Apparatus and method for subsea mooring

Abstract

An apparatus (1) and method for Subsea Mooring are provided. The apparatus (1) includes a downwardly extending arrangement of at least two and preferably three legs (2a, 2b, 2c). A drill bit (8a, 8b, 8c) is coupled to each respective leg (2a, 2b, 2c), and each said drill bit (8a, 8b, 8c) is configured for drilling into a seabed (51). At least one of said drill bits (8a, 8b, 8c) is configured to rotate in a first direction whilst drilling into the seabed (51) and at least one other of said drill bits (8a, 8b, 8c) is configured to rotate in a second direction, opposite to said first direction. Both said at least one and said at least one other of the drill bits (8a, 8b, 8c) are arranged to simultaneously drill into the seabed (51).

Description

[0001] TITLE

[0002] “Apparatus and Method for Subsea Mooring”

[0003] FIELD OF THE INVENTION

[0004] The present invention relates to an apparatus that is used to lay or provide a foundation for the subsea mooring or anchoring of large structures such as offshore floating wind turbines or other large floating structures.

[0005] BACKGROUND TO THE INVENTION

[0006] The world's rapidly growing population and the accumulating requirement for energy, in addition to the detrimental environmental repercussions caused by fossil fuel use, have triggered an urgent global demand for alternative energy sources. Wind energy is emerging as a promising substitute due to the numerous advantages that wind energy presents over conventional fossil fuel energy sources.

[0007] Wind turbines have the potential to offer an eco-friendly solution towards satisfying the ever-growing global demand for alternative energy sources, as they do not emit any of the pollutants responsible for climate change, such as harmful greenhouse gases. Exploiting wind power energy sources mitigates our dependency on fossil fuels, as a result cutting emissions of carbon dioxide and fine particles, as well as other climatealtering substances that contribute to the greenhouse effect. Furthermore, wind is an abundant source of energy that is unlimited over time, inexhaustible and accessible to a large extent on all of the Earth's surface.

[0008] Performance levels of the transformation of wind energy to electricity have already accomplished remarkable degree of efficiency, achieving efficiency ranges of approximately 40% to 50%; converging towards the maximum theoretical level, which according to Betz’s law is 59%. This impressive level of efficiency, along with the relatively low operational costs make them economically viable as well. After a wind turbine is installed, it requires only minimal maintenance in comparison to other energy sources. Moreover, wind energy could help achieve energy self-sufficiency, providing unquestionable economic benefits to those countries which adopt it, whilst also taking a step towards sustainable development. Offshore wind turbines present several advantages over onshore installations. The wind energy potential of onshore wind turbines portrays a high degree of variability. In stark contrast, offshore wind offers consistent, dependable and stronger, yet less turbulent, wind resources.

[0009] In order to harness the full potential of wind energy, engineers and inventors have devised various designs and features of offshore wind turbines to cater to specific locations and meteorological conditions. The two main types of offshore wind turbines are “Fixed-bottom” and “Floating” offshore wind turbines. Fixed-bottom offshore wind turbines generally comprise of a steel monopole foundation secured to the seafloor and are by and large only suitable for offshore locations with relatively shallow waters so that foundations can be secured to the seabed. Floating offshore wind turbines on the other hand comprise of a floating structure anchored to the seafloor, they are suitable for relatively deep offshore waters and are therefore particularly useful for wind farm projects deployed far from the shore.

[0010] At the present moment Fixed-bottom offshore wind turbines are the considerably more prevalent of these two main types. Almost all currently operating offshore wind farms employ fixed foundation turbines, aside from of a few pilot projects.

[0011] Although offshore wind power is particularly more challenging and expensive than onshore counterparts, the abundance and consistency of wind in the open ocean may offset these difficulties. That being said there is a very apparent requirement for enhancements of the present approaches to installation of offshore wind turbines to be made and a subsequent cost reduction in order for offshore wind turbines to become a viable and attractive solution to investors and companies within the energy sector. Energy sources that are economically viable inherently attract investments from private companies and governments. Accelerated installation will make offshore wind turbines more competitive with the other sources of energy, such as fossil fuels.

[0012] One crucial barrier to the widespread adoption of offshore wind energy is the relatively high cost of installation of the turbines and in particular the towers on which they are supported. The installation of offshore wind turbines can be slow, usually requiring great amounts of resources and time. One of the particularly high cost components of the installation of offshore wind turbines relates to the excessive time that current methods necessitate.

[0013] Installation takes up a significant proportion of the costs associated with offshore wind turbines as the process of installing the offshore wind turbines requires the use of specialized resources, such as vessels, equipment and personnel. Logistically, large expenses are therefore incurred when deploying these resources. Accelerated installation time will inevitably result in a significant reduction in installation costs, and therefore in the overall costs, of offshore wind turbines, as fewer resources are required for installation. Furthermore, reduction in installation times vastly improves the feasibility of offshore wind farm projects; accelerated installation times produce faster project completions, thereby providing a stronger return on investment.

[0014] Commercial Floating offshore wind turbines are only in the early stages of development, and although they show great potential, they still face several technical challenges before large offshore wind projects are adopted around the world.

[0015] Large scale utilization and widespread adoption of renewable energy sources, and particularly offshore wind turbines, has the potential to greatly impact the global shift transitioning towards a sustainable global energy system.

[0016] The present invention therefore aims to address and seeks to overcome the problem of the excessive costs associated with offshore wind turbines. More particularly, the present invention aims to address and seeks to overcome the problem of the excessive installation time associated with offshore wind turbines.

[0017] The present invention therefore aims to provide a mooring apparatus for subsea anchoring of large structures comprising features that reduce the installation time of mooring apparatus compared to hitherto known systems. STATEMENTS OF THE INVENTION

[0018] According to a first aspect of the invention, there is provided a subsea mooring apparatus comprising: a downwardly extending arrangement of at least two legs; and a drill bit coupled to each respective leg, wherein each said drill bit is configured for drilling into a seabed; and wherein at least one of said drill bits is configured to rotate in a first direction whilst drilling into the seabed and at least one other of said drill bits is configured to rotate in a second direction, opposite to said first direction, whilst drilling into the seabed.

[0019] Typically, the at least one of said drill bits is configured to rotate in the first direction whilst drilling into the seabed and the at least one other of said drill bits is configured to rotate in the second direction, (opposite to said first direction), whilst both said at least one and said at least one other of the drill bits are simultaneously drilling into the seabed.

[0020] Typically, the subsea mooring apparatus further comprises a frame. Preferably, the arrangement of legs extend downwardly from the frame. Typically, the frame is secured to each of the legs at the upper extremity of each leg.

[0021] Typically, the frame is configured to support each leg in an equidistant arrangement. In other words, typically, each of the legs are spaced equally apart from each adjacent leg.

[0022] Preferably, the apparatus further comprises at least one connecting mechanism for coupling the apparatus to a tether, such as a rope or chain. Typically, the connecting mechanism is used to couple an offshore wind turbine to the frame and therefore to the apparatus.

[0023] Typically, the frame comprises said at least one connecting mechanism. Preferably, the at least one connecting mechanism comprises a chain connector. Typically, the said connecting mechanism is configured for supporting and directing the apparatus to a predetermined location on a seabed. Typically, the said drill bit is coupled to a lower end of each respective leg.

[0024] Preferably, the rotation of each drill bit is driven by fluid. Typically, the said fluid is pressurised fluid. Preferably, the said fluid is seawater and more preferably said seawater is pressurised, preferably by a pumping mechanism, to a higher pressure than the pressure of seawater taken from the sea at the location of use of the apparatus. Optionally, the said fluid is drilling fluid.

[0025] Optionally, the said fluid is pumped from a vessel. Typically, said fluid pumped from a vessel is pumped via at least one umbilical pipe, preferably by a pumping mechanism where said pumping mechanism is typically located on or is otherwise associated with or used in conjunction with the vessel such as a Remotely Operated Vehicle (ROV). Typically, the umbilical pipe is provided with two ends, one end coupled to the vessel or ROV as appropriate and another end coupled to the apparatus.

[0026] Optionally, the fluid is pumped from a Remotely Operated Vehicle (ROV) comprising a pressurised pumping mechanism. Typically, fluid pumped from said Remotely Operated Vehicle (ROV) is seawater.

[0027] Preferably, the apparatus further comprises at least one fluid inlet. Typically, the fluid inlet is provided on the frame and more preferably the said other end of the umbilical pipe is connected to said at least one fluid inlet.

[0028] Typically, each leg comprises a conduit for conveying the pressurised fluid. Typically, the conduit conveys pressurised fluid from the said at least one fluid inlet to the drill bit of each leg.

[0029] Optionally, the apparatus further comprises at least one flexible tube or pipe for conveying pressurised fluid from the fluid inlet to the conduit of each leg. More preferably, the apparatus comprises a flexible tube or pipe for each of the respective legs for conveying the pressurised fluid from the fluid inlet to the conduit of each leg.

[0030] Optionally, the apparatus further comprises a manifold device, such as a pipe or chamber. Preferably, the manifold device connects the said at least one fluid inlet to each flexible tube or pipe of each respective leg such that said manifold device is configured to distribute, and more preferably evenly distribute, the pressurised fluid to the conduit of each leg.

[0031] Preferably, each of the legs comprise a motive tool / device associated with each respective drill bit, typically, said motive tool / device is configured to translate hydraulic pressure / power and flow from the pressurised fluid into mechanical / rotational energy to rotate the drill bits. Said motive tool / device may be, for example, a fluid motor or a Positive Displacement Motor (PDM).

[0032] Optionally, each leg comprises a fluid motor, such as a turbine drilling motor. Typically, each drill bit is rotated by a fluid motor disposed in fluid communication with the conduit of each leg. Typically, the fluid motor comprises a rotor and a stator. Typically, the stator comprises one or more sets of nozzles.

[0033] Typically, each leg is arranged such that fluid conveyed through the conduit flows through the fluid motor of each leg, flowing through one or more sets of nozzles within the stator and therein driving rotation of the rotor.

[0034] Preferably, the rotor is connected to the drill bit, and more preferably the rotor is rotationally connected to the drill bit, such that rotation of the rotor is configured to rotate the drill bit.

[0035] Optionally, the rotor has a helical gear profile configured to transfer the rotational force of the rotor to the drill bit.

[0036] Optionally, each leg comprises a Positive Displacement Motor (PDM). Typically, each drill bit is rotated by the PDM disposed in fluid communication with the conduit of each leg. Typically, the PDM comprises a rotor and a stator.

[0037] Typically, the stator of the PDM comprises at least two lobes, and the rotor of the PDM typically comprises one less lobe than that of the stator of the PDM.

[0038] The rotor of the PDM typically comprises a helical shape, and the stator of the PDM also typically comprises the same helical shape as the rotor of the PDM. Advantageously, when the rotor has one less lobe than the stator, a cavity is provided between the PDM rotor and the PDM stator which provides passage for the pressurised fluid. When pressurised fluid is conveyed into the cavity, the cavity acts as a wedge under the pressure of the pressurised fluid and (as the pressurised fluid cannot be compressed) pressurised fluid applied to the top of the wedge forces the rotor to move, which (given the helical shape of the rotor and stator of the PDM) causes the rotor of the PDM to rotate.

[0039] Typically, each leg is arranged such that fluid conveyed through the conduit flows through the PDM of each leg, flowing through the cavity between the rotor and the stator and therein driving rotation of the PDM rotor.

[0040] Preferably, the rotor is connected to the drill bit, and more preferably the rotor is rotationally connected to the drill bit, such that rotation of the rotor is configured to rotate the drill bit.

[0041] Optionally, the rotor has a helical gear profile configured to transfer the rotational force of the rotor to the drill bit.

[0042] Preferably, a crossover mechanism is used to rotationally connect the drill bit to the rotor. Advantageously, the crossover mechanism enables connection between the fluid motor and / or the PDM and the drill bit

[0043] Preferably, each leg comprises at least one outlet port, providing a fluid outlet from the conduit. Typically, the outlet port comprises an arrangement of nozzles, or a bypass valve, or dump valve.

[0044] Optionally, the conduit is arranged such that fluid flows out of each of the legs via fluid outlet ports. Preferably, said fluid outlet ports are proximate to the lower drill end of the legs, and, more preferably, said fluid outlet ports are positioned lower than the stator such that the fluid drives rotation of the drill bit of each leg prior to exiting the legs via the fluid outlet ports. Typically, fluid flowing out of each of the legs, for example via the fluid outlet ports, is circulated in an upward direction within the drilled hole towards the seabed. Advantageously, the upwardly directed fluid circulates any swarf, sediment or any other debris to the seabed.

[0045] Preferably, the drill bit of each respective leg comprises a cross sectional surface area that is greater than any other cross-sectional area of said respective leg, such that the drill bit coupled to each respective leg is configured to drill a throughbore defining an annulus.

[0046] Typically, each of the said annulus is defined by the gap between: an outer surface of each leg of each respective drill bit; and the inner surface of said throughbore drilled by the drill bit (coupled to each of the respective legs).

[0047] Typically, at least one of the drill bits is configured to rotate in a first direction whilst drilling into the seabed and at least one other drill bit is configured to rotate in a second opposite direction whilst drilling into the seabed. Typically, the first direction is clockwise and the second direction is anti-clockwise.

[0048] Typically, at least one first leg comprises an inversed rotational arrangement relative to a rotational arrangement of at least one second leg, such that rotation of the inversed rotational arrangement of said first leg is in a first direction and rotation of the rotational arrangement of said second leg is in a second opposite direction.

[0049] Optionally, at least one leg comprises a fluid motor configured to rotate in a first direction and at least one leg comprises a fluid motor configured to rotate in a second opposite direction. Optionally, said inversed rotational arrangement comprises an inversely arranged fluid motor when compared to the fluid motor of said second leg. Typically, the fluid motor stator of said inversed arrangement comprises one or more sets of inversely arranged nozzles. Typically, said inversely arranged nozzles are configured to drive the drill bit of the inversed arrangement in said first direction. Typically, said inversely arranged nozzles are arranged in an opposite direction to said at least one second leg, such that that fluid conveyed through the conduit of said inversely arranged leg flows through the sets of inversely arranged nozzles within the stator, therein driving rotation of the rotor in said first direction.

[0050] Optionally, at least one leg comprises a PDM configured to rotate in a first direction and at least one leg comprises a PDM configured to rotate in a second opposite direction. Optionally, said inversed rotational arrangement comprises an inversely arranged PDM when compared to the PDM of said second leg. Typically, the rotor and the stator of the PDM of said inversed arrangement comprises an inversely arranged helical shape. Typically, the inversely arranged helical shape (of the rotor and stator of the PDM) of the inversed rotational arrangement cause the drill bit of the inversed rotational arrangement to be driven by the pressurised fluid flowing through the cavity (and therein driving inversed rotation of the rotor) to drive inversed rotation of the drill bits (in said first direction).

[0051] Advantageously, at least one of the drill bits being arranged to spin in one rotational direction and at least of the other drill bits is arranged to spin in the other rotational direction prevents the entire template crawling around / rotating around. If that happened, the drilling action would not actually drill into the ground but rather would crawl around in a circle.

[0052] Preferably, the conduit of a first leg is in fluid communication with at least the conduit of a second leg. More preferably, the conduits of each of the legs are in fluid communication such that the pressure is substantially equalised in the conduits of each leg. Advantageously, having substantially equalised pressure in the conduits of each leg provides equalised magnitudes of drill speed and torque.

[0053] Typically, at least two of the drill bits are operable to drill simultaneously. Typically, each of the legs that are operable to drill simultaneously are in fluid communication with one another such that pressurised fluid pumped through the inlet is directed to each of the conduits of said legs that are operable to drill simultaneously.

[0054] Optionally, each leg comprises a telescopic leg configured to telescopically extend downwardly. Typically, the telescopic leg comprises a plurality of concentric tubular sections operable to slide into one another. Preferably, the telescopic legs are configured to extend downwards as the drill bits continue drilling once the frame is on the seabed. The legs are telescopic to increase the depth of the foundation provided by them as the drill bit on their lower end progresses further into the sub-surface terrain.

[0055] Typically, the telescopic legs are operable to change from: a retracted configuration, in which the concentric tubular sections are retracted such that the length of the leg is shortened; to an extended configuration, in which the concentric tubular sections are slidably extended such that the length of the leg is increased (compared to the retracted configuration).

[0056] Typically, said each plurality of concentric tubular sections comprises an outermost tubular section and an innermost tubular section.

[0057] Preferably, the outermost tubular section of each leg is affixed to the frame. More preferably, the outermost concentric tubular section is rigidly connected to the frame, said outermost concentric tubular section defining a base of the telescopic leg. Typically, the outermost tubular section of each leg is the uppermost tubular member when the telescopic leg is in the extended configuration.

[0058] Preferably, the innermost tubular section of each leg is coupled to the drill bit respective to each leg. Typically, the innermost tubular section of each leg is the lowermost tubular member when the telescopic leg is in the extended configuration.

[0059] Typically, each concentric tubular section is slidably connected to an adjacently arranged concentric tubular section.

[0060] Typically, each telescopic leg comprises a locking mechanism provided between each adjacent tubular section, said locking mechanism configured to lock the extended telescopic sections, thereby preventing overextension and disconnecting of the tubular sections. The locking mechanism may comprise an arrangement of mechanical stops configured to be engaged when the telescopic sections have extended to a maximum extension limit. Typically, the telescopic legs comprises an arrangement of mechanical seals provided between each adjacent tubular section, said arrangement of mechanical seals configured to resist fluid pressure and prevent fluid from escaping between each adjacent tubular section of the telescopic legs. Typically, each of the mechanical seals are housed in a groove externally around the innermost tubular section of each of the adjacent tubular sections. Alternatively, each of the mechanical seals are housed in a groove internally within the outermost tubular section of each of the adjacent tubular sections.

[0061] The telescopic arrangement of the legs makes the legs more compact, which is specifically advantageous during transportation and assembly of the legs and / or apparatus. Furthermore, the telescopic arrangement of the legs provide the ability to selectively lengthen the depth of the foundation.

[0062] Optionally, the telescopic legs can be lengthened by increasing the: length of the concentric tubular sections; and / or number of concentric tubular sections on each leg.

[0063] Typically, each concentric tubular section comprises an upper face having a cross sectional area. Preferably, when pressurised fluid is directed downwardly, the pressurised fluid acts against the cross-sectional area of the upper face of each of the concentric tubular section to create a force directed against said cross sectional area of the upper face of each of the concentric tubular section, and thereby downwardly extending the tubular sections. In this way, the cross-sectional area of the upper face of each of the concentric tubular sections act as pistons.

[0064] According to a second aspect of the invention, there is provided a method of installing a subsea mooring apparatus, the method comprising the steps of:

[0065] (A) Assembling a subsea mooring apparatus in accordance with the first aspect of the invention;

[0066] (B) Deploying the subsea mooring apparatus to the seabed;

[0067] (C) Rotating at least one of said drill bits in a first direction whilst drilling into the seabed and rotating at least one other of said drill bits in a second direction, opposite to said first direction, whilst drilling into the seabed. Optionally, the method further comprises the step of:

[0068] (D) Pumping pressurised fluid into a conduit within the subsea mooring apparatus to drive rotation of the drill bits therein drilling a borehole.

[0069] Optionally, the method further comprises the step of:

[0070] (E) Pumping cement into an annulus between the outer surface of the leg and the inner surface of the borehole to secure the apparatus in the seabed.

[0071] Optionally, step (C) further comprises rotating at least one of said drill bits in a first direction whilst drilling into the seabed, and rotating at least one other of said drill bits in a second direction, opposite to said first direction, whilst simultaneously drilling both said at least one and said at least one other of the drill bits into the seabed.

[0072] Preferably, the apparatus once installed in the seabed provides a secure foundation for a mooring line such as a mooring line for a floating wind turbine or other structure such as a floating or semi-submerged or submerged structure.

[0073] The accompanying drawings illustrate presently exemplary embodiments of the disclosure, and together with the general description given above and the detailed description of the embodiments given below, serve to explain, by way of example, the principles of the disclosure.

[0074] In the description that follows, like parts are marked throughout the specification and drawings with the same reference numerals, respectively. The drawings are not necessarily to scale. Certain features of the invention 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. The present invention is susceptible to embodiments of different forms. Specific embodiments of the present invention are shown in the drawings, and herein will be described in detail, with the understanding that the present disclosure is to be considered an exemplification of the principles of the invention and is not intended to limit the invention to that illustrated and described herein. It is to be fully recognized that the different teachings of the embodiments discussed below may be employed separately or in any suitable combination to produce the desired results. Reference to up or down will be made for purposes of description with the terms "above", "up", "upward" or "upper" meaning away from the bottom of the borehole along the longitudinal axis of a leg of the subsea mooring apparatus toward the subsea surface and "below", "down", "downward" or "lower" meaning toward the bottom of the borehole along the longitudinal axis of the leg and away from the subsea surface and deeper into the borehole.

[0075] The various aspects of the present invention can be practiced alone or in combination with one or more of the other aspects, as will be appreciated by those skilled in the relevant arts. The various aspects of the invention can optionally be provided in combination with one or more of the optional features of the other aspects of the invention. Also, optional features described in relation to one embodiment can typically be combined alone or together with other features in different embodiments of the invention. Additionally, any feature disclosed in the specification can be combined alone or collectively with other features in the specification to form an invention.

[0076] Various embodiments and aspects of the invention will now be described in detail with reference to the accompanying figures. Still other aspects, features, and advantages of the present invention are readily apparent from the entire description thereof, including the figures, which illustrates a number of exemplary embodiments and aspects and implementations. The invention is also capable of other and different embodiments and aspects, and its several details can be modified in various respects, all without departing from the spirit and scope of the present invention.

[0077] Any discussion of documents, acts, materials, devices, articles and the like is included in the specification solely for the purpose of providing a context for the present invention. It is not suggested or represented that any or all of these matters formed part of the prior art base or were common general knowledge in the field relevant to the present invention.

[0078] Accordingly, the drawings and descriptions are to be regarded as illustrative in nature, and not as restrictive. Furthermore, the terminology and phraseology used herein is solely used for descriptive purposes and should not be construed as limiting in scope. Language such as "including", "comprising", "having", "containing" or "involving" and variations thereof, is intended to be broad and encompass the subject matter listed thereafter, equivalents, and additional subject matter not recited, and is not intended to exclude other additives, components, integers or steps. In this disclosure, whenever a composition, an element or a group of elements is preceded with the transitional phrase "comprising", it is understood that we also contemplate the same composition, element or group of elements with transitional phrases "consisting essentially of’, "consisting", "selected from the group of consisting of”, “including” or "is" preceding the recitation of the composition, element or group of elements and vice versa. In this disclosure, the words “typically” or “optionally” are to be understood as being intended to indicate optional or non-essential features of the invention which are present in certain examples but which can be omitted in others without departing from the scope of the invention.

[0079] All numerical values in this disclosure are understood as being modified by "about". All singular forms of elements, or any other components described herein including (without limitations) components of the apparatus described herein are understood to include plural forms thereof and vice versa.

[0080] BRIEF DESCRIPTION OF THE DRAWINGS

[0081] Fig. 1 shows a perspective view of an exemplary subsea mooring apparatus in accordance with the present invention, where the apparatus is shown with three legs being in an extended configuration which, in use, is also the installed configuration;

[0082] Fig. 2 is a side view of the subsea mooring apparatus shown in Fig. 1 ;

[0083] Fig. 3 is a plan view of the subsea mooring apparatus shown in Fig. 1 ;

[0084] Fig. 4 shows an exemplary subsea mooring deployment system deploying the subsea mooring apparatus of Fig. 1 in accordance with the present invention, showing the stage of the exemplary subsea mooring deployment system as the subsea mooring apparatus is deployed over the side of a vessel and into a body of water, and where the subsea mooring apparatus is shown with its three legs being in a compact or retracted configuration (which is also the transportation and / or deployment configuration);

[0085] Fig. 5 is a plan view of the exemplary subsea mooring deployment system of Fig. 4 showing the upper deck of the vessel and the various topside equipment on the vessel and which is used to deploy the subsea mooring apparatus over the side of the vessel into the body of water;

[0086] Fig. 6 is the exemplary subsea mooring deployment system of Fig. 4, but shows the next stage of operation of the exemplary subsea mooring deployment system following on from that of Fig. 4 and Fig. 5, where the subsea mooring apparatus of Fig. 1 has been lowered to the seabed below the body of water from the side of the vessel;

[0087] Fig. 7 shows a side view of one of the three legs of the subsea mooring apparatus of Fig. 1 , detailing the exemplary internal leg arrangements configured to rotate a drill bit provided at the lower end thereof, the exemplary internal leg arrangement operable to telescopically extend the respective leg, and showing the exemplary internal leg arrangement of one telescopic leg in an extended configuration;

[0088] Fig. 8 is the exemplary subsea mooring deployment system of Fig. 4, but shows the next stage of operation of the exemplary subsea mooring deployment system following on from that of Fig. 6, where fluid is pumped through a throughbore in each of the legs to drive rotation of the respective drill bits to drill a borehole into the seabed and also to extend the respective telescopic legs;

[0089] Fig. 9 is a side view of one of the legs of the subsea mooring apparatus within borehole formed thereby in the seabed during the stage of operation of the exemplary subsea mooring deployment system shown in Fig. 8, which shows the direction of fluid as it is pumped downwards through the leg and is circulated back up through an annulus between the inner throughbore of the borehole and the outer surface of the drill bit and the telescopic leg;

[0090] Fig. 10 shows a side view of one of the legs of the subsea mooring apparatus of Fig. 4, showing an exemplary internal leg arrangement of the telescopic leg in the compact or retracted (transportation and / or deployment) configuration; and

[0091] Fig. 11 is a side view of one of the legs of the subsea mooring apparatus of Fig. 1 within the borehole of Fig. 9 (and therefore within the annulus surrounded by the seabed), but shows the next stage of operation of the exemplary subsea mooring deployment system following on from that of Fig. 9, where cement is pumped through the throughbore in each of the legs and circulated up through the annulus to form the foundation in the seabed provided by the subsea mooring device shown in Fig. 1.

[0092] DETAILED DESCRIPTION OF THE DRAWINGS

[0093] DESCRIPTION OF THE SUBSEA MOORING APPARATUS 1 Figure 1 shows a perspective view of an exemplary embodiment of a subsea mooring apparatus 1 in accordance with the present invention. The subsea mooring apparatus 1 comprises an arrangement of legs 2a, 2b, 2c. In the example shown, the subsea mooring apparatus 1 comprises three legs, although, in other examples there may only be two legs, or there may be greater than three legs. It is typical, however, that an arrangement of at least three legs is provided. Conveniently, arrangements of at least three legs provide greater balance and stability to the subsea mooring apparatus 1 , specifically when compared to arrangements comprising of two legs, or even one leg.

[0094] The legs 2a, 2b, 2c are elongated, comprising an upper (in use) end and a lower (in use) end. In use, the legs 2a, 2b, 2c are arranged to extend downwardly towards and / or into the seabed 51. In the example shown there is provided a frame 3 for securing the legs 2a, 2b, 2c in place. The legs 2a, 2b, 2c may be, for example, fastened or welded to the frame 3. The frame 3 may be securely arranged proximate to the upper (in use) end of each of the legs 2a, 2b, 2c and advantageously each of the legs 2a, 2b, 2c may be securely arranged at a respective corner of the shape of the frame 3 in order to provide as wide a footprint as possible for the legs 2a, 2b, 2c for a given size of frame 3.

[0095] In this example, the frame 3 comprises three outer frame members 4 arranged in a triangular shape and defining an outer frame section 5, with each of the three legs 2a, 2b, 2c arranged securely at a respective corner of the triangular shape of the frame 3. In the example shown, the three outer frame members 4 are equidistant in length with the outer frame section 5 defining an equilateral triangle with each of the legs 2a, 2b, 2c arranged equidistantly from each respectively adjacent leg 2a, 2b, 2c such that the frame 3 is configured to support each leg 2a, 2b, 2c in an equidistant arrangement. Frame 3 further comprises internal support members 6. Each of the internal support members 6 may inwardly extend from the midpoint of a respective outer frame member 4 to the point of intersection of the inwardly extending internal support members 6. In this example, in which the outer frame section 5 defines an equilateral triangle, the point of intersection is the incentre of the triangular shape of the outer frame section 5.

[0096] The subsea mooring apparatus 1 further comprises a connecting mechanism 7 for coupling the subsea mooring apparatus 1 to a tether, such as a rope or chain, in order to provide a mooring. The connecting mechanism 7 may therefore be used to couple or moor large structures such as an offshore wind turbine (not shown) to the subsea mooring apparatus 1 (during any time after it has been securely installed within / to the seabed 51 , the stages of installation for which will be described subsequently). The connecting mechanism 7 may further be used for supporting, deploying and / or directing the subsea mooring apparatus 1 to a predetermined or impromptu installation location on a seabed 51. The connecting mechanism 7 may form part of the frame 3 or may be otherwise secured to the frame 3 by, for example, a shackle or the like. In the example shown, the connecting mechanism 7 is a chain connector 7 secured to the frame 3 proximate to the point of intersection of the inwardly extending internal support members 6 such that the chain connector 7 is located substantially centrally of the frame 3 and therefore of the subsea mooring apparatus 1. Advantageously, such central positioning of the chain connector 7, as shown in the example subsea mooring apparatus 1 , provides for a more even distribution of the forces and stresses, subjected to the connecting mechanism 7, to each of the internal support members 6 and therein to each of the outer frame members 4 (and therefore to the entire frame 3 and subsea mooring apparatus 1 including the legs 2a, 2b, 2c).

[0097] A drill bit 8a, 8b, 8c is coupled to each respective leg 2a, 2b, 2c and is configured for selective drilling into the seabed 51. In this preferred embodiment, the drill bits 8a, 8b, 8c are coupled to the lower end of each respective leg 2a, 2b, 2c. The drill bits 8a, 8b, 8c may be rotationally driven by pressurised fluid in this preferred embodiment. Optionally and alternatively, the drill bits 8a, 8b, 8c may be rotationally driven by an electrical or other power means (not shown).

[0098] The subsea mooring apparatus 1 may further comprise a fluid inlet 9 for receiving pressurised fluid (particularly where the drill bits 8a, 8b, 8c of this preferred embodiment are driven by fluid), cement or grout. The legs 2a, 2b, 2c are hollow and cylindrical in nature and therefore comprise a throughbore which provides a conduit 22 for conveying fluid (typically in an in use downwards direction) to the upper in use end of the rotational means (such as the drill bits 8a, 8b, 8c), where said conduits 22 are in fluid communication at their respective upper in use end with the lower in use end of the fluid inlet 9. The subsea mooring apparatus 1 further comprises a pipe network or networks for conveying fluid from the lower in use end of the fluid inlet 9 to the upper in use end of the conduit 22 of each leg 2a, 2b, 2c. The pipe network(s) may comprise a series of flexible tube or pipe arrangements 10 for conveying fluid from the fluid inlet 9 to the conduit 22 of each respective leg 2a, 2b, 2c. In the example subsea mooring apparatus 1 shown in Figs. 1-3, there is a pipe arrangement 10 for conveying fluid from the fluid inlet 9 to the conduit 22 of each respective leg 2a, 2b, 2c. The fluid inlet 9 is connected to, and in direct fluid communication with, said pipe arrangements 10. In the example shown in Figs. 1-3 the fluid inlet 9 is conveniently positioned away from the central point of the frame 3 and the connecting mechanism 7, which is advantageous as any umbilicals 18 and crane wire ropes 19 that may be used as a source of power (for the rotation of the drill bits 8a, 8b, 8c) and to lower the subsea mooring apparatus 1 to the seabed 51 , respectively, will be less prone to interfering with one another. A manifold device 11 is used to connect the fluid inlet 9 to the pipe arrangement 10 of each respective leg 2a, 2b, 2c. The manifold device 11 (see Fig. 3) is configured to evenly distribute the pressurised fluid (and, as will be subsequently described, the cement or grout) to the conduit 22 of each leg 2a, 2b, 2c. The manifold device 11 may be, for example, a pipe or chamber.

[0099] This arrangement of the fluid inlet 9, pipe arrangements 10, manifold device 11 and conduits 22 of each respective leg 2a, 2b, 2c, advantageously enables each of the drill bits 8a, 8b, 8c to drill simultaneously, as (due to this arrangement) the drill bits 8a, 8b, 8c on each of the respective legs 2a, 2b, 2c are each in fluid communication with one another. Pressurised fluid that is pumped through the inlet 9 is therefore simultaneously directed to each of the conduits 22 of the legs 2a, 2b, 2c respective to each drill bits 8a, 8b, 8c, therefore providing the advantage that each of the drill bits 8a, 8b, 8c are configured to rotate / drill simultaneously.

[0100] The legs 2a, 2b, 2c of the subsea mooring apparatus 1 may be telescopic legs 2a, 2b, 2c. Said telescopic legs 2a, 2b, 2c may comprise a plurality of concentric tubular sections 12, 13, 14 operable to slide into one another such that the telescopic legs 2a, 2b, 2c are configured to telescopically extend downwardly into the seabed 51 in use.

[0101] DESCRIPTION OF THE SUBSEA MOORING DEPLOYMENT SYSTEM 30 USED TO DEPLOY THE SUBSEA MOORING APPARATUS 1

[0102] In use, the subsea mooring apparatus 1 is lowered down to the seabed 51. The subsea mooring apparatus 1 may be lowered down to the seabed 51 by a subsea mooring deployment system 30 which deploys the subsea mooring apparatus 1 from a vessel 15, for example, by a crane 16. Fig. 4 shows an exemplary subsea mooring deployment system 30 employing and / or deploying the subsea mooring apparatus 1 in accordance with the present invention, showing the stage of the exemplary subsea mooring deployment system 30 in which the subsea mooring apparatus 1 is deployed over the side of the vessel 15 by a crane 16. When the legs 2a, 2b, 2c have been installed in the subsea surface 51 (i.e. when the drill bits 8a, 8b, 8c of the legs 2a, 2b, 2c have drilled into the seabed 51 - and, as will be subsequently described, cement / grout has been pumped, and has cured and hardened in and around the legs 2a, 2b, 2c within the seabed) each leg 2a, 2b, 2c will form a pile in the seabed 51 which will act as a steady and secure support for any structures that may be tethered to the subsea mooring apparatus 1 by transferring the loads (subjected to the subsea mooring apparatus 1) to the high bearing capacity of the hard strata, rocks, or soil within the seabed.

[0103] Fig. 5 shows the upper deck of the vessel 15 and the various topside equipment that may be used. It may be that the vessel 15 is equipped with an umbilical reeler 17, which may be configured to reel umbilicals 18 connected to the subsea mooring apparatus 1 to link the subsea mooring apparatus 1 to a control system (not shown) operated by personnel aboard the topside of the vessel 15. The umbilicals 18 may provide power and / or control to the subsea mooring apparatus 1 . The subsea mooring apparatus 1 may be deployed over the side of the vessel 15 using wire rope 19, that connects the vessel 15, for example via a crane 16, to the subsea mooring apparatus 1 , for example via the connecting mechanism 7.

[0104] The subsea mooring apparatus 1 is lowered down to the seabed 51 from the vessel 15 by the crane 16 until it reaches the location of installation on / in the seabed 51. When the operator or other personnel are ready to start the installation process of the subsea mooring apparatus 1 , they can initiate the next stage of the installation process, in that fluid, which may be drilling fluid such as conventional water based drilling fluid used to drill boreholes in the subsea surface in the oil and gas exploration industry or which more preferably may be seawater 50, is pumped by a pumping mechanism 20 that may be located on or, may otherwise be associated with, or used in conjunction with, the vessel 15 or, for example, a Remotely Operated Vehicle (ROV) (not shown) also typically deployed from the vessel 15. The umbilical pipe 18 may be provided with two ends, one end coupled to the vessel 15 or ROV as appropriate and another end coupled to the subsea mooring apparatus 1 .

[0105] In the exemplary subsea mooring deployment system 30 described herein, at least one of the umbilicals 18 are operable to provide a conduit for pressurised fluid (or as will be subsequently described, cement or grout) to be delivered to the subsea mooring apparatus 1. Optionally, however, one or more additional umbilicals (not shown) may be operable to provide, for example, electrical power or to communicate controls, which may be advantageous in embodiments of the present invention that employ, for example, an electrically powered drilling means (not shown).

[0106] It may be that the umbilical(s) 18 are connected to a Remotely Operated Vehicle (ROV) configured to pump pressurised fluid through the fluid inlet 9 of the subsea mooring apparatus 1. Optionally, umbilical(s) connected to an ROV may be configured to provide, for example, electrical power or to communicate controls to the subsea mooring apparatus 1. It may be that an ROV is directly connected to the subsea mooring apparatus 1 via the fluid inlet 9. Generally, fluid pumped through such an umbilical (not shown) from said ROV is seawater 50.

[0107] The umbilicals 18 may be connected to the subsea mooring apparatus 1 via the fluid inlet 9. The umbilicals 18 may also be selectively and interchangeably connected to the various topside equipment such as a pumping mechanism 20 or, more specifically, to a pressurised fluid pump or a cement pump.

[0108] It may be that drilling fluid is pumped through the fluid inlet 9 to drive rotation of the drill bits 8a, 8b, 8c. Alternatively, if subsea soil / rock conditions permit (and preferably due to its abundance and zero cost) it may be that seawater 50 is pumped through the fluid inlet 9 to drive rotation of the drill bits 8a, 8b, 8c. Pumping seawater 50 can be advantageous as seawater 50 is inherently abundant in the present application (i.e. offshore / subsea applications), and conveniently the use of seawater 50 may greatly reduce the need for transportation and storage resources that are otherwise essential for any such alternative suitable fluids.

[0109] It may be that the umbilicals 18 are connected to a pumping mechanism 20 that is configured to pump pressurised fluid, such as drilling fluid or seawater 50, through the fluid inlet 9 of the subsea mooring apparatus 1 from, for example, a drilling fluid storage tank (not shown) that may be equipped on the upper deck of the vessel 15, or alternatively directly from the sea 50. The fluid may be pressurised, for example, by a pumping mechanism 20 to a higher pressure than that of the pressure of seawater 50 taken from the sea 50 at the location of use of the subsea mooring apparatus 1.

[0110] It may be that the umbilical(s) 18 is / are subsequently connected to a pumping mechanism 20 that is configured to pump cement or grout through the fluid inlet 9 of the subsea mooring apparatus 1 from, for example, a cement storage tank 21 or a grout storage tank (not shown) that may be equipped on the upper deck of the vessel 15.

[0111] DESCRIPTION OF THE ROTATION OF THE DRILL BITS

[0112] Fig. 6 shows the next stage of operation of the exemplary subsea mooring deployment system 30 following on from that of Fig. 4, where the subsea mooring apparatus 1 of Fig. 1 has been lowered to the seabed 51 from the side of the vessel 15. When the subsea mooring apparatus 1 has been deployed and subsequently lowered to the predetermined or impromptu installation location on the seabed 51 , pressurised fluid may be pumped through the fluid inlet 9 via umbilicals 18 connected to the pumping mechanism 20 on the upper deck of the vessel 15. At this stage of operation, said pumping mechanism 20 is connected to, for example, the drilling fluid storage (not shown) that may be equipped on the upper deck of the vessel 15, or alternatively directly from the sea 50.

[0113] Referring now to Fig. 7, a leg 2a, 2b, 2c of the subsea mooring apparatus 1 (in embodiments of which fluid is pumped to drive rotation of the drill bits 8a, 8b, 8c) comprising a throughbore forming a conduit 22 for conveying pressurised fluid is shown. The throughbore of each cylindrical / hollow tubular leg 2a, 2b, 2c comprises a respective conduit 22 for conveying the pressurised fluid. The conduit 22 of each leg 2a, 2b, 2c conveys the pressurised fluid that is directed into the fluid inlet 9 (through the pipe arrangements 10 and manifold device 11) towards the drill bit 8a, 8b, 8c of each leg 2a, 2b, 2c. In embodiments of the present invention in which fluid is pumped to drive rotation of the drill bits 8a, 8b, 8c, each of the legs 2a, 2b, 2c will typically comprise a motive and / or mechanical tool / device 23 associated with each respective drill bit 8a, 8b, 8c, said motive / mechanical tool / device 23 configured to translate hydraulic pressure / power and flow from the pressurised fluid into mechanical / rotational energy to rotate the drill bits 8a, 8b, 8c. Said motive and / or mechanical / tool device 23 may be, for example, a fluid motor 23 or a Positive Displacement Motor (PDM) 23.

[0114] In embodiments of the present invention in which each of the legs 2a, 2b, 2c comprise a fluid motor 23 configured to translate hydraulic pressure / power and flow into mechanical / rotational energy, each drill bit 8a, 8b, 8c is rotated by said respective fluid motor 23 disposed in fluid communication with the conduit 22 of each leg 2a, 2b, 2c. Similarly, in embodiments of the present invention in which each of the legs 2a, 2b, 2c comprise a PDM 23 configured to translate the hydraulic pressure / power and flow into mechanical / rotational energy, each drill bit 8a, 8b, 8c is rotated by said respective PDM 23 disposed in fluid communication with the conduit 22 of each leg 2a, 2b, 2c.

[0115] Examples of suitable fluid motors / PDM include the “Dynomax” Mud Lubrication Motor (https: / / www.dynomaxdrillingtools.com / mud-lubricated-motors) and the “Cougar Drilling Solutions” Motor (htps: / / cougards.com / drilling-motors / ), but other suitable fluid motors / PDM could also be used.

[0116] In the example shown in Fig. 7, the internal arrangement of the leg 2a, 2b, 2c may be adapted for use with a fluid motor 23 comprising a fluid motor rotor and a fluid motor stator, with the fluid motor stator comprising one or more sets of nozzles. Each of the legs 2a, 2b, 2c is arranged such that fluid conveyed through their respective conduit 22 flows through the respective fluid motor 23 of each leg 2a, 2b, 2c, thereby flowing through one or more sets of nozzles within the fluid motor stator and therein driving rotation of the fluid motor rotor. The respective stator of each fluid motor 23 of each leg 2a, 2b, 2c is typically secured to the in use lower most end of said leg 2a, 2b, 2c; and the rotor of the respective fluid motor 23 of each leg 2a, 2b, 2c is rotationally connected to the in use upper most end of the respective drill bit 8a, 8b, 8c of each leg 2a, 2b, 2c in order for the pressurised fluid flowing through the sets of nozzles within the stator (and therein driving rotation of the rotor) to drive rotation of the drill bits 8a, 8b, 8c. In the example shown in Fig. 7, the internal arrangement of the leg 2a, 2b, 2c may alternatively be adapted for use with a PDM 23 where the PDM 23 comprises a PDM rotor and a PDM stator. The stator of the PDM 23 comprises at least two lobes. The rotor of the PDM 23 will comprise one less lobe than that of the stator of the PDM 23. The rotor of the PDM 23 typically comprises a helical shape, and the stator of the PDM 23 also typically comprises the same helical shape as the rotor of the PDM 23. Advantageously, when the rotor has one less lobe than the stator, a cavity is provided between the PDM rotor and the PDM stator which provides passage for the pressurised fluid. When pressurised fluid is conveyed into the cavity, the cavity acts as a wedge under the pressure of the pressurised fluid and (as the pressurised fluid cannot be compressed) the pressurised fluid applied to the top of the wedge forces the rotor to move, which (given the helical shape of the rotor and stator of the PDM 23) causes the rotor of the PDM to rotate. The respective stator of each PDM 23 of each leg 2a, 2b, 2c is typically secured to the in use lower most end of said leg 2a, 2b, 2c; and the rotor of the respective PDM 23 of each leg 2a, 2b, 2c is rotationally connected to the in use upper most end of the respective drill bit 8a, 8b, 8c of each leg 2a, 2b, 2c in order for the pressurised fluid flowing through the cavity between the PDM rotor and the PDM stator (and therein driving rotation of the PDM rotor) to drive rotation of the drill bits 8a, 8b, 8c.

[0117] A crossover mechanism 24 is used if needs be (particularly if the outer diameter and / or threads are not matched between the drill bit 8a, 8b, 8c and the respective fluid motor rotor and / or PDM rotor) to rotationally connect the drill bit 8a, 8b, 8c to said respective rotor. Advantageously, the crossover mechanism 24 provides connection between the fluid motor 23 and / or PDM 23 and the drill bit 8a, 8b, 8c. Examples of crossover mechanisms that can be used in accordance with the present invention can be found at, for example, “Drilling Tools International” (https: / / www.drillingtools.com / subassem- blies) and “Work Strings International” (htps: / / workstringsinternational.com / drilling- equipment / drillstrinq-accessories / crossover-subs / ) but other suitable crossover mechanisms could also be used.

[0118] Now referring to Fig. 8, the next stage of operation of the exemplary subsea mooring deployment system 30 (following on from that of Fig. 6) is shown, where fluid is pumped through the legs 2a, 2b, 2c to drive rotation of the drill bits 8a, 8b, 8c to drill a borehole having a throughbore into the seabed 51.

[0119] The drill bit 8a, 8b, 8c of each respective leg 2a, 2b, 2c has a cross sectional surface area that is greater than any other cross-sectional area of said respective leg 2a, 2b, 2c. In this way the drill bit 8a, 8b, 8c (coupled to each respective leg 2a, 2b, 2c) is configured to drill a throughbore defining an annulus 27, wherein said annulus 27 is defined by the gap between the outer surface of each leg 2a, 2b, 2c and the inner surface of said throughbore of the borehole drilled by the drill bit 8a, 8b, 8c (coupled to each of the respective legs 2a, 2b, 2c).

[0120] Fig. 9 is a side view of one of the legs 2a, 2b, 2c of the subsea mooring apparatus 1 within the created annulus 27 surrounded by the seabed 51 during the stage of operation of the exemplary subsea mooring deployment system 30 shown in Fig. 8. Fig. 9 illustrates the direction of fluid flow as the pressurised fluid is pumped through the fluid inlet 9, through the manifold device 11 , through the pipe arrangements 10 and downwards through the conduit 22 of a leg 2a, 2b, 2c. The pressurised fluid is directed downwards through the conduit 22 of each leg 2a, 2b, 2c, as illustrated by the downwardly pointing arrows in Fig. 9, and through the fluid motor 23 (and through the nozzles within the stator) and / or through the PDM 23 (and through the cavity between the PDM stator and PDM rotor) which drives rotation of the rotor. As the rotor of the fluid motor 23 and / or the rotor of the PDM 23 is rotationally connected to the drill bit 8a, 8b, 8c, the conveyed flow of pressurised fluid (flowing through the nozzles within the stator and / or flowing through the cavity) drives rotation of the drill bits 8a, 8b, 8c.

[0121] After flowing through the conduit 22 and through fluid motor 23 and / or through the PDM 23, the pressurised fluid is then directed upwards (due to hitting the bottom of the borehole) through the annulus 27, as illustrated by the upwardly pointing arrows in Fig. 9. Advantageously, fluid directed out of each of the legs 2a, 2b, 2c, via the fluid outlet ports (not shown), is circulated in an upward direction within the drilled hole towards the seabed 51 , which circulates any swarf, sediment or any other debris or drill cuttings to the seabed 51. Each leg 2a, 2b, 2c comprises a fluid outlet port / a series of fluid outlet port(s) (not shown) for providing a fluid outlet from the conduit 22. The fluid outlet port(s) may comprise an arrangement of nozzles (not shown), especially in embodiments comprising a fluid motor 23. Alternatively, the fluid outlet port(s) may comprise a bypass valve, or dump valve (not shown), especially in embodiments comprising a PDM 23. The drill bit 8a, 8b, 8c may comprise said series of downwardly or outwardly directed outlet port(s) (not shown). The fluid outlet port(s) are arranged within the conduit 22 proximate to the lower drill end of the legs 2a, 2b, 2c, and are therefore conveniently positioned lower than the stator. Advantageously, positioning the fluid outlet ports below the stator ensures that the fluid can be directed through the fluid motor 23 1 through the PDM 23 to drive rotation of the drill bit 8a, 8b, 8c of each leg 2a, 2b, 2c prior to exiting the legs 2a, 2b, 2c and more preferably prior to exiting the drill bit 8a, 8b, 8c via the fluid outlet ports.

[0122] Examples of suitable drill bits that can be used in accordance with the present invention can be found at, for example, “Baker Hughes (https: / / www.bakerhughes.com / drill- ing / drill-bits) and “SLB Solutions” (htps: / / www.slb.com / companies / smith-bits) but other suitable drill bits could also be used.

[0123] DESCRIPTION OF THE CONTRA-ROTATION OF THE DRILL BITS

[0124] At least one of the drill bits 8a, 8b, 8c is configured to rotate in a first direction whilst drilling into the seabed 51 and at least one other of said drill bits 8a, 8b, 8c is configured to rotate in a second direction, opposite to said first direction, whilst drilling into the seabed 51 . The first direction may be clockwise and the second direction may be anticlockwise, or vice versa. In the example subsea mooring apparatus 1 shown in Figs. 1-3, at least one first leg 2a, 2b, 2c (for example leg 2a) comprises an inversed rotation arrangement relative to a rotational arrangement of at least one second leg 2a, 2b, 2c (for example legs 2b and 2c), such that rotation of the inversed rotational arrangement of said first leg 2a is in a first direction and rotation of the rotational arrangement of said second legs 2b, 2c is in a second opposite direction.

[0125] At least one leg 2a, 2b, 2c (for example leg 2a) comprises a fluid motor 23 and / or a PDM 23 configured to rotate in a first direction, and at least one leg 2a, 2b, 2c (for example legs 2b and 2c) comprises a fluid motor 23 and / or a PDM 23 configured to rotate in a second opposite direction. Conveniently, inversely arranged fluid motors and inversely arranged PDM are widely available. Examples of suitable inversely arranged fluid motors / inversely arranged PDM include the “Dynomax” Mud Lubrication Motor (https: / / www.dynomaxdrillingtools.com / mud-lubricated-motors) and the “Cougar Drill-ing Solutions” Motor (https: / / cougards.com / drilling-motors / ), but any other suitable inversely arranged fluid motors / inversely arranged PDM could also be used.

[0126] In embodiments of the present invention in which each of the legs 2a, 2b, 2c comprise a fluid motor 23 configured to translate hydraulic pressure / power and flow into mechanical / rotational energy, said inversed rotational arrangement may comprise an inversely arranged fluid motor 23 when compared to the fluid motor 23 of said second leg 2a, 2b, 2c. The stators of the fluid motor 23 of said inversed arrangement for example comprises one or more sets of inversely arranged nozzles. The inversely arranged nozzles of the inversed rotational arrangement cause the drill bit 8a, 8b, 8c of the inversed rotational arrangement to be driven by the pressurised fluid flowing through the sets of nozzles within the stator (and therein driving inversed rotation of the rotor) to drive inversed rotation of the drill bits 8a, 8b, 8c (in said first opposite direction).

[0127] Said inversely arranged nozzles are preferably arranged / angled in an opposite / reversed direction to the nozzles of said at least one second leg 2a, 2b, 2c, such that that fluid conveyed through the conduit 22 of said inversely arranged leg 2a, 2b, 2c flows through the sets of inversely arranged nozzles within the stator, therein driving rotation of the rotor in said first opposite direction.

[0128] Alternatively, in embodiments of the present invention in which each of the legs 2a, 2b, 2c comprise a PDM 23 configured to translate hydraulic pressure / power and flow into mechanical / rotational energy, said inversed rotational arrangement may comprise an inversely arranged PDM 23 when compared to the PDM 23 of said second leg 2a, 2b, 2c. The rotor and the stator of the PDM 23 of said inversed arrangement for example comprises an inversely arranged helical shape. The inversely arranged helical shape (of the rotor and stator of the PDM 23) of the inversed rotational arrangement cause the drill bit 8a, 8b, 8c of the inversed rotational arrangement to be driven by the pressurised fluid flowing through the cavity (and therein driving inversed rotation of the rotor) to drive inversed rotation of the drill bits 8a, 8b, 8c (in said first opposite direction). Said inversely arranged helical shape is preferably arranged / angled in an opposite / reversed direction to the helical shape of said at least one second leg 2a, 2b, 2c, such that that fluid conveyed through the conduit 22 of said inversely arranged leg 2a, 2b, 2c flows through the cavity between the inversely arranged helical shapes of the rotor and the stator, therein driving rotation of the rotor in said first opposite direction.

[0129] Advantageously, at least one of the drill bits 8a, 8b, 8c being arranged to spin or rotate in one rotational direction and at least of the other drill bits 8a, 8b, 8c is arranged to spin or rotate in the other rotational direction prevents the entire subsea mooring apparatus 1 from crawling around / rotating around. If that happened, the drilling action would not actually drill into the ground but rather would crawl around in a circle.

[0130] Furthermore, at least one of the drill bits 8a, 8b, 8c being arranged to spin in one rotational direction and at least of the other drill bits 8a, 8b, 8c is arranged to spin in the other rotational direction provides the advantage that multiple piles can be effectively driven into the seabed, and the drill bits 8a, 8b, 8c (coupled to each respective lower end of the legs 2a, 2b, 2c) are therefore operable to drill simultaneously, which reduces installation time and costs of the subsea mooring apparatus 1 .

[0131] In alternative prior art mooring systems not featuring contra-rotating drilling means, it is not always possible and / or effective to drill multiple drilling means simultaneously (as the entire mooring system would be prone to crawling around / rotating around and not actually drilling into the ground). As such, in said alternative mooring systems it is estimated to require at least three times longer to install than the present invention (specifically, when considering the simultaneous operation of the three legs / drilling means of the example subsea mooring apparatus 1 herein described).

[0132] In the example shown, the conduits 22 of each of the legs 2a, 2b, 2c are in fluid communication with one another, such that the pressure is substantially equalised in the conduits 22 of each leg 2a, 2b, 2c. Advantageously, having substantially equalised pressure in the conduits 22 of each leg 2a, 2b, 2c provides equalised magnitudes of drill speed and torque. DESCRIPTION OF THE TELESCOPIC LEGS

[0133] The legs 2a, 2b, 2c of the subsea mooring apparatus 1 may be telescopic legs 2a, 2b, 2c. Said telescopic legs 2a, 2b, 2c may comprise a plurality of concentric tubular sections 12, 13, 14 operable to slide into one another such that the telescopic legs 2a, 2b, 2c are configured to telescopically extend downwardly into the seabed 51 in use, providing a significantly greater distance than the legs occupy when in their transportation / deployment / retracted configuration, thereby significantly increasing the pile strength they provide to the subsea mooring apparatus 1.

[0134] The telescopic legs 2a, 2b, 2c may be operable to change from: a retracted configuration, in which the concentric tubular sections 12, 13, 14 are retracted such that the length of the leg 2a, 2b, 2c is shortened; to an extended configuration, in which the concentric tubular sections 12, 13, 14 are slidably extended such that the length of the leg 2a, 2b, 2c is increased (compared to the retracted configuration).

[0135] Fig. 10 shows an example of a telescopic leg 2a, 2b, 2c in which said telescopic leg 2a, 2b, 2c is in the retracted configuration. The telescopic leg 2a, 2b, 2c will typically be in said retracted configuration during the transportation / deployment through the body of water stages of operation of the exemplary subsea mooring deployment system 30 shown in Figs. 4-6.

[0136] An example of a telescopic leg 2a, 2b, 2c in the extended configuration is shown in Fig. 7. The telescopic leg 2a, 2b, 2c will typically transition into said extended configuration during the drilling stage of operation of the exemplary subsea mooring deployment system 30.

[0137] Advantageously, the ability of the telescopic leg 2a, 2b, 2c to telescopically extend downwardly enables an increased depth of the pile or foundation provided by them as the drill bit 8a, 8b, 8c on their lower end progresses further into the sub-surface terrain.

[0138] Each of the plurality of concentric tubular sections 12, 13, 14 includes an outermost tubular section 12 and an innermost tubular section 14, as well as further intermediate tubular section 13 adjacently arranged between the outermost tubular section 12 and the innermost tubular section 14. Each of plurality of concentric tubular sections 12, 13, 14 are slidably connected to an adjacently arranged concentric tubular section, such that said intermediate tubular section 13 is configured to be slidably retracted into the said outermost tubular section 12 and / or slidably extended from the said outermost tubular section 12. Similarly, the said innermost tubular section 14 is configured to be slidably retracted into the said intermediate tubular section 13 and / or slidably extended from the said intermediate tubular section 13.

[0139] The outermost tubular section 12 of each telescopic leg 2a, 2b, 2c is affixed to the frame 3 and defines the uppermost end or base of the telescopic leg 2a, 2b, 2c. The outermost tubular section 12 of each telescopic leg 2a, 2b, 2c is the uppermost tubular section when the telescopic leg 2a, 2b, 2c is in the extended configuration. The lowermost end of the innermost tubular section 14 of each telescopic leg 2a, 2b, 2c is coupled (albeit via the fluid motor 23 I PDM 23 (and the crossover 24 if needed)) to the uppermost end of the drill bit 8a, 8b, 8c respective to each telescopic leg 2a, 2b, 2c. The innermost tubular section 14 of each telescopic leg 2a, 2b, 2c is therefore the lowermost (in use) tubular section when the telescopic leg 2a, 2b, 2c is in the extended configuration.

[0140] Each of the concentric tubular sections 12, 13, 14 comprises an upper face having a cross sectional area 28. When the pressurised fluid is directed downwardly during pumping thereof, the pressurised fluid acts against the cross-sectional area 28 of the upper face of each of the concentric tubular section(s) to create a downwardly directed force against said cross sectional area 28 of the upper face of each of the concentric tubular section(s), which thereby causes the tubular sections 12, 13, 14 to extend downwardly. In this way, the cross-sectional area 28 of the upper face of each of the concentric tubular sections 12, 13, 14 acts as a piston. Furthermore, there is a high pressure volume within the conduit 22 of each leg 2a, 2b, 2c (due to high pressure pumping of the pressurised fluid) during the drilling stage of operation which causes the fluid to expand which thereby exerts further downwardly directed force against the cross sectional area 28 of the upper face of each of the concentric tubular sections 12, 13, 14.

[0141] Advantageously, each of the telescopic legs 2a, 2b, 2c further comprises a locking mechanism 25 provided between each adjacent tubular section 12, 13, 14, said locking mechanism 25 configured to lock the extended tubular sections 12, 13, 14 in said extended configuration, thereby preventing overextension and disconnecting of the tubular sections 12, 13, 14. The locking mechanism 25 is made up of an arrangement of mechanical stops 25 configured to be engaged when the telescopic sections 12, 13, 14 have extended to a maximum extension limit. The telescopic legs 2a, 2b, 2c further comprise mechanical seals 26 provided between each adjacent tubular section 12, 13, 14, where said mechanical seals 26 are configured to resist fluid pressure and prevent fluid from escaping between each adjacent tubular section of the telescopic leg 2a, 2b, 2c. Each of the mechanical seals 26 are either housed: in a groove (not shown) externally around the tubular section that is the innermost arranged of each respectively adjacent tubular sections 12, 13, 14; or in a groove (not shown) internally within the tubular section that is the outermost arranged of each respectively adjacent tubular sections 12, 13, 14.

[0142] This arrangement of the telescopic legs 2a, 2b, 2c makes the telescopic legs 2a, 2b, 2c more compact, which is specifically advantageous during transportation and assembly of the telescopic leg 2a, 2b, 2c and / or the subsea mooring apparatus 1. Furthermore, the telescopic leg 2a, 2b, 2c provide the ability to selectively lengthen the depth of the pile I foundation provided by the installation of the subsea mooring apparatus 1 in the seabed 51.

[0143] Advantageously, the telescopic leg 2a, 2b, 2c can be selectively lengthened by increasing (or selectively shortened by decreasing) the: length of the concentric tubular sections 12, 13, 14; and / or number of concentric tubular sections 12, 13, 14 (on each telescopic leg 2a, 2b, 2c).

[0144] DESCRIPTION OF SECURING THE APPARATUS IN THE SEABED

[0145] After the drill bits 8a, 8b, 8c of each leg 2a, 2b, 2c have drilled sufficiently (such that the lowermost in use surface of the frame 3 is flush against the seabed and / or the telescopic legs 2a, 2b, 2c have full extended) the pumping mechanism 20 (that is pumping pressurised fluid) is disengaged to stop the flow of pressurised drilling fluid in the umbilicals 18. Cement (or grout or other suitable securing material) may then be pumped through the fluid inlet 9 via the umbilicals 18 connected to the pumping mechanism 20 on the upper deck of the vessel 15. At this stage of operation, said pumping mechanism 20 is connected to cement storage 21 that is equipped on the upper deck of the vessel 15. The umbilicals 18 therefore connect the pumping mechanism 20 to the fluid inlet 9 of the subsea mooring apparatus 1 to pump cement through the legs 2a, 2b, 2c and into the annulus 27.

[0146] Fig. 11 is a side view of one of the legs 2a, 2b, 2c of the subsea mooring apparatus 1 within the annulus 27 of the drilled borehole surrounded by the seabed 51 during the stage of operation of the exemplary subsea mooring deployment system 30 subsequent to stage of operation shown in Figs. 8-9, in which cement is pumped through the legs 2a, 2b, 2c and into the annulus 27 to secure the subsea mooring apparatus 1 in the seabed.

[0147] Fig. 11 illustrates the direction of cement (or grout) flow in a leg 2a, 2b, 2c as the cement (or grout) is pumped through the fluid inlet 9, through the manifold device 11 , through the pipe arrangements 10 and through the conduit 22 of a leg 2a, 2b, 2c. The cement (or grout) is directed downwards through the conduit 22 of each leg 2a, 2b, 2c, as illustrated by the downwardly pointing arrows in Fig. 11 , and through the fluid motor 23 (and thereby through the nozzles within the stator) and / or through the PDM 23 (and thereby through the cavity between the PDM stator and PDM rotor). Although the rotor is rotationally connected to the drill bit 8a, 8b, 8c, the cement (or grout) flowing through the nozzles within the fluid motor stator and / or through the cavity between the stator and rotor of the PDM will not sufficiently drive rotation of the drill bits 8a, 8b, 8c. This is mainly due to the material properties of cement (and grout), namely, the substantially higher fluid viscosity that cement (and grout) attributes when in comparison to seawater 501 drilling fluid, which typically means that cement (or grout) is pumped at a much lower rate through the legs 2a, 2b, 2c and through the fluid motor 23 or PDM 23. Furthermore, as the cement (or grout) is typically only pumped through the legs 2a, 2b, 2c when the frame 3 is flush against the seabed 51 and / or the telescopic legs 2a, 2b, 2c have full extended, it is considered inconsequential if the rotor and therefore the drill bits 8a, 8b, 8c are rotationally driven. After flowing through the conduit 22 and through fluid motor 23 and / or through the PDM 23, the cement (or grout) is then directed upwards (due to the lower end of the borehole) through the annulus 27 up towards the seabed 51 , as illustrated by the upwardly pointing arrows in Fig. 11 . The cement (or grout) continues to be pumped until the conduit 22 and the annulus 27 of each leg 2a, 2b, 2c is filled with cement (or grout).

[0148] When the annulus 27 and the conduit 22 of each leg 2a, 2b, 2c is filled with cement (or grout) the pumping mechanism 20 is disengaged to stop the flow of cement (or grout) in the umbilicals 18. The cement will then gradually cure or harden to secure the subsea mooring apparatus 1 in the seabed 51.

[0149] After the annulus 27 and the conduit 22 of each leg 2a, 2b, 2c is filled with cement (or grout) the wire rope 19 of the crane 16 may be detached from the subsea mooring apparatus 1 or the connecting mechanism 7 and subsequently retracted to the upper deck of the vessel 15 via the crane 16. The umbilicals 18 may also be detached from the fluid inlet 9 and reeled back to the upper deck of the vessel 15 via the umbilical reeler 17.

[0150] After the cement (that has filled annulus 27 and the conduit 22 of each leg 2a, 2b, 2c) has hardened and the subsea mooring apparatus 1 has therefore been secured in the seabed 51 , a tether (such as a rope or chain or other mooring line (not shown)) may then be coupled to the subsea mooring apparatus 1 (for example, via the connecting mechanism / chain connector 7) in order to provide a mooring line connected to, or for future connection to, large structures such as an offshore floating wind turbine or other large floating structures; said mooring line therefore anchoring said large structures.

[0151] Modifications and improvements may be made to the hereinbefore described embodiments without departing from the scope of protection.

Claims

CLAIMS:-1. A subsea mooring apparatus comprising: a downwardly extending arrangement of at least two legs; and a drill bit coupled to each respective leg, wherein each said drill bit is configured for drilling into a seabed; and wherein at least one of said drill bits is configured to rotate in a first direction whilst drilling into the seabed and at least one other of said drill bits is configured to rotate in a second direction, opposite to said first direction, whilst drilling into the seabed.

2. A subsea mooring apparatus according to claim 1, further comprising a frame, wherein the arrangement of legs extend downwardly from the frame.

3. A subsea mooring apparatus according to claim 1 , further comprising at least one connecting mechanism for coupling the apparatus to a mooring tether used to couple an offshore wind turbine to the apparatus.

4. A subsea mooring apparatus according to any preceding claim, wherein the said drill bit is coupled to a lower end of each respective leg.

5. A subsea mooring apparatus according to any preceding claim, wherein the rotation of each drill bit is driven by seawater by a pumping mechanism, to a higher pressure than the pressure of seawater taken from the sea at the location of use of the apparatus.

6. A subsea mooring apparatus according to claim 5, wherein the apparatus further comprises at least one fluid inlet and wherein said fluid is pumped from a vessel via at least one umbilical pipe by the pumping mechanism to said at least one fluid inlet.

7. A subsea mooring apparatus according to claim 6, wherein each leg comprises a conduit for conveying the pressurised fluid from the said at least one fluid inlet to the drill bit of each leg.

8. A subsea mooring apparatus according to any of claims 5 to 7, wherein each of the legs comprises a motive device associated with each respective drill bit, wherein said motive device is configured to translate hydraulic pressure / power and flow from the pressurised fluid into rotational energy to rotate the drill bits.

9. A subsea mooring apparatus according to any of claims 5 to 8, wherein each leg comprises a fluid motor and each drill bit is rotated by a fluid motor disposed in fluid communication with the conduit of each leg, wherein each fluid motor comprises a rotor and a stator and said stator comprises one or more sets of nozzles.

10. A subsea mooring apparatus according to claim 9, wherein each leg is arranged such that fluid conveyed through the conduit flows through the fluid motor of each leg, flowing through one or more sets of nozzles within the stator and therein driving rotation of the rotor.

11. A subsea mooring apparatus according to of claim 10, wherein the rotor is rotationally connected to the drill bit, such that rotation of the rotor is configured to rotate the drill bit.

12. A subsea mooring apparatus according to any of claims 5 to 8, wherein each leg comprises a Positive Displacement Motor (PDM) and each leg is arranged such that fluid conveyed through the conduit flows through a PDM of each leg, flowing through a cavity between a rotor and a stator of the PDM and therein driving rotation of the PDM rotor.

13. A subsea mooring apparatus according to claim 12, wherein the rotor is rotationally connected to the drill bit, such that rotation of the rotor is configured to rotate the drill bit.

14. A subsea mooring apparatus according to any preceding claim, wherein the drill bit of each respective leg comprises a cross sectional surface area that is greater than any other cross-sectional area of said respective leg, such that the drill bit coupled to each respective leg is configured to drill a throughbore defining an annulus between: an outer surface of each leg of each respective drill bit; andthe inner surface of said throughbore drilled by the drill bit.

15. A subsea mooring apparatus according to any preceding claim, wherein the said first direction is clockwise and the said second direction is anti-clockwise.

16. A subsea mooring apparatus according to any preceding claim, wherein at least one first leg comprises an inversed rotational arrangement relative to a rotational arrangement of at least one second leg, such that rotation of the inversed rotational arrangement of said first leg is in said first direction and rotation of the rotational arrangement of said second leg is in said second direction.

17. A subsea mooring apparatus according to any preceding claim, wherein at least one leg comprises a motive device configured to rotate in a first direction and at least one leg comprises a motive device configured to rotate in a second opposite direction.

18. A subsea mooring apparatus according to any preceding claim, wherein the conduits of each of the legs are in fluid communication such that the pressure is substantially equalised in the conduits of each leg.

19. A subsea mooring apparatus according to any preceding claim, wherein at least two of the drill bits are operable to drill simultaneously.

20. A subsea mooring apparatus according to any preceding claim, wherein said at least one of said drill bits is configured to rotate in the first direction whilst drilling into the seabed and said at least one other of said drill bits is configured to rotate in the second direction, (opposite to said first direction), whilst both said at least one and said at least one other of the drill bits are simultaneously drilling into the seabed.

21. A subsea mooring apparatus according to any preceding claim, wherein each of the legs that are operable to drill simultaneously are in fluid communication with one another such that pressurised fluid pumped through a fluid inlet is directed to each of the conduits of said legs that are operable to drill simultaneously.

22. A subsea mooring apparatus according to any preceding claim, wherein each leg comprises a telescopic leg configured to telescopically extend downwardly.

23. A subsea mooring apparatus according to any claim 22, wherein each telescopic leg comprises a plurality of concentric tubular sections operable to slide into one another and wherein the telescopic legs are configured to extend downwards as the drill bits continue drilling once the frame is on the seabed, such that the legs increase the depth of the foundation provided by them as the drill bit on their lower end progresses further into the sub-surface terrain, and wherein the telescopic legs are operable to change from: a retracted configuration, in which the concentric tubular sections are retracted such that the length of the leg is shortened; to an extended configuration, in which the concentric tubular sections are slidably extended such that the length of the leg is increased.

24. A subsea mooring apparatus according to either of claims 22 or 23, wherein each telescopic leg comprises a locking mechanism provided between each adjacent tubular section thereof, said locking mechanism configured to lock the extended telescopic sections.

25. A subsea mooring apparatus according to any of claims 22 to 24, wherein each concentric tubular section comprises an upper face having a cross sectional area, such that when pressurised fluid is directed downwardly, the pressurised fluid acts against the cross sectional area of the upper face of each of the concentric tubular section to create a force directed against said cross sectional area of the upper face of each of the concentric tubular section, and thereby downwardly extending the tubular sections.

26. A method of providing a subsea mooring, the method comprising the steps of:(A) Assembling a subsea mooring apparatus in accordance with claim 1;(B) Deploying the subsea mooring apparatus to the seabed;(C) Rotating at least one of said drill bits in a first direction whilst drilling into the seabed, and rotating at least one other of said drill bits in a second direction, opposite to said first direction, whilst drilling into the seabed.

27. A method of providing a subsea mooring according to claim 26, wherein the method further comprises the steps of:(D) Pumping pressurised fluid into a conduit within the subsea mooring apparatus to drive rotation of the drill bits therein drilling a borehole; and (E) Pumping cement into an annulus between the outer surface of the leg and the inner surface of the borehole to secure the apparatus in the seabed.

28. A method of providing a subsea mooring according to either claim 26 or 27, wherein step (C) further comprises rotating the at least one of said drill bits in a first direction whilst drilling into the seabed, and rotating the at least one other of said drill bits in a second direction, opposite to said first direction, whilst simultaneously drilling both said at least one and said at least one other of the drill bits into the seabed.

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