An Eco System Problem

Abstract

Herein, are patent teachings of dispatchable Climate-positive Generation System, to mitigate a potential Eco System Major Accident Risk (MAR) event. Furthermore, said teachings provide security of supply, and a solution to 5 transmission losses from remote Base Load Power Generation Systems, therein another modification to the patent technologies of AU2018313795 referenced herein as the "State of the Art". 10 - 39 - 20 25 23 06 73 09 S ep 2 02 5 20 25 23 06 73 0 9 Se p 20 25 2025230673 09 2025 Sep 10

Description

Field of the Invention Green Technology: This application contains one or more claims to an apparatus, process or product that mitigates climate change by being designed 5 to reduce and / or prevent additional greenhouse gas emissions. Problem-Solution Approach An Eco System Problem, is potential for a global average temperature spike > 4.5°C; a low probability, high impact, Eco System Major Accident Risk 10 (MAR) event with solution herein an inventive concept to mitigate occurrence. A qualitative risk assessment using ‘tail risk’ from the UN Environment Programme (2024) Emissions Gap Report, Figure 4.2: peak warming over the twenty-first century (°C) relative to pre-industrial levels could be 4.5°C at 90th percentile i.e., tail events are often referred to as ‘Black Swan’ events, definition 15 unpredictable but a highly impactful event that lies outside the realm of normal expectations, and cannot be anticipated based on data or established models and involves overlooked risk areas or predicting what you don’t even know, wherein challenges of validation and credibility could explain why climate experts who foresee worst case events, have not published an Eco System MAR event. 20 To address challenges of climate change prediction and mitigation, approaches that combine strengths of AI with traditional climate models are being explored. In the interim to manage risk, a qualitative assessment is used combining expert judgement and analysis of past events until quantitative assessment is available. 2025230673  09 Sep 2025 Herein, said qualitative assessment utilizes expert judgement that will be unequivocal in the preparation of said UN Emission Gap Report and to understand the potential consequences of anthropogenic global warming, past events are analyzed with the Paleocene-Eocene Thermal Maximum (PETM) a 5 known analog for present day climate change due to the rate and magnitude being comparable, albeit occurrence was approximately 56 Million Years ago with a consequence of significant temperature increase: an estimated 5 to 8°C. The PETM is thought to have involved multiple tipping points in the Earth’s climate system, where a relatively small change can trigger a cascade of events 10 leading to a much larger and more dramatic shift. The exact trigger for PETM remains an area of active research with volcanic activity and methane release the primary suspects; it’s also possible that other carbon reservoirs such as the oxidation of organic matter or the melting of permafrost contributed to the cause. The PETM comparison with present anthropogenic global warming is a 15 cascade event: the initial release of carbon, regardless of its sources, may have triggered a feedback loop, leading to the release of more carbon from other reservoirs, creating a positive feedback cycle and further amplifying the warming. Cascade cause of an Ecosystem MAR event: today the initial release of carbon is anthropogenic emissions from inventions driving the technological age, 20 which triggers a feedback loop, leading to the release of more carbon from other reservoirs, creating a positive feedback cycle and further amplifying the warming. Solution, thermal power generation mitigation, herein Climate-positive operation of a system configured as a prime mover for dispatchable power generation. 2025230673  09 Sep 2025 Risk Management Cascade Events To teach, cascade or compound events that potentially cause a MAR event, an illustration of "Swiss cheese" risk model is shown in Fig. 1: depicting multiple slices of cheese stacked vertically, where each slice represents a layer 5 of defense barriers within a system (tipping elements), with holes in each slice representing potential vulnerabilities (tipping elements degradation), an unpredicted alignment of said holes results in realization of the Ecosystem MAR. Herein, the inventive concept is a Climate-positive Generation System (CpGS), a modification of the inventive concept AU2025202013, to enable use of 10 either geothermal fluids or coal, to fuel an Advanced Prime Mover System (APMS) integrated with a Carbon-negative System (CNS) of AU2025202013 for sequestration of exhaust gases. The inventive step is integrating a thermal energy source with said CNS to drive a Climate-positive Prime Mover System, providing a hybrid solution to fulfill a need for adaptation and security of supply. 15 Inventive concept technical advantages: security of supply, a first reduction in anthropogenic emissions with like-to-like replacement of thermal generation or retiring nuclear generation and a second unforeseen reduction of anthropogenic emissions due to the solution being suitable for location adjacent to coastal load centers replacing remote base load generation supply and a notional 6% of 20 transmission losses of lost output, when grid balancing for lost output supplied by fossil fuel generation. An initial application of this patent family AU2018313795 the “State of the Art”, taught of coal combustion and CO2 oceanic sequestration, herein the inventive concept provides a technical alternative, to complete cycle. 2025230673  09 Sep 2025 NOMENCLATURE, teaching layperson technical and non-technical terminology: Carbon-negative (or Carbon-positive): signifies a system or process actively removes CO2 from seawater or atmosphere in excess of the CO2 it emits. Carbon-positive is an alternative term for Carbon-negative, highlighting the 5 positive aspect of removing more CO2 than is emitted. Dispatchable generation refers to sources of electricity that can be programmed on-demand at the request of power grid operators, according to market needs. Non-dispatchable renewable energy sources such as wind power and solar photovoltaic (PV) power cannot be controlled by grid operators. 10         Electrolysis process is for interchange of atoms and ions by the removal or addition of electrons due to the applied current, in a unit called an electrolyzer. CO2 Electrolysis: DC electricity to split CO2 into carbon monoxide (CO) & oxygen to produce value-added chemicals such as methane, ethylene, ethanol. H2O Electrolysis: DC electricity to split water into hydrogen (H2) & oxygen. 15        Heat Recovery Steam Generator (HRSG): Heat of the gas turbine’s exhaust can be high as 450 to 650 °C and is used to generate steam by passing it through a heat recovery steam generator with a live steam temperature. Membrane Separation Technology (MST) has matured as an effective process for the post combustion flue gas separation of CO2, SO2 and NOx. 20 Different membrane materials provide optimum permeability and selectivity based on the operating conditions, and well known to those skilled in the art. 2025230673  09 Sep 2025 Organic Compounds, the most common elements present are carbon, hydrogen, oxygen, and nitrogen. A hydrocarbon is highly combustible, consisting of hydrogen and carbon which is found in crude oil, natural gas, and coal. Fischer-Tropsch: A chemical process developed in the 1920s to convert a 5 mixture of carbon monoxide and hydrogen, called synthesis gas or syngas, into hydrocarbon chains of varying lengths, which can used as synthetic fuel. Solid Oxide Electrolyzer: use a solid ceramic material as the electrolyte. They must operate at temperatures high enough for the solid oxide membranes to function properly (typically 700°-800°C) i.e., effectively use high temperatures 10 to decrease the amount of energy needed to produce hydrogen from water. Solid Acid Electrolysis Cell: CO2 feedstock, steam, and cell operation at temperatures in the range 150-250C produces carbon monoxide, methane, methanol, ethane, ethylene, ethanol, acetaldehyde and propylene. Intermediate Temperature Steam Electrolyzer: Proton-conducting ceramic 15 electrolytes with operation typically in a temperature range of 600 °C to 650 °C. High Temperature Steam Electrolyzer: is a method of electrolysis where steam is dissociated to H2 and O2 at temperatures between 700 and 1000°C. In electrolysis, system efficiencies increase with increasing operating temperatures. Ultra-High Temperature, Steam Electrolyzer is a method of electrolysis 20 where steam is dissociated to H2 and O2 at temperatures above 1000°C by using Ultra High Temperature Ceramics UHTCs composites which conduct energy through material and reradiate it through cooler surfaces. UHTCs provide chemical and structural stability at extremely high operating temperatures. 2025230673  09 Sep 2025 Ultra-High Temperature Combustion Turbine (UHTCT) manufactured using UHTCs for the turbine bladed leading edge, connected to carbon-based composite and thereafter to the turbine metallic structural elements. Utility fuel cells primarily output electricity with water vapor and heat as 5 byproducts. The power output depends on its type, size and operation conditions. Ultra-Clean Coal (UCC) Pre-combustion: new processing technologies with an objective to reduce Ash and Sulphur content in coal to very low levels. Clean Coal Technology (or Coal Treatment) Pre-combustion: involves removing Sulphur and other impurities from coal. This process can involve 10 physical or chemical methods such as coal cleaning (washing) or using specific chemicals to remove containments: i.e. physical cleaning is the Gravimetric Processes, used with froth flotation to separate coal from heavier impurities like minerals based on density, which reduces ash and Sulphur Dioxide Emissions. Coal Cleaning (or Coal Treatment) with filtered seawater involves using 15 seawater as a medium to remove impurities from coal such as salts and minerals, through processes like filtration and washing. This method can be used in conjunction with other coal cleaning techniques, such as flotation or heavy media separation. The filtered seawater can be reused in the process. Elaboration: Coal Cleaning: is a process that removes unwanted materials, like 20 ash, sulfur, and other impurities, from coal to improve its quality and reduce environmental impact. Filtered Seawater: seawater, after being filtered to remove large particles and organisms. Can be used as a washing agent in coal cleaning processes, 2025230673  09 Sep 2025 wherein transportation may contaminate coal and filtered seawater is less likely to introduce new containments into the coal compared to using raw seawater. Processes: Filtration: Coal slurry or coal particles are passed through a filter, and the seawater is used as the wash medium. Washing: Coal filter cakes are 5 washed with filtered seawater to remove dissolved salts and other impurities. Flotation: In this process, coal is separated from impurities using a combination of surfactants air bubbles in filtered seawater. Sulfidation: A form of hot corrosion and a significant problem for combustion with air in coastal or offshore environments: Problem cause: Sea 10 Salt: Coastal and Offshore environments have high concentrations of airborne salt particulates, including sodium (Na) and chlorine (CI). Sulfur: Fossil fuels, especially those with higher Sulphur content, also contribute Sulphur (S). Reaction: Sodium and Sulphur react at high temperatures, forming molten sulfate (Na2SO4). Corrosion: The molten sodium sulfate attaches to metal surfaces, 15 particularly in the hot section, leading to degradation and premature failure, and loss of security of supply. An unforeseen advantage is a solution to sulfidation. Geothermal Systems: Encompass any heat transfer from the Earth’s interior to the surface with hydrothermal systems a subset of geothermal, wherein heat is transferred by naturally occurring hot water or steam, while 20 Engineered Geothermal Systems creates the fluid pathways through fracturing. Deep Geothermal Systems: Temperatures in deep geothermal reservoirs are much higher, generally ranging from 300oC to 500oC and even higher with temperatures increasing with depth according to the local geothermal gradient. 2025230673  09 Sep 2025 Deep Geothermal Seawater: is a geothermal fluid, acting as a carrier medium for heat and dissolved minerals from the Earth’s crust to the surface. Deep Geothermal Fluids: store and transport heat within the Earth’s crust. A heat exchanger is the device that facilitates the transfer of thermal 5 energy from the geothermal fluid (in open loop systems) or the surrounding rock (in closed-loop systems) to another fluid for use. Note steam refers to water in its gaseous state, which is also known as water vapor with composition of typical Natural Geothermal fluids: consisting essentially of hot water or steam (water vapor) with significant amounts of dissolved carbon dioxide (CO2), which are 10 often the most abundant non-condensable gases in geothermal fluids, including: Solutes: Dissolved substances from surrounding rock interactions. Major Ions: Silicon (Si, Sodium (Na), Potassium (K), Calcium (CA), Magensium (Mg), Iron (Fe) and Aluminum (AI). Salts: Often dominated by Sodium Chloride (NaCI) 15         Gases (Volatiles) dissolved in the fluids: Carbon Dioxide (CO2) Hydrogen Sulfide (H2S), Nitrogen (N2), Helium (HE) and other gases, Methane (CH4), Ammonia (NH3), Mercury (Hg), Radon may be present. Factors Influencing Composition is the Fluid Source with categorization based on their overall composition: Na-CI Waters: the most common type, 20 characterized by dissolved salts. Acid-Sulfate Waters: Found in specific conditions, often in the presence of volcanic gases and reactions. High Salinity Brines: Very concentrated salt solutions, sometimes reaching up to 50% NaCI. (Electrolysis, NaCI provides ions to conduct electricity): 2025230673  09 Sep 2025 Geothermal Fluids Filtration System: A multi stage process is used to remove solids, minerals and gases from Geothermal fluids, often including hydro cyclones for coarser particles, followed by cartridge filters for finer particles, and gas extraction systems before the clean steam is used. 5         Dissolved minerals can be separated from geothermal fluids using a combination of techniques, including membrane processes like electro dialysis: this membrane process uses charged membranes to separate charged ions from the fluid. New membrane materials and hybrid systems are being developed to target specific minerals or to achieve simultaneous desalination and 10 concentration. Synthetic ion-exchange resins can selectively absorb ions from geothermal fluids. Gas extraction systems may use steam jet ejectors or vacuum pumps for non-condensable gases (NGCs), such as hydrogen sulfide, Geothermal Reservoir: a naturally occurring underground body of hot rock and water or steam, containing significant thermal energy from the Earth’s core. 15 Key characteristics for a good reservoir are rocks need to be permeable (to allow fluid movement) and porous (to hold the resource). Reservoirs are utilized by drilling into them to access hot water or steam. Engineered Geothermal Reservoir: also known as an Enhanced Geothermal System (EGS) is a human made system designed to extract heat 20 from hot, dry rock formations deep within the Earth’s crust. By injecting high-pressure fluid, typically water, into a well, pre-existing fractures are reopened, and the water pressure causes the rock to fracture or reopens existing fractures, creating a network of fluid pathways. The process is called hydraulic stimulation. 2025230673  09 Sep 2025 Nomenclature for coal power station technical and non-technical terminology: In essence, the furnace is the combustion chamber part of the boiler, where fuel (like coal, gas, oil, waste paper) is burned to generate heat, which is then used to create steam. Herein, is a more detailed breakdown: 5         Boiler (or Steam Generator): This is the main component of a thermal power plant responsible for converting water into steam. Steam Accumulator: An insulated pressure vessel used for storing energy as steam to balance fluctuating steam demand in power generation. Steam Generator (or boiler) other components: Beside the furnace, boilers 10 also include heat transfer surfaces (like tubes and water walls), steam drums, economizers and other equipment to manage the steam generation process. Utility power plant boiler (or Steam Generator): Typical schematic would show the furnace area, where fuel is burned to produce heat, and the steam area, where water is heated to produce steam. The furnace area houses the 15 burners, combustion chamber and the primary heat transfer surfaces that absorb heat from the flame. The steam area includes the steam drum, steam tube and other components where steam is generated and collected. Advanced Ultra-Supercritical (A-USC) Boilers is a type of steam generator used in power plants, specifically those using coal as a fuel. Designed to operate 20 at higher steam temperatures (700-760oC) compared to conventional ultra-supercritical (USC) plants, improving efficiency and reducing CO2 emissions. A-USC type steam generator is designed to be retrofitted to existing power plants, as their basic configuration remains similar to conventional boilers. 2025230673  09 Sep 2025 Double-Reheat A-USC Boilers, increase the average heat absorption temperature reduces low-pressure cylinder exhaust humidity so higher efficiency. Advanced Ultra-Supercritical (A-USC) steam turbines, require advanced materials, i.e., nickel-based super alloys, to withstand the operating conditions. 5        Tandem-Compound Configurations are suitable for A-USC turbines, wherein multiple turbine stages are connected to a single shaft. Economizer improves overall efficiency by using the heat from the exhaust flue gases to heat the incoming feedwater, reducing the temperature of flue gases and increasing the feedwater temperature before it enters the boiler. 10         Electrostatic Precipitators, wherein Bottom Ash is collected at the bottom of the furnace through hoppers, while fly ash is collected from particulate matters found in the flue gas leaving the combustion system, thereby being collected through utilization of said Electrostatic Precipitators (ESP). Flue Gas Desulphurization (FGD) systems are used to remove Sulphur 15 Dioxide from flue gases with the most common FGD technology use a limestone / gypsum wet scrubbing system. Usually the plant is located downstream of the ESP so that most of the fly ash generated from combustion is removed before the gas reaches the FGD plant. The primary dry FGD technologies employ either a spray drying process or a circulating fluid bed 20 (CFB) process. The spray drying process typically uses slaked lime (Ca(OH)2) slurry as a reagent, while the CFB processes typically uses dry hydrated lime. NOX is removed from flue gases by Selective Catalytic Reduction (SCR) or at higher temperatures by Selective Non-Catalytic Reduction (SCNR). 2025230673  09 Sep 2025 Teaching: summary of said State of the Art AU2018313795 / US20200263605: The invention, utilizes the part that the OCC plays in the overall carbon cycle. It is generally recognized that the ocean is a carbon sink since it takes up more carbon from the atmosphere than it gives out. Thus, carbon dioxide from 5 the atmosphere dissolves in the waters of the ocean. Referring first to Fig. 2, there is shown a floating structure 10, which can be a barge, platform, or the like, and which can be dynamically or statically positioned at a suitable offshore location. The positioning of structure 10 in deep water can be accomplished using well known methods used in deep water 10 positioning and mooring of drilling and production platforms in the oil and gas industry. Mounted on structure 10 is a gas processing optimization module 12 which is connected by a conduit 14 to a pipeline 16 laying on the seabed 18. Generally speaking, gas pipeline 16 will be for the transport of light hydrocarbon gases, e. g., natural gas which contains primarily methane. In gas processing 15 module 12, gas transferred from pipeline 16 and line 14 can be treated in various ways well known to those skilled in the art to remove unwanted contaminants, water, and other components that would deleteriously effect downstream operations. Module 12 can also include separation and enrichment systems to Optimize BTU content of the gas from pipeline 16. Also mounted on structure 10 20 is a power station module shown generally as 20 and which can comprise a driver, e.g., a gas turbine, or steam turbine, both of which are well known to those skilled in the art and both of which, in the present invention, would be powered directly or indirectly from the combustion of a fuel, e.g., processed 2025230673  09 Sep 2025 natural gas transferred via line 24 from processing module 12. The combusted gas (flue gas) generated in the driver or power section 22 of module 20 is sent to a gas collection system comprised of a compression station 26 to compress the flue gas and transfer it to a conduit or line 28 to a subsea location at a desired 5 optimal depth which can be in the sunlit waters of the ocean, but is preferably, for reasons discussed above, in a deeper ocean pool at about 3 km or greater below the ocean surface. In a preferred embodiment, prior to compression in compression station 26, the flue gas is sent to a carbon dioxide separation station 25 wherein the carbon dioxide is separated from the flue gas by 10 absorption, adsorption, membrane gas separation, or other methods well known to those skilled in the art. The carbon dioxide only is then sent to compression station 26 and ultimately transferred to a subsea location by conduit 28. The non-carbon dioxide components of the flue gas are then processed and disposed with by means well known to those skilled in the art. The turbine comprising 15 driver 22 is mechanically connected in a well-known fashion to an electric power generator 24 whereby electric power is generated and transferred via line 28 to an electric power substation 30. Substation 30 will generally have switching, protection, and control equipment, and transformers, output from substation 30 being transmitted via electric power transmission line 32 to a remote location, 20 preferably on land. Turning now to Fig. 3, there is shown another embodiment of the present invention. The embodiment shown in Fig. 3 is substantially the same as that shown in Fig. 2 with the exception that gas from pipeline 16 is transferred via line 2025230673  09 Sep 2025 14 to a gas storage tank 15 positioned on structure 10. The gas in storage tank 15 is transferred via line 13 to gas processing module 12. In all other respects, the embodiment of Fig. 3 is the same and functions in the same manner as the embodiment of Fig. 2. 5        Turning now to Fig.4, there is shown another embodiment of the present invention which is similar to the embodiments shown in Figs. 3 and 4, with the exception it employs liquefied natural gas (LNG) as a fuel source. To this end, there is a barge or ship 42 which has a compartment or vessel 44 carrying LNG, the LNG being transferred form compartment 44 via line 48 to storage vessels 46 10 on structure 10. LNG is transferred via line 47 to a regasification module 50 and thereafter regasified liquid natural gas (RLNG) via line 52 to gas processing module 12. Using fuel injection technology, it may be possible for LNG to be used as a fuel, without regasification. In all other respects the embodiment of Fig. 4 is the same and functions in the same manner as the 15 embodiment of Fig. 2 and 3. Referring now to Fig.5, there is shown a schematic layout of a typical gas turbine system that can be used in the power generating system and method of the present invention. The gas turbine system of Fig. 11 comprises a compressor 60, coupled by shaft 62 to a turbine 64. In a well-known manner, air is 20 introduced into compressor 60 via line 66, the air being compressed and then transferred via line 68 to a combustion chamber 70 where it is admixed with a suitable fuel, e.g., natural gas, LNG, the fuel igniting in combustion chamber 70 to generate a high temperature, high pressure gas flow which is introduced via 2025230673  09 Sep 2025 line 74 into turbine 64 to drive turbine 64 wherein it expands down to an exhaust pressure producing a shaft work output via shaft 76 which can then drive an electric power generator, e.g., generator 24. The carbon dioxide combustion gas from turbine 64 is then captured for transfer via line 28 for sequestration at a 5 suitable depth below the surface of ocean as described above with respect to embodiments of Fig. 2, Fig. 3 and Fig. 4. In the case of a steam turbine, the natural gas would be used to convert water to steam, the steam in turn being used to spin the turbine, the output shaft of the turbine being coupled to an electric generator as in the case of the gas 10 turbine. It is further contemplated there could be combination of gas and steam turbines, similar to configurations on land based combined cycle power stations which are well known to those skilled in the art. In all embodiments discussed above, either natural gas or LNG has been used as a fuel source. However, it is within the scope of the present invention for 15 the fuel source to comprise oil, heating oil and other hydrocarbon liquids. Further, the fuel source could comprise coal which could be transferred by barge from the shore to the offshore structure, the coal forming fuel for a boiler generating steam to drive a steam turbine. While admittedly the use of coal poses greater combustion gas capture 20 problems, there are known technologies for capturing combustion gases from the burning of coal or similar solid fossil fuels, which can trap noxious gases other than C02 and transfer the remaining C02 into the ocean as discussed above with respect to the embodiments shown in Figs. 2 - 4. Such a system might be useful 2025230673  09 Sep 2025 where conditions make it difficult to supply the system with natural gas, LNG, or other similar fluid fossil fuels, and wherein the adjacent land is rich in coal deposits. Further, waste paper products could also be used as a fuel source. It is further contemplated that the carbon dioxide collection system may include 5 systems for adding chemical additives, if required, prior to subsea transfer to mitigate potential for localized ocean acidification, due to point source offshore sequestration of carbon dioxide. As described above, the structure can be a floating structure similar to deepwater oil and gas offshore platforms, or a fixed structure similar to current, 10 relatively shallow water oil and gas platforms, thereby forming a semi-permanent structure. However, the use of some type of floating structure is preferable since it allows the system to be transferred at will from one location to another to optimize cost considerations. It will also be understood that feed stock and electric power or export connections will be of a type that could be quickly 15 disconnected to allow the structure to be moved in the event of weather related events such as hurricanes. It will be further understood that power plant, depending upon what type of turbine(s) are employed can also comprise boilers, steam generators, pumps, and typical equipment used in onshore electric power generating stations and 20 systems as well known to those skilled in the art. It is further contemplated system could also include a separate vessel or structure having electric power storage capabilities. End of summary for said State of the Art. 2025230673  09 Sep 2025 Problem of Efficiency for Power Generation Technologies Combined Cycle gas turbine (CCGT) up to 60% & oxy-gas CCGT 49% to 55%. Coal-fired power plants 37% and advanced ultra-supercritical plants 45% to 50%. 5 Comparable problem is lower efficiency Geothermal and oxy-coal fuel sources: Deep geothermal power generation thermal efficiency is about 10-17% and low unit capacity; Binary cycle 6.3 MW, 30.4 MW at single-flash, 37.4 at double flash and 45.4 MW working on superheated steam. The known issue with low efficiency is due to low temperature geothermal fluids affecting the inlet 10 temperature, leading to substantial waste heat. Technical limitations include drilling deep wells through high-temperature, high pressure, and corrosive environments. Reservoir performance is impacted by ability to extract heat effectively from the rock depending on factors like fracture networks and fluid flow. Enhanced Geothermal Systems, limitations include rate thermal conduction 15 in creating suitable fractures and well productivity. All impact commercial viability. Oxy-coal power generation thermal efficiency is typically about 30-40%. Energy Penalty: primary efficiency loss comes from energy required to produce high-purity oxygen, typically with cryogenic air separation units (ASU) and the CO2 compression systems needed for carbon capture. Technical limitations 20 include high combustion temperatures, the need for flue gas recirculation to control heat and stabilize flames, potential material degradation at high temperatures. The known technical issues restrict commercial viability. 2025230673  09 Sep 2025 SUMMARY OF THE INVENTION The invention is as defined in the claims. 5 2025230673  09 Sep 2025 BRIEF DESCRIPTION OF THE DRAWINGS These and further features and advantages of the inventive concept herein will become apparent from the following detailed descriptions, wherein reference is made to the figures in the accompanying drawings. 5 Fig. 1 is for teaching a potential Ecosystem MAR event. Fig. 2 through to Fig. 4 is for teaching of the State of the Art. Fig. 5 teaches of a simplified schematic view of a typical gas turbine system that can be employed in the system and method of said State of the Art invention. Fig. 6 is a simplified schematic view of cumulative embodiments for a first 10 modification integrated with the generation system of said State of the Art. Fig. 7 is a simplified schematic embodiment of a second modification to said State of the Art, for a climate neutral prime mover system. Fig. 8 and Fig. 9 are simplified schematic views of embodiments for the second modification integrated with the generation system of said State of the Art. 15 Fig. 10 through to Fig 13 is cumulative schematic views of the third modification, integrated with offshore or onshore structures and system of said State of the Art. Fig. 14: simplified schematic embodiment of third modification, AU2025202013. Fig. 15 and Fig. 16 simplified schematic embodiments for the present invention. Fig. 17 and Fig. 18 are cumulative schematic views of the present invention, 20 integrated with offshore or onshore structures and system of said State of the Art. Fig. 19 another simplified schematic embodiment of the present invention Fig. 20 and Fig 21 are cumulative schematic views of present modification, integrated with offshore or onshore structures and system of said State of the Art. 2025230673  09 Sep 2025 DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS The present invention is a continuation in part to a third modification of said State of the Art, AU2025202013; herein an Advanced Prime Mover System (APMS) powered by thermal fuel sources is integrated with the Carbon-negative 5 System (CNS) of AU2025202013. Herein, this modification provides CO2 sequestration for a geothermal or coal fuel source when used to drive the APMS enabling a Climate-positive Prime Mover System (CpPMS), and a solution to said comparable thermal efficiency problem of geothermal or coal fuel sources. Subsequently, the present invention is a modification to said State of the 10 Art, explicitly the power station module shown generally as 20, comprising: apparatus of power section 22, and flue gas collection system of carbon dioxide separation station 25, a compression station 26 and a subsea transfer line 28. Embodiments of the invention are described more fully hereafter with reference to the accompanying drawings. Elements that are identified using the 15 same or similar reference characters refer to the same or similar elements. Although specific and cumulative embodiments of the invention have been described herein in some detail, this has been done solely for the purposes of explaining the various aspects of the invention and is not intended to limit the scope of the invention as defined in the claims which follow. Those skilled in the 20 art will understand that the embodiments shown and described are exemplary, and various other substitutions, alterations, and modifications, including but not limited to those design alternatives specifically discussed herein, may be made in the practice of the invention without departing from its scope. 2025230673  09 Sep 2025 The foundation of the present invention is pairing an advanced prime mover system designed specifically to provide a flow of steam generator exhaust gases consisting essentially of water vapor gas and CO2 gas to a Carbonnegative System for sequestration of said CO2 gas with conversion to 5 Magnesium Carbonate; herein apparatus and method are designed to achieve. When using geothermal fluids to power the APMS the residual gases, namely Hydrogen Sulfide (H2S), Nitrogen (N2), Helium (HE), Methane (CH4), Ammonia (NH3), Mercury (Hg) and Radon along with dissolved minerals are 10 separated using a Flash Steam Membrane System to prevent derogation to the system components and disposed of by usual methods and well known to those skilled in the art. Note, CH4 is blended with hydrogen for powering the APMS. When using coal to provide heat energy for powering the APMS, the 15 combustion flue gas constitutes for SOX, NOX are disposed of by usual methods which are well known to those skilled in the art. An unforeseen advantage is fly ash can be repurposed for use in the seawater neutralization system as its alkaline nature can increase seawater’s total alkalinity, beneficial for raising pH. Furthermore, fly ash can be used to increase the alkalinity of seawater in 20 seawater FGD systems making the FGD system more efficient at SO2 removal; also fly ash can be used with seawater to capture CO2 through mineralization where the alkaline seawater creates a pH range that enhances the process. 2025230673  09 Sep 2025 The sequestration apparatus for said Carbon-negative System (CNS) is an electrolyzer with an aqueous solution (e.g., seawater) as an electrolyte. Said electrolyzer is equipped with an Oxygen Selective Anode to provide a solution to one of the known problems for electrolysis of seawater, therein chloride gas. 5        Furthermore said electrolyzer is also equipped with a membrane separation system to optimize performance. Seawater contains the necessary reactants to support the electrolysis process for conversion of said HRSG exhaust gases of CO2 and water vapor to a solid, e.g., Magnesium Carbonate. The electrolysis process generates hydrogen gas at the cathode and oxygen gas 10 at the anode, while producing OH- ions at the cathode which are crucial for the CO2 conversion reaction. The chemical equations of the conversion process are: Water electrolysis: 2H2O (l) ^ 2H2 (g) + O2 (g) + 4H+ (aq) + 4OH- (aq) CO2 absorption: CO2 (g) + OH- (aq) ^ HCO3- (aq) 15 Carbonate formation: HCO3- (aq) + OH- (aq) ^ CO3A2- (aq) + H2O (l) Magnesium carbonate precipitation: Mg2+ (aq) + CO3A2- (aq) ^ MgCO3(s) When said exhaust gases of CO2 and water vapor are electrolyzed in the presence of Mg(OH)2 and NaOH, the rapid precipitation of MgCO3 can occur 20 due to the generation of OH- ions which react with dissolved Mg2+ ions from the Mg(OH)2 in seawater resulting in production of solid magnesium carbonate (MgCO3(s)). 2025230673  09 Sep 2025 The exhaust gases of CO2 and water vapor react with the OH- ions generated forming bicarbonate ions (HCO3-), which generates another reaction with additional OH- ions producing carbonate ions (CO3A2-). Said generated carbonate ions react with Mg2+ ions (from dissolved Mg(OH)2 to form solid 5 magnesium carbonate (MgCO3(s)), therein a synthetic conversion of gaseous CO2 to a solid. The NaOH in seawater provides a source of OH- ions. The precipitation of solid MgCO3 occurs when the concentration of Mg2+ and CO3A2- ions exceed the solubility product constant (Ksp) of MgCO3, therein the excess ions rapidly precipitate out as solid MgCO3. 10         The system and method for sequestration of the present invention, said Carbon-negative System (CnS) provides a solution to a known problem for precipitation rate, herein instantaneous precipitation occurs due to heat transfer from the combustion flue gases of CO2 and water vapor which are used for the electrolysis process, the higher temperatures increase the reaction rate which 15 facilitates faster precipitation due with this augmented by the high concentration of CO2. Furthermore, by adding NaOH to the aqueous electrolyte solution further increases the OH- ion concentration which in turn helps to drive the precipitation reaction by creating a more alkaline environment. A byproduct of said electrolysis process is said depleted seawater, which 20 is introduced to a neutralization system; wherein the dissolution of alkaline minerals found in magnesium-rich rocks (e.g., mafic or ultramafic rocks which contain alkaline minerals such as olivine) is used to raise the concentrations of divalent cations in said depleted seawater, prior to discharge. 2025230673  09 Sep 2025 The sequestration system herein provides synthetic replication for CO2 mineralization which occurs naturally in the Ocean Carbon Cycle and used as a sequestration system for the State of the Art. An unforeseen advantage resulting from CO2 conversion to magnesium carbonate herein is the dissolved CO2 in 5 said seawater is converted into solid carbonates or dissolved bicarbonate ions during the electrolysis process, to which can enhance ocean alkalinity. Furthermore, when the depleted seawater is returned to the ocean, this enables the ocean to absorb more atmospheric CO2, therein a climate-positive effect. An unforeseen advantage of Geothermal Filtration System is minerals like 10 dissolved silica in geothermal fluids can assist in neutralizing seawater. There are two primary embodiments shown, starting with a first primary embodiment in Fig. 15 and Fig 16 with schematic drawings for the CpPMS showing modifications to enable geothermal fluids to be the primary fuel source 15 for the APMS 950. Integration with offshore and onshore structures of AU2025202013 is shown in Fig. 17 and Fig. 18 for geothermal fuel delivery to the APMS with a circle around the power module 20. The second primary embodiment in Fig. 19 is a schematic drawing for the offshore structure 10Q showing a modification to enable supplying pulverized 20 coal to be the primary fuel source for the APMS (900). Fig. 20 and Fig. 21 show schematic drawings for Integration with offshore and onshore structures of AU2025202013 for coal fuel delivery from barge 60 via line 61 to coal stockpile 62 via line 63 to coal cleaning / pulverization 64 and via line 65 to the APMS 900. 2025230673  09 Sep 2025 An outline is shown on schematic Fig. 15 through Fig. 22 encompassing the individual elements of the Climate-positive Prime Mover System, comprising: 400 - The Power Generation System (PGS); and 700 - The Carbon-negative System (CNS); and 5        800 - The Hydrogen Generation System (HGS); and 900 - The Thermal Prime Mover System (PMS); or 950 - The Geothermal Prime Mover System (PMS). We begin with Fig. 2, to teach of the present invention interface with the infrastructure of the state of the art for the supply of startup feedstock for the 10 embodiment shown in Fig. 15 only, for initial conversion to steam energy, wherein organic compounds flow to a prime move system, via a subsea pipeline 16 connected to a subsea riser system 14. Said riser is connected via line 14 to a Gas Processing Module 12, which has been modified for the present invention to include an Acid Gas Removal System 12a. 15        Fig. 3 shows the addition of Storage Tank 15, connected to Gas Processing Module 12 via line 13. Fig. 4 shows an alternative method of organic compound delivery by a LNG carrier to temperature-controlled tanks 44; liquefied organic compounds are transferred from tank compartment 44 via line 48 to storage vessels 46 for 20 transfer via line 47 to a regasification module 50 and thereafter regasified organic compounds are stored in storage tank 15. Using fuel injection technology, it may be possible for liquefied organic compounds to be used for combustion in the PMS, without regasification. 2025230673  09 Sep 2025 Fig. 15 shows present invention schematic for a first primary embodiment, and thereafter the description highlights the modification. Said modification herein, is the change of the primary fuel feedstock for conversion to steam energy from organic compounds to geothermal fluids with 5 the apparatus and method described below, to achieve this: To teach, we begin with a primary source of thermal energy: a supply of hot, pressurized geothermal fluids via a line 960, to a Geothermal Filtration System 962, wherein said Geothermal Filtration System 962 solids and minerals are removed by processes well known to those skilled in the art. 10         The Geothermal Filtration System 962 provides a supply of filtered geothermal fluids via line 964 to a Flash Steam Membrane System (FSMS) 966 wherein a flash steam process occurs when the high pressure of the underground geothermal water or geothermal sweater rapidly decreases in a low pressure tank, causing hot water to rapidly boil and turn into water vapor (steam), 15 therein water in its gaseous state or flashed steam. Thereafter a membrane system is used to separate thermal energy, said water vapor (flashed steam) and a CO2 gas from remaining hot water and non-condensable gases. One of the non-condensable gases is methane, which is supplied to the gas processing and blending module via line 967, with remaining non-condensable gases are 20 disposed by means well known to those skilled in the art. For system operation a flow is provided of said thermal energy, primarily consisting of said water vapor (flashed steam) and said CO2 gases from said FSMS, via line 968 to a HRSG modified inlet 969 of HRSG 201 for APMS 950. 2025230673  09 Sep 2025 For startup, a line 234 supplies Hydrogen to a Hydrogen Storage Tank 235 which is connected to Gas Processing Module for Blending (GPMB) 12b with feedstock from Organic Compound Storage Tank 15. Blended Organic Compounds (BOCs) are then supplied via line 237 to a Preheater 238 and via 5 line 239 to an Ultra-High Temperature Combustion System (UHTCS) 300. During operation, steam from the HRSG 201 is supplied to a first steam electrolyzer 230 providing a flow of hydrogen and oxygen to UHTCS 300, similar to a Combined Heat and Power operation. Wherein HRSG 201 said thermal energy is mixed with hot flue gases from UHTCS, therein improving efficiency. 10         The layout of said UHTCS 300 is similar to a typical gas turbine system used in a power generating system but manufactured to withstand the higher combustion temperatures herein. The UHTCS comprises a compressor 301, coupled by shaft 275 to a turbine 305. In a well-known manner, preheated oxygen is introduced into compressor 301 via line 248, the preheated oxygen 15 being compressed and then transferred via line 302 to a combustion chamber 303 where it is admixed with a suitable blended organic compound i.e., preheated blended hydrogen via line 239, the fuel igniting in combustion chamber 303 to generate a high temperature, high pressure gas flow which is introduced via line 304 into a Ultra-High Temperature Combustion Turbine 20 (UHTCT) 305 to drive said UHTCT 305 wherein it expands down to an exhaust pressure producing a shaft work output via shaft 275 which can then drive a Power Generation System (PGS) 400. A method employed during operation of said UHTCS is fuel biasing, wherein fuel is diverted from upper level burners to 2025230673  09 Sep 2025 lower level burners, or from center burners to side burners, or multiple variations thereof. This method lowers the flame temperature and improves the balance of oxygen concentration during combustion of said fuel with said oxygen. The objective is to achieve complete burnout for the blend of organic compounds. 5        Combustion in the UHTCS 300 provides a flue gas composition consisting essentially of CO2 and water vapor with potential for trace amounts of SOX, NOX and other particulates. The UHTCS 300 exhaust is connected to the inlet for HRSG 969, for mixing with the gases of thermal energy from the FSMS 966 which causes a higher temperature results in an operational performance 10 increase which improves overall efficiency. Wherein, HRSG 201 thermal energy in the mixed exhaust gas steam is transferred in the form of heat to filtered seawater and conversion to steam energy, therein Steam Generator operation. The embodiment shows auxiliary / duct firing system and is connected to a suitably modified HRSG Forced Draft Fan System (FDFS) and shown as 201c. 15 This is an option for operational requirements and the invention herein will work without said FDFS optionality. The purpose of said FDFS is to facilitate throughput in the combustion furnace 203 during HRSG duct firing to avoid damaging equipment, with a Forced Cooling System (FCS) 204, 215 supplied with cogeneration steam 226, with a tie-line providing a supply to combustor 303. 20        The HRSG supplies High Pressure (HP) Steam via line 220 to the Steam Turbine System (STS) 270 for the High Pressure (HP) Turbine 272. Said HRSG also supplies Intermediate Pressure (IP) Steam via lines 222 to the Steam Turbine System (STS) 270 for the Intermediate Pressure (IP) Turbine 273 which 2025230673  09 Sep 2025 is recycled via line 223 to the Low Pressure (LP) Turbines 274. Said Steam Turbine System converts heat in the steam energy to mechanical / kinetic energy to rotate shaft 275 which is connected to power generation system (PGS) 400. Furthermore, compressor 301 and combustion turbine 305 rotate said shaft 275. 5         Reheat cycles for return of steam from 270 to the HRSG 201 are shown via lines 221, 223 and 224 respectively. Cogeneration steam is supplied via lines 225, 227 and 228 to Steam Electrolyzer (SE) 230, wherein electrolysis process generates oxygen and hydrogen products, for supply to said UHTCS 300. Said produced hydrogen is 10 transferred via line 231 to onboard Hydrogen Storage Tank 235. Said produced oxygen is transferred via line 233 to onboard Oxygen (O) storage 245 and via line 233 to the oxygen preheater 247, for supply to UHTCS compressor 301 via line 248 and to the FDFS 201c. Liquefied Oxygen (LO) is supplied via line 140 to the liquid oxygen 15 converter 241 and transferred via line 242 to the Oxygen Storage Tank (OST) 245. An onboard Air Separation Unit (ASU), 243 uses a Cryogenic process to separate oxygen from air. Said ASU supplies OST 245 via line 244. The OST supplies oxygen via line 246 to preheater 247, which supplies oxygen via line 248 to a combustion turbine compressor 301 which supplies compressed oxygen 20 via line 302 to said combustor 303. Said OST also supplies oxygen via line 248, to a HRSG FDFS 201c. 2025230673  09 Sep 2025 Seawater Filtration Plant (SFP) 77 removes seawater containments and provides a flow of filtered seawater to conversion systems of 201, 230 and 701. The SFP pumping system draws seawater from water column via line 76, Fig. 17 The onboard essential supplies’ distribution board supplies AC power via 5 line 260 to AC / DC converter station 85, which supplies DC power for the system and method of electrolysis via line 262 to HTSE 230 and Electrolyzer 701. The sequestration system for the present invention, CNS 700, comprises Membrane Separation Technology (MST) 281 for separating residual gases in the mixed exhaust gas. Said MST 281 is connected to the HRSG Exhaust and 10 downstream to Electrolyzer 701, therein co-electrolysis produces a hydrogen output which is supplied via line 714 and an oxygen output supplied via line 712. The flue gas stack 299 incorporates monitoring equipment 298 to ensure the composition does not contain Green House Gas Constituents. The DCS will monitor the flue gas composition and recalibrate said fuel biasing to optimize 15 operational efficiency, i.e. Burnout. If flue gas monitoring shows detection of trace nitrogen gases, NOx, dictates a leak and air ingress to the closed HRSG system. CNS 700 includes a backpressure management system, a condenser 282, wherein flue gas water vapor is cooled and condensed; it consumes a vastly lower volume and thus lowers the pressure or creates a vacuum. This lower 20 pressure in turn increases the differential pressure across UHTCT 305 and improves efficiency, due to vacuum in the condenser. Said vacuum sucks the water vapor from exhaust and lowers the back pressure. If an elevated back pressure is desirable for process usage, the degree of cooling needs to be 2025230673  09 Sep 2025 controlled to manage the back pressure. Furthermore, said vacuum sucks flue gases through said Membrane Separation System 281 to assist separation. CNS 700 discharge for solids is via line 704 to a strainer 706 and includes a neutralization system 710 connected into the discharge line 702 of said 5 depleted seawater. Said neutralization system 710 is supplied with suitable minerals via line 705 to raise the concentrations of divalent cations in said depleted seawater prior to offshore discharge via line 703 and strainer 708. Fig. 15 includes another embodiment of the present invention with a Hydrogen Generation System (HGS) 800, comprising a Hydrogen Combustion 10 System (HCS) 820, a Compressor 810, a Combustion Chamber 813 and a Hydrogen Combustion Turbine (HCT) 815, providing a flow of combustion flue gases through an exhaust to a HRSG 830, which converts heat energy to steam energy to drive a Steam Turbine System 840, therein mechanical / kinetic energy to rotate a shaft connected to power generation system (PGS) 400. 15         Furthermore, compressor 301 and combustion turbine 305 rotate another shaft 275 connected to another power generation system (PGS) 400. The layout of said HGS is similar to a typical gas turbine system used in power generating system. The HGS comprises a compressor 810, coupled by a shaft to a turbine 815. In a well-known manner, oxygen is introduced into compressor 810 via line 20  712, the oxygen being compressed and then transferred via line to a combustion chamber 813 where it is admixed with hydrogen introduced via line 714, the fuel igniting in combustion chamber 813 to generate a high temperature, high pressure gas flow which is introduced via line into a Hydrogen Combustion 2025230673  09 Sep 2025 Turbine (HCT) 305 to drive said HCT 305 wherein it expands down to an exhaust pressure producing a shaft work output via shaft which can then drive a Power Generation System (PGS) 400. A method employed during operation of said combustion chamber 813 is fuel biasing, wherein fuel is diverted from upper level 5 burners to lower level burners, or from center burners to side burners, or multiple variations thereof. This method lowers the flame temperature and improves the balance of oxygen concentration during combustion of said fuel with said oxygen. The objective is to achieve complete burnout for the hydrogen and oxygen fuel mix. The inclusion of said HGS 800 is for dispatchable response to intermediate 10 demand on distribution / grid networks. Fig. 15 includes a further embodiment with an addition of hydrogen fuel cell 802 combined with HGS 800 providing dispatchable response for peak demand on distribution / grid networks. Fig. 16 shows another embodiment of the present invention with the 15 removal of Organic Compound Storage Tank 15 and associated infrastructure. For startup, a line 234 supplies Hydrogen to a Hydrogen Storage Tank 235 which is connected to Gas Processing Module for Blending (GPMB) 12b with said residual methane separated from geothermal fluids supplied via line 967 to said GPMB. A supply primarily consisting of hydrogen is provided via line 237 to 20 a Preheater 238 and via line 239 to UHTCS 300. During operation, steam from the HRSG 201 is supplied to a first steam electrolyzer 230 providing a flow of hydrogen and oxygen to UHTCS 300, similar to Combined Heat and Power operation, therein improving efficiency. 2025230673  09 Sep 2025 Fig. 17 shows a cumulative view off the present invention, integrated with the offshore structure 10GF and auxiliary systems of said State of the Art. A separate offshore structure 10N is shown for neutralization system 710, but berthed to the primary offshore structure 10M. Line 702 is for transfer of said 5 depleted seawater to said neutralization system 710, which is supplied with suitable minerals via line 705 to raise the concentrations of divalent cations in said depleted seawater prior to offshore discharge via line 703 to strainer 708. CNS 700 is connected via line 704 to strainer 706 for discharge of solid minerals. Fig. 17 illustrates the flow of hot, pressurized geothermal fluids from a 10 geothermal reservoir 954, which is connected by a geothermal wellbore 956 to a subsea wellhead 958 which is connected to a subsea riser system 960. Said subsea riser system 960 provides a flow of hot, pressurized geothermal fluids to a Geothermal Filtration System 962 mounted on the offshore structure 10 GF. Wherein said Geothermal Filtration System solids and minerals are removed and 15 a flow of filtered geothermal fluid is provided to said Flash Steam Membrane System (FSMS) 966. The FSMS is connected to the modified inlet 969 of HRSG 201 for said APMS 950, therein providing a flow of said thermal energy primarily consisting of a water vapor (flash steam) and said CO2 gases. Fig. 18 shows a cumulative view similar to Fig. 17, with the exception: 20 relocation of the primary offshore structure 10GF, to onshore renamed GF / S, and the neutralization system 710 is also relocated to onshore. Discharge is same. As onshore geothermal reservoir 984, provides a flow of geothermal fluids via line 982, to a well head and via line 980 to the Geothermal Filtration system 962. 2025230673  09 Sep 2025 Fig. 19 shows a system schematic for a second primary modification with a thermal energy fuel source of combustion of coal and hydrogen with oxygen to produce exhaust gases consisting essential of CO2 and Water Vapor (steam), with potential for residual amounts of SOX, NOX and other particulates. The fuel 5 modifications to APMS 900 are detailed below, integrated to CNS 700 of AU2025202013: therein CNS 700 supplies Hydrogen Generation System 800. Line 902 provides a supply of coal (fuel) to stockpile 904, which is supplied via line 906 to a Pulverized Treatment System 908 for pulverization of said coal and cleaning with filtered seawater. Said Pulverized Treatment System 10  908 is connected to a Boiler (Steam Generator) 912 via line 910 providing a flow of pulverized treated coal (fuel) to the burner system B. Line 234 provides a supply of hydrogen for startup to storage tank 235 which is connected to hydrogen preheater 238 via line 231. A first electrolyzer 230A provides a flow of hydrogen to said hydrogen preheater 238 via line 233. The hydrogen preheater 15  238 supplies a flow of preheated hydrogen via line 239 to the burner system B. Said first electrolyzer 230A also provides a supply of oxygen via tie in line 246 to oxygen preheater 247. As startup oxygen is supplied via line 246 from storage tanks 245 to said oxygen preheater 247. The oxygen preheater 247 supplies a flow of preheated oxygen via line 248 to the burner system B. A method 20 employed during operation of said Boiler (Steam Generator) 912 is fuel biasing, wherein fuel is diverted from upper level burners to lower level burners, or from center burners to side burners, or multiple variations thereof. The objective is to achieve complete burnout for the blend of pulverized coal and hydrogen. 2025230673  09 Sep 2025 Said pulverized treated coal is admixed with preheated hydrogen and oxygen with the fuel igniting in a combustion chamber (furnace area F of 912) to generate a flow of thermal energy with a high temperature, high pressure gas flow through steam area S of 912, wherein heat is transferred to filtered seawater 5 for conversion to steam energy in a steam generator which provides a flow of steam energy via lines 220, 222 to a first driver 270A which produces a first shaft 275 work output, and is connected to the power generating system 400. A second flow of steam from said steam generator of 912 is provided via line 228 to said first Electrolyzer 230A, wherein electrolysis produces a hydrogen gas output 10 via line 233 for preheating 238 and an oxygen gas output via line 246 for preheating 247. A flow of exhaust gases from 912 is provided via line x to ESP 914 where fly ash is collected from particulate matters found in the exhaust gas. A flow of exhaust gases is provided from ESP 914 to a FGD system 916 to remove Sulphur Dioxide. A flow of exhaust gases is then provided from the FGD 15 System 916 to a (SCR) System 918 for removal of NOX. A flow of exhaust gases is provided from said SCR system 918 to the CNS 700, with said exhaust gases primarily consisting of a CO2 gas and a Water Vapor gas with residual gases comprising a SO2 gas and a NOx gas. The sequestration system for the present invention, CNS 700, comprises MST 281 for separating said residual gases in 20 the exhaust gas to avoid derogation. Said MST 281 is connected to SCR 918 and downstream to Electrolyzer 701, therein co-electrolysis produces a hydrogen output which is supplied via line 714 and an oxygen output supplied via line 712. Fig. 20 and Fig. 21 shows integration with offshore & onshore structures.

Claims

1. A process suitable for Climate-positive operation of a systemconfigured as a prime mover for dispatchable power generation, comprising:providing a flow of thermal energy, an exhaust gas consisting essentially5 of a CO2 gas and a Water Vapor gas with residual gases from a source of combustion for a fuel with an oxygen gas or a source of geothermal energy, to a first steam generator;wherein said first steam generator heat is transferred from said flow of thermal energy to filtered seawater, therein conversion to steam energy with a 10 flow of said steam energy provided to a first steam turbine producing a first shaft work output;providing a flow of said steam energy from said steam generator to a first Electrolyzer, wherein electrolysis produces a hydrogen gas and an oxygen gas, to which is provided as a supplement to said sources of thermal energy;15         providing a flow of said exhaust gases from said steam generator to aMembrane Separation Technology System for separation of said residual gases;providing a flow of said CO2 gas and said Water Vapor gas from said Membrane Separation Technology System to a second Electrolyzer;providing a flow of a filtered seawater to said second Electrolyzer, which is20 equipped with an Oxygen-Selective Anode, wherein said second Electrolyzer electrolysis produces a hydrogen gas, an oxygen gas and a magnesium carbonate; andproviding a flow from said second Electrolyzer to a gas monitoring system.2025230673   04 Aug 20262.     The process of claim 1, further comprises said first shaft workoutput drives a first Power Generator, wherein electricity is generated with a flow of said electricity provided to an export system for transmission to either grid networks or a distribution network.

53. The process of claim 1, further comprises a hydrogen poweredPrime Mover System, wherein a flow of said hydrogen gas from said second Electrolyzer is introduced to a hydrogen combustion chamber, and providing a flow of compressed oxygen to said hydrogen combustion chamber, therein said 10 hydrogen and said compressed oxygen gas are ignited to generate a high temperature, high pressure gas flow to a second driver, wherein said second driver said gas flow expands down to an exhaust pressure producing a second shaft work output.15         4.    The process of claim 3, further comprises said second shaft workoutput drives a second Power Generator, wherein electricity is generated with a flow of said electricity provided to said export system for transmission to either grid networks or a distribution network.20         5.    The process of claim 3, further comprises providing a flow from saidsecond driver of exhaust gases to a first heat recovery steam generator, wherein heat energy in said exhaust gases is converted to steam energy to drive a second steam turbine producing a third shaft work output.2025230673   04 Aug 20266.     The process of claim 5, further comprises said third shaft workoutput drives a third Power Generator, wherein electricity is generated with a flow of said electricity provided to said export system for transmission to either grid networks or a distribution network.

57. The process of claim 2, further comprises proving a flow of saidhydrogen gas and said oxygen gas from said second Electrolyzer to a Hydrogen Fuel Cell, wherein electricity is generated with a flow of said electricity provided to said export system for transmission to either grid networks or a distribution 10 network.

8. The process of claim 1, further comprises said gas monitoringsystem will be supervised through a Distributed Control System for the Prime Mover System, therein said Distributed Control System will optimize efficiency for 15 the Climate-positive operation thereof.

9. The use of a Climate-positive Prime Mover System according toclaims 1 to 8, to provide security of supply for dispatchable power generation.20

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