tapers to a trailing edge (e.g., a teardrop), or the like so that the buoyancy assembly74(and, accordingly, the respective elongated riser joint40), has an elongated non-circular shape as well as a non-cylindrical shape. As will be described in greater detail below, in some embodiments, the buoyancy assembly74may rotate in a circumferential direction46in response to external forces, for example, currents20.

The buoyancy assembly74may also include a bearing76that may be formed between the one or more fasteners56and may interconnect with (e.g., be rotatably coupled to) the clamp72to allow for rotation of the buoyancy assembly74and, thus, the buoyancy foam54, in a circumferential direction46about the main tube58(e.g., the buoyancy assembly74may thus be rotatably coupled to the main tube58) to provide rotation of the buoyancy assembly74with respect to the flange60. The bearing76may interface with (e.g., be coupled to while still allowing for rotation about) a support77that surrounds the main tube58and the support77may itself be statically coupled to the main tube58. Thus, the bearing76(and, accordingly, the buoyancy assembly74) is rotatably coupled to (e.g., coupled to while still allowing for rotation about) the support77and may allow for rotation in a circumferential direction46about the support77(and, thus, the main tube58). As illustrated, the support77may include one or more apertures to allow for passage of a choke line, a kill line, a hydraulic line, a booster line, or the like through the support along the main tube58.

In some embodiments, the bearing76may be a plain bearing such as a bushing or a journal (e.g., radial or rotary) bearing. Likewise, the bearing76may be a rolling-element bearing (e.g., a rolling bearing) that carries the load of the buoyancy assembly74and/or the buoyancy foam54via rolling elements (e.g., balls or rollers), while allowing for rotational motion (e.g., rotation of the buoyancy assembly74and, thus, the buoyancy foam54coupled thereto in a circumferential direction46about the main tube58). As illustrated, the buoyancy assembly74may additionally include support78in the region between the band70and the bearing76. The material used for the support78may be identical to or different from the material of one or more of the buoyancy foam54and the fixed buoyancy foam68or, in some embodiments, the support78may be metal, such as a steel or other metallic plate, that may be utilized to hold one or more the buoyancy foam54and the fixed buoyancy foam68in place. Additionally, it should be noted thatFIG. 5illustrates a region80about the main tube58and the auxiliary lines (e.g., one or more of the choke and kill lines, the hydraulic line, and the booster line) that may be filled by the fixed buoyancy foam68to form a circular rod with a circumference equal to or less than the radius of the clamp72.

WhileFIG. 5illustrates internal components of the elongated riser joint40with an elliptical shape (which may, in some embodiments, include a rotational axis59offset from center57by distance55), as previously discussed, the elongated riser joint40may have alternative shapes while still utilizing analogous components to that described inFIG. 5. For example,FIG. 6illustrates a cross section top view of an elongated riser joint40with an airfoil shape82. As illustrated, the elongated riser joint40with an airfoil shape82includes buoyancy foam54that operates to provide buoyancy to the elongated riser joint40when submerged. The buoyancy foam54may be a single enclosure or the buoyancy foam54may be two or more enclosures that may be affixed to one another via one or more fasteners56(e.g., screws, bolts, pins, locking mechanisms, or the like) or the two or more enclosures may be permanently affixed (e.g., welded) to one another.

Additionally, the buoyancy foam54may rotate through rotation of the enclosures in a circumferential direction46in response to external forces, for example, currents20around the main tube58, whereby the main tube58is circular in shape and terminates in a flange60with apertures62,64, and66. The elongated riser joint40with an airfoil shape82may also include fixed buoyancy foam68that, for example, directly surrounds the main tube58and one or more of the choke and kill lines, the hydraulic line, and the booster line. Furthermore, the elongated riser joint40with an airfoil shape82may include the clamp72and the buoyancy assembly74discussed above with respect toFIG. 5, whereby the clamp72and the buoyancy assembly74operate in conjunction with one another to allow for rotation of the buoyancy foam54, for example, in a circumferential direction46about the main tube58in response to currents20.

As previously discussed, elongated riser joints40(whether shaped as illustrated inFIG. 5,FIG. 6, including a shape with a leading edge that tapers to a trailing edge, or the like) may be disposed along an entire length of the riser12. Alternatively, the elongated riser joints40may be disposed along one or more predetermined portions of the riser12that cumulatively result in a length of elongated riser joints40less than an entire length of the riser12. For example, determination of the location of the elongated riser joints40along the riser12may be determined based on the specific application in which the offshore vessel10is to be deployed. In some embodiments, charts may be developed based on measurements of the currents20at a particular drill site. Table 1 illustrates an example of such a chart:

Table 1 describes the speed of currents20at particular depths over periods of time, for example, one year and ten years. Using this information, a determination of the location (e.g., depth) of an elongated riser joint40, two or more consecutively disposed elongated riser joints40(e.g., two or more elongated riser joints40directly coupled to one another), and/or two or more non-consecutively disposed elongated riser joints40(e.g., two or more elongated riser joints40disposed along the riser12but not directly coupled with one another) can be made. Once this determination is made, disposing the elongated riser joint(s)40may occur. However, it may be appreciated that other information separate from or in addition to the information of Table 1 may be used in determining location(s) and/or numbers of elongated riser joints40disposed along the riser12.

In some embodiments, the buoyancy foam54may be coupled to the main tube58prior the elongated riser joint40being lowered into the sea (e.g., on the drillship10while the riser string12is being made up). Alternatively, the buoyancy foam54may be coupled to the main tube58once disposed in the sea (e.g., once the elongated riser joint40is deployed). For example, a Remotely Operated Vehicles (ROV) may be utilized to affix the buoyancy foam54to the riser12or pup joint in step66. An ROV may be a remotely controllable robot/submersible vessel with that may be controlled from the drillship10. The ROV may move to a selected point in the riser string (e.g., to the deployed elongated riser joint40) and couple buoyancy foam54may be coupled to the main tube58at the predetermined position (depth) determined for the elongated riser joint40.

This written description uses examples to disclose the above description, including the best mode, and also to enable any person skilled in the art to practice the disclosure, including making and using any devices or systems and performing any incorporated methods. The patentable scope of the disclosure is defined by the claims, and may include other examples that occur to those skilled in the art. Such other examples are intended to be within the scope of the claims if they have structural elements that do not differ from the literal language of the claims, or if they include equivalent structural elements with insubstantial differences from the literal languages of the claims. Accordingly, while the above disclosed embodiments may be susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and have been described in detail herein. However, it should be understood that the embodiments are not intended to be limited to the particular forms disclosed. Rather, the disclosed embodiment are to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the embodiments as defined by the following appended claims.