Patent Publication Number: US-11021216-B2

Title: Mooring line corrosion barrier and methods of manufacture and installation

Description:
CROSS-REFERENCE TO RELATED APPLICATION 
     This application claims the benefit of U.S. Provisional Patent Application 62/808,085 filed Feb. 20, 2019 entitled MOORING LINE CORROSION BARRIER AND METHODS OF MANUFACTURE AND INSTALLATION, the entirety of which is incorporated by reference herein. 
    
    
     FIELD OF THE INVENTION 
     Described herein are methods and systems for protecting a mooring line from corrosion, and methods and systems for manufacturing and installing such corrosion barriers on a mooring line. 
     BACKGROUND 
     In traditional offshore operations, the use of chains, wire ropes, or synthetic ropes for mooring lines is desirable. Mooring lines offer flexibility to the floating structure, allowing the structure to move in response to waves, winds, and currents. Mooring lines must be able to withstand large tensile loads, be compliant, and should have a relatively long fatigue life despite repeated cycles of stress and relaxation. 
     Mooring lines in marine environments can be susceptible to corrosion due to the reaction of the salt water and air with the metal in the mooring line. As described in U.S. Pat. No. 4,123,338, coatings, such as thermally sprayed aluminum coatings, have been applied to mooring lines in attempts to protect the mooring line from corrosion. However, existing sprayed coatings often have poor durability during transport and installation of the mooring line. 
     Additionally, corrosion rates for the location where the mooring line is to be used are often not well understood before the mooring line is installed. As such, it can be difficult to design and predict the corrosion allowance for a mooring line. If a mooring line experiences higher corrosion rates than anticipated (i.e., greater than the corrosion allowance), there are few means of remediation other than to change out the corroded portion of the mooring line. 
     Therefore, there remains a need for mooring lines having improved corrosion resistance. In particular, there remains a need for methods and systems that can be implemented at the time of the mooring line&#39;s manufacture as well as methods and systems that can be implemented after installation of the mooring line in the marine environment. It would also be desirable to have methods and systems that allow for maintenance and inspection of the mooring line. 
     Additional background references may include: U.S. Pat. Nos. 4,285,615 A, 4,756,267 A, 6,899,492 B1, 7,188,579 B2, and 8,978,532 B2; U.S. Patent Application Publication No. 2013/0152839 A1; PCT Publication No. WO 2014/049034; and Ma et al., “Life Extension of Mooring System for Benchamas Explorer FSO”, Proceedings of the 19 th  Offshore Symposium, Texas Section of the Society of Naval Architects and Marine Engineers, Houston, Tex., p. 1-14, February 2014. 
     SUMMARY 
     Described herein are mooring systems for floating structures. The mooring system may comprise a line having a first end operatively connected to the floating structure and a second end operatively connected to an anchor underwater or to a seabed, wherein the line comprises at least two substantially rigid links joined together; and a watertight sheath surrounding the line and extending at least along a length of the line from a position below the waterline to a position above the waterline. 
     Also described herein are methods for installing a corrosion barrier around a mooring fine. For example, the method may comprise providing two or more substantially rigid links joined together, wherein the rigid links are hanging in a substantially vertical orientation; providing a sheath that comprises a hinged caisson and a hook to close the caisson; encircling the rigid links with the sheath and closing the caisson, wherein an annular space is formed between the sheath and the rigid links; sealing the bottom end of the sheath; and filling the annular space with a filler material. As another example, the method may provide for encasing at least a portion of a mooring line in a marine environment, and may comprise providing a floating structure in a marine environment; providing a mooring line, wherein the mooring line has a first end that is operatively connected to the floating structure and a second end that is operatively connected to an anchor under the waterline, wherein the mooring line comprises at least two substantially rigid links joined together; providing a corrosion barrier that comprises a hinged caisson and means for closing and sealing the caisson; encircling the rigid links with the caisson, wherein an annular space is formed between the caisson and the rigid links; sealing the bottom end of the corrosion barrier; and filling the annular space with a filler material. 
     In one or more embodiments, the methods described herein may be used to retrofit an existing mooring line. For example, the methods may comprise identifying a length of a mooring line that exhibits degradation; and encasing the length of the line that exhibits the degradation with the corrosion barriers described herein. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       Advantages of the present methodologies and techniques may become apparent upon reviewing the following detailed description and accompanying drawings. 
         FIGS. 1A and 1B  illustrate an example of a mooring chain connected to an offshore floating structure. 
         FIG. 2  is illustrates a cross-section of a mooring chain. 
         FIGS. 3A and 3B  illustrate an exemplary method of installing a barrier around the mooring chain. 
         FIGS. 4A and 4B  illustrate exemplary mooring chains with a single piece barrier in  FIG. 4A  and modular barriers in  FIG. 4B . 
         FIG. 4C  illustrates an H-connector with a cylindrical cross-section. 
         FIG. 5  illustrates an exemplary method of installing a barrier around an in-situ mooring chain. 
     
    
    
     DETAILED DESCRIPTION OF THE DISCLOSURE 
     To the extent the following description is specific to a particular embodiment or a particular use, this is intended to be illustrative only and is not to be construed as limiting the scope of the invention. On the contrary, it is intended to cover all alternatives, modifications, and equivalents that may be included within the spirit and scope of the invention. 
     Example methods described herein may be better appreciated with reference to flow diagrams. While for purposes of simplicity of explanation, the illustrated methodologies are shown and described as a series of blocks, it is to be appreciated that the methodologies are not limited by the order of the blocks, as some blocks can occur in different orders and/or concurrently with other blocks from that shown and described. Moreover, less than all the illustrated blocks may be required to implement various embodiments of an example methodology. Blocks may be combined or separated into multiple components. Furthermore, additional and/or alternative methodologies can employ additional blocks not shown herein. While the figures illustrate various actions occurring serially, it is to be appreciated that various actions could occur in series, substantially in parallel, and/or at substantially different points in time. 
     Various terms as used herein are defined below. To the extent a term used in a claim is not defined below, it should be given the broadest possible definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent. 
     The term “arctic” refers to any oceanographic region wherein ice features may form or traverse through. 
     The term “fluid” refers to gases, liquids, and combinations of gases and liquids. In some embodiments, the term “fluid” may also refer to combinations of gases and solids and/or combinations of liquids and solids. 
     The term “hydrocarbons” refers to molecules formed primarily of hydrogen and carbon atoms, such as oil and natural gas. Hydrocarbons may also include trace amounts of other elements or compounds, such as halogens, metallic elements, nitrogen, oxygen, sulfur, hydrogen sulfide (H 2 S), and carbon dioxide (CO 2 ). Hydrocarbons may be produced from hydrocarbon reservoirs through wells penetrating a hydrocarbon containing formation. Hydrocarbons derived from a hydrocarbon reservoir may include, but are not limited to, petroleum, kerogen, bitumen, pyrobitumen, asphaltenes, tars, oils, natural gas, or combinations thereof. Hydrocarbons may be located within or adjacent to mineral matrices within the earth, termed reservoirs. Matrices may include, but are not limited to, sedimentary rock, sands, silicates, carbonates, diatoms, and other porous media. 
     The term “ice sheet” refers to a floating an moving mass of ice, floe ice, or ice field. The term also encompasses pressure ridges of ice within ice sheets. 
     The term “marine environment” refers to any offshore location. The offshore location may be in shallow waters or deep waters. The marine environment may be an ocean body, a bay, a large lake, an estuary, a sea, or a channel. 
     The term “mooring line” encompasses any line used in the marine field for the control of loads to which it is attached. 
     The term “platform” refers to a deck on which offshore operations, such as drilling operations, take place. The term may also encompass any connected supporting floating structure. 
     The term “seabed” refers to the floor of a marine body. The marine body may be an ocean or sea or any other body of water that experiences waves, winds, and/or currents. 
     The term “subsurface” refers to geological strata occurring below the earth&#39;s surface. 
     The present disclosure provides improved methods and systems for mooring offshore floating oil/gas production platforms or other marine vessels. Mooring lines used to moor offshore floating structures in marine environments can be susceptible to loss of strength (and ultimately failure) due to corrosion. The presently described methods and systems provide improved mooring systems that are designed to prevent or lessen corrosion formation on mooring lines. Further, the methods and systems described herein may be used to retro-fit existing mooring lines that have experienced corrosion degradation. 
     The area of a mooring chain that is likely to see the highest rates of corrosion are in the splash zone where water, air, and the metal material in the mooring line are in contact with one another.  FIG. 1A  presents an illustration  100  of a moored floating structure  102  floating in a marine environment. The floating structure may be any type of floating structure or vessel, such as an FPSO, FLNG, semi-submersible, SPAR, deep-draft caisson vessel, or any vessel that utilizes catenary anchored legged mooring. The floating structure  102  may be anchored to the seafloor by a mooring line  104 . The waterline  106  of the marine environment intersects the moored floating structure  102  and the mooring line  104 . As the waterline  106  moves up and down due to wind, waves, and current, the area of intersection of the mooring line  104  and the waterline  106  may be varied, and this area may be referred to as the splash zone  108 . As seen in  FIG. 1B  a corrosion barrier  110  may be installed around the mooring line  104  to minimize and/or prevent contact between the mooring line  104  and the corrosive environment (i.e., the environment the comprises both air and water) in the splash zone  108 . In one or more embodiments, the top surface of the corrosion barrier  110  may be angled, rounded, or domed to promote water run-off. For example, the top surface of the corrosion barrier may be slanted or be hemispherical in order to prevent rain water from pooling on the top surface. 
       FIG. 2  illustrates a cross-section  200  of the mooring line and the corrosion barrier. As seen in  FIG. 2 , the links of the mooring line  202   a  and  202   b  are encapsulated with a corrosion barrier  208 . The annular space  206  between the mooring line and the exterior  208  of the corrosion barrier can be filled with a filler material. 
     The mooring line may comprise a plurality of rigid links, such as chain links, and may be formed from a metal or metal alloy. For example, the mooring line may comprise metal chain links formed out of steel. The steel alloy may comprise one or more of aluminum, NB, vanadium, titanium, and/or molybdenum. In one or more embodiments, one or more of the plurality of rigid links may have a length that is greater than 24 inches, or greater than 30 inches, or greater than 32 inches, or greater than 34 inches. In one or more embodiments, one or more of the plurality of rigid links may have a diameter that is greater than 4 inches, or greater than 5 inches, or greater than 6 inches. In one or more embodiments, one or more of the rigid links may have a weight of greater than 100 kg/link, or greater than 150 kg/link, or greater than 200 kg/link. 
     The corrosion barrier may comprise a sheath. The sheath may extend along the splash zone of the mooring line. For example, the sheath may extend along the length of the mooring line where both water and air interface the mooring line. For example, in one or more embodiments, the sheath may extend along the length of the mooring line from the deck of the floating structure to a depth of at least 15 meters, or at least 30 meters, or at least 45 meters below the water line. 
     In one or more embodiments, a sheath surrounds the circumference of one or more of the rigid links that form the mooring line. In some embodiments, the sheath may directly abut the rigid links of the mooring line. The sheath is preferably fluid tight and prevents or minimizes the contact of water and air with the encapsulated rigid links. The sheath may be cylindrically shaped or may conform to the shape of the mooring line. 
     The sheath may be comprised of any suitable material. Preferably, the sheath is corrosion resistant, seawater resistant, and/or UV resistant. Preferably, the sheath is also temperature resistant and can withstand the varied temperatures experienced in a marine environment. For example, the watertight sheath may comprise a material that is resistant to degradation over a range of temperatures, such as from −10° C. to 40° C., or from 0° C. to 40° C., or from 0° C. to 30° C., or from 0° C. to 25° C., or from 0° C. to 20° C. 
     In one or more embodiments, the sheath may comprise a polymeric material, such as a polyolefin (such as polypropylene or polyethylene), rubber, epoxy, polyamide, polyester, polyurethane, ABS, polyvinyl, or polyether. The sheath may also comprise additives of one or more different materials that aid in UV resistance, seawater resistance, and/or temperature resistance. 
     In one or more embodiments (such as that shown in  FIG. 2 ), a filler may be positioned between the sheath and the mooring line. The filler may be comprised of any suitable material and may be a solid or a liquid. For example, the filler may comprise a material that enters the sheath as a liquid and hardens over time, or may comprise a material that remains in a viscous liquid phase. For example, the filler may comprise an epoxy or an injection filler. For example, the filler may comprise a poly-dicylcopentadiene filler. In some embodiments, the filler may comprise a buoyant material, that is, the filler may comprise a material that has a density (and thus specific gravity) less than that of seawater. 
     In one or more embodiments, the corrosion barriers described herein may be placed around the rigid links of the mooring line before the mooring line is placed in the marine environment. For example, the corrosion barrier may be installed around mooring line chain links in an on-shore fabrication yard.  FIG. 3A  illustrates an example of an on-shore installation. One or more chain links of a mooring line  104  may be hung from a supportive beam  304  or otherwise raised off of the ground. The corrosion barrier  306  may then be placed around the mooring line  104 . 
     The corrosion barrier  306  may be comprised of two or more modular pieces  308 . The use of modular pieces may provide for easier installation and handling of the corrosion barrier. Further, the use of modular pieces can allow for the corrosion barrier to be composed of different materials along the length of the mooring line. For example, the modular pieces that encircle the chain links that are intended to be predominately below the water line may be comprised of a first material (for example, a material that provides improved resistance to salinity) and the module pieces that encircle the chain links that are intended to be predominately above the water line may be comprised of a second material (for example, a material that provides improved UV resistance). 
       FIG. 3B  illustrates a cross-section  320  of a corrosion barrier that comprises a hinged caisson. As seen in  FIG. 3B , the corrosion barrier may be hinged to provide for ease of installation. The corrosion barrier  306  may have a hinge  324  that allows the corrosion barrier to open and close  329  around the mooring chain links  326   a  and  326   b . The corrosion barrier may have a means  322  for closing or sealing the caisson  306 . For example, the corrosion barrier may have a hook or clasp that allows the caisson to close. 
     Thus, in one or more embodiments, the caisson may be opened and placed around hanging chain links to encircle the chain links of a mooring line  104 . As seen in  FIG. 4A , the corrosion barrier may comprise a single piece  306 . Alternatively, as seen in  FIG. 4B , the corrosion barrier may comprise modular pieces  308  that seal against one another. The modular pieces of the corrosion barrier may have telescoping connections that allow for filler to connect and/or flow between the modules. 
     The bottom end of the corrosion barrier may be sealed, for example a chain link  401  with a circular center member  405  as seen in  FIG. 4C  or with a gasketed clamped connection. After the bottom end of the corrosion barrier is sealed, the annular space between the corrosion barrier and the chain links may be filled with filler  328  (as seen in  FIG. 3B ). The seal at the bottom of the corrosion barrier may be a temporary seal or a removable seal. That is, the seal may be used while the filler is being put into place (and hardening) and then removed after the filler has fully filled-in the annular space between the sheath and the rigid links. 
     In one or more embodiments, the filler may be comprise a first part that is pre-engineered to fit around the rigid links. This first part of the filler may be pre-fabricated to take up the majority of the annular space that is formed between the sheath and the rigid links. The first part of the filler may be placed around the rigid links and the caisson may be closed around the first part of the filler and the links. Then, a second part of the filler may be used to fill in the remaining annular space. 
     In one or more embodiments, the sheath may be removed after the filler has hardened around the rigid links. For example, the sheath may be re-usable and may be removed after installation, leaving behind the hardened filler around the chain length. 
     In one or more embodiments, the corrosion barriers described herein may be placed around the rigid links of the mooring line after the mooring line has been placed in the marine environment. For example, the corrosion barrier  110  may be installed around the mooring line  104  after the mooring line has been installed on the floating structure  102 . For example, as seen in  FIG. 5 , the mooring line may be raised and pulled through a fairlead  501  and into a chain-stopper  505  to locate the corrosion barrier  110  in the vicinity of the waterline  106 . The corrosion barrier may then be installed around the portion of the mooring line that is in the splash line as described with reference to  FIGS. 3-4 . For example, the corrosion barrier may comprises a hinged caisson sheath that is closed to encircle around the mooring line. The bottom end of the corrosion barrier may be sealed and filler may be placed into the annular space between the corrosion barrier and the rigid links. 
     In one or more embodiments, the caisson or sheath of the corrosion barrier may have a port that allows for injecting filler material into the annular space between the sheath and the rigid links. The filler material may then be injected into the annular space under pressure, thus, causing any water in the annular space to be pushed out of the caisson. The corrosion barrier may also have a check valve to allow for air to escape from the annular space. 
     In one or more embodiments, remotely operated vehicles may be used to aid in the installation of the corrosion barrier in in situ marine environments. Further, in one or more embodiments, pumps may be used to remove water from the annular space between the sheath and the rigid links before the filler is installed. 
     The ability to install the corrosion barrier in situ in the marine environment, provides for the ability to retrofit existing mooring lines. For example, a mooring line may have experienced more corrosion than anticipated due to unanticipated environmental conditions. The corrosion barriers described herein can then be used to retrofit such mooring lines to extend the life of the mooring line. 
     Thus, in one or more embodiments, the rigid links of a mooring chain may be inspected for signs of degradation. The inspection may be performed by visual inspection or by other testing means. For example, the chain link diameter may be measured periodically over time to determine changes (i.e., reductions) in the chain length diameter. For example, the chain links may be inspected by CT scan or other testing means. Once one or more chain links in the splash zone of the mooring line are identified as exhibiting degradation or more degradation than models would have expected, the chain links may be retro-fitted to be encapsulated by the corrosion barriers described herein. 
     The methods and systems described herein, may also have the benefit of allowing for ease of maintenance and inspection after the corrosion barrier has been installed. For example, the sheath and filler materials may be chosen to be see-through to allow visual inspection of chain integrity. As another example, the cylindrical shape of the corrosion barrier can allow for the leveraging of pipeline inspection tools to inspect and monitor the mooring chain. Additionally, the chain links and/or corrosion barrier can be inspected or monitored by CT scan, long-wavelength acoustic methods that are capable of piercing the filler material (e.g., by utilizing acoustic resonance techniques). 
     It should be understood that that preceding is merely a detailed description of specific embodiments of the invention and that numerous changes, modifications, and alternatives to the disclosed embodiments can be made in accordance with the disclosure herein without departing from the scope of the invention. The preceding description therefore, is not meant to limit the scope of the invention. Rather, the scope of the invention is to be determined only by the appended claims and their equivalents. It is also contemplated that structures and features embodied in the present embodiments can be altered, rearranged, substituted, deleted, duplicated, combined, or added to each other.