FLOATING PRODUCTION SYSTEM AND METHOD

FIELD OF THE DISCLOSURE

This disclosure relates to a floating production system and method.

BACKGROUND

Conventional systems for floating production and storage use is to store large amounts of extracted materials, such as dead crude oil, natural gas, and/or other extracted materials, in a ship-shaped vessel that is moored using a turret. Both moorings and risers may be used to moor the vessel. The turret is usually mounted in a large opening near the bow of the vessel. Turrets are complex, prone to failure, and expensive to manufacture and operate.

Turrets are typically complex turrets and some are costing upwards of one billion dollars. One such turret may comprise axial and toroidal swivels, high voltage slip rings, cryogenic export lines, mooring lines, and an electro-hydraulic drive.

The risers in turrets are distributed circumferentially and cannot be suspended in catenary. As a result, expensive strain monitoring instrumentation packages are mounted on the risers near touchdown.

Deepwater moorings for turret-moored ships are currently an arrangement of buoyant synthetic ropes, buoyant tanks that resist external pressure at depth, maneuvering chains, ground chains, and anchors. The anchor type may depend on the seabed conditions and may be suction, drag, and/or piled as dictated by those conditions.

The turret has an extremely complex interface with the moorings. Complicated procedures and machinery are needed to pull in and tension the lines. Since the environmental forces on the ship are transmitted to the moorings, a large number of mooring lines is required. Typically, sixteen lines are employed to secure the turret.

These moorings require compliance with the rules of the certification authority. This compliance stipulates inspection at specific intervals and may require the removal of a specific mooring line or lines for visual inspection above sea level, usually on land. Disconnection from the turret and removal is difficult and expensive.

When material is extracted from below the seabed, it is typically stored on ship-shaped vessels. Where the material is crude oil or similar material, the ship-shaped vessel may comprise several tanks that are distributed throughout the ships. Such tanks are partially filled, leaving space above the oil. This space above the oil is typically filled with a humid and corrosive atmosphere. This atmosphere has been known to corrode the tank linings, the tank structure, and even the deck supports and deck plating of the ship-shaped vessel. Protective coatings typically employed are costly and have limited effectiveness.

Ballast tanks are typically arranged down the sides of the oil tanks. The ballast tanks are configured to facilitate uniform loading on the ship's girders. The ballast tanks are also configured to facilitate maintenance of draft and stability of the ship, as the material is being loaded onto the ship or extracted from the ship. The ballast tanks are disposed in the vessel, external to the material storage tanks, making the water-carrying ballast tanks the most vulnerable to collisions, helping to avoid unintended spillage of material.

The amount of material, such as oil, gas, or other material, stored in the storage tanks creates point loads. The point loads require careful distribution throughout the vessel to minimize the effect of shear forces and bending moments caused by the shifting mass of the stored material. Improperly-distributed material may cause plates to buckle and may cause other, more significant, structural damage to the vessel.

Load-monitoring systems are employed to monitor the loading of the material into the ship and to control the loading of the material into the individual storage tanks. Load-monitoring systems may also monitor and manage the distribution of ballast water into the ballast tanks. Such systems are expensive to implement and operate. They typically require expert maintenance and monitoring. Additionally, such systems have many elements, which are prone to malfunction and breakage.

In load-monitoring systems, gauges are typically mounted in the tank top. The gauges may use radar or sonar to measure the depth of material, such as oil, in the tank. Based on these readings, the system may then compute the weight of the oil.

SUMMARY

One aspect of the disclosure relates to a floating production system. The floating production system may comprise a superstructure configured to float on the sea. The superstructure may have a first portion that is configured to rest above the surface of the sea and a second portion that is configured to rest below the surface of the sea. The floating production system may comprise a mooring system configured to moor the superstructure to the seabed.

In the prior art turrets, the risers are distributed circumferentially and cannot be suspended in catenary. Providing risers in catenary enables the principal stress at touchdown (a function of angle and tension at the top of the risers) to be controlled. As a result, expensive strain monitoring instrumentation packages are mounted on the risers near touchdown.

The mooring system may comprise a first end. The first end may be operatively connected to the superstructure. The first end may be configured to secure the mooring system to the superstructure. The mooring system may comprise a second end. The second end may be configured to secure the mooring system to the seabed. The mooring system may comprise a line. The line may be disposed between the first end and the second end. The line may be configured to facilitate the mooring of the superstructure to the seabed. The line may be a neutrally buoyant line.

The neutrally buoyant line may comprise a first line portion. The first line portion may extend from the superstructure through a first upper portion of the neutrally buoyant line. The second line portion may extend from the seabed through a second lower portion of the neutrally buoyant line. A neutrally buoyant pipe portion may extend between the first upper portion and the second lower portion of the neutrally buoyant line. The first line portion and/or the second line portion may be a chain, a cable, and/or a combination thereof.

The second end of the mooring system may comprise an anchor. The anchor may be configured to anchor the mooring system to the seabed. The second end of the mooring system may comprise a deadweight. The deadweight may be configured to counteract the buoyancy of the line.

The mooring system, comprising a neutrally buoyant line, may be arranged in catenary. Arranging the neutrally buoyant line in catenary may provide sufficient horizontal tension, to provide desirable horizontal stability for the floating production system. Arranging the neutrally buoyant line in catenary may reduce the tension and strain provided to the mooring system caused by its own weight.

Another aspect of the disclosure relates to a system for transporting material from the seabed to a semi-submersible platform on the surface of the sea. The system for transporting material from the seabed to a floating production system, on the surface of the sea, may comprise two or more pipes disposed between the seabed and a semi-submersible platform. The floating production system may be configured to float on the surface of the sea. The pipes may have a first end extending toward the semi-submersible platform. The pipes may have a second end extending toward the seabed. The pipes may be configured to facilitate the transport of liquid material from the seabed toward the surface of the sea. The pipes may be configured to convey injection water. The pipes may comprise control umbilicals to facilitate the provision of power, instrumentation, and/or other elements.

The system for transporting material from the seabed to the superstructure of the semi-submersible platform may comprise a pipe anchor. The system for transporting material from the seabed to the superstructure of the semi-submersible platform may be locked into a seabed template with piles. The pipe anchor may be configured to anchor at least one pipe to the seabed. The system for transporting material from the seabed to the semi-submersible platform may comprise a pipe connector, configured to secure at least one pipe to the semi-submersible platform. The pipe connector may be configured to facilitate the transfer of liquid material between the pipes and the semi-submersible platform.

The two or more pipes may be arranged in catenary. The two or more pipes may be arranged in a coplanar curtain. The radii of the bends in the pipes may be configured to be above a fatigue threshold. The pipe curtain may be suspended in catenary. The pipe curtain may be suspended in catenary, such that the radius of curvature of the pipes near the seabed can be controlled by measuring the angle of declination and the tension. The catenary suspension of the pipes may be controlled by one or more actuators. The one or more actuators for controlling parameters of the catenary of the pipes may be disposed on a superstructure of the floating production platform.

The system for transporting material from the seabed to the superstructure of the floating production system may comprise a bearing. The system for transporting material from the seabed to the superstructure of the floating production system may comprise multiple bearings. The bearing(s) may be disposed on the superstructure. The bearing(s) may be configured to secure the two or more pipes to the superstructure. The bearing(s) may be configured to reduce the bend moments in the two or more pipes. The bearing(s) may be adapted to facilitate the control of the bend of the radii of the two or more pipes arranged in catenary.

The system for transporting material from the seabed to the superstructure may comprise a ground riser. The ground riser may be configured to secure the two or more pipes to the seabed for transporting material from the seabed to the superstructure, which may comprise an anchor template. The anchor template may be configured to secure the two or more pipes to the seabed. The anchor template may be configured to withstand horizontal forces applied on the anchor template by the two or more pipes in catenary. The anchor template may be configured to facilitate decoupling of the two or more pipes.

Another aspect of the disclosure relates to a semi-submersible vessel. The semi-submersible vessel may comprise an upper portion configured to provide a platform. The semi-submersible vessel may comprise a lower portion. The lower portion of the semi-submersible vessel may comprise vertically-disposed legs, extending downward from the upper portion. The lower portion of the semi-submersible vessel may comprise a horizontally-disposed pontoon. The pontoon may extend between at least two of the legs. The pontoon may extend between at least two of the legs adjacent to the end of the legs opposite to the upper portion.

The lower portion may be configured to provide sufficient buoyancy to maintain the upper portion substantially above the water. The lower portion may be configured to store liquid matter. The liquid matter stored in the lower portion may comprise one or more of sea water, ballast water, and/or crude oil.

The lower portion may be comprised of rectangular tubular elements. The lower portion may comprise a plurality of cubic boxes. The lower portion may comprise a plurality of blocks. The boxes and/or blocks may take any dimensions. The boxes and/or blocks may be symmetrical. The boxes and/or blocks may be asymmetrical. Individual rectangular tubular elements and/or cubic boxes may be operably connected to adjacent rectangular tubular elements. The rectangular tubular elements and/or cubic boxes may be connected through one or more of welding, riveting, sticking, mechanical seal, bolting, using fish plates, and/or other connecting methods. The rectangular tubular elements and/or cubic boxes may be formed of metal. The rectangular tubular elements and/or cubic boxes may be formed from an alloy. The rectangular tubular elements and/or cubic boxes may be formed of steel.

The lower portion of the semi-submersible vessel may be configured to receive an amount of crude oil for storage. The lower portion of the semi-submersible vessel may be configured to eject an amount of ballast water. The lower portion of the semi-submersible vessel may be configured to eject an amount of ballast water in response to receiving an amount of crude oil for storage. The amount of ballast water ejected may be an amount corresponding to the amount of crude oil received for storage. The amount of ballast water ejected may be an amount selected based on a determination made to meet one or more parameters. The determination may be based, at least in part, on the amount of crude oil received, or to be received, for storage.

The semi-submersible vessel may comprise filtration tanks. The filtration tanks may be configured to receive and/or filter one or more contaminants from the ejected ballast water. The filtration tanks may be configured to eject filtered ballast water into the sea.

These and other features, and characteristics of the present technology, as well as the methods of operation and functions of the related elements of structure and the combination of parts and economies of manufacture, will become more apparent upon consideration of the following description and the appended claims with reference to the accompanying drawings, all of which form a part of this specification, wherein like reference numerals designate corresponding parts in the various figures. It is to be expressly understood, however, that the drawings are for the purpose of illustration and description only and are not intended as a definition of the limits of the invention. As used in the specification and in the claims, the singular form of “a”, “an”, and “the” include plural referents, unless the context clearly dictates otherwise.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates a semi-submersible platform, in accordance with one or more implementations;

FIG. 2 illustrates a system for transporting material from the seabed to a semi-submersible platform on the surface of the sea, in accordance with one or more implementations;

FIG. 3 illustrates a semi-submersible vessel configured to store liquids, in accordance with one or more implementations;

FIG. 4 illustrates a portion of a semi-submersible vessel configured to store liquids, in accordance with one or more implementations; and

FIG. 5 illustrates a cross-sectional view of a semi-submersible vessel configured to store material, in accordance with one or more implementations.

DETAILED DESCRIPTION

Deepwater moorings present difficulties in the use of chain or cable for a number of reasons. For example, the angle of catenary in the portion of the chain or cable adjacent to the semi-submersible platform is typically too steep to provide significant lateral restraint until the vessel is significantly off-station. The density of the chain may be so great that its own weight may cause fatigue in the chain, leaving no margin of error for environmental forces. Such situations cause the chains to fatigue prematurely, necessitating continual monitoring and maintenance, as well as inspection by regulatory authorities.

FIG. 1 illustrates a floating production system 100, in accordance with one or more implementations. The floating production system 100 may be configured to float on the sea surface 102. The floating production system 100 may comprise a superstructure 104 configured to float on the sea surface 102. The superstructure 104 may have a first portion 106 that is configured to rest above the surface of the sea 102 and a second portion 108 that is configured to rest below the surface of the sea 102. The floating production system 100 may comprise a mooring system 110 configured to moor the superstructure 104 to the seabed 112.

The mooring system 110 may comprise a first end 114. The first end 114 may be operatively connected to the superstructure 104. The first end 114 may be configured to secure the mooring system 110 to the superstructure 104. The mooring system 110 may comprise a second end 116. The second end 116 may be configured to secure the mooring system 110 to the seabed 112. The mooring system 110 may comprise a neutrally buoyant line 118. The neutrally buoyant line 118 may be disposed between the first end 114 and the second end 116 of the mooring system 110. The neutrally buoyant line 118 may be configured to facilitate the mooring of the superstructure 104 to the seabed 112.

The mooring system 110 may comprise neutrally buoyant line(s) 118 suspended from the semi-submersible platform 100. The neutrally buoyant line(s) 118 may be suspended in a relatively straight line. The neutrally buoyant line(s) 118 may connect with an upper chain and a lower chain. The neutrally buoyant line(s) 118 may be configured to have relatively equal tension at the top, as the tension at the bottom of the neutrally buoyant line(s) 118. The mooring system 110 may comprise multiple neutrally buoyant lines 118 suspended in catenary to form a curtain of neutrally buoyant lines 118. The curtain of neutrally buoyant mooring lines 118 suspended in catenary may provide horizontal force. The horizontal force provided by the neutrally buoyant mooring lines 118 suspended in catenary may facilitate maintaining the semi-submersible platform 118 over a desired area of the seabed. The multiple neutrally buoyant mooring lines 118, suspended in a catenary curtain, may comprise a section of the mooring system 110. The mooring system 110 may comprise multiple sections. For example, the mooring system may comprise a mooring section, a first side of the semi-submersible platform 100, and a mooring section on a second side of the semi-submersible platform 100. Mooring sections may be disposed on multiple sides of the semi-submersible platform 100. In some implementations, mooring sections may be disposed at and/or near the corners of the semi-submersible platform 100.

The neutrally buoyant line 118 may comprise a first line portion 120. The first line portion 120 may extend from the superstructure 104 through a first upper portion 120 of the neutrally buoyant line 118. The second line portion 122 may extend from the seabed 112 through a second lower portion 122 of the neutrally buoyant line 118. The first line portion 120 and/or the second line portion 122 may comprise a chain, a cable, and/or a combination thereof. The neutrally buoyant line 118 may comprise a neutrally buoyant pipe portion 124. The neutrally buoyant pipe portion 124 may extend between the first upper portion 120 and the second lower portion 122 of the neutrally buoyant line 118. The neutrally buoyant pipe portion 124 may have a length of the depth of the sea, i.e., the distance between the sea surface 102 and seabed 112. The neutrally buoyant pipe portion 124 may have a length of up to four times the depth of the sea, i.e., four times the distance between the sea surface 102 and seabed 112. The neutrally buoyant pipe portion 124 may have a length selected to comply with one or more parameters. The length of the neutrally buoyant pipe portion 124 may be selected to provide a pre-selected tension or range of tension in the neutrally buoyant pipe portion 124.

The neutrally buoyant pipe 124 may comprise pipe having a variety of diameters. The neutrally buoyant pipe 124 may comprise pipe having a variety of wall thicknesses. The neutrally buoyant line 118 may comprise a negatively-buoyant portion. The negatively-buoyant portion may be disposed toward the lower portion of the neutrally buoyant line 118. The neutrally buoyant line 118 may comprise a positively-buoyant portion. The positively-buoyant portion may be disposed toward the upper portion of the neutrally buoyant line 118. By using such a mooring system 110, the horizontal mooring stiffness may be increased. Increasing the horizontal mooring stiffness may decrease the offset of the semi-submersible platform 100, compared to using solid chains and/or cables. By using such mooring systems 110, the weight of the mooring system is less than using solid chains and/or cable, making the mooring system safer and easier to use.

The neutrally buoyant pipe 124 may comprise seals 132. The seals 132 may be disposed at either end of the neutrally buoyant pipe 124. The neutrally buoyant pipe 124 may comprise multiple seals 132 disposed along the neutrally buoyant pipe 124. The neutrally buoyant pipe 124 may comprise multiple sections of neutrally buoyant pipe. Each section of neutrally buoyant pipe may comprise seals.

The second end 116 of the mooring system 110 may comprise an anchor 126. The anchor 126 may be configured to anchor the mooring system 110 to the seabed 112. The second end 116 of the mooring system 110 may comprise a deadweight 128. The deadweight 128 may be configured to counteract the buoyancy of the neutrally buoyant pipe 124. The neutrally buoyant line 118 may comprise floats 130 disposed at intervals along the neutrally buoyant line 118 to provide buoyancy to the neutrally buoyant line 118.

In some implementations, the buoyancy of the buoyant line 118 may facilitate the moorings to be pre-laid. The neutrally buoyant lines 118 may be fitted with pennant buoys. The pennant buoys may be configured such that they may be retrieved from the sea. The pennant buoys may be configured such that they may be connected to the semi-submersible platform 100. The connection may be facilitated by anchor-handling tugs.

In some implementations, the upper portion 120 of the neutrally buoyant line 118 may pass through a lower bearing 134. The lower bearing 134 may be attached to the second portion 108 of the semi-submersible platform 100. The lower bearing 134 may be a swivel fairleader. In some implementations, the upper portion 120 of the neutrally buoyant line 118 may be connected to the superstructure 104 of the semi-submersible platform 100. The upper portion 120 of the neutrally buoyant line 118 may be connected to the superstructure 104 of the semi-submersible platform 100 by a second bearing 136. The second bearing 136 may be configured to facilitate the tensioning of the neutrally buoyant line 118 to a desired level of tension.

The mooring system 110 may be arranged in catenary. The lines comprising the neutrally buoyant lines 118 may be disposed in catenary to avoid bending moments in the lines. The lines arranged in catenary may provide increased horizontal tension on the floating production system to facilitate the floating production system to remain in location. The angle of the buoyant mooring line 118 at the top of the mooring system 110 may be provided by the following equations:

${xp}_{k} := A 1 a \cos h (\frac{D_{o, k} + A 1}{A 1})$

${Ψ1}_{k} := a \tan (\sin h (\frac{{xp}_{k}}{A 1}))$

$T 1_{k} := \frac{HT}{\cos {Ψ1}_{k}}$

$T 2_{k} := {[{(T 1_{k})}^{2} + G^{2} + 2 T 1_{k} G \sin ({Ψ1}_{k})]}^{\frac{1}{2}}$

${ΔΨ}_{k} := a \cos [\frac{[{(T 1_{k})}^{2} + {(T 2_{k})}^{2}] - G^{2}}{2 T 1_{k} T 2_{k}}]$

The double catenary profile may be provided by the following equations:

$x 0_{k} := {xp}_{k} \cdot (- 1) + A 2 \cdot a \sin h (\tan ({Ψ1}_{k} + Ψ_{k}))$

$y 0_{k} := A 2 \cdot (\cos h (\frac{{xp}_{k} + x 0_{k}}{A 2}) - 1) - A 1 \cdot (\cos h (\frac{{xp}_{k}}{A 1}) - 1)$

${xs}_{k} := A 2 \cdot a \cos h (\frac{S + y 0_{k} + A 2}{A 2}) - x 0_{k}$

The catenary length may be provided by the following equations:

$l 1_{k} := A 1 \cdot \sin h (\frac{{xp}_{k}}{A 1})$

$l 2_{k} := A 2 \cdot (\sin h (\frac{{xs}_{k} + x 0_{k}}{A 2}) - \sin h (\frac{{xp}_{k} + x 0_{k}}{A 2}))$

$x_{k} := {xs}_{k} - l 1_{k}$

$i := 0 \dots 100$

$z 1_{i, k} := - l 1_{k} + \frac{{xp}_{k}}{100} \cdot i$

$z 2_{i, k} := - l 1_{k} + {xp}_{k} + (\frac{{xs}_{k} - {xp}_{k}}{100}) \cdot i$

$y 1_{i, k} := A 1 \cdot (\cos h (\frac{z 1_{i, k} + l 1_{k}}{A 1}) - 1)$

$y 2_{i, k} := - y 0_{k} + A 2 \cdot (\cos h (\frac{z 2_{i, k} + l 1_{k} + x 0_{k}}{A 2}) - 1)$

The length of the line may be any length. For example, the length of the line may be in excess of 3×10⁴meters (e.g. l2_l=3.123×10⁴). The length of the line may be dependent on a number of factors. One such factor may be the depth of the ocean at the location of the floating production system. Another factor may be ocean currents, the density of the line, and/or other factors. The tension at the end of the line may be provided by:

${VT}_{k} := l 1_{k} \cdot μ1 + l 2_{k} \cdot μ2 + G$

$T_{k} := \sqrt{{HT}^{2} + {({VT}_{k})}^{2}}$

$Φ_{k} := a \tan (\frac{HT}{{VT}_{k}}) \cdot \frac{180}{π}$

Most risers presently used are hoses. Such hoses may be expensive and represent a large percentage of the field investment. Hoses may be pressure limited and necessitate the use of complex seabed equipment, including chokes, to reduce oil pressure on the seabed prior to entry to the hose. Hoses and the seabed equipment are typically cumbersome and expensive to manufacture and implement. In some instances, wells may be combined through manifolds to reduce the total number of hoses. Preventing cross-circulation between wells requires implementation of multiple check valves, which are prone to failure.

FIG. 2 illustrates a system 200 for transporting material from the seabed 202 to a semi-submersible platform 204 on the surface 206 of the sea, in accordance with one or more implementations. The system 200 for transporting material from the seabed 202 to a semi-submersible platform 204 on the surface 206 of the sea may comprise two or more pipes 208 disposed between the seabed 202 and a semi-submersible platform 204. The semi-submersible platform 204 may be configured to float on the surface 206 of the sea. The pipes 208 may have a first end 210 extending toward the semi-submersible platform 204. The pipes 208 may have a second end 212 extending toward the seabed 202. The pipes 208 may be configured to facilitate the transport of liquid material from the seabed 202 toward the surface 206 of the sea.

The system 200 for transporting material from the seabed 202 to the semi-submersible platform 204 may comprise a pipe anchor 214. The pipe anchor 214 may be configured to anchor at least one pipe 208 to the seabed 202. The system 200 for transporting material from the seabed 202 to the semi-submersible platform 204 may comprise a pipe connector 216 configured to secure at least one pipe 208 to the semi-submersible platform 204. The pipe connector 216 may be configured to facilitate the transfer of liquid material between the pipes 208 and the semi-submersible platform 204.

The two or more pipes 208 may be arranged in catenary. The two or more pipes 208 may be arranged in a coplanar curtain. The radii 218 of the bends 220 in the pipes 208 may be configured to be above a fatigue threshold.

The system 200 for transporting material from the seabed 202 to the semi-submersible platform 204 may comprise a bearing 222. The bearing 222 may be disposed on the semi-submersible platform 204. The bearing 222 may be configured to secure the two or more pipes 204 to the semi-submersible platform 204. The bearing 222 may be configured to reduce the bend moments in the two or more pipes 208. The bearing may be adapted to facilitate the control of the bend 220 of the radii 218 of the two or more pipes 208 arranged in catenary.

The system 200 for transporting material from the seabed 202 to the semi-submersible platform 204 may comprise a ground riser 224. The ground riser 224 may be configured to secure the two or more pipes 208 to the seabed 202. The system 200 for transporting material from the seabed 202 to the semi-submersible platform 204 may comprise an anchor template. The anchor template may be configured to secure the two or more pipes 208 to the seabed 202. The anchor template may be configured to withstand horizontal forces applied on the anchor template by the two or more pipes 208 in catenary. The anchor template may be configured to facilitate decoupling of the two or more pipes 208.

Well pressure may be applied to the pipes 208 in catenary without exceeding a threshold stress level in the pipes 208. Such systems 200 may comprise chokes 226. The chokes 226 may be operatively connected to the pipes 208. The chokes 226 may be placed on the deck 228 of the semi-submersible platform 204.

The catenary pipes 208 may be formed of any suitable material. The suitable material may have relatively high strength. The suitable material may have corrosion resistant properties. For example, the catenary pipes 208 may be formed from one or more of steel, aluminum, titanium, metal alloys, composites, plastics, and/or other suitable material. The catenary pipes 208 may be configured to facilitate the transport of water, gas, and/or other fluids. The system 200 may be configured to facilitate the transport of fluids from the sea surface 206 to the seabed 202. For example, the system 200 may be configured to facilitate water injection, gas reinjection, and/or other fluid transport. Internally clad pipes may be used for the transport of corrosive fluids.

The system 200 may comprise a second pipe encasing the catenary pipes 208. The second pipes may be configured to provide an additional barrier to guard against unintentional leaks and/or damage to the pipes 208.

Crude oil may be stored in a semi-submersible vessel using a seawater displacement system. The semi-submersible vessel may be a platform, a submerged barge, a grounded barge, and/or other vessel capable of storing liquid material. The semi-submersible vessel may comprise a steel ring pontoon, columns, or legs, and a deck. The steel ring pontoon, columns, and deck may be structurally integrated. The steel ring pontoon, columns, and deck may be structurally independent. Crude oil may be stored within storage tanks disposed in the pontoons and/or columns of the semi-submersible vessel. The storage tanks may be filled with water to provide ballast. The ballast water may cause the semi-submersible vessel to have a desired amount of draft. The ballast water may be ejected from the tanks in response to receiving an amount of crude oil into the tanks. The semi-submersible vessel may comprise secondary tanks to facilitate the adjustment of draft, stability, and/or other parameters of the semi-submersible vessel.

Typical systems for storing crude oil at off-shore production facilities include storage tanks distributed along long ship-shaped vessels. The storage tanks were typically only partially filled. Partially-filled storage tanks leave ullage, a space between the surface of the oil and the top of the storage tank. The atmosphere of the ullage is typically corrosive, humid, and can cause corrosion of the tanks. Acids may form, which may corrode the tanks, steel deck supports, deck plating, and other structural elements of the storage vessels. Protective coatings are costly and have limited effectiveness and shelf-lives.

FIGS. 3 and 4 illustrate a semi-submersible vessel 300 configured to store liquids, in accordance with one or more implementations. The semi-submersible vessel 300 may comprise an upper portion 302 configured to provide a platform 304. The semi-submersible vessel 300 may comprise a lower portion 306. The lower portion 306 of the semi-submersible vessel 300 may comprise vertically-disposed legs 308 extending downward from the upper portion 302. The lower portion 306 of the semi-submersible vessel 300 may comprise a horizontally-disposed pontoon 310. The pontoon 310 may extend between at least two of the legs 308. The pontoon 310 may extend between at least two of the legs 308 adjacent to the end of the legs opposite to the upper portion 302.

The semi-submersible vessel may be configured to have a regular four-sided shape. The dimensions of the semi-submersible vessel may be selected based on one or more environmental parameters. For example, the width, length and/or height of the semi-submersible vessel may be selected, based on the water depth of the intended operational location for the semi-submersible platform, a characteristic of the environment conditions of the intended operational location for the semi-submersible platform. The intended operational location may include the location in which the semi-submersible platform will be based, used, or the location that it may be transported through.

Test results have shown that the semi-submersible vessel can be scaled to any dimension and provide for satisfactory hydro-dynamic and static variables. Various ratios may be employed between the various dimensions of the semi-submersible vessel. For example only, a column breadth may equal a size C. The column width may be selected to equal or substantially equal the column breadth, i.e. size C. The column height may be selected to equal a multiple of the column breadth and/or width. One such selected height may be equal to six times C. The distance between adjacent columns may be selected to be a multiple of the column breadth and/or width. For example, the selected distance between adjacent columns may be selected to be four time C. The height of the pontoons may be selected to be a multiple of the column breadth and/or width. For example, the pontoon height may be selected to be a half of C. The depth of the main deck may be selected to be a multiple of the column breadth and/or width. For example, the depth of the main deck may be selected to be a quarter of C.

The dimensions, ratios, and/or scales provided herein are to provide examples only and are not intended to be limiting. The disclosed inventive concepts are intended to cover semi-submersibles and/or floating production platforms having any ratio, size, dimensions and/or other parameters.

A software system may be provided to aid in the development and design of the floating production platform. The software system may be implemented using one or more physical computer processors. The one or more physical computer processors may be configured to execute machine-readable instructions to facilitate the development and design of the floating production platform.

The software system may be configured to receive, from a user, a selection and/or entry of one or more parameters defining a size of the vessel. The one or more size parameters may include a width, breadth, height, and/or other size parameter. The software system may be configured to receive, from a user, a selection and/or entry of one or more element parameters. The system may comprise a database of elements that are selectable by the user. In some implementations, the system may be configured to allow selection and/or entry of dimensions of elements by a user. The elements may represent construction elements, such as welded blocks that will make up the structure of the floating production system. The elements may be arranged in layers, such that the bottom layers may be the first layer. Additional elements placed on top of the bottom layers may be designated the second layer, third layer, and so on.

The software system may be configured to facilitate the selection and/or entry of the individual layers. The software system may be configured to facilitate manipulation by the user of the individual layers in response to selection and/or entry of the individual layers.

The software system may be configured to facilitate the selection and/or entry of individual and/or groups of elements to be ballasted. The software system may be configured to facilitate the selection and/or entry of a type of ballast. For example, a ballast type may be water, oil, and/or a combination thereof.

The software system may be configured to facilitate selection and/or entry of a draught for the vessel. In response to selection and/or entry of a draught for the vessel by a user, the software system may be configured to provide an indication of the amount of ballast needed to achieve the selected and/or entered draught. The software system may be configured to provide an indication of recommended locations for the ballast based on one or more parameters of the floating production system being designed. Such parameters may include maintaining a desired centered of gravity, or range for the center of gravity, during certain operating conditions.

The software system may be configured to facilitate selection of a viewing angle by a user, such that the user may change the viewing angle to a desired viewing angle.

The software system may be configured to facilitate the selection and/or entry of loads to be added to the vessel. Facilitating selection and/or entry of loads to be added to the vessel may include selection and/or entry of a location to place the loads. Facilitating selection and/or entry of loads to be added to the vessel may include selection and/or entry of a type of load, such as fixed load or moving load.

The software system may be configured to perform calculations based on the parameters of the designed vessel. The software system may be configured to determine whether the designed vessel meets predefined fit-for-purpose parameters. The software system may be configured to provide an indication of dimensions and/or elements of the designed vessel that need to be changed to comply with the fit-for-purpose parameters. The software system may be configured to provide suggested changes to be made to the designed vessel so that the vessel will comply with the fit-for-purpose parameters.

The semi-submersible vessel may have a size selected based on a number of parameters. The parameters may include payload parameters, environmental parameters, aesthetic parameters, functionality parameters, and/or other parameters. The dimensions of the semi-submersible vessel may be any size. For example, the length and/or width of the main deck of the semisubmersible vessel may be less than 30 meters or may extend beyond 120 meters. The depth of the main deck may be determined based on desired payload and/or weight distribution of desired equipment.

The lower portion 306 may be configured to provide sufficient buoyancy to maintain the upper portion 302 substantially above the water 312. The lower portion 306 may be configured to store liquid matter 314. The liquid matter 314 stored in the lower portion 306 may comprise one or more of sea water, ballast water, and/or crude oil. The lower portion 306 may be configured to store two or more types of liquid matter. For example, the lower portion 306 may be configured to store an amount of a first type of liquid matter. The lower portion 306 may be configured to fill the remaining volume of the lower portion 306 with a second type of liquid matter. The lower portion 306 may comprise one or more storage tanks. The one or more storage tanks may be comprised to store liquid material. The one or more storage tanks may be comprised to store multiple types of liquid material. The one or more storage tanks may be comprised to store a first amount of a first type of liquid material. The one or more storage tanks may be configured to fill the remaining volume of the storage tanks with a second type of liquid material.

The lower portion 306 may be comprised of tubular elements. The tubular elements may resemble rectangular blocks. The lower portion may comprise a plurality of cubic boxes 316. Individual rectangular tubular elements and/or cubic boxes 316 may be operably connected to adjacent rectangular tubular elements. The rectangular tubular elements and/or cubic boxes may be connected through one or more of welding, riveting, sticking, mechanical seal, construing, and/or other connecting methods. The rectangular tubular elements and/or cubic boxes may be formed of metal. The rectangular tubular elements and/or cubic boxes may be formed from an alloy. The rectangular tubular elements and/or cubic boxes may be formed of steel. As used herein, the term rectangular tubular elements is intended to encompass tubular elements having walls with equal dimensions, forming a square, as well as tubular elements having walls with different dimensions.

The end walls 318 of the blocks may form bulkheads between adjacent cubic boxes. The end walls 318 may form a second protective layer for storage tanks disposed within the cubic boxes.

The lower portion 306 of the semi-submersible vessel 300 may be configured to receive an amount of crude oil for storage. The lower portion 306 of the semi-submersible vessel 300 may be configured to eject an amount of ballast water. The lower portion 306 of the semi-submersible vessel 300 may be configured to eject an amount of ballast water in response to receiving an amount of crude oil for storage. The amount of ballast water ejected may be an amount corresponding to the amount of crude oil received for storage. The amount of ballast water ejected may be an amount selected based on a determination made to meet one or more parameters. The determination may be based, at least in part, on the amount of crude oil received, or to be received, for storage.

The semi-submersible vessel 300 may comprise filtration tanks 320. The filtration tanks 320 may be configured to receive and/or filter one or more contaminants from the ejected ballast water. The filtration tanks 320 may be configured to eject filtered ballast water into the sea.

FIG. 5 illustrates a semi-submersible platform 500 wherein the pontoons 502 are configured to store liquid. In particular, the pontoons 502 may be configured to store oil. The pontoons 502 may be configured to store ballast. In some implementations, the ballast may comprise sea water. The pontoon 502 may comprise a keel 504 and a deck 506. The deck 506 may be configured to be parallel with the keel 504. The deck 506 may be configured to have a slope relative to the keel 504. The slope of the deck 506 relative to the keel 506 may be less than one degree, approximate one degree, one degree, or more than one degree. The deck 506 may be configured to have a variable slope relative to the keel 504.

The semi-submersible platform 500 may be configured to trim to facilitate emptying of the tanks and/or cleaning.

The pontoon 502 may have a storage portion 508. The storage portion 508 of the pontoon 502 may comprise tanks. The storage portion 508 of the pontoon 502 may comprise linings. The linings may protect the structure of the pontoon 502 from harmful effects of the material stored within the pontoon 502. The storage portion 508 may be configured to store sea water, oil, other material and/or a combination thereof. The storage portion 508 of the pontoon 502 may have a designated minimum level 510 for one or more stored materials. For example, when the pontoon 502 is configured to store one or more of oil or water, there may be a minimum material level 510 of the water or oil in the storage portion 508 of the pontoon 502. In the example where oil and water are stored in the pontoon 502, the minimum level 510 may be the minimum level of water in the storage portion 508 of the pontoon 502. The storage portion 508 of the pontoon 502 may have a designated maximum material level 512 for the material stored on the storage portion 508 of the pontoon 502. The designated maximum material level 512 may be the maximum level of the combined materials in the storage portion 508 of the pontoon 502.

In one example, where the pontoon 502 is configured to store oil and water, the minimum material level 510 may be minimum water level in the pontoon 502. The oil, crude oil, dead crude oil and/or combination thereof, herein referred to as “oil”, may be stored in the pontoon with the water. The hydrophobic nature of oil may cause a water-oil interface to form wherein the oil is disposed in the pontoon 502 above the water.

Water, for example sea water, may be placed into the pontoon 502 to provide a stabilizing effect for the semi-submersible vessel 500. Water may be placed into the pontoon 502 to eliminate ullage. Water may be placed into the pontoon 502 to reduce the differential pressure on the pontoon 502. When oil is provided to the pontoon 502 for storage, the water, acting as ballast, may be extracted from the pontoon 502. When oil is provided to the pontoon 502 for storage, the water may be displaced from the pontoon 502. The water and oil stored in the pontoon 502 may provide the necessary stability for the semi-submersible vessel 500. When oil is removed from the pontoon 502, water may be introduced to continue to provide stability to the semi-submersible vessel 500. When oil is removed from the pontoon 502, water may be introduced to control differential pressure.

When the pontoon 502 is submerged, the tanks in the pontoon 502 may be submerged. Submerging the pontoons 502 may reduce the pressure differential on the pontoons 502. Reducing the pressure differential on the pontoons 502 may facilitate the use of lighter materials to construct the pontoons 502.

When water is removed from the pontoon 502 it may pass through filtration systems 514. The water may be removed through a water removal pipe 516. The water removal pipe 516 may have an entry end 518. The entry end 518 of the water removal pipe 516 may be disposed in the pontoon 502 at a level below the minimum material level 510 for material stored in the pontoon 502. Water may be added to the pontoon 502 to provide ballast to the pontoon 502. Water may be obtained from the sea. Water from the sea may be obtained and passed through a filtration system 520 to filter the sea water before being provided to the pontoon 502. The water may be provided to the storage portion 508 of the pontoon 502 through a diffuser 522. The diffuser 522 may be disposed within the storage portion 508 of the pontoon 502 below the designated minimum material level 510.

Material may be provided to the pontoon 502 for storage. The material, such as oil, may be provided by a material storage pipe 524. The material storage pipe 524 may comprise an exit end 526. The exit end 526 may be disposed in and/or at the pontoon 502 to provide material to the pontoon 502 for storage. The exit end 526 of the material storage pipe 524 may be positioned at the top of the pontoon 502. The exit end 526 of the material storage pipe 524 may be fitted with a diffuser, baffle plate, and/or may be dynamically positioned such that the distance between the end of the storage pipe 524 and the top of the stored material and/or combined material, in the pontoon 502 is less than a threshold distance. The exit end 526 of the material storage pipe 524 may be positioned, stationary or dynamically varied, to be below the surface of the stored material in the pontoon 502.

The stored material, such as oil, in the pontoon 502, may be extracted from the pontoon 502. A material extraction pipe 528 may facilitate the extraction of the material from the pontoon 502. The material extraction pipe 528 may comprise an extraction end 530. The extraction end 530 may be disposed in the pontoon 502. The extraction end 502 may be disposed below the surface of the material to be extracted, such as oil. The extraction end 530 may be disposed above the minimum material level 510. Positioning the extraction end 530 above minimum material level 510 may avoid extracting water with the material. The extraction end 530 may be configured to be dynamically positioned. The extraction end 530 may be stationary. When the material, such as oil, is extracted through the extraction pipe 528, replacement material, such as sea water may be introduced into the pontoon 502. Introducing the water into the pontoon 502 may cause the material to be extracted, such as oil, to maintain an upper level position.

The semi-submersible platform 500 of the floating production system may comprise multiple oil storage tanks. The oil storage tanks may be disposed in the pontoons 502 of the semi-submersible platform 500. The pontoons may facilitate a single storage tank. The pontoons may facilitate multiple storage tanks. The storage tanks may be disposed in other elements of the semi-submersible platform 500. The storage tanks may be interconnected. The storage tanks may be interconnected using cross-levelling valves. In some implementations, the cross-levelling valves may be open during working conditions, when the floating production system is being used to extract materials. The ross-levelling valves may be closed during transit.

In some implementations, ballast water may be supplied to the tanks through free-flooding valves. In some implementations, ballast water may be supplied to the tanks, facilitated by the use of pumps.

In some implementations, the semi-submersible platform may comprise a deck structure. The deck structure may be configured to contain elements of the floating production system. For example, the floating production system may comprise living quarters, process and utilities elements, power generation elements, control modules, safety system elements, flare handling elements, mechanical handling system elements, and/or other elements.

The storage tanks may comprise anti-corrosive paint, sacrificial anodes, hot blast aluminum coatings, and/or other elements to reduce corrosion inside and/or outside of the tanks and/or pontoons.

In some implementations comprising multiple storage tanks, the storage tanks may be filled and/or emptied at approximately the same rate. Cross-levelling valves may facilitate the equalization of the pontoons and/or tanks.

In some implementations, the floating production platform may be installed at a location. The pontoons 502 and/or storage tanks may be flooded with ballast water to the waterline level. Oil and/or other material, may be provided to the storage tanks. The oil and/or other material provided to the storage tanks may displace the water.

A multi-stage settling tank system may be implemented to remove contaminants from the displaced water. A filtration and/or treatment system may be implemented to remove contaminants from the displaced water. The water filtration system may comprise multiple settling tanks, including a first tank and a second tank. Water may be removed from the bottom of the first tank and introduced to the top of the second tank. The water may be removed using a pump. The water filtration system may comprise a contaminant separator. The contaminant separator may be configured to remove contaminants from the water. The contaminant separator may be configured to scrub the water such that is complies with IMO and/or MARPOL requirements.

The pontoons 502 may comprise protection systems. The protection systems may comprise fendering systems to provide protection against damage caused by collisions with the pontoons 502.

The floating production system may comprise a trimming system. The trimming system may comprise one or more sets of trimming tanks. The sets of trimming tanks may be disposed in the leg portions, or columns, of the floating production system. Pneumatic and/or hydraulic pumping systems may facilitate the control of valves and/or pumps, which facilitate the introduction or removal of water from the sets of trimming tanks. The trimming system may perform functions automatically. The trimming system may be manually controlled. The trimming system may be configured to remove water and/or other ballast material from a first set of tanks in a first leg portion to a second set of tanks in a second leg portion of the floating production system. In some implementations the floating production system, it may be configured to operate having a slight trim. Providing a slight trim may facilitate the avoidance of air pockets forming in the one or more tanks.

A method of mooring a floating production system is disclosed. The method may comprise mooring the superstructure to the seabed. Mooring the structure to the seabed may comprise providing a mooring system having a first end operatively connected to the superstructure and configured to secure the mooring system to the superstructure. Mooring the structure to the seabed may comprise providing a mooring system with a second end that is configured to secure the mooring system to the seabed. Mooring the structure to the seabed may comprise providing at least one line between the first and second ends, wherein the line is arranged in catenary.

A method for transporting liquids between the seabed and a semi-submersible platform is provided. The method may comprise the steps of providing one or more pipes disposed between the seabed and a semi-submersible platform. The pipes, having a first end extending toward the semi-submersible platform and a second end extending toward the seabed. The pipe may be configured to facilitate the transport of liquid material from the seabed toward the surface of the sea and/or the semi-submersible platform. The pipes may be disposed in the ocean in a coplanar curtain. The method may further comprise controlling the angle of inclination of the pipes at the first end of the pipes. Controlling the angle of inclination may be accomplished using a bearing disposed on the semi-submersible. The bearing may be a gimbal.

A method of storing oil is provided. The method may comprise providing a semi-submersible vehicle having an upper portion and a lower portion. The lower portion may comprise a rectangular ring (as used herein rectangular ring may also include a square ring). The method may comprise facilitating the introduction of water into the rectangular ring. The method may comprise facilitating the introduction of liquid material, such as oil, into the rectangular ring. The liquid material may displace the water. The method may comprise treating the displaced water to remove contaminants.

Although the present technology has been described in detail for the purpose of illustration, based on what is currently considered to be the most practical and preferred implementations, it is to be understood that such detail is solely for that purpose and that the technology is not limited to the disclosed implementations, on the contrary, is intended to cover modifications and equivalent arrangements that are within the spirit and scope of the appended claims. For example, it is to be understood that the present technology contemplates that, to the extent possible, one or more features of any implementation can be combined with one or more features of any other implementation.

FLOATING PRODUCTION SYSTEM AND METHOD

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