Classifications

• • C—CHEMISTRY; METALLURGY
  • C07—ORGANIC CHEMISTRY
  • C07C—ACYCLIC OR CARBOCYCLIC COMPOUNDS
  • C07C7/00—Purification; Separation; Use of additives
  • C07C7/10—Purification; Separation; Use of additives by extraction, i.e. purification or separation of liquid hydrocarbons with the aid of liquids
• • C—CHEMISTRY; METALLURGY
  • C07—ORGANIC CHEMISTRY
  • C07C—ACYCLIC OR CARBOCYCLIC COMPOUNDS
  • C07C7/00—Purification; Separation; Use of additives
• • C—CHEMISTRY; METALLURGY
  • C07—ORGANIC CHEMISTRY
  • C07C—ACYCLIC OR CARBOCYCLIC COMPOUNDS
  • C07C9/00—Aliphatic saturated hydrocarbons
  • C07C9/02—Aliphatic saturated hydrocarbons with one to four carbon atoms
  • C07C9/04—Methane
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
  • C10G31/00—Refining of hydrocarbon oils, in the absence of hydrogen, by methods not otherwise provided for
  • C10G31/06—Refining of hydrocarbon oils, in the absence of hydrogen, by methods not otherwise provided for by heating, cooling, or pressure treatment
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
  • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
  • C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
  • C10L3/10—Working-up natural gas or synthetic natural gas
  • C10L3/101—Removal of contaminants
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
  • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
  • C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
  • C10L3/10—Working-up natural gas or synthetic natural gas
  • C10L3/101—Removal of contaminants
  • C10L3/102—Removal of contaminants of acid contaminants
  • C10L3/104—Carbon dioxide
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
  • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
  • C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
  • C10L3/10—Working-up natural gas or synthetic natural gas
  • C10L3/108—Production of gas hydrates
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
  • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
  • C10L3/12—Liquefied petroleum gas
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B41/00—Equipment or details not covered by groups E21B15/00 - E21B40/00
  • E21B41/0099—Equipment or details not covered by groups E21B15/00 - E21B40/00 specially adapted for drilling for or production of natural hydrate or clathrate gas reservoirs; Drilling through or monitoring of formations containing gas hydrates or clathrates
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
  • E21B43/34—Arrangements for separating materials produced by the well
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
  • C10L2290/00—Fuel preparation or upgrading, processes or apparatus therefore, comprising specific process steps or apparatus units
  • C10L2290/06—Heat exchange, direct or indirect
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
  • C10L2290/00—Fuel preparation or upgrading, processes or apparatus therefore, comprising specific process steps or apparatus units
  • C10L2290/30—Pressing, compressing or compacting

Definitions

• the present disclosure relates to extracting and processing natural gas.
• the source of the natural gas may be a subterranean or a subsea reservoir of natural gas or natural gas and crude oil, or the natural gas that has been extracted from a reservoir of a naturally formed clathrate hydrate.
• the present disclosure also relates to separating both natural gas from impurities and associated water from impurities.
• the present disclosure further relates to retrofitting a crude oil production system to obtain, transport and use natural gas.
• Methane and other volatile gases separated during the production of crude oil are frequently burned off (or flared) because they cannot be processed by traditional means.
• Standard methods for the transportation of natural gas include pumping as a gas through a pipeline or transporting in a container as compressed natural gas (CNG) or liquefied natural gas (LNG).
• a pipeline is a physical pipe which connects the source of natural gas and the desired destination for the natural gas. Energy is required to pump natural gas through the pipeline.
• CNG systems the natural gas is compressed and stored in a pressurized container for transportation. Energy is required to compress the natural gas and to maintain the pressure during transportation.
• the gas is expanded for subsequent utilization or integration into a natural gas distribution system.
• a stranded gas reservoir is therefore understood as a natural gas field that has been discovered but remains unusable for either physical or economic reasons.
• a natural gas reservoir may be considered stranded because the quantity of natural gas is too small, because it is too difficult to reach, or because it is geographically removed from a market for the energy.
• a reservoir may be deemed stranded if the natural gas contains too many impurities by percentage composition. These impurities may include, for instance, carbon dioxide, hydrogen sulfide, water vapor, and nitrogen.
• Watanabe U.S. Patent Publication 2010/0325955 teaches making almost almond shaped hydrate pellets (tubular form) and packing the hydrate pellets in containers to retain discrete objects and to keep the temperature low so as to prevent agglomeration.
• Watanabe may be analogized to producing ice cubes instead of powdered ice (or snow) but retaining the ice cubes as the cubes they are without solidifying the ice cubes into a large block.
• Zhang U.S. Patent Publication 2008/0135257 teaches mining a marine sediment hydrate by heating the naturally formed hydrate to form natural gas. Zhang in essence collects gas that is released. In so doing, Zhang recognizes that the conditions where hydrates form naturally are indeed the conditions which would lead to hydrate formation in subterranean environments (i.e. at the conditions on the seafloor). Hence, according to the teachings of Zhang, hydrates reform because as the hydrates rise to the surface of the sea, the hydrates subsequently dissociate to form natural gas. Zhang merely teaches allowing the natural gas to subsequently reform hydrates knowing the hydrates will later dissociate. Jones, U.S.
• Patent Publication 2010/0048963 teaches producing hydrate reservoirs from a plurality of hydrocarbon reservoirs with at least one conventional hydrocarbon reservoir. The excess heat in the production of the conventional reservoir is used as the source of heat to dissociate and hence produce the natural gas from the natural gas hydrate reservoir.
• Natural gas is a gas consisting largely of methane and other hydrocarbons.
• the reservoir may contain natural gas, crude oil (which is a mixture of oil and natural gas), or the reservoir may be natural gas stored as a natural gas clathrate hydrate (NGCH).
• the methods feature an optional first step of drilling a well to reach the reservoir. If the reservoir is natural gas, then the contents are ready to be transported. In the instances where the reservoir is crude oil, the methods feature a second step of separating the oil and the natural gas. The methods may feature a third step of transporting, pumping or piping the oil component for processing according to known methods. Similarly, the third step may feature collecting the oil component into separate shipping containers for suitable transport.
• the stranded natural gas may exist in the form of a natural gas clathrate hydrate (NGCH).
• the second step may include dissociating the original natural gas clathrate hydrate (NGCH) into gas and water by, for instance, applying heat or lowering the pressure or both.
• the methods may feature a fourth step of cleaning the natural gas of debris.
• the methods may feature a fifth step of transporting, pumping or piping the natural gas into a gas/clathrate hydrate processing facility, such as one proximate on the seafloor.
• the gas/clathrate hydrate processing facility may be designed to transform the natural gas such that it forms natural gas clathrate hydrate (NGCH).
• a promoter may be provided to facilitate transformation of the natural gas into a structure II (sll) hydrate.
• the transforming of natural gas so that it forms natural gas clathrate hydrates (NGCH) may result in separation of impurities from the natural gas such as CO 2 .
• the impurities including CO 2 may then be pumped back into the reservoir to maintain the pressure of the reservoir and to reduce or avoid release of CO 2 into the atmosphere.
• NGCH solid natural gas clathrate hydrates
• NGCH solid natural gas clathrate hydrates
• the solid hydrates such as natural gas clathrate hydrates are first assembled and placed into shipping containers that are then emptied at the sea surface into a larger transport carrier for transport to a destination for conversion back to natural gas or re-gasification.
• the solid natural gas clathrate hydrates are assembled and placed into shipping containers, and these shipping containers are themselves used to transport the natural gas clathrate hydrates (NGCH) to a destination for re-gasification, i.e. conversion back to natural gas.
• NGCH natural gas clathrate hydrates
• the solid hydrates may be transported to the sea surface and then to a target destination such as a terminal either at a port or floating in the sea, i.e. a Floating Liquefied Natural Gas (FLG). There it may be dissociated to water and natural gas and then further processed, according to known techniques to, for instance, liquefied natural gas (LNG).
• LNG liquefied natural gas
• the natural gas reservoir may be found on land or in the sea such as, for instance, at the seafloor.
• the transporting, pumping or piping of the natural gas into a gas/clathrate hydrate processing facility may be performed at any depth from the seafloor to the surface of the sea.
• the gas/clathrate hydrate processing facility designed to transform the natural gas so that it forms solid natural gas clathrate hydrates may be found at the seafloor, at the surface of the sea, such as, for instance on an oil platform or proximate to an oil platform, or on land, such as, for instance, proximate a crude oil well.
• methods are described herein for extracting natural gas from a reservoir of natural gas hydrates, such as those that may be found in a subterranean environment such as at the seafloor.
• the methods feature an optional first step of drilling a subsea well to extract the hydrocarbons. In some instances, depending upon the hydrocarbon makeup of the reservoir, the well may yield natural gas only.
• the methods may feature a second step of cleaning the natural gas of debris.
• the methods may feature a third step of transporting, pumping or piping the natural gas into a gas/clathrate hydrate processing facility.
• the gas/clathrate hydrate processing facility may be found at or proximate to the seafloor, at or proximate to the sea surface, or on land.
• the gas/clathrate hydrate processing facility may be designed to transform the natural gas so that it forms solid hydrates such as clathrate hydrate.
• a promoter may be provided to facilitate transformation of the natural gas into a structure II (sll) hydrate. Heat generated from this exothermic process of transforming the natural gas so that it forms a natural gas clathrate hydrate may optionally be conducted or convected back to the source of the natural gas and subsequently used to facilitate liberating additional natural gas.
• such solid natural gas clathrate hydrates may be assembled and placed into shipping containers suitable for transporting the solid natural gas clathrate hydrates to the sea surface.
• the natural gas clathrate hydrate are first assembled and placed into shipping containers that are then emptied at the sea surface into a larger transport carrier for transport to a destination for conversion back to natural gas.
• the solid natural gas clathrate hydrates are assembled and placed into shipping containers, and these shipping containers are themselves used to transport the natural gas clathrate hydrate to a destination for conversion back to natural gas.
• the solid natural gas clathrate hydrates may be transported to the sea surface and dissociated to water and natural gas according to known techniques. The natural gas may then be processed further according to known techniques to, for instance, liquefied natural gas (LNG).
• LNG liquefied natural gas
• the methods involve converting stranded gas such as natural gas to form natural gas clathrate hydrates and may result in liberation of impurities from the natural gas such as CO2.
• the CO2 may then be pumped back into the reservoir from whence it came, for instance a subterranean or subsea reservoir to maintain reservoir pressure and avoid entry into the atmosphere of CO2.
• the invention provides a method for extracting natural gas or a mixture of oil and natural gas from a subterranean environment such as beneath the seafloor and converting it into a solid hydrate such as a clathrate comprising: a) extracting natural gas or a mixture of oil and natural gas; b) optionally separating the natural gas from the mixture of oil and natural gas in a first tank or vessel; c) transporting the natural gas to a second tank or vessel; d) introducing sea water into the second tank or vessel; e) providing a promoter; f) mixing the natural gas and water to form a NGCH/water slurry; g) removing excess water from the NGCH slurry to form a solid comprising a clathrate; and h) processing the solid comprising a clathrate into a transportable form.
• the methane clathrate hydrate may be transferred to a vessel for storage and transportation.
• the ideal characteristics of the vessel are 1) neutrally or near-neutrally buoyant (i.e. the same or similar density as the external fluid or sea water), 2) strong (to contain the material without leaking contents or rupturing) and 3) flexible so that it would not contain much or any void volume as the vessel is filled.
• the vessel may be suitable to sustain a pressure differential so that the internal pressure may be maintained in order for the contained clathrate hydrate to remain in the stability region (i.e. remain as a hydrate rather than prematurely dissociate to a natural gas and water). In some instances, the pressure vessel is flexible so that the volume expands as it is filled.
• the vessel is rigid but filled with water or other inert fluid that may be emptied as the clathrate hydrate is loaded into the vessel.
• the vessel may contain a bladder or diaphragm to separate the hydrate clathrate from the water or other inert fluid.
• a bladder or diaphragm is a common feature used frequently in the aerospace industry to prevent mixing between two species such as a liquid fuel and an inert gas used to maintain the pressure of the vessel.
• the processing of the solid comprising a clathrate into a transportable form may feature molding or shaping the solid into a suitable size and shape for transport or may feature dissociating the clathrate to water and natural gas according to known techniques.
• the natural gas may then be processed further according to known techniques to, for instance, liquid natural gas (LNG).
• the methods involve converting natural gas to form solid hydrates such as clathrates and may result in liberation of impurities from the natural gas such as C02.
• the C02 may then be pumped back into the subterranean environment or reservoir to avoid release into the atmosphere.
• a system for extracting natural gas or a mixture of oil and natural gas from a reservoir, such as beneath the seafloor, and converting it into a solid hydrate such as a clathrate featuring the following: a) a first tank or vessel designed to function as a gas/oil separator; b) a second tank or vessel designed to function as a NGCH processor; and c) a third tank or vessel adapted to function as a NGCH Collection /Shipping container.
• the system may optionally comprise d) a well-head entry, and the system may optionally comprise e) a turbine/flow restrictor that may be coupled to a flow restrictor a first tank or vessel designed to function as a gas/oil separator.
• the turbine may be attached to the exit of the well head to generate mechanical and electrical power to run electric motors and mechanical processing devices.
• the first tank or vessel designed to function as a gas/oil separator or gas/oil/water separator by traditional means.
• the separator may operate as a cyclone where heavier (primarily oil) particles physically separated from the lighter (primarily gas) particles. In three phase separations where there is a large quantity of water, beyond what is needed for production, the excess water may be pumped into a disposal well.
• the second tank or vessel designed to function as a NGCH processor may operate at the local pressure or it may operate at a higher pressure.
• the second tank or vessel may be designed to operate as a continuous or batch process. In some instances, there may be multiple (e.g. 3) smaller batch processing tanks or vessels, Tank 2a, Tank 2b, Tank 2c, etc. staggered in time to accommodate larger residence times in the Tank 2 stage and provide for continuous production from the reservoir.
• the second tank or vessel may be semi flexible and may feature a valved top inlet and/or a bottom outlet. Each tank may contain diagnostic and control sensors (i.e. for temperature, pressure, composition). There may also be one or more apparatuses to provide for mixing.
• the third tank or vessel may be adapted to function as a NGCH Collection /Shipping Container
• the ideal characteristics of the container are 1) neutrally or near- neutrally buoyant (i.e. the same or similar density as the external fluid or sea water), 2) strong (to contain the material without leaking contents or rupturing) and 3) flexible so that it would not contain any void volume as the vessel is filled.
• the vessel may sustain a pressure differential so that the internal pressure may be maintained in order for the contained clathrate hydrate to remain in the stability region (i.e. remain as a hydrate rather than prematurely dissociate to a natural gas and water).
• the pressure vessel may be flexible so that the volume may expand as it is filled.
• the vessel is rigid but filled with water or other inert fluid that is emptied as the clathrate hydrate is loaded into the vessel.
• the vessel may contain a bladder or diaphragm to separate the hydrate clathrate from the water or other inert fluid.
• a bladder or diaphragm is a common feature used frequently in the aerospace industry to prevent mixing between two species such as a liquid fuel and an inert gas used to maintain the pressure of the liquid fuel.
• the methods and systems described herein provide for separating CO2 and other impurities from natural gas present in the reservoir. Such undesired gases may be captured and sequestered. The methods may be performed so that release of CO2 into the atmosphere is minimized. When applied to a reservoir of natural gas or natural gas and crude oil, the CO 2 pumped back into such reservoir may thereby increase internal pressure of the same and hence provide for greater efficiency in extracting the remaining reservoir. CO 2 does not form an sll clathrate hydrate according to the methods and systems described herein. As such, CO 2 may effectively be separated from natural gas.
• the methods and systems described herein provide methods for producing usable water.
• the methods feature forming a natural gas clathrate hydrate according to any of the methods described herein and subsequently processing the natural gas clathrate hydrate to release the natural gas.
• the water generated from the artificially formed natural gas clathrate hydrate may be substantially free of impurities inherent in the original source.
• the water produced thereby may be further processed, as necessary, for subsequent use, such as, for instance, as industrial ‘grey’ water or as potable water.
• Figures 1A and IB provide phase equilibrium curves (boundaries) for formation of clathrate hydrates from methane ( Figure 1A), and equilibrium curves for natural gas containing other volatile hydrocarbons.
• the curves depict the hydrate/gas phase boundaries of pure methane and a methane/hydrocarbon admixture at various temperatures and sea depths. Also shown are temperature isoclines for the Gulf of Mexico and the North Sea.
• Figure 2 depicts hydrate equilibrium data for both a structure I (si) methane clathrate hydrate and a structure II (sll) methane clathrate hydrate.
• the si is for a methane/ water system and the sll is from a methane/THF/water system.
• Figure 3 depicts the presently described methods and systems for forming a structure II (sll) methane clathrate hydrate.
• Figure 4 depicts instances of the presently described methods and systems where parallel streams for stable methane clathrate formation are provided.
• Figure 5 depicts the retrofitting of the presently described methods and systems to an oil production facility.
• Figure 6 also depicts the retrofitting of the presently described methods and systems to an oil production facility.
• Figure 7 is a schematic of a system to process natural gas obtained from the dissociation of clathrate hydrates that naturally occur at or below the seafloor.
• the method optionally provides the opportunity to direct latent heat that is produced from the formation of artificial hydrates to enhance dissociation of natural gas in the reservoir.
• Figure 8 depicts the retrofitting the methods and systems described herein to an existing off-shore production facility where the natural gas is currently being flared. Instead, the natural gas is directed to the surface or below the surface of the sea for subsequent processing for storage and transport. A portion of the natural gas can be flared to generate energy to operate the process and to permit the disposal of unwanted impurities.
• Figure 9 is a notional diagram where a hydrate is converted to natural gas for subsequent processing to liquid natural gas (LNG) at a floating offshore production and offloading vessel (FSPO).
• LNG liquid natural gas
• FSPO floating offshore production and offloading vessel
• the product can be shipped to an LNG terminal at a port location for processing to LNG.
• Ranges may be expressed herein as from “about” one particular value, and/or to “about” another particular value. When such a range is expressed, another aspect includes from the one particular value and/or to the other particular value. Similarly, when values are expressed as approximations, by use of the antecedent “about,” it will be understood that the particular value forms another aspect. It will be further understood that the endpoints of each of the ranges are significant both in relation to the other endpoint, and independently of the other endpoint.
• any embodiment of any of the methods can consist of or consist essentially of - rather than comprise/include/contain/have - any of the described steps, elements, and/or features.
• the term “consisting of’ or “consisting essentially of’ can be substituted for any of the open-ended linking verbs recited above, in order to change the scope of a given claim from what it would otherwise be using the open-ended linking verb.
• stranded gas reservoir is defined herein as a natural gas reservoir that is known but remains unusable for either physical or economic reasons.
• natural gas is defined herein as both the final product, i.e., methane and the crude material which is obtained from natural sources.
• natural gas includes methane and higher order desirable hydrocarbons, and oil as having hydrocarbons that form a liquid, though not a gas at standard pressure.
• crude natural gas is used interchangeably with “natural gas.” Crude natural gas comprises, inter alia, methane, as well as, other hydrocarbons and gases such as carbon dioxide, nitrogen, hydrogen sulfide, helium, and the like.
• methane hydrate, methane clathrate and methane hydrate clathrate are used interchangeably.
• methane hydrate clathrate and natural gas hydrate clathrate are also used interchangeably unless specifically indicating a difference.
• References to a type I or structure I (si) clathrate are used interchangeably.
• the term for a type II or structure II (sll) clathrate are used interchangeably with one another.
• Gas clathrate hydrates are nonstoichiometric crystalline solids formed from the reaction of water and gas under certain conditions of relatively high pressure and low temperature. (See, e.g. Sloan et ah, Clathrate Hydrates of Natural Gases. 3rd ed. ; CRC Press, Taylor & Francis Group: Boca Raton, FL, 2008).
• the methods and systems described herein enable extracting natural gas using methods that are economical from a cost and energy balance perspective.
• the methods and systems described herein require less energy to produce natural gas compared to the stored potential energy in the natural gas that is extracted.
• the methods described herein enable producing natural gas from reservoirs that are otherwise unusable and, therefore, regarded as “stranded.”
• the source of the natural gas may be a subterranean or a subsea reservoir of petroleum that can be either natural gas or a combination of natural gas and crude oil.
• the source may also be the natural gas that has been extracted from a subsea reservoir of naturally formed clathrate hydrates.
• the methods and systems described herein also provide for retrofitting a production system of petroleum.
• the methods and systems described herein can be adapted to further capture and separate higher molecular weight volatiles, for example, ethane, propane, butane and pentanes. This can be achieved by allowing a change in temperature and pressure in a processing vessel such that species with different hydrate formation conditions form solid gas clathrate hydrate.
• the gases may be isolated by conventional methods such as distillation or by cold-finger condensation.
• the methods and systems described herein may be adapted to capture natural gas that has been harvested from naturally formed natural gas hydrate clathrate reservoirs such as those formed in the deep sea or sub-permafrost. These clathrates may also contain impurities, including carbon dioxide. The methods and systems may be utilized to remove such impurities.
• Crude oil comprises natural gas.
• the methods and systems described herein are useful for extracting natural gas from a source of crude oil. As further described herein, the method and systems may be performed at the subsea level, on the seafloor, at an intermediate level, at the sea surface, or on land. The methods and systems described herein may be adapted to the composition and amount of natural gas in the crude oil.
• the methods and systems described herein provide for separating natural gas and oil at a well head, processing the resulting natural gas into solid natural gas clathrate hydrate (NGCH), and filling shipping containers with the solid NGCH for transport, such as, for instance, for transport to the sea surface and for transport to distant facilities for reconverting the solid NGCH to natural gas .
• the methods and systems described herein include the overall processing system design and the materials used, as well as the transport container design and materials used.
• the methods and systems for recovering methane from crude oil described herein feature the following: a) receiving crude oil into a first vessel in an amount to create a head space; b) adjusting temperature and/or pressure of the vessel; c) separating dissolved gases from the vessel; d) transferring the separated gases into a second vessel; e) introducing service water or ingested sea water into the second vessel; f) providing a promoter and optionally a surfactant into the second vessel in an amount sufficient to form a clathrate slurry; and g) transferring the slurry to a third vessel to form a stable sll methane clathrate hydrate.
• the methods described herein can be conducted on a batch scale as described herein and depicted in Figure 3.
• the methods can be adapted to be a continuous process as depicted in Figure 4 by placing one or more vessels 2 (102) and 3 (103) in parallel.
• the stable methane clathrate hydrate is suitably formed it can be transferred to a container for transport to facility for use or to a facility wherein the clathrate further processed.
• the methods may feature the following optional additional steps: h) transferring the processed crude oil from the first vessel to a container, pipeline, ship, or the like for further processing; and i) removing any unprocessed gases from the second vessel, i.e., CO2 , other impurities, and volatile hydrocarbons, for example, ethane, propane and butane.
• unprocessed gases i.e., CO2 , other impurities, and volatile hydrocarbons, for example, ethane, propane and butane.
• Crude oil from a reservoir may also contain CO2 as well as other impurities. CO2 liberated during the methods described herein may be further processed.
• the gas may be processed into a liquid or a solid form.
• the gas may be captured by conventional means, such as on an absorbent. This may be performed, for instance, when adjusting the temperature and pressure of the first vessel (101) in subsequent runs.
• the promoter provided in step (f) may be contained in water removed from vessel 3 (103).
• the promoter may be recovered for recycling into the process.
• THF which is an effective promoter forms a minimum azeotrope with water at 64 0 C which contains 6.7% water in mass fraction.
• the THF may be azeotroped to form an aqueous solution high in THF content that may be a suitable source of the promoter. Because formation of the sll hydrate is an exothermic process, the energy released may be used to supplement the energy necessary to recover the promoter. Volatile hydrocarbons can be likewise captured and further treated for use.
• any CO2 released may be re-injected back into the reservoir.
• the methods described herein may feature the following: a) receiving crude oil into a first vessel in an amount sufficient to create a head space; b) adjusting temperature and/or pressure of the first vessel to produce separation of dissolved gases; c) transferring the separated gases into a second vessel; d) introducing service water or ingested sea water into the second vessel; e) providing a promoter and optionally a surfactant into the second vessel in an amount sufficient to form a clathrate slurry; f) removing non-methane gases that do not from a clathrate; g) transferring the non-methane gases of f) into the reservoir; h) transferring the clathrate slurry to a third vessel; and i) reducing the amount of service water present in the third vessel to form a stable sll methane clathrate hydrate.
• the CO2 and other impurities separated from the crude oil in the disclosed process may be directly injected back into the crude oil reservoir.
• this features a) receiving crude oil into a vessel in an amount sufficient to create a head space; b) adjusting temperature and/or pressure of the vessel to separate dissolved gases; c) transferring the separated gases into a second vessel; d) introducing service water and a promoter into the second vessel to form a clathrate slurry; e) transferring any CO2 and other impurities liberated from the crude oil back into the crude oil reservoir; and f) transferring the slurry to a third vessel and reducing the amount of service water present to form a stable sll methane clathrate hydrate.
• the methods described herein feature retrofitting to a crude oil production facility.
• methane and other volatile gases are contained in a low boiling distillate fraction, for example, a naphtha fraction.
• This naphtha fraction is allowed to condense so that liquid naphtha is separated from any volatile gases, including lower boiling point hydrocarbons.
• This gaseous fraction is typically flared or burned off.
• the methods may feature the following: a) receiving volatile gases separated during a refinery process into a first vessel containing service water and a promoter; b) adjusting temperature and/or pressure of the first vessel to thereby form a methane clathrate slurry; c) removing volatile gases; d) transferring the methane clathrate slurry to a second vessel; and e) removing service water thereby forming a stable sll methane clathrate hydrate.
• the stable sll clathrate hydrate thereby formed may be transported. In some instances the methane clathrate hydrate may be transferred to a vessel for storage and transportation.
• the ideal characteristics of the vessel are 1) neutrally or near-neutrally buoyant (i.e. the same or similar density as the external fluid or sea water), 2) strong (to contain the material without leaking contents or rupturing) and 3) flexible so that it would not contain any void volume as the vessel is filled.
• the vessel may sustain a pressure differential so that the internal pressure may be maintained in order for the contained clathrate hydrate to remain in the stability region (i.e. remain as a hydrate rather than prematurely dissociate to a natural gas and water).
• the pressure vessel is flexible so that the volume expands as it is filled.
• the vessel is rigid but filled with water or other inert fluid that is emptied as the clathrate hydrate is loaded into the vessel.
• the vessel may contain a bladder or diaphragm to separate the hydrate clathrate from the water or other inert fluid.
• a bladder or diaphragm is a common feature used frequently in the aerospace industry to prevent mixing between two species such as a liquid fuel and an inert gas used to maintain the pressure of the liquid fuel.
• Naturally occurring clathrates may contain CO2 as well as other impurities.
• the method and system described herein may enable separating these impurities and reforming substantially pure methane clathrate hydrates.
• the resulting solid methane clathrate hydrates may be further processed.
• the methods described herein for collecting methane from a sea bed reservoir feature the following: a) collecting natural gas or a mixture of crude oil and natural gas in a first containment vessel; b) transferring the natural gas into a second containment vessel; c) introducing service water or ingested sea water into the second containment vessel; d) introducing a promoter and optionally a surfactant into the second vessel; e) mixing the contents of the second vessel to thereby form a methane clathrate hydrate aqueous slurry; f) removing excess water from the methane clathrate hydrate aqueous slurry to thereby form a solid methane clathrate hydrate; and g) transferring the solid methane clathrate hydrate to a container suitable for transport.
• the methods may also be adjusted to remove any contaminant gases, such as, for instance, sulfur containing gases, as well as CO 2 . These contaminant gases may be captured and retained or transferred back to the sea bed reservoir.
• any contaminant gases such as, for instance, sulfur containing gases, as well as CO 2 .
• the methods and systems described herein are for collecting methane from a stream of produced crude oil.
• the methane may be collected because the solubility of absorbed gases decreases as pressure decreases. Likewise, gases are more soluble in liquids as temperature decreases.
• the methods described herein for removing hydrocarbon gases from crude oil may feature: a) collecting crude oil in a first containment vessel having a first temperature and pressure; b) adjusting the temperature and/or the pressure to dissociate any entrained hydrocarbon gases; c) transferring the released hydrocarbon gases into a second containment vessel; d) introducing service water or ingested sea water into the second containment vessel; e) providing a promoter and optionally a surfactant into the second containment vessel; f) mixing the contents of the second containment vessel to thereby form a natural gas clathrate hydrate aqueous slurry; g) removing excess water from the natural gas clathrate hydrate aqueous slurry to thereby form a solid clathrate hydrate.
• the methods take advantage of properties of natural gas admixtures to fractionate natural gas into its components. This fractionation may be performed at a site of further processing. Sites of Production
• the methods and systems described herein may be performed at any location.
• the system described herein may be located on the seafloor adjacent to or connected to a crude petroleum reservoir.
• the methods may be performed below sea level but above the seafloor, for example, as a submerged system tethered to an oil rig and modified to interrupt or otherwise capture crude oil before it reaches the rig.
• the methods and systems described herein may be performed on land, such as connected directly to an above ground wellhead or at a point in a process (upstream production or at refinery) where natural gas and associated impurities would otherwise be flared.
• the methods and systems described herein for forming a solid methane clathrate hydrate may be performed at a land-based facility. In such instances, it may be desirable and necessary to subsequently dissociate the artificially formed methane clathrate hydrate to natural gas and water. Performing the process enables extracting pure water and natural gas that may be utilized rather than discarded. Additionally, it may separate and concentrate impurities in the original water and gas streams for disposal, either flaring or sequestration through conventional methods. The volume of fluid required for disposal may be greatly reduced by applying this method.
• the methods and systems described herein may be adapted to production facilities.
• methane and other volatile gases separated during the refining process are normally flared or burned off because they cannot be processed by traditional means such as a pipeline, CNG, or LNG methods.
• the volatile gases may be directed into the methods described herein for removal of methane and other gases.
• Methane containing crude oil is known to seep out of bore holes along the seafloor.
• the methane entrained therein either escapes into the atmosphere or is part of a petroleum surface layer. Capture of this crude oil discharge prior to it reaching the surface allows for producing the methane that may be unrecoverable when it reaches the surface and preventing it from escaping into the atmosphere.
• Methane clathrate hydrates can form in crude oil reservoirs. The present methods and systems can be used to convert the natural gas in methane clathrate hydrates to stable, shippable sll methane clathrate hydrates.
• Non-methane clathrate hydrates may be isolated from methane and produced separately.
• Figure 1 depicts the phase equilibrium curves (boundaries) for the formation of clathrate hydrates of pure methane, pure ethane, pure propane and pure butane. Without wishing to be limited by theory, by adjusting the temperature and pressure of capture vessels described herein, these non-methane hydrocarbons can be isolated from methane.
• NGCH from natural gas mixtures generally requires less hydrostatic pressure at the same temperature than the formation of MCH from pure methane ( Figure 1).
• other less typical or artificially blended hydrocarbon gas mixtures involving less methane and more ethane, propane, butane and iso-pentane, etc., also form solid clathrate hydrates, and the higher the proportion of these higher molecular weight gas components, the lower the pressure required.
• the temperature range for clathrate formation becomes much narrower and in instances where formation from pure butane requires water temperatures below 4°C, pressures required for clathrate hydrate formation from these pure hydrocarbon gasses.
• the seafloor provides an ideal environment to form and process NGCH.
• Thermodynamic promoters are suitable for use in the methods and systems described herein.
• Thermodynamic promoters are compounds that alter or shift the equilibrium conditions of methane hydrate formation.
• the thermodynamic promoters also improve the kinetic rate of formation.
• One disadvantage of using a thermodynamic promoter is a lower storage efficiency. Adding a thermodynamic promoter for hydrate formation provides more moderate formation conditions (lower pressure and high temperature). The multifold reduction of pressure at more ambient temperatures offsets the observed reduction in storage capacity.
• Tetrahydrofuran is one such suitable promoter that is widely available.
• suitable promoters that facilitate forming a sll hydrate include cyclopentane (CP), 2,2 - dimethyl butane (neohexane), methyl cyclohexane (MCH), neohexane, 2-methylcyclohexane, pinacolone, isoamyl alcohol and tertiary butyl methyl ether (TBME).
• CP cyclopentane
• neohexane 2,2 - dimethyl butane
• MCH methyl cyclohexane
• neohexane 2-methylcyclohexane
• pinacolone isoamyl alcohol and tertiary butyl methyl ether (TBME).
• a chemical promoter is provided in order to facilitate forming a structure II (sll) hydrate under temperature and pressure conditions that are unfavorable for formation of a structure I (si) hydrate.
• the hydrate that is formed is a sll hydrate.
• Tetrahydrofuran (THF) is a suitable promoter that is widely available.
• Suitable promoters that form a sll hydrate include cyclopentane (CP), 2,2 - dimethyl butane (neohexane), methyl cyclohexane (MCH), neohexane, 2-methylcyclohexane, pinacolone, isoamyl alcohol and tertiary butyl methyl ether (TBME).
• CP cyclopentane
• neohexane 2,2 - dimethyl butane
• MCH methyl cyclohexane
• neohexane 2-methylcyclohexane
• pinacolone isoamyl alcohol and tertiary butyl methyl ether (TBME).
• the methods and systems described herein feature providing a thermodynamic promoter that results in formation of a natural gas clathrate hydrate having a structure II (sll) hydrate instead of a structure I (si) hydrate.
• a structure II (sll) hydrate instead of a structure I (si) hydrate.
• sH structure H
• comparisons of the sll to the si hydrates apply similarly to the comparisons between the sll and sH hydrates there are some key advantages for forming a sll hydrate by adding a promoter when storing and transporting natural gas.
• One advantage of providing a promoter to facilitate forming a structure II hydrate for the storage and transportation of methane is the broader range of stability for sll hydrates, as shown in Figure 2.
• temperatures up to 35 °C
• the required pressure increases significantly to more than 10 MPA for a temperature of 12 °C.
• a structure I hydrate can only maintain stability by controlling the temperature and presumably this is achieved by relying on a combination of two phenomena.
• the self-preservation effect is observed whereby the hydrate has a very low dissociation rate at a narrow temperature and pressure band.
• the thermal mass can be exploited such that artificially formed hydrate is so large that it takes a long time to raise the temperature. Forming such a large structure of a buoyant material that must be anchored to the seafloor as it is being generated. These constraints are not present when a structure II hydrate is formed.
• This formation step can be performed at the seafloor so that the local pressure and temperature correspond to a set of conditions for which sll hydrates form. In this instance, it is possible to operate at in situ conditions, i.e. such that temperature and pressure are in equilibrium with the conditions inside and outside the reaction container.
• the methods and systems described herein separate natural gas from any impurities, particularly solids and gases, for instance, carbon dioxide (CO 2 ) prevalent in natural gas reservoirs.
• CO 2 carbon dioxide
• Carbon dioxide is inhibited from forming an sll clathrate hydrate.
• the temperature and pressure conditions allowing formation of an sll CO 2 hydrate are more unfavorable than the conditions for a sll methane hydrate.
• the natural gas formation can be performed under a set of conditions in which sll CO 2 hydrates will not form. It is conjectured that the CO 2 molecule is too large to fit into a hydrate cage of structure II. In other words, substantially no CO 2 hydrate is formed in such conditions where a methane sll hydrate is formed. As such, the CO 2 does not participate in the conversion.
• the CO 2 passes through the system.
• One option is to sequester the exiting carbon dioxide gas and other non-desired compounds by injecting them back into the reservoir, i.e. back into the ground.
• CO 2 may form a hydrate in the natural gas hydrate formation stage, and some CO 2 and other impurities may also be entrained in the natural gas hydrate during its formation. In the latter case, some CO 2 may be sequestered while other CO 2 may be part of production gasses.
• a surfactant may be provided in the methods and systems described herein such as, for instance, a dilute concentration of a micellular substance (one side polar and one side non polar) to enhance the reaction.
• a dilute concentration of a micellular substance one side polar and one side non polar
• Suitable surfactants are well known in the art and may be provided in a dilute concentration (as small as parts per million to as much as 1-2%).
• Figures 1A and IB depict the phase equilibrium curves (boundaries) for the formation of clathrate hydrates from methane and natural gas in terms of sea depth (proportional to pressure) and water temperature.
• the temperature is lower and pressure is higher for this embodiment.
• Figure IB shows that for natural gas, which comprises components other than methane, the temperature is shifted higher and the pressure to lower values for clathrate formation.
• the methods and systems described herein are based in part upon the relationships demonstrated in Figure 2.
• the conditions depth and its corresponding pressure and temperature
• the data in Figure 1A, IB relate to the conditions in the North Sea and Gulf of Mexico but can be modified to any location with appropriate knowledge of the temperature profile in the sea and the depth. If the local conditions are not conducive to implementing the processes described herein, then it is possible to achieve these conditions within the process by either increasing the pressure or decreasing the temperature or a combination of adjusting both the pressure and temperature.
• Either variable, i.e., pressure or temperature may be manipulated predicated on the depth of the desired hydrocarbon or positioning of the disclosed apparatus. Therefore, collection and recovery may be performed at any depth below the surface of the sea.
• the methods and systems described herein are effective for extracting methane from crude petroleum by converting the extracted methane to a methane clathrate hydrate. Once the methane clathrate hydrate is formed, the methane clathrate hydrate is isolated and delivered to a vessel for storage and/or shipment to a location. Once the methane clathrate hydrate is delivered to a user destination, the methane clathrate hydrate may be dissociated to yield the methane for the destination user’s intended purposes. [0097]
• the service water described herein may be sea water or another water source such as process water extracted from a reservoir. The water may have contaminants such as salt or other contaminants. When the methane hydrate clathrate is dissociated to form water and methane, the recovered water may be desalinated or purified of contaminants, if not completely processed for this purpose.
• impurities may be separated from natural gas, for example, solids and gases.
• Carbon dioxide (CO 2 ) may be prevalent in petroleum reservoirs. Without wishing to be limited by theory, carbon dioxide normally does not become entrained in a sll clathrate hydrate.
• the temperature and pressure conditions that allow for formation of a sll CO 2 clathrate hydrate are distinct from the conditions necessary to form a sll methane clathrate hydrate.
• By controlling the operating temperature and pressure of the formation step it is possible to operate in a region where substantially no CO 2 clathrate hydrate is formed and yet methane hydrate is formed. Therefore, the CO 2 does not participate in the conversion. Under conditions controllable by the disclosed processes, CO 2 passes through the system.
• One non limiting option is to sequester the exiting carbon dioxide gas and other non-desired compounds by injecting them back into the reservoir, i.e., back into the ground.
• Other short chain hydrocarbons may be contained within natural gas clathrates, for example, ethane, propane, butane and isomers of propane and butane. These gases may have added commercial value. There are phase equilibrium curves (boundaries) for the formation of clathrate hydrates of pure methane, pure ethane, pure propane and pure butane. These non methane hydrocarbons may be isolated from methane by adjusting the temperature and pressure of capture vessels described herein.
• the heat of formation of a sll hydrate is approximately three times the heat of formation necessary to form a si methane clathrate hydrate.
• the corresponding heat of dissociation i.e. the heat of necessary to liberate the sequestered methane
• a promoter When methane is then processed into a clathrate hydrate for storage and transportation, if a promoter is used to form a sll hydrate then three times as much energy is released when the heat of formation for the phase transition back to a hydrate.
• This energy from the heat of formation may be directed by way of one or more conventional methods, such as conduction through process equipment or forced convection via a heat transfer loop, in order to promote the production of natural gas from a reservoir of naturally formed hydrates.
• the natural gas may come from production from a petroleum reservoir of natural gas and oil. During the conveyance of produced hydrocarbons from a subsea well to the surface, pressure falls, and the absorbed gas comes out of solution. In this scenario, the gas helps push the oil to the surface. At the surface, it is frequently difficult to utilize this gas, as the quantity may be too small to economically produce it.
• the gas may be processed by the processes described herein whereby by the gas is mixed with process water or injected sea water to form an sll hydrate, with the addition of a thermodynamic promoter.
• the impurities and small fraction of natural gas are burned in order to generate electricity to either run the compressor to increase the pressure or a refrigerator/compressor to lower the temperature of the system.
• Another source is natural gas originating in a subterranean petroleum reservoir.
• the processing may either be on land or water (river, lake or sea). This includes processing of otherwise flared gas, such as in the Permian or Bakkan.
• the methods and systems described herein form a methane clathrate hydrate to facilitate transport to a location where it may be used. As such, it is important to maintain the hydrate in a stable form to prevent its dissociation to natural gas and water. This can be accomplished by maintaining the pressure and temperature to the ‘left’ of the equilibrium curve depicted in Figure 2 for the corresponding hydrate structure (si, sll or sH).
• a pressure vessel may be transported to the surface via traditional methods. Some examples include by a remote-operated-vehicle, brought to the surface in conjunction with other maintenance operations, via ship-board crane, platform-based crane or on a dedicated pulley system.
• the containers may be transported to a desired processing site by standard transportation methods, including being tugged along by a tug boat in the sea or loaded on a bulk carrier.
• the desired processing site may be a location without a local fuel source and one for which conventional methods of natural gas supply (specifically LNG) may not be feasible.
• LNG natural gas supply
• the shipping containers can be designed to deliver sufficient natural gas to the local population on an “as needed” basis. They may also provide storage to serve as a reserve or stockpile for contingencies.
• the apparatus disclosed herein can, therefore, be adapted to receive and use any size transport container.
• one aspect of the present disclosure relates to methods for providing a source of natural gas to a processor or user.
• the disclosed process features: a) providing a stable sll methane clathrate hydrate; and b) transporting the clathrate to a customer.
• the stable sll methane clathrate hydrates can be transported to the customer by filling a suitable container at the point at which the clathrate is formed, for example, at the seafloor or on the sea surface.
• the container may have the ability to maintain a pressure differential with respect to the external pressure.
• the necessary minimum pressure is dependent upon the temperature, including temperatures as high as 35°C for a structure II (sll) methane hydrate.
• a pressurized container with no void volume can be filled on the seafloor where the disclosed processes and apparatuses form e clathrate hydrate. Once filled, the pressurized container may be transported to an end user, i.e., a processing or collection site or an end user.
• the methane clathrate hydrate Once the methane clathrate hydrate is transported to the desired location it can be dissociated to form natural gas and water.
• the temperature and pressure of the hydrate must correspond to a condition where the water and gas phase is the preferred condition i.e. on the ‘right’ of the equilibrium curve shown in Figure 2. Either raising the temperature and/or lowering the pressure provides this result. The most likely way to achieve this is to allow the container to achieve equilibrium temperature and pressure. It is also necessary to add heat to the system for the heat of dissociation.
• the source of this heat can be a combination of one or more of the following: 1) undesired process heat that would otherwise be disposed into the environment or 2) the sea or other body of water which is at a lower temperature, or 3) radiation from the sun and 4) convection from external circulating air.
• FSPO Floating Production Storage and Offloading
• the natural gas clathrate hydrate is first converted (dissociated) to water and natural gas by a process as described herein.
• the source of heat for the hydrate dissociation may also include heat discharge from the FSPO or LNG terminal.
• the natural gas is then processed to LNG.
• the water recovered from the hydrate dissociation may be utilized in the FSPO or LNG terminal.
• Figure 3 is a plot of experimental results assembled by Veluswamy el al, Applied Energy 2018; 216:262-285). These data show the dependency of the methane/water system versus the methane/THF/water system on temperature and pressure.
• methane/water system the following references apply: ( «) methane/water. (See, De Roo JL, el al, AIChE J 1983;29:651-7); (!) methane/water (see, Thakore et al., Ind Eng Chem Res 1987;26:462-9);
• Figure 3 demonstrates that the equilibrium curve (in temperature and pressure) shifts from the red to the blue (open to solid symbols) when a promoter is provided thereby requiring a higher temperature to form natural gas hydrates for a given pressure, or, requiring a lower pressure for hydrate formation at a higher temperature.
• the curve also determines the conditions for maintaining a hydrate during transport and storage. When forming hydrate at the bottom of the sea it is possible to utilize the local temperature and pressure . It is relatively easy to increase pressure during processing using a suitable pressure chamber in order to shift the operating position to the left on the demonstrated curve in order, to produce conditions favoring natural gas hydrate formation.
• a surfactant may be provided such as, for instance, a dilute concentration of a micellular substance (one side polar and one side non-polar) to enhance the reaction and reducing agglomeration of formed hydrate particules.
• a dilute concentration of a micellular substance one side polar and one side non-polar
• Suitable surfactants are well known in the art and may be provided in a dilute concentration (as small as parts per million to as much as 1-2%).
• Figure 4 depicts a process for forming a structure II (sll) methane clathrate hydrate.
• a suitable apparatus may be juxtaposed to the point where natural gas is collected to be burned. The natural gas collected at this point may be converted into stable clathrates given the thermodynamic effects of the promoter to form sll clathrates.
• feed line 200 is connected to reservoir 100.
• the reservoir may be either an underground, an undersea bed or well head or other source of natural gas such as that resulting from producing or processing fossil fuels.
• Crude oil is delivered through valve 110 by pump 111.
• the crude oil continues to heat exchanger 112 then into the bottom of vessel 101.
• dissolved gases become gradiently dissolved, i.e., as the dissolved gases that are proximal to the head space leave the crude oil and enter the head space, this concentration gradient causes more gas to percolate upwards.
• the gases in the head space may be diverted via line 201 by pump 112 to head exchanger 114 where the temperature of the gas may be adjusted.
• the gas then flows into chamber 102 where the gas is mixed with service water entering via line 204 and a promoter provided via line 208 to form a crude slurry or a pellet.
• the slurry or pellet is passed via pump 118 into nucleation chamber 103 where methane clathrate hydrate pellets are formed and undesirable gases such as CO2 are liberated.
• excess water is removed via line 205 and may be alternatively recycled for use via line 204.
• Liberated gases may be sent to the original reservoir, directed to an alternate reservoir or collected for entrainment via line 206.
• the clathrate hydrate formed thereby may then be delivered for processing or shipment via line 203.
• Vessel 103 can be adapted to introduce air or nitrogen as gases and water are removed to fill any void volume that is necessary.
• Methane depleted crude oil may be removed from vessel 101 via line 206 or alternatively recycled to stream 207, regardless of whether the process is conducted continuously, batch wise or incrementally.
• a surfactant may be added by modifying the configuration of vessels 102 or 103 to allow for introducing either an aqueous stream of surfactant or a solid surfactant readily soluble in existing water.
• the surfactant can be contained in the service water stream.
• the methods and systems described herein may be adapted or otherwise retrofitted to recover methane from volatile gases released from crude oil refining.
• the processes can receive volatile gases from any point in a refinery process, for example, from the first distillate of petroleum naphtha cut or from any gas processing step.
• FIG. 6 depicts the retrofitting of the processes described herein to an oil refinery.
• a cooled low volatile stream enters reflux vessel 300 via line 301.
• Reflux vessel 300 contains an upper gaseous layer (white), a lower condensate layer (gray) and sour water collector.
• the condensed layer typically naphtha, may be recycled into the refinery via line 302 via a pump.
• the sour water may be removed via line 303 for disposal.
• Pump 420 delivers the gaseous layer into heat exchanger 430 via line 410 and pump 421 into vessel 400. Service water and a promoter are introduced by pump 424 via line 413 causing a clathrate slurry to form.
• the slurry is then transferred via pump 422 into vessel 401 where service water is removed, and a stable sll methane clathrate hydrate is formed. Excess promoter may be removed with the excess service water. Separated volatiles are removed via 412 utilizing pump 423. The stable methane clathrate hydrate can be removed by pump 427 via line 411.
• Natural Gas or an oil/gas mixture rises up a tubing string from an underground reservoir to a well head at the seafloor.
• the gas/oil mixture may be mostly liquid at the original reservoir depth.
• the pressure may be lower than the reservoir but still greater than the local pressure at the seafloor.
• the temperature will also fall, but still be much higher than the local water temperature.
• the fluid temperature and pressure will change because of the boiling and adiabatic expansion of the gas out of the oil as the pressure decreases while traveling up the wellbore.
• the disclosed apparatus can be fitted to the system to take advantage of the change in temperature and pressure.
• Tank 2 may be designed to operate as a batch process. In fact it may be desirable to have multiple (e.g. 3) smaller batch processing tanks, Tank 2a, Tank 2b, Tank 2c, etc. staggered in time to act as a semi-continuous process. This may reduce the buoyancy forces of the gas separator tank that might act as a holding tank to store gas in between tank fills. Having multiple smaller batch processing tanks also facilitates maintainability of the system.
• Tank 2 may be adapted to introduce a promoter and/or a dilute concentration of a surfactant into the process.
• Described herein are systems and methods for extracting natural gas from crude oil and converting it to solid clathrate hydrates.
• the disclosed clathrates may be efficiently transported.
• the methods described herein feature a first step of drilling a subsea well to extract natural gas from hydrocarbon reservoirs (oil and gas) below the seafloor.
• the configuration of the disclosed methods depends on the hydrocarbon makeup coming from the reservoir, the well may yield gas only, or a mix of gas and oil.
• the oil is separated from the gas at the seafloor through a specially designed separator.
• the oil component is then piped to the sea surface and processed in the usual fashion.
• the natural gas component is cleaned of debris and piped into a gas/clathrate hydrate processing facility on the seafloor designed to form and place solid hydrates in large shipping containers for transporting to the sea surface.
• the pressure in the oil or gas in the exit pipe just below the sea surface typically is much higher than the water pressure at the seafloor. In traditional systems, this pressure is utilized to move the oil and gas to the surface for processing. In the method described here, the pressure is not used for pushing the gas to the surface. As such, the gas expansion that occurs at the exit point from the seafloor, which may or may not involve a flow restrictor of some kind, can provide a means for power generation (electric or mechanical) through a turbine.

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