Power generation system

Abstract

Some embodiments relate to a power generation system. An example power generation system includes a gas turbine to generate power by combustion of natural gas; an organic Rankine cycle (ORC) generator for generating power through heat recovery; a gas supply line for supplying vaporized liquefied natural gas (LNG) to the gas turbine; a power supply subsystem for receiving power from at least one of the gas turbine or the ORC generator and supplying power to at least one remote power receiving end; and a damper. The damper may allow the gas turbine and the ORC generator to operate together in a first position and allow the gas turbine and the ORC generator to operate independently of each other in a second position.

Description

Technical Field

[0001] The present disclosure generally relates to a power generation system. More specifically, the present disclosure relates to a damper for supplementary combustion in an LNG power generation system. Background Art

[0002] There are a number of obstacles to providing reliable electricity to rural areas in geographically remote locations, especially at economically viable costs. For example, the Papua New Guinea (PNG) archipelago consists of a number of islands, each of which has large rural areas where residents live in dispersed small communities, as well as industrial areas. The terrain and landscape of the islands present a challenging environment for operating a transmission network. A recurring challenge faced by countries such as PNG is the variation in electricity demand in different regions and at different times. The electricity load consists of dispersed smaller loads. Mining, fishing and other similar industries generate large amounts of local electricity demand, but this demand only exists during specific periods when mining production or fishing is active. At other times, the low population density generates much smaller electricity demand. Current power generation solutions cannot effectively meet these varying demands, and thus the energy cost is high.

[0003] Disadvantages of previous concepts include that the concepts focused on large power stations, which provided sufficient funds to overcome the obstacles. In some cases, such large-scale power stations require more funds than reasonable investment. In addition, larger manufacturers do not obtain a large amount of financial benefits from small power plants, so the manufacturers do not focus on smaller-scale power stations. For example, a small-scale power station may involve the same amount of work as a large power plant because the small-scale power station may have all the same / similar components, but its benefits are not commensurate with the required capital.

[0004] Large power stations can be configured to meet relatively high average electricity demands. However, the demands in remote areas may vary significantly and the average electricity demand is low, which is not suitable for using large generators. Such rapid and / or widespread variations in demand may be difficult to meet because turbines may generally only respond slowly to changes in demand. Slow response to changing demands may result in reduced turbine efficiency.

[0005] It is desirable to solve or improve one or more disadvantages or deficiencies of previous power generation solutions, such as low efficiency or high energy cost, or at least provide a useful alternative.

[0006] Throughout this specification, the word "comprise" or variations such as "comprises" or "comprising" will be understood to imply the inclusion of the stated element, integer, or step or group of elements, integers, or steps but not the exclusion of any other element, integer, or step or group of elements, integers, or steps.

[0007] Any discussion of documents, acts, materials, devices, articles, etc. included in this specification should not be taken as an admission that any or all of these constitute a part of the prior art base or are common general knowledge in the field relevant to the present disclosure just because they existed before the priority date of each claim in the appended claims. Summary of the Invention

[0008] Some embodiments relate to a power generation system. The power generation system may comprise: a gas turbine for generating electricity by burning natural gas; an organic Rankine cycle (ORC) generator for generating electricity by heat recovery; a gas supply line for supplying vaporized liquefied natural gas (LNG) to the gas turbine; a power supply subsystem for receiving power from at least one of the gas turbine or the ORC generator and supplying power to at least one remote power receiving end; and a damper that allows the gas turbine and the ORC generator to operate together in a first position and allows the gas turbine and the ORC generator to operate independently of each other in a second position.

[0009] In some embodiments, the ORC generator may have a first power generation capacity, and the gas turbine may have a second power generation capacity higher than the first power generation capacity.

[0010] In some embodiments, the power generation system may include a controller. The controller may be configured to control the position of the damper at the first position or the second position in response to a change in the load drawn by the at least one remote power receiving end.

[0011] In some embodiments, the controller may be configured to position the damper at the first position when the load drawn by the at least one remote power receiving end is at or above a first threshold power load and to position the damper at the second position when the load drawn by the at least one remote power receiving end is below the first threshold power load.

[0012] The first threshold power load may correspond to the second power generation capacity.

[0013] In some embodiments, the gas turbine may be arranged to be selectively in fluid communication with an exhaust stack and the ORC generator. Thus, in the first position of the damper, the fluid flow path from the gas turbine to the exhaust stack is closed to the gas leaving the gas turbine, and the fluid flow path from the gas turbine to the ORC generator is opened, thereby allowing the gas leaving the gas turbine to flow into the ORC generator.

[0014] In the second position of the damper, the fluid flow path from the gas turbine to the exhaust stack may be opened to allow the gas leaving the gas turbine to enter the exhaust stack, and the fluid flow path from the gas turbine to the ORC generator may be closed to the gas leaving the gas turbine.

[0015] In some embodiments, the damper may include at least one airtight damper.

[0016] The ORC generator may include a fresh air ignition stack and may be configured to generate electricity from the heat recovered from the exhaust gas leaving the gas turbine and / or the gas entering the ORC from the fresh air ignition stack.

[0017] When the load drawn by the at least one remote power receiving end is lower than a second threshold power load, the ORC generator may be configured to generate electricity from the gas entering the ORC generator through the fresh air ignition stack.

[0018] In some embodiments, the fresh air ignition stack may be located downstream of the gas turbine.

[0019] In some embodiments, the power generation system may include an auxiliary burner arranged downstream of the fresh air ignition stack and in fluid communication with at least one storage tank to receive boil-off gas from one or more LNG storage tanks. The auxiliary burner may be adapted to burn the boil-off gas to generate auxiliary heat for operating the ORC generator.

[0020] In some embodiments, the power generation system may include a heat exchanger. The heat exchanger may be configured to receive the heated gas from the auxiliary burner and to heat the working fluid of the ORC generator. The fuel source for the gas turbine generator and the ORC generator may be LNG.

[0021] Some embodiments relate to a floating power generation system. The floating power generation system may include a system according to any one of the embodiments described above installed on a ship. The ship may include a ship frame, a hull surrounding the ship frame and defining a bow section and a stern section, and a deck supported by the ship frame. A power supply subsystem is configured to supply power to at least one remote power receiving end away from the ship.

[0022] Some embodiments relate to a method of controlling the operation of a power generation system according to any one of the embodiments described above. The method of controlling the operation of the power generation system may include the method may include controlling the position of the air damper in the first position to allow the gas turbine and the ORC generator to operate together, or controlling in the second position to allow the gas turbine and the ORC generator to operate independently of each other.

[0023] In some embodiments, when the load drawn by the at least one remote power receiving end is at or above the first threshold power load, the air damper is positioned in the first position. When the load drawn by the at least one remote power receiving end is below the first threshold power load, the air damper may be positioned in the second position. The first threshold power load may correspond to the second power generation capacity.

[0024] The power generation system may be controlled to operate the gas turbine or the ORC generator in response to the power load drawn by the at least one remote power receiving end.

[0025] When the drawn power load is higher than the second threshold power load and lower than the first threshold power load, the power generation system may be controlled to operate the gas turbine instead of the ORC generator.

[0026] When the drawn power load is within the second threshold power load, the power generation system may be controlled to operate the ORC generator instead of the gas turbine. The power generation system is controlled to operate the ORC generator instead of the gas turbine when the drawn power load is within the second threshold power load.

[0027] In some embodiments, the second threshold power load may correspond to the first power generation capacity, and the first threshold power load corresponds to the second power generation capacity. BRIEF DESCRIPTION OF THE DRAWINGS

[0028] One or more embodiments will now be described by way of specific examples with reference to the accompanying drawings, in which:

[0029] Figure 1 is a schematic diagram of a floating power generation system;

[0030] Figure 2 is Figure 1 Perspective view of the floating power generation system;

[0031] Figure 3 Perspective view of the floating dock of the floating power generation system;

[0032] Figure 4a -b is the perspective view of the bulk LNG storage barge;

[0033] Figure 5 Schematic diagram of the interface between the gas turbine power plant and the ORC power plant;

[0034] Figure 6 is Figure 1 Process schematic diagram of the equipment on the LNG storage barge;

[0035] Figure 7a -e is Figure 1 Process schematic diagram of the equipment on the power generation barge;

[0036] Figure 8a-8c Process schematic diagram of the equipment on the power generation barge;

[0037] Figure 9 is Figure 9 Top perspective view of the power generation barge;

[0038] Figure 10 Perspective view of the power generation barge showing the barge structure;

[0039] Figure 11 is Figure 1 Top perspective view of the storage barge;

[0040] Figure 12 is showing the barge structure of Figure 11 the storage barge;

[0041] Figure 13a Flow chart showing the process for determining the position of the damper;

[0042] Figure 13b Flow chart of the process for determining whether to operate the gas turbine generator or the ORC generator;

[0043] Figure 14a -c is the 11KV main power single line diagram;

[0044] Figure 15a -c is the 415V barge power single line diagram;

[0045] Figure 16a -c is the 110VDC power generation barge power single line diagram;

[0046] Figure 17a -b is a schematic overall layout of a 110 VDC power supply; and

[0047] Figure 18a -b is a schematic diagram of a power communication architecture. Detailed implementation

[0048] Overview of the power generation system

[0049] The power generation system of the present disclosure has been developed to provide power to remote areas with variable power demands at the lowest possible energy cost.

[0050] The power generation system utilizes liquefied natural gas (LNG) as fuel to conform to the expected available resources in countries such as PNG and the desire to transition from existing diesel power generation.

[0051] Due to the frequent seismic and volcanic activities in countries such as PNG, any power infrastructure plan is preferably incorporated with a design that will mitigate the impact of the seismic and volcanic activities experienced in these countries. Traditional land-based power plants provide little or no protection against these hazards.

[0052] An offshore power generation system 100 has been developed. Compared with land-based power generation systems, the offshore power generation system significantly reduces fuel handling and LNG logistics costs, while mitigating potential damage caused by seismic activities and minimizing any environmental impact. The floating power generation system 100 can be repositioned as needed to meet fluctuating local power demands, so that once industrial activities in any one area stop, the LNG storage, regasification, and power generation assets will not be idle. Allowing the power generation system 100 to move in water while being fixed in place and taking advantage of the natural damping effect of the ocean to reduce the likelihood of damage caused by earthquakes. The power plant equipment can be easily removed from any volcanic event.

[0053] The LNG used to fuel the floating power generation system 100 can initially be stored in a bulk storage facility. The bulk storage facility can be up to 800 kM to 1000 kM away from the location of the power generation system 100.

[0054] The power generation system 100 includes an LNG storage barge 120, a power generation barge 110, and a floating dock 130. The LNG storage barge 120 and the power generation barge 110 are moored to the floating dock during the operation of the power generation system 100. The power generation barge 110 is designed to minimize the draft of the barge, thereby allowing the barge to be placed in a protected port and as close to the shore as possible. This design allows the use of overhead power pipelines to connect to the onshore transmission and distribution system

[0055] The LNG storage barge 120 is a non-powered barge that houses an LNG storage tank sufficient to store a minimum fuel supply, e.g., a 30-day supply of LNG, as well as an associated boil-off gas (BOG) collector. The LNG storage barge is transported between the bulk LNG storage facility 400 where fuel is loaded and the location of the floating power generation system 100 using an articulated tugboat (ATB). The ATB employs a hydraulic interlock method that matches the ATB to the barge to be pushed. The ATB typically travels 50% faster than a tugboat, can operate in open seas, and consumes approximately 25% less fuel than a tugboat. When transporting, the ATB can also operate using LNG from the LNG storage barge to avoid the use of diesel fuel. Disconnecting the propulsion member from the LNG storage barge 120 eliminates the risk of propulsion maintenance issues that could jeopardize the reliability of LNG supply to the remote power generation system 100. It also has the additional benefit that a non-powered barge requires far fewer crew members than a powered barge.

[0056] For example, the power generation barge 110 is a single platform and an independent power plant with a power generation capacity in the range of 5 - 20 MW. This level of power generation capacity is relatively small and suitable for providing power to dispersed smaller communities. The power generation barge 110 is capable of operating for a minimum number of days, e.g., seven days, without an external fuel supply. For this purpose, the power generation barge 110 includes two LNG tanks, one LNG tank located on the starboard side of the barge and one LNG tank located on the port side of the barge. For example, the LNG tanks can be C-type cryogenic tanks. The LNG tanks can be configured as pressurized tanks to allow sufficient time to deliver the LNG to the desired location within a few days without overpressure problems. This arrangement means that LNG only needs to be transferred periodically (e.g., every seven days) between the LNG storage barge and the power generation barge, and the transfer can be carried out under favorable weather and sea conditions. Additionally, the LNG storage barge can be completely emptied because the supply of LNG is accommodated on the power generation barge before returning to the bulk storage facility for refilling. Equipment for regasification, vaporizers, LNG storage, BOG tanks, and high-pressure LNG liquid transfer pumps can be installed one each on the starboard and port sides of the power generation barge to provide redundancy and ensure the reliability of the power plant in case any one piece of equipment fails.

[0057] The power generation barge 110 generates electricity using a gas turbine (GT) generator 112, partly because the gas turbine generator has lower reliability and maintenance requirements compared to a reciprocating engine. The main consumables of the gas turbine generator are inlet air, lubricating oil, and fuel filters, and thus the requirements for the main consumables of a reciprocating engine, which include a large amount of lubricating oil, are lower. Since the power generation barge 110 can be located far from the supply of such consumables, the use of the gas turbine generator 112 reduces the number of delivery trips and waste materials.

[0058] The power generation barge 110 also includes an Organic Rankine Cycle (ORC) generator 114 that generates electricity through waste heat recovery. When compared to the simple cycle operation of the gas turbine generator 112, the gas turbine generator 112 can operate alone in a simple cycle or together with the ORC generator 114 in a combined cycle to produce a combined cycle efficiency that reduces the Levelized Cost of Energy (LCOE) (the average price / unit output required for the power plant to break even over its operating life) by up to 60%. Operating the gas turbine generator 112 and the ORC generator 114 together in a combined cycle increases the power generation efficiency by approximately 23% compared to a natural gas fuel generator. The increase in power generation efficiency also has the additional benefit of reducing NOX emissions by approximately 25% / Kwh.

[0059] It is well known that ORC generators are used to recover low-grade heat energy in geothermal applications. Heat Recovery Steam Generators (HRSGs) are commonly used in power plant applications and are much cheaper. However, this power generation system 100 utilizes the ORC generator 114 because the power generation system is offshore and does not have access to the large amounts of fresh water required to operate an HRSG. In addition, HRSGs require consumables in the form of chemicals for water treatment and are an open loop that rejects heat to the environment. In contrast, the ORC generator is a closed loop that does not require consumables, thus minimizing weight and energy consumption.

[0060] The ORC generator 114 of the power generation system 100 operates using a heat fluid as the working fluid. The power generation barge 110 includes a Waste Heat Recovery Unit (WHRU) 516 in which the heat fluid is vaporized by high-temperature (500 - 600 °C) exhaust gases discharged from the gas turbine and supplemented by Boil-off Gas (BOG) ignited in an auxiliary ignition burner. The resulting high-pressure vapor is allowed to expand in a turbine operably associated with the generator. The expanded vapor drives the generator and is then condensed using a seawater / ethylene glycol heat exchanger and pumped back to the WHRU 516 in a closed loop.

[0061] The ORC generator 114 can be operated separately from the gas turbine 112 as an independent generator. This can be achieved by adding a fresh air ignition stack and burner and applying a diverter damper positioned between the gas turbine generator and the fresh air ignition stack / burner. The diverter damper can be positioned to operate the gas turbine generator 112 and the ORC generator 114 to operate together in a combined cycle or independently. This arrangement provides a degree of redundancy in the power generation capacity of the power generation system 100 and also allows the generator to operate during low load periods to maximize its efficiency.

[0062] Power generation system 100 includes a closed-loop thermal circuit to capture and utilize the latent energy released during LNG regasification to improve system efficiency. When the fuel is converted to a liquid state, it contains latent energy which is approximately 10% of the fuel's own BTU (British Thermal Unit) content. Its capture and utilization in the thermal circuit increases the power generation capacity and reduces parasitic load losses, thus improving the overall efficiency of the power generation system 100.

[0063] In the regasification and vaporization of LNG, the power generation system 100 utilizes seawater at approximately 25 °C from an offshore PNG supply. Utilizing a liquid-to-liquid vaporizer allows the transfer of latent energy into the closed-loop thermal circuit, which provides a medium for converting the latent energy into useful work.

[0064] The hot fluid circuit utilizes latent energy to cool the inlet air supplied to the gas turbine generator 112 from an average ambient temperature of 26 °C to 15 °C, which has the effect of increasing the output of the gas turbine generator 112 by approximately 10% and increasing the fuel efficiency by approximately 3%. Once a portion of the latent energy in the hot fluid is used to cool the inlet air, the inlet air is then used to provide cooling for the power barge equipment, which includes air conditioning, turbine lubricating oil cooling, and liquid-cooled air compressors, thereby reducing parasitic load and further improving the overall system efficiency.

[0065] During the transportation, storage, and handling of LNG, boil-off gas (BOG) is continuously generated. The LNG must be maintained at a temperature equal to or below -161 °C to maintain its liquid state. The LNG gets heated when it comes into contact with the storage tank wall and evaporates to produce BOG. The conventional practice in large LNG fuel power plants is to compress the BOG, re-liquefy the BOG, and then immediately vaporize it for injection into the gas turbine. However, the requirement for a BOG compressor and the associated high parasitic load reduce the overall efficiency of the power plant. An alternative to this arrangement is to flare the BOG to the atmosphere to control the storage tank pressure, but doing so results in approximately 10% fuel loss.

[0066] This power generation system 100 utilizes BOG during the operation of the ORC generator 114 as fuel for an auxiliary burner. As discussed above, the BOG is ignited in the exhaust stream of the gas turbine / fresh air ignition chimney at the auxiliary burner in front of the WHRU 516 to capture the BOG energy in the ORC generator without the need for an expensive compressor or a significant increase in parasitic load.

[0067] Detailed description of the embodiments

[0068] Figure 1 and Figure 2 The overall arrangement of the power generation system 100 according to some embodiments is shown. Figure 1The main components of the power generation system 100 are shown in schematic form, while Figure 2 is an illustrative layout of the power generation system 100. The power generation system 100 is shown installed in the sea off the coast adjacent to a land-based substation 135.

[0069] The power generation system 100 includes a power generation barge 110, an LNG storage barge 120, and a floating dock 130. The LNG storage barge 120 and the power generation barge 110 can be moored to the floating dock during operation of the power generation system.

[0070] The LNG storage barge 120 includes a floating vessel having a generally rectangular plan view. The vessel includes a frame 220 and a hull 222 surrounding the frame 220. The frame supports a plurality of LNG storage tanks 122 and a manifold system 125. The manifold system 125 is configured to facilitate the transfer of LNG from one or two storage tanks 122 through a supply conduit 127 to a gas turbine 112. The manifold system 125 may include conduits, valves, manifolds, flow control components, displays, and sensors (e.g., pressure sensors and flow sensors). The LNG storage capacity of the LNG storage barge 120 is approximately 3000 m 3 , which provides a thirty-day supply for the power barge 110. In Figure 1 the illustrative embodiment shown, the LNG storage barge 120 has two LNG storage tanks 122 supported thereon, each LNG storage tank having a storage capacity of approximately 1500 m 3 . In Figure 2 , four LNG storage tanks 122 are shown, each LNG storage tank having a storage capacity of approximately 750 m 3 . The number of LNG storage tanks 122 on the barge 120 can vary as long as the storage capacity is sufficient to store a minimum fuel supply, e.g., sufficient to operate the gas turbine 112 for thirty days. The amount of fuel stored ensures that the LNG storage barge 120 only needs to return to a bulk storage facility 400 once every thirty days, which may be hundreds of kilometers away from the power generation system location. Providing a storage capacity for a thirty-day LNG supply allows for sufficient redundancy in the shipping schedule in case weather or sea conditions prevent LNG shipments. The LNG in the storage tanks 122 is supplied to the power generation barge through the LNG supply conduit 127.

[0071] The vessel frame 220 and hull 222 of the LNG storage barge 120 define a barge having a wide and shallow draft suitable for shallow water mooring. The hull 222 defines a bow section and a stern section of the barge. The deck 1110 (see Figure 11)Supported by the ship frame 220 to facilitate operation and maintenance access. The LNG storage barge 120 does not have its own built-in propulsion member. Instead, the hull 222 has a recess 224 defined in the central portion of the stern section to receive the bow of a driving ship, such as an articulated tugboat (ATB) (not shown). The recess 224 is shaped to have a vertex with an acute angle that is large enough to receive the bow of the driving ship and allow the bow to drive the LNG storage barge 120 by pushing it forward. The recess 224 includes a part of a two-part interlocking mechanism (not shown) for locking the LNG storage barge 120 to the ATB. The ATB includes the second part of the two-part interlocking mechanism. For example, a hydraulic piston can be driven from the ATB into the barge 120 to mate the two ships into a single floating unit. In one embodiment, the hydraulic interlocking mechanism is a hydraulic pin. As Figure 11 seen, the bow section of the hull 222 has an acute angle surface 1140, which facilitates the forward passage of the barge on the water. Disconnecting the propulsion member from the LNG storage barge 120 eliminates the risk of propulsion maintenance problems that could endanger the reliability of the LNG supply to the remote power generation system 100. It also has the additional benefit that a non-powered barge requires far fewer crew members than a powered barge.

[0072] The power generation barge 110 is a generally rectangular floating ship, the plan area of which is approximately 30 m 2 , and includes a ship frame 230 that supports the main deck 930 and a below-deck space 1020 below the main deck. The hull 232 surrounds the frame 230 and defines the bow section and the stern section of the power generation barge 110. The power barge 110 is an independent LNG storage, regasification, and combined cycle power plant as will be described herein. Power is generated using a gas turbine 112 and / or an ORC generator 114. The LNG supply conduit 127 supplies LNG to the power generation barge 120, where the LNG is vaporized to be used as fuel in the gas turbine 112. The ORC 114 operates using a heat transfer fluid as the working fluid. The waste heat from the gas turbine 112 can be used to provide heat energy to the heat transfer fluid. Both the gas turbine 112 and the ORC generator 114 generate electricity for a power subsystem 116 controlled by a control center 115. The control center 115 monitors the power load demand of the land-based substation 135 and controls the operation of the power plant accordingly.

[0073] The vessel frame 230 and hull 232 of the power barge 110 define a barge having a wide and shallow draft suitable for shallow water mooring. The hull 232 defines a bow section and a stern section of the barge. The power barge 110 does not have its own built-in propulsion member. Instead, the hull 232 has a recess 234 defined in the central portion of the stern section to receive the bow of a driving vessel, such as an articulated tugboat (ATB) (not shown). The recess 234 is shaped to have an apex of an acute angle that is large enough to receive the bow of the driving vessel and to allow the bow to drive the power barge by pushing the power barge 110 forward. As seen in 9, the bow section of the hull 232 has an acute angle surface 940, which facilitates the forward passage of the barge on water. As with the LNG storage barge 120, decoupling the propulsion member from the power barge significantly reduces the required number of crew members and avoids potential interruptions in power supply due to propulsion maintenance when problems occur at locations remote from the power generation system 100.

[0074] The power barge 110 has a shallow draft to allow the barge to be positioned in a protected port and as close to the shore as possible. This allows the use of overhead power lines 132, 134 that connect from the power supply subsystem 116 to the land transmission and distribution system at the substation 135. In some embodiments, the first power line 132 may extend from the power supply subsystem 116 to a connection device 133 that is electrically connected to the second power line 134 to supply power to the substation 135. The connection device 133 may include a transformer, a fuse breaker and a load break elbow, a coaxial operating load break switch, and / or other systems to physically and / or electrically allow the first power line 132 to be connected and disconnected from the second power line 134. For example, the connection device 133 may be located on a floating dock 130 (e.g., at or near the security gate 140), on the gangway 136, or at a safety device on land. A quick connect / disconnect system (not shown) on the power barge 110 may allow the gas turbine 112 and the ORC generator to be disconnected from the first power line 132 to quickly remove the barge in an emergency.

[0075] The floating dock 130 is an elongated steel structure connected to a fixed structural pile or tower 305 that secures the position of the floating dock 130 relative to the seabed while allowing it to rise and fall with sea conditions (e.g., due to tidal currents). The floating dock 130 includes an elongated onshore dock section 322 and an elongated offshore dock section 326. The onshore dock section 322 is connected to the offshore dock section 326 by a central platform 324 that extends at a right angle to the dock sections and is generally parallel to the shoreline. An offshore platform 328 extends parallel to the central platform 324 at the offshore end of the offshore dock section 326, and an onshore platform 320 extends parallel to the central platform 324 at the onshore end of the onshore dock section 322. Between the offshore platform 328 and the central platform 324, LNG storage barge mooring compartments 312 are defined on either side of the offshore dock section 326. Between the offshore platform 328 and the central platform 324, power generation barge mooring compartments 310 are defined on either side of the onshore dock section 322.

[0076] Each of the offshore dock section 326 and the onshore dock section 322 includes an interlocking device 340 located on either side thereof for locking the power generation barge 110 and the LNG storage barge 120 into the mooring compartments 312, 310. Interlocking the barges and the floating dock 130 in this manner reduces the degree and angle of movement that may occur due to tidal and wave effects at the critical LNG fluid transfer conduit 127 between the LNG storage barge 120 and the power generation barge 110 and allows for the transfer of LNG fuel during periods of greater wind and sea conditions. The interlocking device 340 can be a mechanical mechanism adapted to limit movement between the floating dock 130 and the power generation barge 110 and / or the LNG storage barge 120. For example, the interlocking device 340 can be a hydraulic interlocking device, such as a hydraulic pin.

[0077] Known floating power generation systems typically use mooring / berthing lines or sea anchor systems to secure a vessel to a platform / dock. Due to wind and / or sea conditions, these mooring / berthing lines and sea anchor systems typically result in a greater degree and angle of movement of the vessel relative to the platform / dock. Reducing this movement by using the interlocking device 340 can allow for the transfer of resources between the LNG storage barge 120 and the power generation barge 110 when greater wind and / or sea conditions would prevent or limit resource transfer in known floating power generation systems. That is, the interlocking device 340 can allow the floating power generation system 100 to overcome limitations in resource transfer of known floating power generation, such as LNG and BOG transfer, due to wind and / or sea conditions. This in turn allows for smaller resource transfers to be performed intermittently, e.g., in response to demand, rather than having to perform large resource transfers in smaller wind and / or sea conditions.

[0078] The seaward end of the floating dock 130 further includes a floating wall 335 that extends collinearly from either end of the seaward platform 328 and is generally parallel to the shoreline. When moored in the mooring bay 312, the floating wall 335 extends beyond the ends of the LNG storage barge 120 to provide some protection for the LNG storage barge and the power generation barge 110 from tidal surges. At the landward end of the floating dock, a gangway 136 extends from the seaward platform 320 to the land to provide access for personnel from the shore to the floating dock 130.

[0079] As schematically shown in Figure 1 a security gate 140 may be installed at the landward end of the floating dock 130. When the power generation barge 110 and the LNG storage barge 120 are moored in the floating dock 130 and interlocked with the floating dock, the security gate 140 provides a controlled entrance onto the floating dock 130 and thus provides a controlled entrance onto the power generation barge and the LNG storage barge. The security gate 140 includes a security gate, door or other barrier and has a controlled access device such as a terminal that requires the presentation of a key or the like to allow access through the gate, door or other barrier. Persons passing through the security gate 140 may access the length of the floating dock 130, which includes the landward platform 320, the central platform 324 and the seaward platform 328, to access the moored power generation barge 110 or LNG storage barge 120.

[0080] As partially and schematically shown in Figure 3 the overhead power line 132 of the power barge 110 extends towards the shore parallel to the gangway 136. A support structure 342 extends vertically upward from the landward platform 320 to support the first power line 132 on its seaward side where it is connected to the connection device 133 and / or the second power line 134. Additional support structures 342 for the first power line 132 may be provided at the power generation barge 110. For example, power from the power generation barge 110 may be connected through the 11 kV first power line 132 using a coaxial operating load break switch mounted on the pile structure 305. An overhead line pole on one of the piles of the pile structure 305 may have a fuse cutout and a load break elbow mounted at the top of the pole to allow the power line 132 to be isolated and disconnected from the power generation barge 110.

[0081] The floating dock 130 rises and falls with the tide and always maintains neutral buoyancy. The floating dock 130 accepts power barges 110 of different sizes, such as barges with a smaller power capacity or barges with a larger power generation capacity, to provide for the replacement of the barges and the scalability of the power generation system 1. This is achieved through the interchangeability of the interlocking connections 340, which can be used to interlock power barges 110 or LNG storage barges 120 of various power capacities. In an optional embodiment, a standby power barge 110 is provided to allow the entire power barge 110 to be exchanged during maintenance work on the gas turbine 112, thus eliminating any outage requirements for the power generation system 100 for this purpose.

[0082] Figures 4A and 4B show the floating dock 130 installed adjacent to the bulk storage facility 400, which is also located in the sea away from the seaward end of the floating dock 130. The bulk storage facility 400 facilitates the storage of 40,000 m 3 of LNG in a plurality of storage tanks 452. The bulk storage facility 40 is necessary to provide a fueling station for the smaller 3,000 m 3 LNG storage barge 120, and the bulk storage facility 40 is located at a hub location where the LNG storage barge 120 can reach by sea. The bulk storage facility 400 reduces the shipping time to the remote power generation system site. For example, the bulk storage facility 400 is located at a distance of 800 - 1000 Km from a plurality of remote power generation systems 100, resulting in a return LNG shipping cycle from the bulk storage facility 400 to the power generation system 100 of approximately 9 days by sea. The bulk storage facility 400 can also supply larger volumes of LNG, which is necessary for supplying multiple larger generators at remote locations with the highest power demand.

[0083] The bulk storage facility 400 is a floating structure having a platform 450 supported by fixed structural piles or towers 405, 465 (see Figure 4B), which fix the position of the bulk storage facility 400 relative to the seabed while allowing it to rise and fall with the tide. The platform 450 supports a plurality of storage tanks 452 thereon. In the example of Figure 4A, the platform supports 17 storage tanks 452, however the number of storage tanks can vary according to the specific storage capacity requirements at a particular location. The bulk storage facility 400 is located offshore of the floating dock 130 and helps to provide protection for the power generation system 100 in the open sea.

[0084] The plan view of platform 450 is rectangular and has two longer sides, the two longer sides including a landward-facing side 424, a seaward-facing side 425, and two shorter sidewalls 432. Platform 450 consists of a supporting perimeter frame 464 to which walls 424, 425, 432 are attached. The landward-facing side 424 of platform 450 extends the length of the seaward platform 328 of floating dock 130 and seawall 335 and is parallel to the seaward platform and the seawall. A gangway 420 extends between platform 450 and the seaward platform 328 of floating dock 130 to provide personnel access to bulk storage facility 400. A pair of mooring bays 412 are defined by sidewalls 432, a passage dock 430 extending from the landward-facing wall 424 of platform 450 into the sea and collinear therewith, and a seawall 435 positioned at the distal end of passage dock 430 and extending parallel to sidewalls 432, one mooring bay on each side of the platform. Sidewalls 432, passage platform 430, and seawall 435 form a U-shaped barrier in the sea to define mooring bays 412 in which fuel supply LNG storage barge 120 can be moored. When LNG storage barge 120 is moored in mooring bay 412, passage dock 430 provides personnel access from platform 450 to the LNG storage barge. The facility management control system in control room 455 on platform 450 controls the operation of bulk storage facility 400, including monitoring the liquid level in storage tank 452 and performing LNG supply operations to storage tank 122 on moored LNG storage barge 120. The facility management control system includes dedicated control panels for each system or subsystem. For example, the gas turbine (GT) system and ORC 114 each have dedicated control panels to allow an operator to monitor and control. In addition, the facility management control system integrates the operation of GT, ORC, fuel transfer, heat exchange fluid system, and ballast system (which need to be adjusted as fuel is consumed). The facility management control system further monitors the fuel level in the fuel barge and controls fuel transfer as needed using the fluid transfer infrastructure (e.g., pumps, valves, conduits) in system 100.

[0085] A fluid delivery conduit (not seen in the figure) is provided for the purpose of refueling LNG storage barge 120 from storage tank 452. A valve system (not seen in the figure) is provided to control the supply of LNG in the fluid delivery conduit.

[0086] Turning now to the operation of power generation system 100, Figure 5 is a schematic diagram showing the interface between gas turbine power plant 112 and ORC 114 and the main components of ORC 114. The equipment and fluid connections for gas turbine 112 and ORC 114 are shown in more detail in FIG. 8. Gas turbine power plant 112 contains one or more marine versions of natural gas turbines, such as those made by Solar TurbinesTM The manufactured 5.3MW Solar Taurus 60 turbine (under ISO conditions) or 15.6MW Solar Titan 130 turbine (under ISO conditions). These marine versions of the turbines are suitable for marine environments, for example, by using a stainless-steel casing and critical components. The gas turbine generator 112 also incorporates a thrust bearing and a three-point mounting system to allow for the deflection and movement of the power barge 110. The electrical capacity of the gas turbine is selected according to the intended use of the power plant. In this example, the 5.3MW and 15.6MW gas turbines are suitable for small power plant ratings required for remote areas such as in PNG. It should be understood that any suitable gas turbine suitable for the intended use can be used. The gas turbine generator requires regular maintenance and overhaul. In one embodiment of the power generation system 100, an additional power barge 110 is provided so that during maintenance, the power barge 110 can be exchanged with a replacement barge without causing a significant interruption to the power supply to the substation 135.

[0087] Each of the gas turbines 112 includes a generator for generating electricity through shaft work. In Figure 5 the schematic diagram, the gas turbine power plant 112 includes three gas turbine generators 112 that can have the same or different electrical capacities. However, depending on the specific design of the power barge 110, the power generation system 100 can have only a single gas turbine generator 112 or multiple gas turbine generators 112. For clarity, the following description assumes a single gas turbine generator 112.

[0088] The gas turbine 112 has an exhaust duct 512 through which the exhaust gas passes after passing through the engine turbine. The exhaust gas is typically at a temperature of 500 - 600°C. The exhaust duct 512 is arranged to be in fluid communication with the ORC chimney 514 at its lower end 515 and rises to the top of the ORC chimney 514, at which point the exhaust gas exits to the ambient atmosphere at the upper end 517.

[0089] As seen in Figure 5 the ORC chimney 514 is integrated into the waste heat recovery unit (WHRU) 516. The WHRU 516 provides an interface between the gas turbine 112 and the ORC 114. The ORC power plant 114 itself is an independently operable electricity generator. However, when the ORC power plant is operated in combination with the gas turbine power plant 112, the process efficiency is increased, as will be described herein.

[0090] The evaporator 520 and optionally the preheater 518 form part of the WHRU 516 to recover heat from the exhaust gas in the ORC chimney 514 to heat the hot fluid of the ORC 114. The WHRU 516 is essentially a heat exchanger utilizing a closed-loop hot oil circuit passing through the ORC chimney 514 and the evaporator 520 of the ORC 114. The hot oil circuit includes a hot oil conduit 520 and a pump 814, as seen in Figure 8b The hot oil conduit 530 passes through the upper end 517 of the ORC chimney 514 and exits the chimney 514 at its lower end 515. The hot oil conduit 530 then continues to the evaporator 520. In Figure 5 The conduit 530 also passes through the preheater 518, although this is optional. When leaving the evaporator 520 or the preheater 518 (if used), the conduit 530 returns to the upper end 517 of the chimney 514.

[0091] The hot fluid in the conduit 530 is pumped by the pump 814 into the upper end of the ORC chimney 530 and is heated by the exhaust gas flowing upward through the ORC chimney 514. The heated hot oil exits the lower end 515 of the ORC chimney 514 and passes through the evaporator 520, where its thermal energy is transferred to the working fluid of the ORC passing through the evaporator 520. The hot oil is thus cooled when it leaves the evaporator 520. If the hot oil also flows through the preheater 518, the hot oil transfers additional thermal energy to the ORC working fluid before the working fluid enters the evaporator 520.

[0092] The cooled hot oil is then pumped back into the ORC chimney 514. The exhaust gas in the ORC chimney 514 is cooled from 500 degrees Celsius to approximately 130 degrees Celsius, the waste heat energy is transferred to the ORC working fluid, and is used to generate electricity at the ORC 114. Cooling the exhaust gas in the ORC chimney 514 can reduce the parasitic load of the ORC 114. Cooling the exhaust gas in the ORC chimney 514 can improve the overall efficiency of the floating power generation system 100.

[0093] The ORC 114 operates in a standard ORC closed loop. The cycle includes a preheater 518, an evaporator 520, an expansion turbine 522, an electric generator 524, a condenser 526, and a recuperator 528 through which the hot fluid passes during the cycle. The ORC working fluid is the hot fluid transported through the cycle in the hot fluid conduit 532. A pump 534 in the conduit 532 located between the condenser 526 and the recuperator 528 is used to pump the low-pressure, low-temperature hot fluid through the conduit 532 out of the condenser 526 and into the recuperator 528. The hot fluid recovers heat and pressure, and then passes through the preheater 518 and the evaporator 520, where heat is transferred from the very hot hot oil in the hot oil conduit 530 of the WHRU 516 and evaporates into vapor at high temperature and high pressure.

[0094] The turbine 522 can be a radial turbine, such as an Atlas Copco radial turbine, or the turbine can be an axial turbine, such as a Turboden axial turbine. In the case where the turbine 522 is a radial turbine, the turbine has variable inlet vanes that can be controlled to adjust the power output of the ORC generator 114. For example, if a rapid drop or peak in voltage is detected at the control room 910 of the ORC generator 114, the automatic pneumatic control associated with the turbine 522 will open or close the vanes to a certain extent to increase or decrease the flow rate of the hot fluid passing through it. In the case where the turbine 522 is an axial turbine, the automatic controller associated with the turbine 522 opens and closes the valve in the hot fluid conduit 532 to increase or decrease the flow rate of the hot fluid passing through the turbine 522. The vaporized high-pressure hot fluid leaving the evaporator rapidly flows through the turbine 522, causing the turbine shaft to rotate to generate work. The rotating shaft drives the electric generator 524 to generate electricity for the power subsystem 116.

[0095] The hot fluid expands in the turbine 522, and the pressure and temperature of the hot fluid decrease. The cooled vapor passes through the recuperator 528, in which the cooled vapor is used to transfer heat to the condensed hot fluid passing through the recuperator in the opposite direction that has left the condenser 526 as described above, thereby further cooling the vapor. The cooled vapor hot fluid leaving the recuperator 528 then condenses into a liquid form in the condenser 526, and the cycle starts again.

[0096] The condenser 526 forms part of a separate seawater circuit 536. The seawater circuit supplies seawater to the seawater conduit 537 at approximately 26°C. The seawater pump 538 in the seawater conduit 537 is arranged to pump seawater into the condenser 526 to cool the hot fluid vapor, thereby condensing the hot fluid vapor. At a temperature of approximately 36°C, the warmed seawater leaves the condenser and returns to the discharge conduit 820, where Figure 8c seen.

[0097] Figures 6 to 8c is a process and equipment diagram of the LNG storage barge 120 ( Figure 6 ) and the power generation barge 110 (Figs. 7 - 8c). The LNG is initially stored on the LNG storage barge 120 and then transferred from the storage barge 120 to the power barge 110. Each of Figs. 7 - 8c shows a part of the power barge process, which can continue in another figure. Therefore, for clarity, Figures 6-8cEach figure in [the document] illustrates where it connects to one of the other figures. When two related figures are viewed together, it is obvious that there may be minor overlaps between some of the figures.

[0098] The LNG storage barge 120 is arranged in a port and starboard layout, where the starboard half of the LNG storage barge 120 is a mirror image of the port half. This intentional duplication of equipment provides redundancy for the storage barge 120 and ensures an LNG supply in the event of any equipment failure on either half of the storage barge 120. Figure 6 The port half of the storage barge 120 is shown. Those skilled in the art will understand that the starboard half is identical in terms of equipment and differs only in the placement of pipes / conduits. Each half of the storage barge 120 houses four LNG storage tanks 122. The total volume capacity of the LNG storage tanks 122 ranges between 1000 m 3 and approximately 6000 m 3 In an embodiment, the four LNG storage tanks 122 have a total volume capacity of approximately 3000 m 3 However, this capacity can be provided by two or three tanks instead of four tanks. Each LNG storage tank 122 has a fluid transfer conduit 623 for supplying LNG into the tank 122. A valve system 624 in the fluid transfer conduit 623 at each tank 122 is operable to control the flow of LNG in the fluid transfer conduit 623 and into the LNG storage tank 122. An additional fluid transfer conduit 625 allows LNG to flow out of the LNG storage tank 122 and into the LNG supply conduit 127. The valve system 624 includes a valve in the fluid transfer conduit 625 to control the flow of LNG out of the tank 122 and into the fluid transfer conduit 625.

[0099] The storage barge 120 further includes a boil-off gas (BOG) exhaust conduit 630 to receive and convey the boil-off gas generated by the LNG in the LNG storage tanks 122. The boil-off gas can be conveyed through the BOG exhaust conduit 630 to the power barge 110. The storage barge 120 further includes one or more compressed air tanks 612 to supply compressed air for the operation of one or more ballast pumps 610 and / or one or more high-pressure pumps 716. The ballast pumps 610 pump seawater into ballast tanks located within the hull 222 for ballast control when the storage of LNG is depleted. In Figure 7b and 7eAs can be seen, the compressed air supply line 614 for supplying compressed air to the compressed air tank 612 is arranged to be in fluid communication with one or more air compressors 780 located on the power barge 110. Positioning one or more air compressors 780 on the power barge 110 eliminates the requirement for an ignition source for the air compressors 780 located on the storage barge 120. The pump control interface at the ballast pump 610 allows the control of the ballast pump 610 and / or one or more high-pressure pumps 716 by an external controller (such as the control room computing device 1815) in the control center 115 ( Figure 18a ) for this purpose, an external control line is connected to the pump control interface.

[0100] The LNG supply conduit 127 supplies LNG at -160 degrees Celsius and 1 bar to the power barge 110. The boil-off gas (BOG) exhaust conduit 630 transports the boil-off gas from the tanks on each barge at -160 degrees Celsius and 1 bar to the power barge 110.

[0101] The LNG supply conduit 127 and the BOG exhaust conduit 630 extend to Figures 7a-7e and Figure 9 and 10 the power barge 110 shown in. The power barge 110 has power generation equipment arranged on the port side 711a and the starboard side 711b, which evenly distributes the weight on the barge. Some equipment is replicated on the port side and the starboard side of the power barge 110 to provide the necessary redundancy of the power plant equipment, thus ensuring the continuity of power supply in case of equipment failure.

[0102] LNG is supplied to the LNG bladder tanks 710 at each side of the port side 711a and the starboard side 711b of the barge. The bladder tanks 710 are installed on the upper deck of the power barge 110, and the capacity of each bladder tank is 250 m 3 , which is sufficient to provide fuel for the gas turbine power plant 112 for about 7 days continuously. In terms of simpler fuel replenishment logistics, a single larger LNG tank has the advantage over several smaller tanks. In addition, due to the smaller surface area of the tank in contact with LNG, a single well-insulated tank generates significantly less BOG than several smaller tanks. Each bladder tank 710 is fluidly connected to the BOG tank 720 through a pipeline 712 to store the BOG evaporated from the LNG stored in the bladder tank 710. The capacity of the BOG tank 720 is 25 m 3 . As can be seen in Figure 8b , an additional pipeline 722 is provided between the BOG tank 720 and the auxiliary ignition burner 830 of the power barge 110 to supply fuel to the auxiliary ignition burner 830.

[0103] The starboard side LNG belly tank 710 is fluidly connected to the vaporizer 730 through the LNG supply conduit 714. The vaporizer 730 is a plate and shell heat exchanger that receives LNG at -163 °C on its 'cold' side and receives a hot fluid at 15.8 °C on its "hot" side. The high-pressure pump 716 is located in the LNG supply conduit 714 to pump the LNG in the conduit 714 into the vaporizer 730. In some embodiments, the high-pressure pump 716 is a pneumatic pump. For example, the high-pressure pump 716 can be a pneumatic submersible cryogenic transfer pump. Using a pneumatic pump can reduce the risk of fire of flammable materials (such as LNG) on the storage barge 120.

[0104] The hot fluid (ethylene glycol in this embodiment) is introduced into the 'hot' inlet 734 of the vaporizer 730 at 15.8 °C. The plate and shell vaporizer 730 facilitates heat transfer between the two fluids as the two fluids pass through the vaporizer 730, such that the LNG vaporizes into natural gas as it passes through the vaporizer 730 and exits the vaporizer at -77 °C at the 'cold' outlet 736. The hot fluid exits the vaporizer 730 at the 'hot' outlet 738 at a temperature of 3 °C.

[0105] The natural gas exits the vaporizer 730 and enters the natural gas conduit 750 to be transported to the natural gas / hot fluid superheater 744. The superheater 744 is another plate and shell heat exchanger that utilizes the thermal energy stored in the hot fluid before the hot fluid enters the vaporizer 730 to transfer additional thermal energy to the natural gas in the superheater 744. The hot fluid is supplied to the superheater 744 at the 'hot' inlet 746 at a temperature of 24 °C and exits the superheater at the 'hot' outlet at a temperature of 15.8 °C, which is the temperature at which the hot fluid enters the vaporizer 730. The natural gas is supplied to the superheater 744 at the 'cold' inlet 751 at a temperature of -77 °C, which is the temperature at which the natural gas exits the vaporizer 730. It is warmed by heat exchange with the hot fluid and exits the superheater 744 at the 'cold' outlet 752 of the superheater and enters the delivery conduit 754 to be transported to the gas turbine power plant 112 to be burned as fuel. That is, for example, the operating temperature of the hot fluid is between approximately 3 °C and approximately 24 °C.

[0106] The hot fluid passes through the vaporizer 730 and the superheater 744 as part of a closed-loop hot fluid circuit that will be described below. The hot fluid circuit recovers the potential energy released when the LNG is converted to its vapor state in the vaporizer 730 and transfers the potential energy to the hot fluid in the hot fluid circuit. Then, the potential energy is utilized at several points in the hot fluid circuit to increase the efficiency or power output of the power barge. As in Figure 7aAs shown, the hot fluid circuit includes a superheater 744, a vaporizer 730, a cooling header manifold 760, a mixing tank 762, and an ethylene glycol / seawater heat exchanger 770. As described above, the hot fluid passes through the superheater 744 and enters conduit 745, from which the hot fluid passes through the vaporizer 730 and is cooled to 3°C. From here, the hot fluid reaches the cooling header manifold 760 through additional conduit 739. The cooling header manifold 760 also receives the hot fluid in conduit 761 that has passed through the BOG tank 720 to cool the ethylene glycol to a temperature within the target cooling temperature range before the ethylene glycol enters the cooling header manifold 760. The temperature of the cooled ethylene glycol will depend on the ambient temperature and the amount of evaporation generated, although a lower temperature is preferred. The closed-loop hot fluid circuit helps control the pressure of the boil-off gas (BOG) in the tank. The ethylene glycol will be much hotter than the boil-off gas, so this will increase the pressure in the BOG tank to help raise the pressure to the pressure required for the auxiliary burner. That is, the ethylene glycol is used to heat the BOG so that the pressure of the BOG increases before entering the auxiliary burner. Therefore, due to the heat transfer of the ethylene glycol, the temperature of the BOG also increases.

[0107] The hot fluid supply is split into multiple streams at the cooling header manifold 760 for delivery to other parts of the power barge 110. Fluid conduit 763 delivers the hot fluid from the cooling header manifold 760 to the mixing tank 762. Fluid conduit 764 delivers the hot fluid from the cooling header manifold 760 to the port side air compressor 780 (see Figure 7b ), in which the hot fluid is used to cool the air compressor 780. The hot fluid then returns to the mixing tank 762 through fluid conduit 767. Fluid conduit 765 delivers the hot fluid from the cooling header manifold 760 to the below-deck HVAC unit 782 (see Figure 7b ), in which the hot fluid is used to cool the HVAC unit 782. The hot fluid then returns to the mixing tank 762 through fluid conduit 768. Fluid conduit 766 delivers the hot fluid from the cooling header manifold 760 for use at the gas turbine 112, particularly for cooling the inlet air of the gas turbine engine 112, as will be described later. In one embodiment, a portion of the hot fluid can also be diverted for cooling the turbine lubricating oil. The hot fluid utilized at the gas turbine 112 is heated by the turbine inlet air and / or the turbine lubricating oil and returns to the mixing tank 762 through fluid conduit 783.

[0108] The capacity of the mixing tank 762 is 100 m 3, and mixes and stores the hot fluid received from fluid conduits 763, 767, 768. The mixing tank 762 has an outlet leading to fluid conduit 769, which is fluidly connected to the ethylene glycol / seawater heat exchanger 770. The ethylene glycol hot fluid in the hot loop flows from the mixing tank 762 through fluid conduit 769 and is pumped by the ethylene glycol pump 772 into the 'cold' inlet 774 of the ethylene glycol / seawater heat exchanger 770. The ethylene glycol / seawater heat exchanger 770 is a plate and shell heat exchanger that facilitates heat transfer between the hot fluid and seawater to heat the hot fluid before it is delivered to the superheater 744 or to the BOG tank 720 through fluid conduit 789, so that it is cooled before the hot fluid re-enters the cooling header manifold 760. The hot fluid loop then completes and starts again.

[0109] The temperature of the hot fluid when it enters the heat exchanger 770 is 21 °C, which has been heated during the process of cooling the equipment on the power barge 110 as described above. The hot fluid is further heated by the seawater passing through the heat exchanger 770 and leaves the heat exchanger 770 at the 'cold' outlet 776 at a temperature of 24 °C. Seawater is supplied from the ocean in the seawater supply conduit 777 to the 'hot' inlet 778 of the heat exchanger 770 at a flow rate of 55 m 3 / h and at an ambient temperature of 26 °C. The seawater passes through the hot side of the heat exchanger 770, in which some of the heat in the seawater is transferred to the hot fluid and leaves at the 'hot' outlet 779 at a temperature of 24 °C and returns to the ocean through fluid conduit 781.

[0110] Thus, the closed-loop hot loop utilizes the potential released during the vaporization of LNG, captures the potential in the hot fluid of the superheater 744, and effectively uses it to provide cooling for the inlet air of the gas turbine 112, the turbine lubricating oil, and other equipment (such as the air compressor 780 and the HVAC unit 782) on the power barge 110. This results in an increase in the efficiency of the entire power generation system.

[0111] The seawater pump 790 pumps seawater from the sea into the power barge. In Figure 7d , three seawater pumps 790 are shown, each of which can operate at a pressure of 5 bar and has a flow rate of 100 cubic meters per hour. Seawater is pumped into the seawater pump 790 through the seawater supply conduit 792. The seawater is distributed in the distribution conduit 794 for the heat exchangers 780 on each side of the starboard side and port side of the power barge 110 and the ballast system 795 located under the deck, as Figure 7d indicated. The distribution conduit 794 supplies water to the starboard side seawater supply conduit, and a portion is diverted into the port side seawater supply conduit 777 for the port side heat exchanger 780.

[0112] A conventional practice for large LNG fuel power plants is to include two or more thermal circuits, one thermal circuit capable of operating under cryogenic conditions and another thermal circuit capable of operating under non-cryogenic conditions. A thermal circuit capable of operating under cryogenic conditions is generally not suitable for systems operating at non-cryogenic temperatures because the extremely low temperatures can have a negative impact on those systems. The utilization of the potential of LNG vaporization allows for the use of a single closed-loop thermal circuit that is not exposed to the cryogenic temperatures of LNG.

[0113] Figure 8a-8c It is a schematic diagram of a device with pipeline connections for a gas turbine generator 112, a WHRU 516, and an ORC generator 114, and any one of natural gas, boil-off gas, and compressed air. The gas turbine generator 112 is shown in Figure 8a which. It includes an air inlet 802, which, in the illustrated example, includes a three-stage intake air filter. In some embodiments, the three-stage intake air filter may include at least one low-loss filter, for example, a low-loss filter for each stage. The ambient air entering the air inlet 802 passes through the filter and enters the air inlet duct 804, which guides the air into the gas turbine engine 112. The main components of the gas turbine engine 112 are not visible in Figure 8a and consist of a compressor, a combustion chamber 806, a turbine, and a generator. The air inlet duct 804 includes one or more cooler coils 808 through which the inlet air passes before entering the compressor of the gas turbine engine 112. The cooler coil 808 is fluidly connected to a hot fluid supply duct 783 to supply ethylene glycol hot fluid at a temperature of 3 °C to the cooler coil 808. The ambient air enters the air inlet 802 at a temperature of 26 °C. When the ambient air flows through the cooler coil 808, the inlet air is cooled to a temperature of approximately 15 °C before being compressed in the compressor.

[0114] The combustion chamber 806 is fluidly connected to a natural gas supply in the supply duct 812, which, after vaporizing the LNG in the vaporizer 730, supplies natural gas from each of the port and starboard supply ducts 754. Compressed air enters the combustion chamber 806, where it is injected and ignited by natural gas. The resulting combusted gas expands rapidly through the turbine, which rotates to drive the electric generator. Using cold hot fluid from the thermal circuit to lower the temperature of the inlet air in the gas turbine 112 increases the efficiency of the gas turbine generator by approximately 10% and the fuel efficiency by 3%.

[0115] In some embodiments, the supply conduit 812 may also be fluidly connected to a natural gas (NG) supply stored in an NG accumulator 896. For example, in the case of a sudden increase in consumption, the NG accumulator 896 can be used to store additional natural gas supplied to the combustion chamber 806. That is, for example, if a load is suddenly drawn from the gas turbine generator 112, the NG accumulator 896 will supply additional natural gas to the gas turbine generator 112. The size of the NG accumulator is selected to accommodate the expected difference resulting from GT fuel gas consumption and the residence time required for the LNG process to reach pressure.

[0116] The turbine is fluidly connected at its outlet to a turbine exhaust duct 814 to discharge the exhaust gas. The turbine exhaust duct is a conduit leading to the atmosphere and is also fluidly connected to a pipe 842 through which the exhaust gas can be selectively diverted for use in the WHRU 116 and thus also in the ORC 114. A diverter damper 840 is pivotally mounted in the turbine exhaust duct 814 to selectively divert the exhaust gas. The damper 840 can move between a first position in which the gas turbine 112 and the ORC generator operate together and a second position in which the gas turbine 112 and the ORC generator 114 operate independently of each other. In the first position of the damper 840, the exhaust duct (or exhaust stack) 814 is closed to the gas leaving the turbine, thereby allowing the gas to flow into the pipe 842. In the second position of the damper 840, the exhaust duct is opened to allow the gas leaving the gas turbine to enter the exhaust duct 814 while the pipe leading to the WHRU 116 is closed to the gas. In the illustrated embodiment, the diverter damper 840 consists of an airtight damper, but any suitable form that allows the selective diversion of gas from the turbine exhaust duct 840 to the WHRU 116 can be employed. An equivalent diverter device can also be used.

[0117] The pipe 842 provides a fluid connection between the gas turbine 112 and the WHRU 116. Upstream of the WHRU 116 is a fresh air ignition stack 844 that effectively replicates the turbine exhaust gas when the ORC generator 114 will operate independently. The fresh air ignition stack 844 includes an air inlet 845 to draw fresh air into the stack 844. A fan 846 located at the air inlet draws air into the inlet 845 and through an air filter 847. A blower 854 further supplies fresh air to the fresh air ignition stack 844 upstream of the combustion chamber 848. The supply of natural gas is diverted from the supply conduit 812 to a supply conduit 852 to provide fuel to a valve 850 in the fresh air ignition stack 844 at a pressure of 30 bar, a flow rate of 1800 cubic meters per hour, and a temperature of 19 °C. The fresh air and natural gas burn in the combustion chamber 848, and the co-ignited gas leaves the fresh air ignition stack 844 and enters the pipe 842.

[0118] An additional diverter damper 860 is pivotally mounted in the duct 842 to selectively permit gases in the fresh air ignition stack 844 to enter the duct 842. In a first position of the damper 860, the duct 842 is closed to the fresh air ignition stack 844. In a second position of the damper 860, the duct 842 is open to permit co-ignited gases leaving the fresh air ignition stack 844 to enter the duct 842. The damper 860 consists of an airtight damper, but may take any suitable form that permits opening and closing of the duct 842 leading to the fresh air ignition stack 844.

[0119] Downstream of the turbine exhaust duct 512 and the fresh air ignition stack 844, the duct 842 is fluidly connected to an auxiliary burner 830. The auxiliary burner 830 includes a combustion chamber that receives ambient air from a blower 856 and fuel in the form of BOG supplied from the BOG tank 720 to the combustion chamber through a supply conduit 722.

[0120] The turbine exhaust gases leave the gas turbine at a temperature of approximately 500 °C. The co-ignited gases leave the fresh air ignition stack at approximately the same temperature. The exhaust gases or co-ignited gases in the duct 842 enter the auxiliary burner 830 and are ignited by the BOG to further heat the gases to a temperature of approximately 600 °C before the gases enter the WHRU 116. With this arrangement, the BOG is effectively utilized to generate auxiliary heat for operating the ORC 114 through heat transfer from the combusted BOG and the exhaust gases / co-ignited gases to the working fluid of the ORC. The location of the auxiliary burner downstream of the gas turbine 112 and the fresh air ignition stack 844 has the effect that the BOG is utilized regardless of whether the gas turbine 112 and the ORC 114 are operating independently or together.

[0121] The position of the damper 840 and the position of the damper 860, as well as the operation of the gas turbine 112 and the operation of the ORC generator 114, are controlled by a control system or controller 908, which may be operated from a control center 115 on the power generation barge 110. The control system or controller 908 may be configured to monitor the electrical load drawn at at least one remote power receiving end and automatically control the operation of the gas turbine 112 and the ORC 114 in response to the monitored drawn load.

[0122] Whether the gas turbine 112 or the ORC 114 operates alone, or whether both operate together in a combined cycle, depends on the electrical load drawn by at least one remote power receiving end (e.g., a substation 135 serving an industrial facility or a residential area). The normal operation of the power barge 110 assumes that the gas turbine 112 and the ORC will operate in a combined cycle, however this is not always effective and it may be necessary to operate the gas turbine 112 or the ORC 114 alone. FIG. 13A is a flowchart of a decision process for positioning the damper 840. At step S1300, the electrical load drawn by the remote receiving end is determined by the control system or controller 908. The ORC 114 has a first power generation capacity, and the gas turbine 112 has a second power generation capacity higher than the first power generation capacity. In the case where the load drawn by at least one remote power receiving end is at or above a threshold electrical load (e.g., the second power generation capacity of the gas turbine 112), at step S1302, the damper 840 is positioned at a first position to allow turbine exhaust gas to enter the pipe 842 and be used for the WHRU 116. If the load drawn at at least one remote power receiving end drops below the threshold electrical load, it is inefficient to operate the gas turbine 112 and the ORC 114 in a combined cycle, and at step S1304, the damper 840 is positioned at a second position to allow the gas turbine 112 and the ORC 114 to operate independently.

[0123] In this case, when the air damper 840 is positioned at the second position, the gas turbine 112 operates in a simple cycle without the ORC 114, or the ORC 114 operates independently without the gas turbine 112. FIG. 13B is a flowchart of a decision-making process for operating either the gas turbine 112 or the ORC 114. At step S1306, the control system or controller 908 determines the electrical load drawn by the remote receiving end. If the electrical load drawn at the remote power receiving end is higher than the first power generation capacity, i.e., the power generation capacity of the ORC 114, and lower than the second power generation capacity, i.e., the power generation capacity of the gas turbine 112, then at step S1308, the gas turbine 112 operates alone in a simple cycle. If the electrical load drawn at the remote power receiving end is within the first power generation capacity, then at step S1310, the ORC 114 operates alone in a simple cycle without the gas turbine 112. If the gas turbine 122 operates alone, positioning the air damper 840 at the second position prevents the turbine exhaust gas from entering the pipe 842, rather than leaving the gas turbine through the turbine exhaust pipe 512. If the gas turbine 112 is not operating, closing the air damper 840 leading to the pipe 842 ensures that the co-ignited gas from the fresh air ignition chimney 844 flows in the direction of the auxiliary burner 830. In this way, the power barge 110 can operate at the most efficient level at any given time to draw the electrical load. The power generation capacity of the gas turbine will depend on the specific gas turbine used, and thus a threshold electrical load must be set for the specific gas turbine 112 used, which is lower than the threshold electrical load of the air damper 840 positioned at the second position. Thus, if a 15.6 MW Solar Titan 130 turbine is used, the electrical load threshold will be 15.6 MW. Similarly, if the ORC 114 has a power generation capacity of 6 MW, the threshold electrical load is approximately 6 MW, which is lower than the threshold electrical load at which only the ORC 114 will operate. The ability to operate the gas turbine 112 and the ORC generator 114 independently of each other also provides a degree of redundancy in case either generator requires maintenance.

[0124] Figure 9 and Figure 10Shows the overall layout of the power barge 110. Although not all equipment is visible in these figures, the LNG storage tank 710, high-pressure LNG pump 716, seawater pump 538, and ethylene glycol / thermal fluid circulation pump 534 are all located below deck. The control center 115 is located on the main deck. For safety reasons, the vaporizer 730 and BOG tank 720 are also located on the main deck so that the vaporized LNG is not stored in the limited space below deck. The black start generator (BSG) 920 is located on the main deck for the emergency restart of the gas turbine 112. Alternatively, the black start generator 920 can be located on the floating dock 130 to reduce the weight of the power generation barge 110. The gas turbine 112, ORC 114, WHRU 116, pump 772, and heat exchangers 744, 770 are all located on the main deck for serviceability.

[0125] The ballast of the power generation barge 110 is controlled by adding and removing seawater to the ballast tanks located below deck as fuel is transferred from the storage barge 120 or consumed for power generation.

[0126] In Figure 10 the deck 930 and hull 232 are removed to more clearly show the frame 230 of the power generation barge 110. The frame 230 consists of multiple steel frame sections 1010 connected together in an open grid frame to minimize weight while providing the necessary strength to support the power plant equipment.

[0127] Figure 11 and Figure 12 shows the overall layout of the LNG storage barge 120. As seen in Figure 11 the deck 1110 of the vessel has no power plant equipment. Four LNG storage tanks 122 are located side by side within the vessel frame 220, extending fore and aft along the length of the vessel and evenly distributed from port to starboard. The LNG storage tanks 122 are covered by the tank shell 1112. The gantry 1130 is installed above the tank shell 1112 for personnel access to the area and any equipment installed above each tank 122. Access to the gantry 1130 is through stairways at the bow and stern of the storage tanks 122 from the deck 1110. The interlock connection point 1150 at the bow end of the LNG storage barge 120 allows for an interlock connection with the interlock device 340 at the floating dock 130 to moor the LNG storage barge 120 in the mooring bay 310.

[0128] In Figure 12 the deck 1110 and cover 1112 are removed to more clearly show the frame 220 of the LNG storage barge 120. The frame 220 consists of multiple steel frame sections 1210 connected together in an open grid frame to minimize weight while providing the necessary strength to support the LNG storage tanks 122.

[0129] Figure 14a -c is the 11KV main power single-line diagram of the active power system 1400 according to some embodiments. Figure 14a The reference lines shown in -c indicate that the shown figure continues in another figure. For example, the reference line marked with "Connected to Figure 14b " Figure 14a continues at the corresponding "Connected Figure 14b " on Figure 14a . Similar logic applies to the alternative reference lines shown in Figure 14a -c.

[0130] Refer to Figure 14a , the active power system 1400 may include a neutral grounding resistor panel (NGRP) 1402. For example, the NGRP 1402 can be used in the active power system 1400 to protect electrical equipment such as transformers and generators from fault events (e.g., short circuits) and transient phenomena (such as lightning). The NGRP 1402 can limit transient overvoltages to a safe value during a fault event or transient phenomenon to avoid outages and damage to the equipment within the active power system 1400. For example, the NGRP 1402 can reduce fault current while still allowing sufficient fault current to flow to activate the protection device.

[0131] The active power system 1400 further includes a gas turbine system 1404 to generate electrical energy using the gas turbine 112, as previously described. The gas turbine system 1404 may further include an automatic voltage regulator (AVR) 1410 to automatically maintain the output voltage of the gas turbine system 1404. That is, for example, the AVR 1410 can be used to regulate the output voltage of the gas turbine system 1404 at a predetermined voltage value. The gas turbine system 1404 may further include a protection device 1412.

[0132] The protection device 1412 can be used to provide overcurrent protection to the active power system 1400. In some embodiments, the protection device 1412 can provide some or all of the following protection features, either individually, in combination, or both, as outlined in "IEEE Standard C37.2 Power System Device Function Numbers, Acronyms, and Contact Designations": 87G (generator differential), 27 (under-voltage relay), 59 (over-voltage relay), 81 (frequency relay), 59N (neutral over-voltage), 32 (directional power relay), 40 (field relay / loss of excitation), 49G (machine or transformer thermal relay / thermal overload ground), 46 (reverse or phase balance current relay or stator current unbalance), 51V (voltage restraint time overcurrent), 50 (instantaneous overcurrent relay), and / or 50G (ground instantaneous overcurrent). In some embodiments, for example, the protection device 1412 can include multiple relays.

[0133] The prime power system 1400 further includes an ORC system 1406 to generate electrical energy using an ORC generator 114, as previously described. The ORC system 1406 may further include an AVR 1410 and a protection device 1412 to perform the functions as previously described. The prime power system 1400 further includes a BSG system 1408 to generate electrical energy using a BSG generator 920. For example, the BSG system 1408 can be used to start the gas turbine 112 of the gas turbine system 1404. For example, the BSG system 1408 can be used to start the ORC generator 114 of the ORC system 1406. The BSG system 1408 may further include an AVR 1410 and a protection device 1412 to perform the functions as previously described.

[0134] Reference Figure 14b , reference letters "A" and "B" indicate the continuation of the lines from Figures 14b to 15b . For example, Figure 14b the line marked with "A" in Figure 15b continues at the corresponding "A" on Figure 14b and 15b the "B" on

[0135] The prime power system 1400 further includes monitoring and protection (MP) panels 1420, 1422, and 1424 that are in electrical communication with the gas turbine system 1404, the ORC system 1406, and the BSG system 1408, respectively. Each MP panel 1420, 1422, and 1424 is used to monitor the electrical power provided by its respective system and provide circuit protection in the event of a fault. The MP panels 1420, 1422, and 1424 each include a circuit breaker 1450, a step-down transformer 1452, a metering device 1454, a protection device 1456, and a plurality of current transformers 1458. In some embodiments, the circuit breaker 1450 can be a three-phase circuit breaker appropriately rated according to the system to which it is connected. For example, the circuit breaker 1450 can be rated at 1600A, 1000A, 600A, or 200A. For example, the MP panel 1420 in electrical communication with the gas turbine system 1404 can be rated at 1000A to accommodate the electrical output of the gas generator 112. In some embodiments, the circuit breaker 1450 can be a draw-out circuit breaker. That is, the circuit breaker 1450 can be, for example, a circuit breaker that can be physically removed from the system under no-load conditions.

[0136] Step-down transformer 1452 can be used to step down the voltage input of each MP panel 1420, 1422, and 1424 to power other electrical components within the panel, such as metering device 1454 and protection device 1456. For example, MP panel 1420 receives an input voltage from gas turbine system 1404, and step-down transformer 1452 reduces the input voltage to an appropriate voltage to power metering device 1454 and protection device 1456. In some embodiments, step-down transformer 1452 can include a circuit breaker in series with each secondary winding. That is, for example, a circuit breaker can be included between each secondary winding and the connected electrical components, such as metering device 1454 and protection device 1456.

[0137] Metering device 1454 can be used for some or all of the following: analysis of efficiency, losses, and capacity; bill verification, cost allocation, and sub-metering; power quality compliance monitoring; problem notification and diagnosis; demand for power factor management; and control of loads, generators, or other equipment. In some embodiments, for example, metering device 1454 can be an off-the-shelf device, such as Schneider ION 7650.

[0138] Protection device 1456 can be used to provide overcurrent protection to prime power system 1400. In some embodiments, protection device 1456 can provide some or all of the following protection features, either individually, in combination, or both, as outlined in "IEEE Standard C37.2 Functional Numbers, Acronyms, and Contact Designations for Power System Devices": 50 (instantaneous overcurrent relay), 50N (neutral instantaneous overcurrent), 50G (ground instantaneous overcurrent), 87G (generator differential), 25 (synchronizing or synchronism-check device), 27 (undervoltage relay), 59 (overvoltage relay), and / or 81 (frequency relay). For example, protection device 1456 can be an off-the-shelf device, such as Selinc SEL-351A.

[0139] In some embodiments, current transformer 1458 can be used to reduce the alternating current input to each MP panel 1420, 1422, and 1424 for use by metering device 1454 and protection device 1456. For example, MP panel 1420 receives an input alternating current from gas turbine system 1404, and current transformer 1458 reduces the input alternating current to an appropriate alternating current to provide to metering device 1454 and protection device 1456.

[0140] In some embodiments, each of the MP panels 1420, 1422, and 1424 includes an electrical connection to a synchronizer 1459. The synchronizer 1459 can be used to 'synchronize' the frequencies of the gas turbine system 1404, the ORC system 1406, and the BSG system 1408 to match the frequency of the operating network or the system drawing power from the generator. When at least two of the gas turbine system 1404, the ORC system 1406, or the BSG system 1408 supply power to the operating network simultaneously, they must be synchronized so that they supply power in parallel. In some embodiments, the synchronizer 1459 can control the operation of the gas turbine system 1404, the ORC system 1406, or the BSG system 1408 such that it has the same line voltage, frequency, phase sequence, phase angle, and waveform as the operating network to which it is synchronized.

[0141] The prime power system 1400 can further include a first auxiliary transformer (T-AUX1) 1432 and a second auxiliary transformer (T-AUX2) 1436. T-AUX1 1432 and T-AUX2 1436 can be used to step down the high voltage supplied by the gas turbine system 1404, the ORC system 1406, or the BSG system 1408 individually or in combination with each other to a lower voltage available for the barge power system 1500, which will be described in conjunction with Figure 15a -c. For example, T-AUX1 1432 can step down the supplied 11 kV voltage to a lower voltage of 0.415 kV or 415 V. Similarly, T-AUX2 1436 can step down the supplied 11 kV voltage to a lower voltage of 0.415 kV or 415 V. In some embodiments, for example, T-AUX1 1432 is a grounded Y-δ transformer. In some embodiments, for example, T-AUX2 1436 is a grounded Y-δ transformer.

[0142] The prime power system 1400 further includes MP panels 1434 and 1438 for each of T-AUX1 1432 and T-AUX2 1436, respectively. The MP panels 1434 and 1438 are used to monitor the power supplied to the first auxiliary transformer 1432 and the second auxiliary transformer 1436 by the gas turbine system 1404, the ORC system 1406, and / or the BSG system 1408 through their respective MP panels 1420, 1422, and 1424, and to provide circuit protection in case of a fault. Each of the MP panels 1434 and 1438 includes a circuit breaker 1450, a step-down transformer 1452, a metering device 1454, a protection device 1456, and a plurality of current transformers 1458. The MP panels 1434 and 1438 operate in the same manner as the MP panels 1420, 1422, and 1424, as previously described.

[0143] Reference Figure 14c, the prime power system 1400 further includes MP panels 1472 and 1474. The MP panels 1472 and 1474 are used to monitor the power output from the prime power system 1400 to the external substation 135 and provide circuit protection in case of a fault. Each of the MP panels 1472 and 1474 includes a circuit breaker 1450, a step-down transformer 1452, a metering device 1454, a first protection device 1475, a second protection device 1476, a plurality of current transformers 1458, and an electrical connection to a synchronizer 1459. The MP panels 1472 and 1474 operate in the same manner as the MP panels 1420, 1422, and 1424, as previously described. In some embodiments, the first protection device 1475 and the second protection device 1476 of the MP panels 1472 and 1474 further include a fiber optic cable (FOC) communication connection 1490 to the external substation 135. That is, for example, each of the first protection device 1475 and the second protection device 1476 and the metering device 1454 of the MP panels 1472 and 1474 can provide data to and receive data from the external substation 135.

[0144] In some embodiments, the first protection device 1475 can provide, individually, in combination, or both, some or all of the following protection features as outlined in "IEEE Standard C37.2 Power System Device Function Numbers, Acronyms, and Contact Designations": 67 (AC Directional Overcurrent Relay), 67N (Neutral Directional Overcurrent), 21 (Distance Relay), 25 (Synchronizing or Synchronism Check Device), 27 (Undervoltage Relay), 59 (Overvoltage Relay), 50BF (Overvoltage Relay Breaker Failure), 81 (Frequency Relay), 87L (Isolated Line Current Differential), and / or X (Auxiliary Relay). In some embodiments, for example, the first protection device 1475 can be an off-the-shelf device, such as a MiCOM P543.

[0145] In some embodiments, the second protection device 1476 can provide, individually, in combination, or both, some or all of the following protection features as outlined in "IEEE Standard C37.2 Power System Device Function Numbers, Acronyms, and Contact Designations": 67 (AC Directional Overcurrent Relay), 67N (Neutral Directional Overcurrent), 21 (Distance Relay), 25 (Synchronizing or Synchronism Check Device), 27 (Undervoltage Relay), 59 (Overvoltage Relay), 50BF (Overvoltage Relay Breaker Failure), 81 (Frequency Relay), 87L (Isolated Line Current Differential), and Y (Auxiliary Relay). In some embodiments, for example, the second protection device 1476 can be an off-the-shelf device, such as a Selinc SEL-311L.

[0146] The prime power system 1400 further includes a main control panel 1480 for metering the power output of the prime power system 1400 and monitoring the prime power system 1400. The main control panel 1480 includes a step-down transformer 1452, a revenue metering panel 1482, a plant metering panel 1483, an SAC panel 1484, and a plurality of current transformers 1458. The functions of the step-down transformer 1452 and the plurality of current transformers 1458 are as described previously.

[0147] In some embodiments, the revenue metering panel 1482 includes a first metering device and a second metering device 1454 for metering the output of the prime power system 1400 to the external substation 135. In some embodiments, the second metering device 1454 can be used to ensure that the first metering device 1454 operates as required. That is, for example, the reading of the first metering device 1454 can be checked against the reading of the second metering device 1454 to ensure that the device operates correctly. For example, the metering device 1454 of the revenue metering panel 1482 can be an off-the-shelf device, such as the Schneider ION 9600. In some embodiments, the revenue metering panel 1482 can further include a communication connection 1490 with at least one fiber optic cable (FOC) to the external substation 135.

[0148] In some embodiments, the plant metering panel 1483 includes a metering device 1454 for internally monitoring the output of the prime power system 1400. The function of the metering device 1454 of the plant metering panel 1483 is as described previously.

[0149] The switchyard automation control (SAC) panel 1484 can be used to monitor and control the prime power system 1400. In some embodiments, the SAC panel 1484 includes a control unit. For example, the control unit can be an off-the-shelf device, such as the SEL-2032, or the SEL-3530 or the SEL-3555. The SAC panel 1484 can communicate with some or all of the following: the metering devices 1454 of the MP panels 1420, 1422, 1424, 1426, 1428, 1472, and 1474, the protection devices 1456 of the MP panels 1420, 1422, 1424, 1426, and 1428, and the first protection device 1475 and the second protection device 1476 of the MP panels 1472 and 1474. In some embodiments, the SAC panel 1484 can further include a communication connection 1490 with at least one fiber optic cable (FOC) to the external substation 135.

[0150] The SAC panel 1484 can also be connected to the switch 1489. When actuated by the SAC panel 1484, the switch 1489 disconnects the substation 135 connected by the external power supply connection 1492 from the main power system 1400. In some embodiments, for example, the switch 1489 can be a coaxial-operated load break switch actuated by a motor.

[0151] Figure 15a -b is a 415V barge electrical single line diagram of the barge power system 1500 according to some embodiments. The barge power system 1500 receives power from the main power system 1400 through connections marked "A" and "B", as Figure 15b shown. The barge power system 1500 includes a plurality of power buses 1510 to distribute the power supplied by the main power system 1400 to a plurality of components within the barge power system 1500. The barge power system 1500 further includes a plurality of motors 1530. In some embodiments, for example, the plurality of motors 1530 can include any one of pumps, fans, HVAC, turbines, hydraulic systems, lighting, crane systems. In some embodiments, the plurality of motors 1530 receive power through the power buses 1510. The barge power system 1500 can further include a plurality of variable frequency drives (VFDs) 1520. In some embodiments, some or all of the plurality of motors 1530 can receive power from the power buses 1510 through the VFD 1520.

[0152] As Figure 15b shown, the barge power system 1500 further includes an uninterruptible power supply (UPS) 1540. The UPS 1540 can be used to supply power to a plurality of components in the barge power system 1500 in the event of a fault or power outage. For example, a loss of power from the main power system 1400 may cause the UPS 1540 to start to supply power to, for example, a plurality of components of the barge power system 1500.

[0153] Referring to FIG. 15c, the barge power system 1500 can further include a power bus 1550 to distribute the power supplied by the main power system 1400 to a plurality of control panels 1560 within the barge power system 1500. In some embodiments, for example, in the event of a fault or power outage, the power bus 1550 can receive power from the UPS 1540. The plurality of control panels 1560 can be used to control various systems, electromechanical devices of the barge power system 1500. For example, the plurality of control panels 1560 can control lighting, general power, fire protection systems, and / or generators.

[0154] Referring Figure 16a to, reference letters "W" and "X" indicate the continuation of the line from Figures 16a to 16c For example, Figure 16aThe line marked with "W" in Figure 16c continues at the corresponding "W" on Figure 16b and 16c the "Y" and "Z" on

[0155] Figure 16a -c is a single-line diagram of the 110VDC power generation barge electrical system of the barge DC power system 1600 according to some embodiments. The barge DC power system 1600 includes a first battery system 1610 and a second battery system 1620. Each of the first battery system 1610 and the second battery system 1620 includes a battery charger, a battery management system, and a battery array 1615, all of which are in electrical communication with each other. In some embodiments, the battery charger receives an input power supply from connection 1640. The battery charger can use the input power supply to charge the battery array 1615. In some embodiments, the input power supply is rated at 240V, 13A. In some embodiments, the battery charger can convert the input power supply into a 110VDC power supply. In some embodiments, the battery array 1615 can include multiple batteries.

[0156] Each of the first battery system 1610 and the second battery system 1620 provides power rated at 110VDC to the 110VDC distribution bus 1630. In some embodiments, the second battery system 1620 can act as a failover power supply. That is, for example, in the case where the first battery system 1610 cannot provide power, the second battery system 1620 can provide power to the 110VDC distribution bus 1630. The 110VDC distribution bus 1630 can supply a 110VDC power supply to various systems and components of the offshore power generation system 100. In some embodiments, the distribution bus 1630 supplies power to the conversion interface circuit 1650. The conversion interface circuit 1650 converts the 110VDC power supply from the 110VDC distribution bus 1630 into a 24VDC power supply. Then the 24VDC power supply is supplied to the 24VDC distribution bus 1660. In some embodiments, the 24VDC distribution bus 1660 can supply a 24VDC power supply to various systems and components of the offshore power generation system 100.

[0157] Figure 17a -b is a general layout schematic diagram of the 110VDC power supply (DCPS) 1700, such as the barge DC power system 1600. For example, in some embodiments, the DCPS 1700 can be in the form as in Figure 17aThe form of the electrical cabinet shown in -b. This electrical cabinet can be an off-the-shelf and easily obtainable electrical cabinet. In some embodiments, the DCPS 1700 can accommodate the barge DC power system 1600. In some embodiments, there can be a second DCPS 1700 to accommodate the components of the barge DC power system 1600. That is, for example, the DCPS 1700 can contain the battery first battery system 1610, the battery array 1615, the 110 VDC distribution bus 1630, and the 24 VDC distribution bus 1660, and the second DCPS 1700 can contain the second battery system 1620, the battery array 1615, the 110 VDC distribution bus 1630, and the 24 VDC distribution bus 1660.

[0158] Figure 18a -b is a schematic diagram of a power communication architecture 1800 according to some embodiments. At least a part of the power communication architecture 1800 can be located in the control center 115. Figure 18a -b provides a graphical representation of the data communication between the SAC panel 1484 and the MP panels 1420, 1422, 1424, 1426, 1428, 1472, and 1474, as well as the power plant metering panel 1483. That is, the power communication architecture 1800 includes the SAC panel 1484, the MP panels 1420, 1422, 1424, 1426, 1428, 1472, 1474, and the power plant metering panel 1483. In some embodiments, the power communication architecture 1800 can further include an external communication connection 1810. For example, the external communication connection 1810 can provide communication between the power communication architecture 1800 and an external computing device.

[0159] In some embodiments, the power communication architecture 1800 can further include a control room computing device 1815. For example, the control room computing device 1815 can allow a user to control and monitor the systems and components of the power communication architecture 1800. In some embodiments, the power communication architecture 1800 can further include a printer 1820 or other peripheral devices that communicate with the control room computing device 1815. In some embodiments, the power communication architecture 1800 can further include a barge power system control panel 1825. For example, the power system control panel 1825 can include some or all of the control panels for controlling the systems of the offshore power generation system 100.

[0160] Those skilled in the art will understand that various changes and / or modifications can be made to the above embodiments without departing from the broad general scope of the present disclosure, including the following clauses. Therefore, the present embodiments should be considered illustrative in all respects and not restrictive.

[0161] Clause 1. A power generation system comprising: a gas turbine for generating electricity by combustion of natural gas; a gas supply line for supplying vaporized liquefied natural gas (LNG) to the gas turbine; a power subsystem for receiving electricity from the gas turbine and supplying power to at least one remote power receiving end; a vaporizer configured to vaporize the LNG; and a closed-loop thermal fluid circuit configured to recover the latent energy of the vaporized LNG to cool a thermal fluid in the closed-loop thermal fluid circuit, wherein the gas turbine includes an air inlet for inhaling ambient air; and wherein the air inlet is configured such that the ambient air flowing therethrough is cooled by the cooled thermal fluid.

[0162] Clause 2. The system according to Clause 1, wherein the gas turbine includes a lubricating oil cooler, and wherein the thermal fluid circuit is configured to exchange thermal energy with the lubricating oil in the lubricating oil cooler, thereby cooling the lubricating oil and heating the thermal fluid.

[0163] Clause 3. The system according to Clause 2, wherein the thermal fluid circuit includes a heat exchanger in which the thermal fluid exchanges thermal energy with seawater passing through the heat exchanger, thereby further heating the thermal fluid before it returns to the vaporizer.

[0164] Clause 4. The system according to any one of Clauses 1 to 3, wherein a portion of the thermal fluid cooled at the vaporizer is diverted from the thermal fluid circuit for cooling air conditioning equipment and / or compressor equipment.

[0165] Clause 5. The system according to any one of Clauses 1 to 4, further comprising an organic Rankine cycle (ORC) generator for generating electricity by heat recovery, wherein the power subsystem is configured to receive electricity from at least one of the gas turbine or the ORC generator to supply power to the at least one remote power receiving end.

[0166] Clause 6. The system according to Clause 5, wherein the ORC generator is configured to generate electricity in addition to or instead of the gas turbine.

[0167] Clause 7. The system according to Clause 5 or Clause 6, wherein the ORC generator includes a fresh air ignition chimney and is configured to generate electricity from heat recovered from the exhaust gas leaving the gas turbine and / or the gas entering the ORC from the fresh air ignition chimney.

[0168] Clause 8. The system according to any one of Clauses 5 to 7 further includes an auxiliary burner, which is arranged downstream of the fresh air ignition chimney and is in fluid communication with at least one storage tank to receive boil-off gas from one or more LNG storage tanks; wherein the auxiliary burner is adapted to burn the boil-off gas to generate auxiliary heat for operating the ORC generator.

[0169] Clause 9. The system according to Clause 8, wherein the closed-loop thermal fluid circuit and / or the thermal fluid of the ORC generator are used to heat the boil-off gas and thereby increase the pressure of the boil-off gas before the boil-off gas enters the auxiliary burner.

[0170] Clause 10. The system according to any one of Clauses 5 to 9 further includes a damper, which allows the gas turbine and the ORC generator to operate together in a first position and allows the gas turbine and the ORC generator to operate independently of each other in a second position.

[0171] Clause 11. The system according to any one of Clauses 5 to 10, wherein the ORC generator has a first power generation capacity, and the gas turbine has a second power generation capacity higher than the first power generation capacity.

[0172] Clause 12. The system according to any one of Clauses 5 to 11, wherein the working fluid of the ORC generator is a thermal fluid.

[0173] Clause 13. The system according to Clause 12 further includes a heat exchanger, which is configured to receive the heated gas from the auxiliary burner and is used to heat the thermal fluid of the ORC generator.

[0174] Clause 14. The system according to Clause 12 or Clause 13, wherein the ORC generator includes a condenser, which is configured to use seawater as a coolant to condense the thermal fluid.

[0175] Clause 15. The system according to any one of Clauses 5 to 14, wherein the ORC generator includes a radial expander.

[0176] Clause 16. The system according to Clause 15, wherein the radial expander includes variable inlet vanes, and the variable inlet vanes can be controlled so as to adjust the power output of the ORC generator in response to the instantaneous power load drawn by the at least one remote power receiving end.

[0177] Clause 17. The system according to any one of Clauses 5 to 14, wherein the ORC includes an axial expander, and the axial expander can be controlled so as to be able to adjust the power output of the ORC generator in response to the instantaneous power load drawn by the at least one remote power receiving end.

[0178] Clause 18. The system according to any one of Clauses 1 to 17, wherein the power output of the gas turbine is between about 5 MW and about 20 MW.

[0179] Clause 19. The system according to any one of Clauses 5 to 18, wherein the power output of the ORC generator is between about 3 MW and about 7 MW.

[0180] Clause 20. The system according to any one of Clauses 1 to 19, wherein the heat transfer fluid in the closed-loop heat transfer fluid circuit and / or the ORC generator is one of ethylene glycol and hot oil.

[0181] Clause 21. The system according to any one of Clauses 1 to 20, wherein the operating temperature of the heat transfer fluid in the closed-loop heat transfer fluid circuit and / or the ORC generator is between about 3 °C and about 24 °C.

[0182] Clause 22. A floating power generation system comprising the system according to any one of Clauses 1 to 21 mounted on a ship, the ship including a ship frame, a hull surrounding the ship frame and defining a bow section and a stern section, and a deck supported by the ship frame; wherein the power supply subsystem is configured to supply power to at least one remote power receiving end away from the ship.

[0183] Clause 23. The system according to Clause 22, wherein the ship has no propulsion member.

[0184] Clause 24. The system according to Clause 22 or Clause 23, wherein the ship is formed as a barge.

[0185] Clause 25. The system according to any one of Clauses 22 to 24, further comprising at least one LNG storage tank located on the ship.

[0186] Clause 26. A power generation system comprising: a gas turbine for generating electricity by combustion of natural gas; an organic Rankine cycle (ORC) generator for generating electricity by heat recovery; a gas supply line for supplying vaporized liquefied natural gas (LNG) to the gas turbine; a power supply subsystem for receiving electricity from at least one of the gas turbine or the ORC generator and supplying electricity to at least one remote power receiving end; and a damper that allows the gas turbine and the ORC generator to operate together in a first position and allows the gas turbine and the ORC generator to operate independently of each other in a second position.

[0187] Clause 27. The system according to Clause 26, wherein the ORC generator has a first power generation capacity and the gas turbine has a second power generation capacity higher than the first power generation capacity.

[0188] Clause 28. The system according to Clause 26 or Clause 27, further comprising a controller configured to control the position of the damper at the first position or the second position in response to a change in the load drawn by the at least one remote power receiving end.

[0189] Clause 29. The system according to any one of Clauses 26 to 28, wherein the controller is configured to position the damper at the first position when the load drawn by the at least one remote power receiving end is at or above a first threshold power load and to position the damper at the second position when the load drawn by the at least one remote power receiving end is below the first threshold power load.

[0190] Clause 30. The system according to Clause 29, wherein the first threshold power load corresponds to the second power generation capacity.

[0191] Clause 31. The system according to any one of Clauses 26 to 30, wherein the gas turbine is arranged to be selectively fluidly connected to a) an exhaust chimney and b) the ORC generator, whereby in the first position of the damper, the fluid flow path from the gas turbine to the exhaust chimney is closed to the gas leaving the gas turbine and the fluid flow path from the gas turbine to the ORC generator is opened to allow the gas leaving the gas turbine to flow into the ORC generator.

[0192] Clause 32. The system according to Clause 31, wherein in the second position of the damper, the fluid flow path from the gas turbine to the exhaust chimney is opened to allow the gas leaving the gas turbine to enter the exhaust chimney, and the fluid flow path from the gas turbine to the ORC generator is closed to the gas leaving the gas turbine.

[0193] Clause 33. The system according to any one of Clauses 26 to 32, wherein the damper comprises at least one airtight damper.

[0194] Clause 34. The system according to any one of Clauses 26 to 33, wherein the ORC generator includes a fresh air ignition chimney and can be configured to generate electricity from the heat recovered from the exhaust gas leaving the gas turbine and / or the gas entering the ORC generator through the fresh air ignition chimney.

[0195] Clause 35. The system according to Clause 34, wherein when the load drawn by the at least one remote power receiving end is lower than a second threshold power load, the ORC generator can be configured to generate electricity from the gas entering the ORC generator through the fresh air ignition chimney.

[0196] Clause 36. The system according to Clause 34 or Clause 35, wherein the fresh air ignition chimney is located downstream of the gas turbine.

[0197] Clause 37. The system according to any one of Clauses 34 to 36, further comprising an auxiliary burner arranged downstream of the fresh air ignition chimney and in fluid communication with at least one storage tank to receive boil-off gas from one or more LNG storage tanks; wherein the auxiliary burner is adapted to burn the boil-off gas to generate auxiliary heat for operating the ORC generator.

[0198] Clause 38. The system according to Clause 37, further comprising a heat exchanger configured to receive the heated gas from the auxiliary burner and to heat the working fluid of the ORC generator.

[0199] Clause 39. The system according to any one of Clauses 26 to 38, wherein the fuel source for the gas turbine generator and the ORC generator is LNG.

[0200] Clause 40. A floating power generation system comprising a system according to any one of Clauses 26 to 39 installed on a ship, the ship including a ship frame, a hull surrounding the ship frame and defining a bow section and a stern section, and a deck supported by the ship frame; wherein the power supply subsystem is configured to supply power to at least one remote power receiving end away from the ship.

[0201] Clause 41. A method of controlling the operation of a power generation system according to any one of Clauses 26 to 40, the method comprising controlling the position of the air damper in the first position to allow the gas turbine and the ORC generator to operate together, or controlling it in the second position to allow the gas turbine and the ORC generator to operate independently of each other.

[0202] Clause 42. The method according to Clause 41, wherein when the load drawn by the at least one remote power receiving end is at or above the first threshold power load, the air damper is positioned in the first position.

[0203] Clause 43. The method according to Clause 41 or Clause 42, wherein when the load drawn by the at least one remote power receiving end is below the first threshold power load, the air damper is positioned in the second position.

[0204] Clause 44. The method according to any one of Clauses 41 to 43, wherein the first threshold power load corresponds to the second power generation capacity.

[0205] Clause 45. The method according to any one of Clauses 41 to 44, wherein the power generation system is controlled to operate the gas turbine or the ORC generator in response to the power load drawn by the at least one remote power receiving end.

[0206] Clause 46. The method according to Clause 45, wherein when the drawn power load is higher than the second threshold power load and lower than the first threshold power load, the power generation system is controlled to operate the gas turbine instead of the ORC generator.

[0207] Clause 47. The method according to Clause 45 or Clause 46, wherein the power generation system is controlled to operate the ORC generator instead of the gas turbine when the drawn power load is within the second threshold power load.

[0208] Clause 48. The system according to Clause 46 or Clause 47, wherein the second threshold power load corresponds to the first power generation capacity, and the first threshold power load corresponds to the second power generation capacity.

[0209] Clause 49. A liquefied natural gas (LNG) storage system, comprising: a floating vessel formed as a barge, the vessel including: a vessel frame, a hull surrounding the vessel frame and defining a bow section and a stern section, and a deck supported by the vessel frame; at least two LNG storage tanks carried by the vessel frame, the at least two LNG storage tanks including a first LNG storage tank located on the port side of the vessel and a second LNG storage tank located on the starboard side of the vessel; fluid transfer conduits connected to the at least two LNG storage tanks to allow fluid to flow into and out of the at least two LNG storage tanks; and a valve system for controlling the fluid flow in the fluid transfer conduits; wherein the vessel frame and the hull define a wide and shallow draft.

[0210] Clause 50. The system according to Clause 49, wherein the vessel has no built-in propulsion member.

[0211] Clause 51. The system according to Clause 49 or Clause 50, wherein the vessel has a recess defined in a central portion of the stern section to receive the bow of the vessel for driving.

[0212] Clause 52. The system according to any one of Clauses 49 to 51, wherein the bow section of the hull has an acute surface to facilitate the forward passage of the vessel on water.

[0213] Clause 53. The system according to any one of Clauses 49 to 52, further comprising at least one ballast pump for pumping seawater into the hull for ballast control.

[0214] Clause 54. The system according to Clause 53, further comprising at least one compressed air storage tank for supplying compressed air for operating the at least one ballast pump.

[0215] Clause 55. The system according to Clause 53 or Clause 54, further comprising a pump control interface to allow the at least one ballast pump to be controlled by an external controller when an external control conduit is connected to the pump control interface.

[0216] Clause 56. The system according to any one of Clauses 49 to 55, further comprising at least one pneumatic pump for pumping LNG from the at least two LNG storage tanks into the fluid transfer conduits.

[0217] Clause 57. The system according to Clause 56, further comprising at least one compressed air storage tank for supplying compressed air for operating the at least one pneumatic pump.

[0218] Clause 58. The system according to any one of Clauses 49 to 57, wherein each of the at least two LNG storage tanks has a boil-off gas (BOG) exhaust conduit connected thereto to allow the boil-off gas to be discharged into a BOG storage tank.

[0219] Clause 59. The system according to any one of Clauses 49 to 58, wherein the total volume capacity of the at least two LNG storage tanks is between about 1000 m 3 and about 6000 m 3 .

[0220] Clause 60. The system according to Clause 59, wherein the total volume capacity is between about 1500 m 3 and about 4000 m 3 .

[0221] Clause 61. The system according to Clause 59, wherein the total volume capacity is between about 2000 m 3 and about 3500 m 3 .

[0222] Clause 62. The system according to any one of Clauses 59 to 61, wherein the at least two LNG storage tanks comprise two to four LNG storage tanks with a total volume capacity of about 3000 m 3 .

[0223] Clause 63. The system according to any one of Clauses 49 to 62, wherein the ship has no power plant on the deck.

[0224] Clause 64. A floating LNG storage facility, comprising: a floating dock fastened by fixed piles positioned near the coastline; at least one LNG storage system according to any one of Clauses 49 to 63 moored to the floating dock.

[0225] Clause 65. The facility according to Clause 64, wherein a plurality of the LNG storage systems in the LNG storage system are moored to the floating dock.

[0226] Clause 66. The facility according to Clause 64 or Clause 65, further comprising a floating power generation system moored to the floating dock and configured to generate electricity using LNG, wherein the at least one LNG storage system is configured to supply LNG to the floating power generation system through the fluid delivery conduit.

[0227] Clause 67. The facility according to any one of Clauses 64 to 66, wherein the plurality of the LNG storage systems in the LNG storage system are each moored to the floating dock using an interlocking device.

[0228] Clause 68. The device according to Clause 67, wherein the interlocking device is a mechanical mechanism for restricting movement.

[0229] Clause 69. The device according to Clause 67 or Clause 68, wherein the interlocking device is a hydraulic pin.

[0230] Clause 70. The device according to any one of Clauses 64 to 69, wherein the floating dock is configured to rise and fall with sea conditions relative to the fixed pile.

[0231] Clause 71. A floating LNG storage device, comprising: a floating dock fastened by a fixed pile positioned near the coastline; at least one mooring pod configured to accommodate the LNG storage system according to any one of Clauses 49 to 63; a bulk LNG storage facility located at the end of the floating dock farthest from the coastline, the bulk LNG storage facility having an LNG storage capacity sufficient to refuel at least two LNG storage systems in the LNG storage system.

[0232] Clause 72. The floating LNG storage device according to Clause 71, wherein the bulk LNG storage facility has an LNG storage capacity sufficient to refuel at least four LNG storage systems in the LNG storage system.

[0233] Clause 73. The device according to Clause 71 or Clause 72, wherein the at least one mooring pod is configured to moor the LNG storage system according to any one of Clauses 1 to 15 by using an interlocking mechanism.

[0234] Clause 74. The device according to Clause 73, wherein the interlocking device is a mechanical mechanism for restricting movement.

[0235] Clause 75. The device according to Clause 73 or Clause 74, wherein the interlocking device is a hydraulic pin.

[0236] Clause 76. The device according to any one of Clauses 71 to 75, wherein the floating dock is configured to rise and fall with sea conditions relative to the fixed pile.

[0237] Clause 77. A floating power generation system, comprising: a ship, the ship including: a ship frame, a hull surrounding the ship frame and defining a bow section and a stern section, and a deck supported by the ship frame; a gas turbine located on the ship, the gas turbine for generating electricity by burning natural gas; an organic Rankine cycle (ORC) generator located on the ship, the ORC generator for generating electricity by heat recovery; a gas supply pipeline located on the ship, the gas supply pipeline for supplying liquefied natural gas (LNG) to the gas turbine; and a power supply subsystem for receiving electricity from at least one of the gas turbine or the ORC generator and supplying power to at least one remote power sink away from the ship.

[0238] Clause 78. The system according to Clause 77, wherein the ship has no propulsion member.

[0239] Clause 79. The system according to Clause 77 or Clause 78, wherein the ship has a recess defined in a central portion of the stern section to receive the bow of the ship for driving.

[0240] Clause 80. The system according to any one of Clauses 77 to 79, wherein the bow section of the hull has an acute surface to facilitate the ship's forward passage on water.

[0241] Clause 81. The system according to any one of Clauses 77 to 80, wherein the ship is formed as a barge.

[0242] Clause 82. The system according to any one of Clauses 77 to 81, further comprising at least one LNG storage tank located on the ship.

[0243] Clause 83. The system according to Clause 82, wherein the at least one LNG storage tank includes a plurality of LNG storage tanks arranged below the deck.

[0244] Clause 84. The system according to any one of Clauses 77 to 83, wherein the ORC generator is configured to generate electricity in addition to or instead of the gas turbine.

[0245] Clause 85. The system according to any one of Clauses 77 to 84, wherein the ORC generator has a first power generation capacity, and the gas turbine has a second power generation capacity higher than the first power generation capacity.

[0246] Clause 86. The system according to Clause 85, wherein the power subsystem is configured to change the operation of the ORC generator in response to a change in the load when the gas turbine and the ORC generator are operating simultaneously to generate electricity and when the change in the load drawn by the at least one remote power receiving end is within the first power generation capacity.

[0247] Clause 87. The system according to any one of Clauses 77 to 86, wherein the ORC generator includes a radial expander.

[0248] Clause 88. The system according to Clause 87, wherein the radial expander includes variable inlet vanes that can be controlled to adjust the power output of the ORC generator.

[0249] Clause 89. The system according to any one of Clauses 77 to 88, wherein the power output of the gas turbine is between approximately 5 MW and approximately 20 MW.

[0250] Clause 90. The system according to any one of Clauses 77 to 89, wherein the power output of the ORC generator is between approximately 2 MW and approximately 6 MW.

[0251] Clause 91. The system according to any one of Clauses 77 to 90, further comprising: at least one storage tank for receiving boil-off gas from one or more LNG storage tanks; and an auxiliary burner for burning the boil-off gas to generate auxiliary heat for operating the ORC generator.

[0252] Clause 92. The system according to any one of Clauses 77 to 91, further comprising a damper that allows the gas turbine and the ORC generator to operate together in a first position and allows the gas turbine and the ORC generator to operate independently of each other in a second position.

[0253] Clause 93. The system according to any one of Clauses 77 to 92, wherein the ORC generator includes a fresh air ignition stack.

[0254] Clause 94. A power generation device comprising: a floating dock coupled to a fixed tower and configured to move up and down with the water level relative to the fixed tower, the floating dock being positioned to allow access to the floating dock from the shoreline; at least one floating power generation system according to any one of Clauses 77 to 93 moored to the floating dock; and at least one floating LNG storage vessel moored to the floating dock to supply LNG to the at least one floating power generation system.

[0255] Clause 95. The apparatus according to Clause 94, wherein the floating dock comprises: a gangway that allows personnel to enter; at least one first compartment respectively for accommodating the at least one floating power generation system; and at least one second compartment respectively for accommodating the at least one floating LNG storage vessel.

[0256] Clause 96. The apparatus according to Clause 95, wherein the at least one floating power generation system is moored closer to the shoreline than the at least one floating LNG storage vessel.

[0257] Clause 97. The apparatus according to any one of Clauses 94 to 96, wherein the at least one floating power generation system is moored to the floating dock by using an interlocking device.

[0258] Clause 98. The apparatus according to any one of Clauses 94 to 97, wherein the at least one floating LNG storage vessel is moored to the floating dock by using an interlocking device.

[0259] Clause 99. The apparatus according to Clause 97 or Clause 98, wherein the interlocking device is a mechanical mechanism for restricting movement.

[0260] Clause 100. The apparatus according to any one of Clauses 97 to 99, wherein the interlocking device is a hydraulic pin.

Claims

1. A power generation system, comprising: a gas turbine configured to generate electricity by burning natural gas; an organic Rankine cycle (ORC) generator configured to generate electricity by heat recovery; a gas supply line configured to supply vaporized liquefied natural gas (LNG) to the gas turbine; a power subsystem configured to receive electricity from at least one of the gas turbine or the ORC generator and supply power to at least one remote power sink; and a damper that allows the gas turbine and the ORC generator to operate together in a first position and allows the gas turbine and the ORC generator to operate independently of each other in a second position.

2. The system according to claim 1, wherein the ORC generator has a first power generation capacity and the gas turbine has a second power generation capacity higher than the first power generation capacity.

3. The system according to claim 1 or claim 2, further comprising a controller configured to control the position of the damper at the first position or the second position in response to a change in the load drawn by the at least one remote power sink.

4. The system according to any one of claims 1 to 3, wherein the controller is configured to position the damper at the first position when the load drawn by the at least one remote power sink is at or above a first threshold power load and to position the damper at the second position when the load drawn by the at least one remote power sink is below the first threshold power load.

5. The system according to claim 4, wherein the first threshold power load corresponds to the second power generation capacity.

6. The system according to any one of the preceding claims, wherein the gas turbine is arranged to be selectively fluidly connected to a) an exhaust stack and b) the ORC generator, whereby in the first position of the damper, the fluid flow path from the gas turbine to the exhaust stack is closed to the gas leaving the gas turbine and the fluid flow path from the gas turbine to the ORC generator is opened to allow the gas leaving the gas turbine to flow into the ORC generator.

7. The system according to claim 6, wherein in the second position of the damper, the fluid flow path from the gas turbine to the exhaust stack is opened to allow the gas leaving the gas turbine to enter the exhaust stack and the fluid flow path from the gas turbine to the ORC generator is closed to the gas leaving the gas turbine.

8. The system according to any one of the preceding claims, wherein the damper comprises at least one airtight damper.

9. The system according to any one of the preceding claims, wherein the ORC generator includes a fresh air ignition stack and is configured to generate electricity by heat recovered from the exhaust gas leaving the gas turbine and / or from the gas entering the ORC generator through the fresh air ignition stack.

10. The system according to claim 9, wherein when the load drawn by the at least one remote power receiving end is lower than a second threshold power load, the ORC generator can be configured to generate electricity from the gas entering the ORC generator through the fresh air ignition chimney.

11. The system according to claim 9 or claim 10, wherein the fresh air ignition chimney is located downstream of the gas turbine.

12. The system according to claim 9 or claim 10 or claim 11, further comprising an auxiliary burner arranged downstream of the fresh air ignition chimney and in fluid communication with at least one storage tank to receive boil-off gas from one or more LNG storage tanks; wherein the auxiliary burner is adapted to burn the boil-off gas to generate auxiliary heat for operating the ORC generator.

13. The system according to claim 12, further comprising a heat exchanger configured to receive the heated gas from the auxiliary burner and for heating the working fluid of the ORC generator.

14. The system according to any one of claims 1 to 13, wherein the fuel source for the gas turbine generator and the ORC generator is LNG.

15. A floating power generation system comprising the system according to any one of the preceding claims mounted on a ship, the ship including a ship frame, a hull surrounding the ship frame and defining a bow section and a stern section, and a deck supported by the ship frame; wherein the power supply subsystem is configured to supply power to at least one remote power receiving end away from the ship.

16. A method of controlling the operation of a power generation system according to any one of the preceding claims, the method comprising controlling the position of the air damper in the first position to allow the gas turbine and the ORC generator to operate together, or controlling it in the second position to allow the gas turbine and the ORC generator to operate independently of each other.

17. The method according to claim 16, wherein when the load drawn by the at least one remote power receiving end is at or above the first threshold power load, the air damper is positioned in the first position.

18. The method according to claim 16 or claim 17, wherein when the load drawn by the at least one remote power receiving end is lower than the first threshold power load, the air damper is positioned in the second position.

19. The method according to claim 16 or claim 17 or claim 18, wherein the first threshold power load corresponds to the second power generation capacity.

20. The method according to any one of claims 16 to 19, wherein the power generation system is controlled to operate the gas turbine or the ORC generator in response to the power load drawn by the at least one remote power receiving end.

21. The method according to claim 20, wherein the power generation system is controlled to operate the gas turbine rather than the ORC generator when the drawn electrical load is higher than a second threshold electrical load and lower than a first threshold electrical load.

22. The method according to claim 20 or claim 21, wherein the power generation system is controlled to operate the ORC generator rather than the gas turbine when the drawn electrical load is within the second threshold electrical load.

23. The system according to claim 21 or claim 22, wherein the second threshold electrical load corresponds to the first power generation capacity, and the first threshold electrical load corresponds to the second power generation capacity.

Images