WO2018217703A1

WO2018217703A1 - Subsea riser systems and methods

Info

Publication number: WO2018217703A1
Application number: PCT/US2018/033824
Authority: WO
Inventors: Frank Benjamin Springett; Christopher Dale Johnson; Eric Trevor Ensley; Travis James Miller
Original assignee: National Oilwell Varco, L.P.
Priority date: 2017-05-22
Filing date: 2018-05-22
Publication date: 2018-11-29

Abstract

A marine riser assembly (50) includes a first riser (60) having an upper end coupled to a floating offshore structure (20) and a lower end disposed subsea. In addition, the marine riser assembly includes a second riser (70) having an upper end coupled to the floating offshore structure (20) and a lower end disposed subsea. Further, the marine riser assembly includes a riser interface assembly (100) coupled to a subsea blowout preventer (14), the lower end of the first riser, and the lower end of the second riser. The subsea blowout preventer (14) is disposed at an upper end of a subsea wellbore (19). The first riser (60) and the riser interface assembly (100) are configured to provide access to the wellbore (19) through the subsea blowout preventer (14). The second riser (70) and the riser interface (100) are configured to provide access to the wellbore (19) through the subsea blowout preventer (14).

Description

SUBSEA RISER SYSTEMS AND METHODS

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application claims benefit of U.S. provisional patent application Serial No. 62/509,289 filed May 22, 2017, and entitled "Subsea Riser Systems and Methods," which is hereby incorporated herein by reference in its entirety.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

[0002] Not applicable.

BACKGROUND

[0003] Field of the Disclosure

[0004] This disclosure relates generally to subsea riser systems and methods for offshore wells. More particularly, the disclosure relates to subsea risers and couplings between a subsea stack at the sea floor and the risers that define a plurality of paths for accessing the subsea stack and well extending therefrom.

[0005] Background to the Disclosure

[0006] Subsea wells are typically made up by installing a primary fluid conductor into a borehole extending from the seabed and securing a wellhead to the upper end of the primary conductor. A subsea stack, also referred to as a blowout preventer (BOP) stack, is often mounted to the wellhead. The stack typically includes a blowout preventer mounted directly to the upper end of the wellhead and a lower marine riser package (LMRP) mounted to the upper end of the BOP. The primary conductor, wellhead, BOP, and LMRP are installed in a vertical arrangement one- above-the-other. The lower end of a riser extending subsea from a surface vessel or rig is coupled to a flex joint at the top of the LMRP.

[0007] For drilling operations, a drill string is suspended from the surface vessel or rig through the riser, LMRP, BOP, wellhead, and primary conductor to drill a borehole. During drilling, casing strings that line the borehole and extend downhole from the primary conductor are successively installed and cemented in place to ensure borehole integrity. After the well is drilled and cased, completion operations are performed to make the well ready for production, and then the well is produced.

[0008] During downhole operations (e.g., drilling, completion, production, etc.), various strings (e.g. pipe strings, coiled tubing, production tubing, etc.) are suspended from the surface vessel or rig through the riser, LMRP, BOP, wellhead, primary conductor and into the casing to perform various functions. Typically, the various tool strings are deployed downhole, used to perform the activity, and then "tripped" (removed) one-at-a-time in succession. The time required to deploy and trip each tool string, in which -effectively- no progress is made toward improving or evaluating the borehole, is a significant portion of the overall operation time.

BRIEF SUMMARY OF THE DISCLOSURE

[0009] Embodiments of marine riser assemblies are disclosed herein. In one embodiment, a marine riser assembly comprises a first riser having an upper end coupled to a floating offshore structure and a lower end disposed subsea. In addition, the mariner riser comprises a second riser having an upper end coupled to the floating offshore structure and a lower end disposed subsea. Further, the marine riser comprises a riser interface assembly coupled to a subsea blowout preventer, the lower end of the first riser, and the lower end of the second riser. The subsea blowout preventer is disposed at an upper end of a subsea wellbore. The first riser and the riser interface assembly are configured to provide access to the wellbore through the subsea blowout preventer. The second riser and the riser interface are configured to provide access to the wellbore through the subsea blowout preventer.

[0010] Embodiments of methods for performing downhole operations from a surface vessel with a marine riser assembly extending from the surface vessel to a subsea blowout preventer (BOP) stack are disclosed herein. In one embodiment, a method for performing downhole operations from a surface vessel with a marine riser assembly comprises (a) deploying a first string through a first marine riser of the marine riser assembly and into the wellbore. In addition, the method comprises (b) performing a first operation in the wellbore with the first string. Further, the method comprises (c) removing the first string from the wellbore and into the first marine riser. Still further, the method comprises (d) removing the first string from the first marine riser to the surface vessel after (c). Moreover, the method comprises (e) positioning a second string in a second marine riser of the marine riser assembly during (a), (b), or (c), wherein the first marine riser and the second marine riser are laterally spaced apart. The method also comprises (f) deploying the second string from the second marine riser and into the wellbore after (c) and (e) but before (d). [0011] Embodiments of marine riser assemblies are disclosed herein. In one embodiment, a marine riser assembly comprises a first riser having an upper end coupled to a floating offshore structure and a lower end disposed subsea. In addition, the mariner riser assembly comprises a second riser having an upper end coupled to the floating offshore structure and a lower end disposed subsea. The second riser is laterally offset from the first riser. Further, the mariner riser assembly comprises a spacer assembly disposed about the first riser and configured to prevent the second riser from laterally impacting the first riser. The spacer assembly is configured to radially expand between a collapsed position and a deployed position.

[0012] Embodiments described herein comprise a combination of features and characteristics intended to address various shortcomings associated with certain prior devices, systems, and methods. The foregoing has outlined rather broadly the features and technical characteristics of the disclosed embodiments in order that the detailed description that follows may be better understood. The various characteristics and features described above, as well as others, will be readily apparent to those skilled in the art upon reading the following detailed description, and by referring to the accompanying drawings. It should be appreciated that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes as the disclosed embodiments. It should also be realized that such equivalent constructions do not depart from the spirit and scope of the principles disclosed herein.

BRIEF DESCRIPTION OF THE DRAWINGS

[0013] For a detailed description of the disclosed exemplary embodiments, reference will now be made to the accompanying drawings, wherein:

[0014] Figure 1 is a schematic view of an embodiment of an offshore system for drilling, completion, and/or production including a riser interface assembly and a riser spacer assembly in accordance with the principles disclosed herein;

[0015] Figure 2 is an side view of the riser interface assembly of Figure 1 ;

[0016] Figure 3 is a side view of the riser spacer assembly of Figure 1 shown in an open, radially-expand position, in accordance with the principles disclosed herein; [0017] Figure 4 is a side view of the riser segment and riser spacer assembly of Figure 3 shown in a closed, radially-collapsed position;

[0018] Figure 5 is a bottom view of the riser segment and riser spacer assembly of Figure 3;

[0019] Figure 6 is a schematic, partial cross-sectional side-view of an embodiment of a riser interface assembly, shown in a first position, in accordance with the principles disclosed herein;

[0020] Figure 7 is a schematic, partial cross-sectional side-view of the riser interface assembly of Figure 6, shown in a second position;

[0021] Figure 8 is a side view of an embodiment of a marine riser assembly including a riser interface assembly and riser spacer assemblies in accordance with the principles disclosed herein; and

[0022] Figure 9 is a flow diagram of a method for deploying multiple tool strings into an offshore wellbore, in accordance with the principles disclosed herein.

NOTATION AND NOMENCLATURE

[0023] The following description is exemplary of certain embodiments of the disclosure. One of ordinary skill in the art will understand that the following description has broad application, and the discussion of any embodiment is meant to be exemplary of that embodiment, and is not intended to suggest in any way that the scope of the disclosure, including the claims, is limited to that embodiment.

[0024] The figures are not necessarily drawn to-scale. Certain features and components disclosed herein may be shown exaggerated in scale or in somewhat schematic form, and some details of conventional elements may not be shown in the interest of clarity and conciseness. In some of the figures, in order to improve clarity and conciseness, one or more components or aspects of a component may be omitted or may not have reference numerals identifying the features or components. In addition, within the specification, including the drawings, like or identical reference numerals may be used to identify common or similar elements.

[0025] As used herein, including in the claims, the terms "including" and "comprising," as well as derivations of these, are used in an open-ended fashion, and thus are to be interpreted to mean "including, but not limited to... ." Also, the term "couple" or "couples" means either an indirect or direct connection. Thus, if a first component couples or is coupled to a second component, the connection between the components may be through a direct engagement of the two components, or through an indirect connection that is accomplished via other intermediate components, devices and/or connections. The recitation "based on" means "based at least in part on." Therefore, if X is based on Y, then X may be based on Y and on any number of other factors. The word "or" is used in an inclusive manner. For example, "A or B" means any of the following: "A" alone, "B" alone, or both "A" and "B." In addition, when used herein including the claims, the word "substantially" means within a range of plus or minus 10%. When used herein including the claims, the word "uniform" is equivalent to the phrase "uniform or substantially uniform."

[0026] In addition, the terms "axial" and "axially" generally mean along a given axis, while the terms "radial" and "radially" generally mean perpendicular to the axis. For instance, an axial distance refers to a distance measured along or parallel to a given axis, and a radial distance means a distance measured perpendicular to the axis. As understood in the art, the use of the terms "parallel" and "perpendicular" may refer to precise or idealized conditions as well as to conditions in which the members may be generally parallel or generally perpendicular, respectively. Furthermore, any reference to a relative direction or relative position is made for purpose of clarity, with examples including "top," "bottom," "up," "upper," "upward," "down," "lower," "clockwise," "left," "leftward," "right," and "right-hand." For example, a relative direction or a relative position of an object or feature may pertain to the orientation as shown in a figure or as described. If the object or feature were viewed from another orientation or were implemented in another orientation, it may be appropriate to describe the direction or position using an alternate term.

[0027] The use of ordinal numbers (i.e. first, second, third, etc.) to identify one or more components within a possible group of multiple similar components is done for convenience and clarity. The ordinal numbers used in the Detailed Description for members of a particular group of components may not necessarily correspond to the ordinal numbers used in the claims when referring to various members of the same group or a similar group of components.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0028] As previously described, typical systems and methods for working offshore wells incur significant time lapse between the utilization of successive tool strings due to sequential deployment and retrieval of the tools for a single wellbore. However, as will be described in more detail below, embodiments of apparatuses, systems, and methods described herein offer the potential to reduce those time lapses. In particular, embodiments described herein include apparatuses, systems, and methods for accessing a single wellbore from multiple, coupled risers that extend in parallel to a surface vessel, allowing a first tool string extending through a first riser to be operating in the wellbore while a second tool string is being deployed into a second riser and positioned proximal the wellbore for later entry into the wellbore.

[0029] As described above, during downhole operations (e.g., drilling, completions, etc.), strings (e.g., drill strings, tool strings, etc.) are typically deployed and retrieve (i.e., tripped) one-at-a-time. The process of tripping a tubular string can be lengthy, and during that time, no other downhole operations can be performed as the tubular string being tripped through the riser significantly limits access to the riser and wellbore therebelow. As a result, while tripping, the surface vessel or platform, which may have a very large day rate, is generally sitting idle. However, in embodiments described herein, riser assemblies including a plurality of risers with selective access to the wellbore are provided. The plurality of risers enables the tripping of a first string through a first riser, while a second string is simultaneously positioned and staged in a second riser. Thus, embodiments described herein allow for the deployment of a string simultaneously with the tripping of another string, which offers the potential to leverage dual activity vessels to beneficially minimize the down or idle time of the vessel. Methods and apparatus for performing multiple activities involving a marine vessel having a single derrick and multiple tubular activity stations are described in U.S. Patent 6,085,851 , which is incorporated herein by reference for all purposes.

[0030] Referring now to Figure 1 , an embodiment of an offshore system 10 in accordance with the principles described herein is shown. In general, system 10 can be used in drilling operations, completion operations, production operations, or combinations thereof. In this embodiment, system 10 includes a subsea blowout preventer (BOP) stack 1 1 mounted to a wellhead 12 at the mud line or sea floor 13. Stack 1 1 includes a blowout preventer (BOP) 14 attached to the upper end of wellhead 12 and a lower marine riser package (LMRP) 15 connected to the upper end of BOP 14. A primary fluid conductor 18 extends from wellhead 12 into a subterranean borehole or wellbore 19. System 10 includes a vessel 10 at the sea surface 17, which in this embodiment, is a floating offshore structure, and thus, may also be referred to as platform 20. In other embodiments, the vessel (e.g., vessel 20) can be a drill ship or any other vessel disposed at the sea surface for conducting offshore operations (e.g., semi-submersible platform, tension leg platform, spar, etc.). Platform 20 includes a drilling derrick 21 and a lifting device 22, which in this embodiment is a full depth crane.

[0031] A marine riser assembly 50 extends subsea from platform 20 to a flex joint at the top of LMRP 15. Riser assembly 50 provides multiple paths or passageways for fluid communication and tool transfer between platform 20 and stack 1 1 , thereby providing multiple paths for accessing wellbore 19. In this embodiment, riser assembly 50 includes a first marine riser 60, a second marine riser 70 horizontally off-set from first marine riser 60, and a riser interface assembly 100 coupling risers 60, 70 to stack 1 1 . Risers 60, 70 are generally oriented parallel to each other, but are laterally spaced apart. Each riser 60, 70 includes multiple riser segments made of large-diameter pipe connected end-to-end to form an elongate tubular structure. For example, riser 60 includes a plurality of riser segments 60A and riser 70 includes a plurality of riser segments 70A as shown in enlarged section 1 -1 of Figure 1 .

[0032] First riser 60 has a central or longitudinal axis 61 , an upper end 62 coupled to platform 20, and a lower end 64 coupled to riser interface assembly 100 proximal stack 1 1 . Similarly, second riser 70 has a central or longitudinal axis 71 , an upper end 72 coupled at platform 20, and a lower end 74 coupled to riser interface assembly 100 proximal stack 1 1 . In this embodiment, riser 70 has a smaller diameter than riser 60.

[0033] Floatation devices 82 are coupled to each riser 60, 70. Floatation device 82 are suitable for subsea installation and may include, for example, high density foam capable of withstanding the high hydrostatic pressures experienced near the depth of well head 12 or stack 1 1 . Floatation devices 82 also act as thermal insulators for risers 60, 70. In Figure 1 , the floatation device 82 on each riser 60, 70 includes a plurality of axially spaced sections or individual flotation devices disposed along the corresponding riser 6 70. In a typical embodiment, between 90 and 98% of the length of riser 60, for example, is covered by floatation devices 82. In some other embodiments, more or less of the length of the riser is covered by floatation devices 82. In some embodiments, floatation devices 82 are installed only on the first riser 60 or only on the second riser 70.

[0034] Riser interface assembly 100 is positioned subsea immediately adjacent to the upper end of stack 1 1 . A plurality of couplings 84 connect riser interface assembly 100 to lower end 64 of riser 60, to lower end 74 of riser 70, and to the upper end of stack 1 1 (i.e., the flex joint of LMRP 15). In this embodiment, each coupling 84 is a flange joint, however, in other embodiments, other types of connections know in the art for connecting two tubulars can be used including, without limitation, threaded connections, quick-connect fittings, etc. Riser interface assembly 100 provide access for fluid communication and tool transfer between risers 60, 70 and wellbore 19 via stack 1 1 1 . Thus, interface assembly 100 couples both risers 60, 70 to wellbore 19. In some embodiments, assembly 100 provides simultaneous fluid communication between riser 60, riser 70, and wellbore 19.

[0035] During operations, elongate risers 60, 70 may sway, bend, flex, and vibrate in response to ocean currents, movement of platform 20, etc. To prevent risers 60, 70 from impacting and potentially damaging each other when they move relative to each other, a plurality of axially or vertically spaced riser spacer assemblies 150 are provided between risers 60, 70 to maintain the separation between risers 60, 70. An embodiment of a riser spacer assembly 150 is shown in enlarged section 1 -1 of

Figure 1 . In this embodiment, riser spacer assembly 150 is mounted to riser 70 and extends radially outward therefrom. In general, the plurality of axially spaced riser spacer assemblies 150 can be mounted along riser 70, riser 60, or both risers 60,

70. Riser spacer assembly 150 will be described in more detail below.

[0036] BOP 14, LMRP 15, wellhead 12, and conductor 18 are arranged such that each shares a common central axis 25. In other words, BOP 14, LMRP 15, wellhead

12, and conductor 18 are coaxially aligned. In addition, BOP 14, LMRP 15, wellhead

12, and conductor 18 are vertically stacked one-above-the-other, and the position of platform 20 is controlled such that axis 25 is remains in a vertically or substantially vertically orientation. In general, platform 20 can be maintained in position over stack 1 1 with mooring lines and/or a dynamic positioning (DP) system. However, it should be appreciated that platform 20 moves to a limited degree during normal drilling and/or production operations in response to external loads such as wind, waves, currents, etc. Such movements of platform 20 result in upper end 62 of riser

60, which is secured to platform 20, moving relative to the lower end 64 of riser 60, which is secured to LMRP 15. Similarly, the upper end 72 of riser 70 moves relative to the lower end 74 of riser 70. Wellhead 12, BOP 14 and LMRP 15 are generally fixed in position at the sea floor 13, and thus, each riser 60, 70 may flex and pivot about its lower end 64, 74 as platform 20 moves at the surface 17. Consequently, although risers 60, 70 is shown as extending vertically from platform 20 to LMRP 15 in Figure 1 , it should be appreciated that risers 60 70 may deviate somewhat from vertical as platform 20 moves at the surface 17.

[0037] Referring now to Figure 2, riser interface assembly 100 includes a first tubular member 1 10 and a second tubular member extending from first tubular member 1 10. First tubular member 1 10 has a linear, vertical central axis 1 1 1 and second tubular member 120 has a linear central axis 121 oriented at an acute angle 128 with respect to axis 1 1 1 . First tubular member 1 10 includes an upper end 1 12 having a connector 1 13 and a lower end 1 14 having a connector 1 16. Second tubular member 120 includes an upper end 122 having a connector 123, and a lower end 124 intersecting tubular member 1 10 between ends 1 12, 1 14, thereby providing access for fluid communication and tool transfer between tubular members 1 10, 120. In this embodiment, connector 123 is vertically spaced below connector 1 13 by a vertical off-set distance 129 to allow upper ends 1 12, 122 to be horizontally closer while accommodating the size (e.g., the diameter) of the connectors 1 13, 123 without interference, as may occur in some embodiments. A valve 130 is disposed along tubular member 120 to selectively control fluid communication and access between members 1 10, 120.

[0038] Referring now to both Figures 1 and 2, first tubular member 1 10 extends from lower end 64 of riser 60 to LMRP 15, and second tubular member 120 extends from lower end 74 of riser 70 to first tubular member 1 10. The angle 128 is selected to accommodate the passage of tools from tubular member 120 through tubular member 1 10 into stack 1 1 1 , and to accommodate the extraction of the tool back through tubular member 120. In embodiments described herein, acute angle 128 is preferably less than 10° and is more preferably between 1 ° and 4°. On interface assembly 100, upper end 1 12 defines or functions as a first, upper port for fluid communication and tool transfer with riser 60; lower end 1 14 defines or functions as a second, lower port for fluid communication and tool transfer with stack 1 1 1 and wellbore 18; upper end 122 defines and functions as a third, upper port for fluid communication and tool transfer with riser 70; and lower end 124 defines and functions as a fourth, internal port for fluid communication and tool transfer with first tubular member 1 10, stack 1 1 1 , and wellbore 18. Because lower end 124 merges with tubular member 1 10 as tubular member 120 extends toward lower end 1 14, lower end 1 14 defines or functions as a port for both tubular members 1 10, 120.

[0039] Connectors 1 13, 1 16, 123 define part of couplings 84. In particular, each connector 1 13, 1 16, 123 couples with a corresponding connector on lower end 64 of first riser 60, the upper end of LMRP 20, and lower end 74 of second riser 70, respectively, thereby forming a coupling 84 between each mating pair of connectors. As described above, although connectors 1 13, 1 16, 123 are shown as flanges. In other embodiments, one or more of the connectors 1 13, 1 16, 123 and its mating connector may be another connector known in the art, such as a threaded fitting or a quick-connect style fitting, as examples.

[0040] Referring now to Figure 3, one segment 70A of riser 70 and one riser spacer assembly 150 mounted thereto is shown. Riser segment 70A includes a tubular riser body 140 extending along axis 71 between upper and lower connectors 76, a plurality of circumferentially-spaced tubular conduits or pipes 142 disposed about body 140 and extending between connectors 76, and multiple floatation devices 82 mounted to the outside of pipes 142. Spacer assembly 150 extends circumferentially around riser body 140.

[0041] The various pipes 142 are circumferentially spaced about riser body 140 and have diameters that are smaller than the diameter of riser body 140. Pipes 142 pass-through connectors 76. Multiple, axially-spaced clamps 143 help to hold pipes 142 adjacent but radially off-set from riser body 140. Figure 3 includes four floatation devices 82A, 82B, 82C, 82D positioned around body 140 and pipes 142. Floatation devices 82A, 82B, 82C are fixably mounted to riser body 140, while floatation device 8D is slidingly coupled to riser body 140. Spacer assembly 150 is coupled to riser body 140 between floatation devices 82C, 82D. Other locations along axis 71 are possible for spacer assembly 150, including being adjacent one of the connectors 76. In this embodiment, floatation device 82D is slidably mounted to riser body 140 such that it can move axially along riser body 140 in response to actuation (extension and contraction) of spacer assembly 150.

[0042] Referring now to Figures 3 and 5, spacer assembly 150 includes a plurality of uniformly circumferentially-spaced spreader arms 156 disposed about body 140, a support ring 160 disposed about riser body 140 and coupled for axial movement with floatation device 82D, a plurality of support arms 162 coupled between ring 160 and arms 156, and webbing 164 extending between each pair of circumferentially adjacent arms 156. Webbing 164 is a flexible, resilient, elongate member suitable for use in the subsea environment. In this embodiment, webbing 164 includes a cable and a plurality of rollers strung on the cable between the cable and the distal end of each arm 156 to allow some limited relative movement between the cables and arms 156. Examples of suitable materials for webbing 164 include, without limitation, flexible strap material, cable, rope, chain, or actual webbing, having multiple ropes or cable cross-members interlinked. Webbing 164 may Nylon, Spectra®, or another fiber. The webbing material may include a flexible structural member covered by coating material or a soft sheath to reduce the potential for damaging floatation devices 82. In some other embodiments, webbing 164 includes a plurality of rigid or semi-rigid segments connected by bendable joints or flexible members, such a cable or rope, as examples.

[0043] Each spreader arm 156 has an upper end 157 pivotally coupled to riser body

140 and a lower end 158 opposite end 157. Although arms 156 can pivot relative to riser body 140 about upper ends 157, upper ends 157 cannot move translationally

(e.g., axially) relative to riser body 140. Webbing 164 extends between the lower ends 158 of each pair of circumferentially adjacent arms 156. As arms 156 pivot up and down relative to riser body 140 about upper ends 157, lower ends 158 rotate radially outward and upward relative to riser body 140 and lower ends 158 rotate radially inward and downward relative to riser body 140. In this embodiment, upper ends 157 of arms 156 are disposed at a common axial position along riser body 140.

An inner end 165 of each support arm 162 pivotally couples to ring 160 to move with ring 160, and an outer end 166 of each support arm 162 pivotally couples to one of the spreader arms 156 at a location between ends 156, 158.

[0044] As best shown in Figure 5, in this embodiment, spacer assembly 150 includes eight spreader arms 156 and eight support arms 162, having one support arm 162 aligned with each arm 156. Webbing 164 extends circumferentially around riser body 140. Spacer assembly 150 is configured such that an upward axial movement of ring 160 causes arms 162 to push distal ends 158 radially outward and axially upward relative to riser body 140, expanding and potentially applying a tension to webbing 164. Alternatively, downward axial movement of ring 160 causes arms 162 to pull on spreader arms 156 and webbing 164 radially inward and axially downward relative to riser body 140. When spreader arms 156 are positioned radially adjacent or proximal riser body 140, webbing 164 droops downward along the outside floatation device 82D positioned therebelow (e.g., gravity may keep webbing 164 adjacent or contacting device 82D with arms 164 rotated downward adjacent riser body 140). Thus, riser spacer assembly 150, arms 156, and webbing 164 may each be described as having a deployed or open position with distal ends 158 of arms 156 and webbing 164 coupled thereto extended radially outward away from riser body 140 at a diameter 152 (Figures 3 and 5), and a collapsed or closed position with distal ends 158 of arms 156 and webbing 164 coupled thereto retracted radially inward adjacent and proximal riser body 140 at a dimeter 153 (Figure 4). In the deployed position, spacer assembly 150 and webbing 164 restricts and/or prevents the laterally adjacent riser 60 from coming into direct contact with and impacting riser 70.

[0045] Floatation device 82D rises axially upward along body 140 to exert an axial, vertical force against ring 160 of spacer assembly 150, thereby transitioning spacer assembly 150 from the withdrawn position shown in Figure 4 to the deployed position shown in Figure 3, when riser segment 70A is lowered subsea. For example, device 82D may have sufficient buoyancy to rise upward along body 140 when lowered subsea, and such buoyancy maintains spacer assembly 150 in the open position while generally statically positioned subsea. However, floatation device 82D falls vertically downward along body 140 to exert an axial, downward force against ring 160 of spacer assembly 150, thereby transitioning spacer assembly 150 from the deployed position shown in Figure 3 to the withdrawn position shown in Figure 4, when riser segment 70A is removed from the sea. For example, the weight of device 82D may be sufficient to fall downward along body

140 when lifted from the sea as the buoyancy no longer generates an upward force, thereby pulling ring 160 and arms 156 downward toward riser body 140.

[0046] Spacer assembly 150 and device 82D are transported and stored in the collapsed position and device 82D in its lowermost position proximal connector 76.

In the storage position, the diameter 153 of spacer assembly 150 is substantially the same as the outer diameter of floatation devices 82, providing for relatively easy deployment from and retrieval to platform 20. For example, deployment and retrieval of riser segment 70A may require passing riser segment 70A through a hole or a moon pool in structure 20 having a smaller diameter than the expanded diameter contraction of spacer assembly 150 can be adjusted by mechanical or electrical features that sense and respond to the depth of floatation device 82 D or spacer assembly 150 in the water. As examples, in some embodiments, spacer assembly 150 may be configured to expand after device 82D is partially or fully submerged or after both spacer assembly 150 and device 82D are submerged.

[0047] Referring now to Figure 6, another embodiment of a marine riser assembly 50' is shown. Similar to assembly 50 previously described, riser assembly 50' extends subsea from platform 20 to a flex joint at the top of LMRP 15. In addition, riser assembly 50' provides multiple paths or passageways for fluid communication and tool transfer between platform 20 and stack 1 1 , thereby providing multiple paths for accessing wellbore 19.

[0048] In this embodiment, riser assembly 50' includes a first marine riser 60, a second marine riser 70 horizontally off-set from first marine riser 60, and a riser interface assembly 200 coupling risers 60, 70 to stack 1 1 . Risers 60, 70 are each as previously described. One or more spacer assemblies 150 can be mounted to one or both risers 60, 70.

[0049] Similar to interface assembly 100 previously described, interface assembly

200 facilitates fluid communication and tool transfer between each riser 60, 70 and wellbore 19 via stack 1 1 , thereby providing multiple paths for accessing wellbore 19.

In this embodiment, interface assembly 200 includes a body or base 202 and a gate

204 movably mounted to base 202 along a sliding interface 206. In addition, a first through passage or port 212 and a second through passage or port 222 are provided in gate 204, and through passage or port 214 is provided in base 202. Each port

212, 222 extends vertically from an upper surface 208 of gate 204 to interface 206, and port 214 extends vertically from a lower surface 210 of base 202 to interface

206. Ports 212, 222 in gate 204 are positioned and oriented to move into and out of alignment with port 214 in base 202 as gate 204 moves laterally relative to base 202.

When one port 212, 222 is aligned with and in fluid communication with port 214, the other port 212, 222 is closed off and sealed by base 202. Thus, assembly 200 is configured as a valve that is located between riser 60 and wellbore 19 and is located between riser 70 and wellbore 19. A tubular member or tubular connection conduit

212', 222', 214' extends from each port 212, 222, 214, respectively, and provides access and fluid communication thereto. In particular, conduit 212' extends upwardly from port 212 and gate 204, conduit 222' extends upwardly from port 222 and gate 204, and conduit 214' extends downwardly from port 214 and base 202. In other words, each conduit 212', 222' has a lower end fixably (e.g. rigidly) attached to gate 204 and an upper end distal gate 204, and conduit 214' has an upper end fixably attached to base 202 and a lower end distal base 202. The upper end of each conduit 212', 222' includes a connector 1 13, 123, respectively, for connecting the conduit 212', 222' to a corresponding riser 60, 70, respectively, and the lower end of conduit 214' includes a connector 1 16 for connecting the conduit 214' to the flex joint of LMRP 50. Each conduit 212', 222', 214' has a central axis 21 1 , 221 , 215, respectively, that is coaxially aligned with axis 61 , 71 , 25, respectively. In this embodiment, each connector 1 13, 123, 1 16 is a flange that is fixably secured to a mating flange at the corresponding end of riser 60, 70 and stack 1 1 , respectively.

[0050] Gate 204 can be selectively slide horizontally relative to base 202 between a first position with ports 212, 214 and associated conduits 212', 214' aligned and in fluid communication (Figure 6), and a second position with ports 222, 214 and associated conduits 222', 214' aligned and in fluid communication (Figure 7). In the first position, valve 200 is open for communication between ports 212, 214 and is closed with respect to port 222 and port 214. In the second position, valve 200 is open for communication between ports 222, 214 and is closed with respect to port 212 and port 214. In at least some embodiments, gate 204 is configured to achieve a third position in which both upper ports 212, 222 are equally space and on opposite sides of lower port 214, isolating all three ports 212, 222, 214 from fluid communication through valve 200, placing valve 200 in a fully closed position. Despite the movement of gate 204, conduits 212', 222' attached to gate 204, and the lower ends of risers 60, 70 attached to conduits 212', 222', base 202 and port 214 remain fixed relative to stack 1 1 , well head 12, and wellbore 19. Thus, in the first position shown in Figure 6, fluid and/or a tool string can pass through riser 60, conduit 212', upper port 212, conduit 214', lower port 214, and stack 1 1 into wellbore 19, while port 222, conduit 222', and its riser 70 are sealed and isolated from lower port 214, stack 1 1 , and wellbore 19; and in the second position shown in Figure 7, fluid and/or a tool string can pass through riser 70, conduit 222', upper port 222, conduit 214', lower port 214, and stack 1 1 into wellbore 19, while port 212, conduit 212', and its riser 60 are sealed and isolated from lower port 214, stack 1 1 , and wellbore 19. [0051] Considering another embodiment, Figure 8 presents a marine riser assembly 250 that may replace any of the riser assemblies 50, 50' discussed herein. Riser assembly 250 is similar to riser assembly 50. For example, riser assembly 250 includes first and second risers that are generally parallel and are coupled at their lower ends to a riser interface assembly 100 and separated by multiple riser spacer assemblies 150. More specifically, riser assembly 250 includes a first riser 60, a second riser 270, and a riser interface assembly 100 coupled to the lower ends of risers 60, 270. In addition, riser assembly 250 provides multiple paths or passageways for fluid communication and tool transfer between platform 20 and stack 1 1 , thereby providing multiple paths for accessing wellbore 19.

[0052] First riser 60 is as previously described. For example, first riser 60 includes multiple riser segments 60A that include or are coupled to multiple floatation devices 82. Second riser 270 is similar to second riser 70; however, second riser 270 includes multiple riser segments 270A that lack floatation devices. Another difference of riser assembly 250 is that the riser spacer assemblies 150 are mounted to the first riser 60 rather than to the second riser 270. The coupling of a riser spacer assemble 150 to the riser segments of riser 60 is as previously described. The riser spacer assemblies 150 are configured to maintain a separation distance between risers 60, 270. In other embodiments, riser assembly 250 includes a riser interface assembly 200 (as previously described and shown in Figures 6 and 7 in place of riser interface assembly 100. Some embodiments of riser assembly 250 have insulation on second riser 270 as well as on riser 60.

[0053] In the manner described, embodiments disclosed herein include multiple risers 60, 70 that extend from platform 20 to an interface assembly 100, 200 secured to BOP stack 1 1 . The interface assemblies 100, 200 provide selective access to the wellbore 19 for each riser 60, 70 via the BOP stack 1 1 . Multiple risers 60, 70 can leverage the capabilities of dual activity vessels such that a string (e.g., drill string, tool string, etc.) can be tripped from the wellbore 19 through one riser 60, 70 while a second string is deployed and stage in the other riser 60, 70. Since the lower ends 64, 74 of both risers 60, 70 are proximal BOP stack 1 1 , the second string can be deployed and positioned proximal BOP stack 1 1 , while the first string is being tripped from the wellbore 19 and BOP 1 1 . Once the first string is completely removed from the wellbore 19 and BOP 1 1 into its corresponding riser 60, 70, the second string can immediately be lowered through its corresponding riser 60, 70. The ability to simultaneously trip the first string and deploy the second string offers the potential to save the time that would otherwise be required to completely remove the first string to the surface (i.e., completely remove from the riser) before beginning deployment of the second string.

[0054] Referring now to Figure 9, an embodiment of a method 300 for using a riser assembly 50, 50', 250 is shown. Beginning in block 302, method 300 includes deploying a first string through a first marine riser of the marine riser assembly and into the wellbore. At block 304, method 300 includes performing a first operation in the wellbore with the first string. Block 306 includes removing the first string from the wellbore and into the first marine riser. Block 308 includes removing the first string from the first marine riser to the surface vessel after block 306. Block 310 includes positioning a second string in a second marine riser of the marine riser assembly during block 304 or block 306, wherein the first marine riser and the second marine riser are laterally spaced apart. Block 312 includes deploying the second string from the second marine riser and into the wellbore after block 306 and block 310 but before block 308. Block 314 includes opening a valve positioned between the second riser and the wellbore after block 306 and block 310 but before block 308. In various embodiments, method 300 the marine riser assembly further comprises a riser interface assembly including a first tubular member and a second tubular member extending from the first tubular member. The first tubular member is positioned between the first marine riser and the wellbore. The second tubular member is positioned between the first tubular member and the second marine riser. The first tubular member is configured to provide fluid communication between the first marine riser and the wellbore, and the second tubular member is configured to provide fluid communication between the second marine riser and the first tubular member. The valve is positioned along the second tubular member.

[0055] In some embodiments of method 300, opening the valve comprises sliding the lower ends of first and second marine risers horizontally relative to the wellbore.

[0056] In various embodiments, method 300 includes moving a gate, such as gate 22, in a first direction relative to a valve, such as base 202, to transition from a first position wherein the first riser is in fluid communication with the wellbore and a second position wherein the second riser is in fluid communication with the wellbore. In some embodiments, moving the gate in the first direction comprises moving the first and second risers relative to the wellbore.

[0057] Although method 300 is described in connection with riser assembly 50, it can also be used in connection with riser assembly 50'. In general, the operation of riser assembly 50' and corresponding interface assembly 200 (Figure 6 and Figure 7) is similar to the operation of riser assembly 50 and corresponding interface assembly 100 with the exception that gate 204 is actuated to provide selective access to wellbore 19 from each riser 60, 70. In contrast, the permanent intersection of tubular member 1 10 and the end 124 of tubular member 120 along with a dedicated valve 130 may allow simultaneous fluid communication between both riser 60, 70 and wellbore 19 provided valve 130 is opened.

[0058] Although riser interface assembly 100 was shown as having a valve 130 imbedded within tubular member 120, in some embodiments, valve 130 is instead a coupled between connector 124 and second riser 70.

[0059] In Figure 3, spacer assembly 150 is shown with spreader arms 156 pivotally attached to riser body 140 and extending downward, and the inner end 165 of support arm 162 pivotally couples to the sliding support ring 160. In some embodiments, the "umbrella" structure of spacer assembly 150 is turned upside- down and the attachments are reversed. In these embodiments, support arm 162 is located above the inner, pivot ends 157 of the spreader arms 156, and inner end 165 of support arm 162 pivotally couples to riser body 140. The pivot ends 157 of arms 156 are pivotally attached to sliding support ring 160, which is again coupled to a flotation device 82 below it. Alternatively, with cables, floatation device 82 of various embodiments may be located axially above spacer assembly 150 and connected to ring 160 by a cable. This arrangement would allow spacer assembly 150 to be submerged or partially submerged before the floatation device experienced buoyancy and began to open the spreader.

[0060] Referring to Figures 3-5, although spacer assembly 150 was described as having one support arms 162 for each spreader arms 156, some embodiments may include multiple support arms 162 for each spreader arms 156. Or, the spreader arm 156 may be jointed configuring it to fold. So too, in some embodiments, each spreader arm 156 of Figures 3-5 may be replaced by multiple spreader arms or by a jointed spreader arm.

[0061] [0062] Having described above various aspects of riser assemblies, spacer assemblies, and methods for performing downhole operations from a surface vessel, various additional features may include, but are not limited to the following:

[0063] In a first aspect, a marine riser assembly may comprise a first riser having an upper end coupled to a floating offshore structure and a lower end disposed subsea. In addition, the marine riser assembly may comprise a second riser having an upper end coupled to the floating offshore structure and a lower end disposed subsea. Further, the marine riser assembly may comprises a riser interface assembly coupled to a subsea blowout preventer, the lower end of the first riser, and the lower end of the second riser. The subsea blowout preventer is disposed at an upper end of a subsea wellbore. The first riser and the riser interface assembly are configured to provide access to the wellbore through the subsea blowout preventer. The second riser and the riser interface are configured to provide access to the wellbore through the subsea blowout preventer.

[0064] A second aspect can include the marine riser assembly of the first aspect, wherein the first riser is in fluid communication with the wellbore through the riser interface assembly and the blowout preventer, and wherein the second riser is in selective fluid communication with the wellbore through the riser interface assembly and the subsea blowout preventer.

[0065] A third aspect can include the marine riser assembly of the first or second aspect, wherein the riser interface assembly comprises a first tubular member having an upper end and a lower end. THe riser interface assembly may also comprises a second tubular member having an upper end and a lower end. The lower end of the second tubular member is coupled to the first tubular member between the upper end and the lower end of the first tubular member. The second tubular member is in fluid communication with the first tubular member.

[0066] A fourth aspect can include the marine riser assembly of any of the first to third aspects, wherein the first tubular member has a central axis and the second tubular member has a central axis, and wherein the central axis of the second tubular member at the lower end of the second tubular member is oriented at an acute angle relative to the central axis of the first tubular.

[0067] A fifth aspect can include the marine riser assembly of any of the first to fourth aspects, wherein the riser interface assembly has a first position with the first riser in fluid communication with the blowout preventer and a second position with the first riser isolated from the blowout preventer, and wherein the second riser is isolated from the blowout preventer with the riser interface assembly in the first position and is in fluid communication with the blowout preventer with the riser interface assembly in the second position.

[0068] A sixth aspect can include the marine riser assembly of any of the first to fifth aspects, wherein the riser interface assembly includes a body and a gate movably coupled to the body, wherein the gate is configured to move relative to the body to transition the riser interface assembly between the first position and the second position.

[0069] A seventh aspect can include the marine riser assembly of any of the first to sixth aspects, further comprising a spacer assembly disposed about and coupled to the first riser. The spacer assembly is configured to radially expand between a collapsed position and a deployed position.

[0070] An eight aspect can include the marine riser assembly of any of the first to seventh aspects, wherein the spacer assembly comprises a plurality of spreader arms, wherein each spreader arm has a first end pivotally coupled to the first riser and a second end opposite the first end. In addition, the spacer assembly may comprise a plurality of support arms. Each support arm has a first end pivotally coupled to the first riser and a second end pivotally coupled to one of the spreader arms. Further, the spacer assembly may comprise a webbing coupled to the second ends of the spreader arms and extending circumferentially around the first riser.

[0071] A ninth aspect can include the marine riser assembly of any of the first to eight aspects, wherein the spacer assembly further comprises a support ring extending circumferentially about the first riser and configured to slide axially along the first riser. The support ring is pivotally coupled to the first ends of the support arms.

[0072] In a tenth aspect, a method for performing downhole operations from a surface vessel with a marine riser assembly extending from the surface vessel to a subsea blowout preventer (BOP) stack comprises (a) deploying a first string through a first marine riser of the marine riser assembly and into the wellbore. In addition, the method comprises (b) performing a first operation in the wellbore with the first string. Further, the method comprises (c) removing the first string from the wellbore and into the first marine riser. Still further, the method comprises (d) removing the first string from the first marine riser to the surface vessel after (c). Moreover, the method comprises (e) positioning a second string in a second marine riser of the marine riser assembly during (a), (b), or (c). The first marine riser and the second marine riser are laterally spaced apart. The method also comprises (f) deploying the second string from the second marine riser and into the wellbore after (c) and (e) but before (d).

[0073] An eleventh aspect can include the method of the tenth aspect, further comprising opening a valve positioned between the second riser and the wellbore after (c) and (e) and before (d).

[0074] A twelfth aspect can include the method of the tenth or eleventh aspect, wherein the marine riser assembly further comprises a riser interface assembly including a first tubular member and a second tubular member extending from the first tubular member. The first tubular member is positioned between the first marine riser and the wellbore. The second tubular member is positioned between the first tubular member and the second marine riser. The first tubular member is configured to provide fluid communication between the first marine riser and the wellbore. The second tubular member is configured to provide fluid communication between the second marine riser and the first tubular member. The valve is positioned along the second tubular member.

[0075] A thirteenth aspect can include the method of any of the tenth to twelfth aspects, wherein opening the valve comprises moving the lower ends of first marine riser and the second marine riser horizontally relative to the wellbore.

[0076] A fourteenth aspect can include the method of any of the tenth to thirteenth aspects, further comprising moving a gate relative to a valve body to transition from a first position with the first riser in fluid communication with the wellbore and a second position with the second riser is in fluid communication with the wellbore.

[0077] A fifteenth aspect can include the method of any of the tenth to fourteenth aspects, wherein moving the gate comprises moving the first riser and the second riser relative to the wellbore.

[0078] In a sixteenth aspect, a marine riser assembly comprises a first riser having an upper end coupled to a floating offshore structure and a lower end disposed subsea. In addition, the marine riser assembly may include a second riser having an upper end coupled to the floating offshore structure and a lower end disposed subsea. The second riser is laterally offset from the first riser. Further, the marine riser assembly may include a spacer assembly disposed about the first riser and configured to prevent the second riser from laterally impacting the first riser. The spacer assembly is configured to radially expand between a collapsed position and a deployed position.

[0079] A seventeenth aspect can include the marine riser assembly of the sixteenth aspect, wherein the spacer assembly comprises a plurality of spreader arms. Each spreader arm has a first end pivotally coupled to the first riser and a second end opposite the first end. In addition, the spacer assembly may comprises a plurality of support arms, each support arm having a first end pivotally coupled to the first riser and a second end pivotally coupled to one of the spreader arms. Further, the spacer assembly may comprise a webbing coupled to the second ends of the spreader arms and extending circumferentially around the first riser.

[0080] A eighteenth aspect can include the marine riser assembly of the sixteenth or seventeenth aspect, further comprising a riser interface assembly coupling the lower end of the first riser and the lower end of the second riser to a subsea blowout preventer. The subsea blowout preventer is disposed at an upper end of a subsea wellbore. The riser interface assembly and the first riser are configured to provide access to the wellbore through the subsea blowout preventer. The riser interface assembly and the second riser are configured to provide access to the wellbore through the riser interface assembly and the subsea blowout preventer.

[0081] While exemplary embodiments have been shown and described, modifications thereof can be made by one of ordinary skill in the art without departing from the scope or teachings herein. The embodiments described herein are exemplary only and are not limiting. Many variations, combinations, and modifications of the systems, apparatuses, and processes described herein are possible and are within the scope of the disclosure. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims. The inclusion of any particular method step or operation within the written description or a figure does not necessarily mean that the particular step or operation is necessary to the method. The steps or operations of a method listed in the specification or the claims may be performed in any feasible order, except for those particular steps or operations, if any, for which a sequence is expressly stated. In some implementations two or more of the method steps or operations may be performed in parallel, rather than serially. The recitation of identifiers such as (a), (b), (c); (1 ), (2), (3); etc. before operations in a method claim are not intended to and do not specify a particular order to the operations, but rather are used to simplify subsequent reference to such operations.

Claims

CLAIMS What is claimed is:

1 . A marine riser assembly, comprising:

a first riser having an upper end coupled to a floating offshore structure and a lower end disposed subsea;

a second riser having an upper end coupled to the floating offshore structure and a lower end disposed subsea; and

a riser interface assembly coupled to a subsea blowout preventer, the lower end of the first riser, and the lower end of the second riser, wherein the subsea blowout preventer is disposed at an upper end of a subsea wellbore;

wherein the first riser and the riser interface assembly are configured to provide access to the wellbore through the subsea blowout preventer; wherein the second riser and the riser interface are configured to provide access to the wellbore through the subsea blowout preventer.

2. The marine riser assembly of claim 1 , wherein the first riser is in fluid communication with the wellbore through the riser interface assembly and the blowout preventer;

wherein the second riser is in selective fluid communication with the wellbore through the riser interface assembly and the subsea blowout preventer.

3. The marine riser assembly of claim 1 , wherein the riser interface assembly comprises:

a first tubular member having an upper end and a lower end; and

a second tubular member having an upper end and a lower end, wherein the lower end of the second tubular member is coupled to the first tubular member between the upper end and the lower end of the first tubular member;

wherein the second tubular member is in fluid communication with the first tubular member.

4. The marine riser assembly of claim 3, wherein the first tubular member has a central axis and the second tubular member has a central axis; wherein the central axis of the second tubular member at the lower end of the second tubular member is oriented at an acute angle relative to the central axis of the first tubular.

5. The marine riser assembly of claim 1 , wherein the riser interface assembly has a first position with the first riser in fluid communication with the blowout preventer and a second position with the first riser isolated from the blowout preventer;

wherein the second riser is isolated from the blowout preventer with the riser interface assembly in the first position and is in fluid communication with the blowout preventer with the riser interface assembly in the second position.

6. The marine riser assembly of claim 5, wherein the riser interface assembly includes a body and a gate movably coupled to the body, wherein the gate is configured to move relative to the body to transition the riser interface assembly between the first position and the second position.

7. The marine riser assembly of claim 1 , further comprising a spacer assembly disposed about and coupled to the first riser;

wherein the spacer assembly is configured to radially expand between a collapsed position and a deployed position.

8. The marine riser assembly of claim 7, wherein the spacer assembly comprises:

a plurality of spreader arms, wherein each spreader arm has a first end pivotally coupled to the first riser and a second end opposite the first end;

a plurality of support arms, wherein each support arm has a first end pivotally coupled to the first riser and a second end pivotally coupled to one of the spreader arms;

a webbing coupled to the second ends of the spreader arms and extending circumferentially around the first riser.

9. The marine riser assembly of claim 7, wherein the spacer assembly further comprises:

a support ring extending circumferentially about the first riser and configured to slide axially along the first riser;

wherein the support ring is pivotally coupled to the first ends of the support arms.

10. A method for performing downhole operations from a surface vessel with a marine riser assembly extending from the surface vessel to a subsea blowout preventer (BOP) stack, the method comprising:

(a) deploying a first string through a first marine riser of the marine riser assembly and into the wellbore;

(b) performing a first operation in the wellbore with the first string;

(c) removing the first string from the wellbore and into the first marine riser;

(d) removing the first string from the first marine riser to the surface vessel after (c);

(e) positioning a second string in a second marine riser of the marine riser assembly during (a), (b), or (c), wherein the first marine riser and the second marine riser are laterally spaced apart; and

(f) deploying the second string from the second marine riser and into the wellbore after (c) and (e) but before (d).

1 1 . The method of claim 10, further comprising opening a valve positioned between the second riser and the wellbore after (c) and (e) and before (d).

12. The method of claim 1 1 , wherein the marine riser assembly further comprises a riser interface assembly including a first tubular member and a second tubular member extending from the first tubular member, wherein the first tubular member is positioned between the first marine riser and the wellbore, wherein the second tubular member is positioned between the first tubular member and the second marine riser, wherein the first tubular member is configured to provide fluid communication between the first marine riser and the wellbore, and wherein the second tubular member is configured to provide fluid communication between the second marine riser and the first tubular member wherein the valve is positioned along the second tubular member.

13. The method of claim 1 1 , wherein opening the valve comprises moving the lower ends of first marine riser and the second marine riser horizontally relative to the wellbore.

14. The method of claim 10, further comprising moving a gate relative to a valve body to transition from a first position with the first riser in fluid communication with the wellbore and a second position with the second riser is in fluid communication with the wellbore.

15. The method of claim 14, wherein moving the gate comprises moving the first riser and the second riser relative to the wellbore.

16. A marine riser assembly, comprising:

a second riser having an upper end coupled to the floating offshore structure and a lower end disposed subsea, wherein the second riser is laterally offset from the first riser; and

a spacer assembly disposed about the first riser and configured to prevent the second riser from laterally impacting the first riser;

17. The marine riser assembly of claim 16, wherein the spacer assembly comprises:

a plurality of support arms, each support arm having a first end pivotally coupled to the first riser and a second end pivotally coupled to one of the spreader arms; a webbing coupled to the second ends of the spreader arms and extending circumferentially around the first riser

18. The marine riser assembly of claim 16, further comprising a riser interface assembly coupling the lower end of the first riser and the lower end of the second riser to a subsea blowout preventer, wherein the subsea blowout preventer is disposed at an upper end of a subsea wellbore;

wherein the riser interface assembly and the first riser are configured to provide access to the wellbore through the subsea blowout preventer;

wherein the riser interface assembly and the second riser are configured to provide access to the wellbore through the riser interface assembly and the subsea blowout preventer.