Patent Grant
12050054
The invention relates to the liquefaction of natural gas to form liquefied natural gas (LNG), and more specifically, to the production of LNG in remote or sensitive areas where the construction and/or maintenance of capital facilities, and/or the environmental impact of a conventional LNG plant may be detrimental.
LNG production is a rapidly growing means to supply natural gas from locations with an abundant supply of natural gas to distant locations with a strong demand for natural gas. The conventional LNG production cycle includes: a) initial treatments of the natural gas resource to remove contaminants such as water, sulfur compounds and carbon dioxide; b) the separation of some heavier hydrocarbon gases, such as propane, butane, pentane, etc. by a variety of possible methods including self-refrigeration, external refrigeration, lean oil, etc.; c) refrigeration of the natural gas substantially by external refrigeration to form liquefied natural gas at near atmospheric pressure and about −160° C.; d) transport of the LNG product in ships or tankers designed for this purpose to a market location; e) re-pressurization and regasification of the LNG at a regasification plant to a pressurized natural gas that may distributed to natural gas consumers. Step (c) of the conventional LNG cycle usually requires the use of large refrigeration compressors often powered by large gas turbine drivers that emit substantial carbon and other emissions. Large capital investment in the billions of US dollars and extensive infrastructure are required as part of the liquefaction plant. Step (e) of the conventional LNG cycle generally includes re-pressurizing the LNG to the required pressure using cryogenic pumps and then re-gasifying the LNG to pressurized natural gas by exchanging heat through an intermediate fluid but ultimately with seawater or by combusting a portion of the natural gas to heat and vaporize the LNG.
Although LNG production in general is well known, technology improvements may still provide an LNG producer with significant opportunities as it seeks to maintain its leading position in the LNG industry. For example, floating LNG (FLNG) is a relatively new technology option for producing LNG. The technology involves the construction of the gas treating and liquefaction facility on a floating structure such as barge or a ship. FLNG is a technology solution for monetizing offshore stranded gas where it is not economically viable to construct a gas pipeline to shore. FLNG is also increasingly being considered for onshore and near-shore gas fields located in remote, environmentally sensitive and/or politically challenging regions. The technology has certain advantages over conventional onshore LNG in that it has a reduced environmental footprint at the production site. The technology may also deliver projects faster and at a lower cost since the bulk of the LNG facility is constructed in shipyards with lower labor rates and reduced execution risk.
Although FLNG has several advantageous over conventional onshore LNG, significant technical challenges remain in the application of the technology. For example, the FLNG structure must provide the same level of gas treating and liquefaction in an area or space that is often less than one quarter of what would be available for an onshore LNG plant. For this reason, there is a need to develop technology that reduces the footprint of the liquefaction facility while maintaining its capacity to thereby reduce overall project cost. Several liquefaction technologies have been proposed for use on an FLNG project. The leading technologies include a single mixed refrigerant (SMR) process, a dual mixed refrigerant (DMR) process, and expander-based (or expansion) process.
In contrast to the DMR process, the SMR process has the advantage of allowing all the equipment and bulks associated with the complete liquefaction process to fit within a single FLNG module. The SMR liquefaction module is placed on the topside of the FLNG structure as a complete SMR train. This “LNG-in-a-Box” concept is favorable for FLNG project execution because it allows for the testing and commissioning of the SMR train at a different location from where the FLNG structure is constructed. It may also allow for the reduction in labor cost since it reduces labor hours at ship yards where labor rates tend to be higher than labor rates at conventional fabrication yards. The SMR process has the added advantage of being a relatively efficient, simple, and compact refrigerant process when compared to other mixed refrigerant processes. Furthermore, the SMR liquefaction process is typically 15% to 20% more efficient than expander-based liquefaction processes.
The choice of the SMR process for LNG liquefaction in an FLNG project has its advantages; however, there are several disadvantages to the SMR process. For example, the required use and storage of combustible refrigerants such as propane significantly increases loss prevention issues on the FLNG. The SMR process is also limited in capacity, which increases the number of trains needed to reach the desired LNG production. Also, to remove heavy hydrocarbons and recover the necessary natural gas liquids for refrigerant makeup, a scrub column is often used.
The integrated scrub column design, such as the one depicted in
The expander-based process has several advantages that make it well suited for FLNG projects. The most significant advantage is that the technology offers liquefaction without the need for external hydrocarbon refrigerants. Removing liquid hydrocarbon refrigerant inventory, such as propane storage, significantly reduces safety concerns on FLNG projects. An additional advantage of the expander-based process compared to a mixed refrigerant process is that the expander-based process is less sensitive to offshore motions since the main refrigerant mostly remains in the gas phase. However, application of the expander-based process to an FLNG project with LNG production of greater than 2 million tons per year (MTA) has proven to be less appealing than the use of the mixed refrigerant process. The capacity of an expander-based process train is typically less than 1.5 MTA. In contrast, a mixed refrigerant process train, such as that of known dual mixed refrigerant processes, can have a train capacity of greater than 5 MTA. The size of the expander-based process train is limited since its refrigerant mostly remains in the vapor state throughout the entire process and the refrigerant absorbs energy through its sensible heat. For these reasons, the refrigerant volumetric flow rate is large throughout the process, and the size of the heat exchangers and piping are proportionately greater than those of a mixed refrigerant process. Furthermore, the limitations in compander horsepower size results in parallel rotating machinery as the capacity of the expander-based process train increases. The production rate of an FLNG project using an expander-based process can be made to be greater than 2 MTA if multiple expander-based trains are allowed. For example, for a 6 MTA FLNG project, six or more parallel expander-based process trains may be sufficient to achieve the required production. However, the equipment count, complexity and cost all increase with multiple expander trains. Additionally, the assumed process simplicity of the expander-based process compared to a mixed refrigerant process begins to be questioned if multiple trains are required for the expander-based process while the mixed refrigerant process can obtain the required production rate with one or two trains. An integrated scrub column design may also be used to remove heavy hydrocarbons for an expander-based liquefaction process. The advantages and disadvantages of its use is similar to that of an SMR process. The use of an integrated scrub column design limits the liquefaction pressure to a value below the cricondenbar of the feed gas. This fact is a particular disadvantage for expander-based processes since its process efficiency is more negatively impacted by lower liquefaction pressures than mixed refrigerant processes. For these reasons, there is a need to develop a high LNG production capacity FLNG liquefaction process with the advantages of an expander-based process. There is a further need to develop an FLNG technology solution that is better able to handle the challenges that vessel motion has on gas processing. There remains a further need to develop a heavy hydrocarbon removal process better suited for expander based process by eliminating the efficiency and production loss associated with conventional technologies.
U.S. Pat. No. 6,412,302 describes a feed gas expander-based process where two independent closed refrigeration loops are used to cool the feed gas to form LNG. In an embodiment, the first closed refrigeration loop uses the feed gas or components of the feed gas as the refrigerant. Nitrogen gas is used as the refrigerant for the second closed refrigeration loop. This technology requires smaller equipment and topside space than a dual loop nitrogen expander-based process. For example, the volumetric flow rate of the refrigerant into the low pressure compressor can be 20 to 50% smaller for this technology compared to a dual loop nitrogen expander-based process. The technology, however, is still limited to a capacity of less than 1.5 MTA.
U.S. Pat. No. 8,616,012 describes a feed gas expander-based process where feed gas is used as the refrigerant in a closed refrigeration loop. Within this closed refrigeration loop, the refrigerant is compressed to a pressure greater than or equal to 1,500 psia (10,340 kPa), or more preferably greater than 2,500 psia (17,240 kPa). The refrigerant is then cooled and expanded to achieve cryogenic temperatures. This cooled refrigerant is used in a heat exchanger to cool the feed gas from warm temperatures to cryogenic temperatures. A subcooling refrigeration loop is then employed to further cool the feed gas to form LNG. In one embodiment, the subcooling refrigeration loop is a closed loop with flash gas used as the refrigerant. This feed gas expander-based process has the advantage of not being limited to a train capacity range of less than 1 MTA. A train size of approximately 6 MTA has been considered. However, the technology has the disadvantage of an increased equipment count and increased complexity due to its requirement for two independent refrigeration loops and the compression of the feed gas.
GB 2,486,036 describes a feed gas expander-based process that is an open loop refrigeration cycle including a pre-cooling expander loop and a liquefying expander loop, where the gas phase after expansion is used to liquefy the natural gas. According to this document, including a liquefying expander in the process significantly reduces the recycle gas rate and the overall required refrigeration power. This technology has the advantage of being simpler than other technologies since only one type of refrigerant is used with a single compression string. However, the technology is still limited to capacity of less than 1.5 MTA and it requires the use of liquefying expander, which is not standard equipment for LNG production. The technology has also been shown to be less efficient than other technologies for the liquefaction of lean natural gas.
U.S. Pat. No. 7,386,996 describes an expander-based process with a pre-cooling refrigeration process preceding the main expander-based cooling circuit. The pre-cooling refrigeration process includes a carbon dioxide refrigeration circuit in a cascade arrangement. The carbon dioxide refrigeration circuit may cool the feed gas and the refrigerant gases of the main expander-based cooling circuit at three pressure levels: a high pressure level to provide the warm-end cooling; a medium pressure level to provide the intermediate temperature cooling; and a low pressure level to provide cold-end cooling for the carbon dioxide refrigeration circuit. This technology is more efficient and has a higher production capacity than expander-based processes lacking a pre-cooling step. The technology has the additional advantage for FLNG applications since the pre-cooling refrigeration cycle uses carbon dioxide as the refrigerant instead of hydrocarbon refrigerants. The carbon dioxide refrigeration circuit, however, comes at the cost of added complexity to the liquefaction process since an additional refrigerant and a substantial amount of extra equipment is introduced. In an FLNG application, the carbon dioxide refrigeration circuit may be in its own module and sized to provide the pre-cooling for multiple expander-based processes. This arrangement has the disadvantage of requiring a significant amount of pipe connections between the pre-cooling module and the main expander-based process modules. The “LNG-in-a-Box” advantages discussed above are no longer realized.
Thus, there remains a need to develop a pre-cooling process that does not require additional refrigerant and does not introduce a significant amount of extra equipment to the LNG liquefaction process. There is an additional need to develop a pre-cooling process that can be placed in the same module as the liquefaction module. Furthermore, there is an additional need to develop a pre-cooling process that can easily integrate with a heavy hydrocarbon removal process and provide auxiliary cooling upstream of liquefaction. Such a pre-cooling process combined with an SMR process or an expander-based process would be particularly suitable for FLNG applications where topside space and weight significantly impacts the project economics. There remains a specific need to develop an LNG production process with the advantages of an expander-based process and which, in addition, has a high LNG production capacity without to significantly increasing facility footprint. There is a further need to develop an LNG technology solution that is better able to handle the challenges that vessel motion has on gas processing. Such a high capacity expander-based liquefaction process would be particularly suitable for FLNG applications where the inherent safety and simplicity of expander-based liquefaction process are greatly valued.
In the production of LNG, feed gas is required to be conditioned to remove heavy hydrocarbons, such as long-chain alkanes and aromatics, which would freeze under the cryogenic conditions of natural gas liquefaction. For mixed refrigerant (MR) based liquefaction processes, such as propane pre-cooled mixed refrigerant processes or dual MR processes, when mixed refrigerant components such as ethane, propane, and butane must be produced from the feed gas to replace mixed refrigerant lost in the respective refrigerant loop, pre-liquefaction conditioning of the feed gas may involve deep natural gas liquids (NGL) recovery. Such NGL recovery not only removes freezing heavy hydrocarbons but also extracts ethane and liquefied petroleum gas (LPG) to generate mixed refrigerant make-up via a downstream deethanizer, a depropanizer, and/or a debutanizer. However, when mixed refrigerant components can be obtained from other sources, such as existing ethane/propane/butane streams in brownfield expansion projects or external sources where either the logistics are convenient for importation (e.g. gulf coast project) or there is a need to simplify downstream processing (e.g. using FLNG), it would be desirable to minimize slip to a scrub column bottom stream of non-freezing components such as ethane/methane/propane, while targeting the removal of heavy hydrocarbons from the feed stream via said slip to the scrub column bottom stream.
The configuration depicted in
According to disclosed aspects, a method is provided for producing liquefied natural gas (LNG) from a natural gas stream. Heavy hydrocarbons are removed from the natural gas stream in a first separator to thereby generate a separated natural gas stream and a separator bottom stream. The separated natural gas stream is used as a coolant in a heat exchanger to thereby generate a pretreated natural gas stream. The pretreated natural gas stream is compressed and cooled to form a chilled pretreated natural gas stream. A portion of the chilled pretreated gas stream forms a recycle stream to exchange heat with the separated natural gas stream in the heat exchanger, thereby generating a cooled recycle stream. A temperature and a pressure of the cooled recycle stream are reduced. The cooled recycle stream is separated into a gaseous separator overhead stream and a reflux stream. The reflux stream is directed to a top portion of the first separator. The chilled pretreated gas stream is liquefied to form LNG.
An apparatus for the liquefaction of a natural gas stream is also provided. A first heat exchanger cools at least a portion of the natural gas stream to generate a cooled natural gas stream. The portion of the natural gas stream is combined with the natural gas stream. A first separation device removes heavy hydrocarbons from the natural gas stream to thereby generate a separated natural gas stream and a separator bottom stream. The separated natural gas stream is directed to the first heat exchanger to act as a coolant therein, thereby generating a pretreated natural gas stream. A compression and cooling unit compresses and cools the pretreated natural gas stream to form a chilled pretreated stream. A portion of the chilled pretreated gas stream is recycled to the first heat exchanger as a recycle stream to exchange heat with one or more process streams comprising at least one of the portion of the natural gas stream and the separated natural gas stream, thereby generating a cooled recycle stream. A temperature and pressure reducing device reduces the temperature and pressure of the cooled recycle stream. A fourth separation device separates the cooled recycle stream into a gaseous separator overhead stream and a reflux stream. The reflux stream is directed to a top portion of the first separator. At least one liquefaction unit liquefies the chilled pretreated gas stream.
Various specific aspects, embodiments, and versions will now be described, including definitions adopted herein. Those skilled in the art will appreciate that such aspects, embodiments, and versions are exemplary only, and that the invention can be practiced in other ways. Any reference to the “invention” may refer to one or more, but not necessarily all, of the embodiments defined by the claims. The use of headings is for purposes of convenience only and does not limit the scope of the present invention. For purposes of clarity and brevity, similar reference numbers in the several Figures represent similar items, steps, or structures and may not be described in detail in every Figure.
All numerical values within the detailed description and the claims herein are modified by “about” or “approximately” the indicated value, and take into account experimental error and variations that would be expected by a person having ordinary skill in the art.
As used herein, the term “compressor” means a machine that increases the pressure of a gas by the application of work. A “compressor” or “refrigerant compressor” includes any unit, device, or apparatus able to increase the pressure of a gas stream. This includes compressors having a single compression process or step, or compressors having multi-stage compressions or steps, or more particularly multi-stage compressors within a single casing or shell. Reference herein to more than one compressor includes more than one single-stage compressor, one or more multi-stage compressors, and any combination thereof. Evaporated streams to be compressed can be provided to a compressor at different pressures. Some stages or steps of a cooling process may involve two or more compressors in parallel, series, or both. The present invention is not limited by the type or arrangement or layout of the compressor or compressors, particularly in any refrigerant circuit.
As used herein, “cooling” broadly refers to lowering and/or dropping a temperature and/or internal energy of a substance by any suitable, desired, or required amount. Cooling may include a temperature drop of at least about 1° C., at least about 5° C., at least about 10° C., at least about 15° C., at least about 25° C., at least about 35° C., or least about 50° C., or at least about 75° C., or at least about 85° C., or at least about 95° C., or at least about 100° C. The cooling may use any suitable heat sink, such as steam generation, hot water heating, cooling water, air, refrigerant, other process streams (integration), and combinations thereof. One or more sources of cooling may be combined and/or cascaded to reach a desired outlet temperature. The cooling step may use a cooling unit with any suitable device and/or equipment. According to some embodiments, cooling may include indirect heat exchange, such as with one or more heat exchangers. In the alternative, the cooling may use evaporative (heat of vaporization) cooling and/or direct heat exchange, such as a liquid sprayed directly into a process stream.
As used herein, the term “environment” refers to ambient local conditions, e.g., temperatures and pressures, in the vicinity of a process.
As used herein, the term “expansion device” refers to one or more devices suitable for reducing the pressure of a fluid in a line (for example, a liquid stream, a vapor stream, or a multiphase stream containing both liquid and vapor). Unless a particular type of expansion device is specifically stated, the expansion device may be (1) at least partially by isenthalpic means, or (2) may be at least partially by isentropic means, or (3) may be a combination of both isentropic means and isenthalpic means. Suitable devices for isenthalpic expansion of natural gas are known in the art and generally include, but are not limited to, manually or automatically, actuated throttling devices such as, for example, valves, control valves, Joule-Thomson (J-T) valves, or venturi devices. Suitable devices for isentropic expansion of natural gas are known in the art and generally include equipment such as expanders or turbo expanders that extract or derive work from such expansion. Suitable devices for isentropic expansion of liquid streams are known in the art and generally include equipment such as expanders, hydraulic expanders, liquid turbines, or turbo expanders that extract or derive work from such expansion. An example of a combination of both isentropic means and isenthalpic means may be a Joule-Thomson valve and a turbo expander in parallel, which provides the capability of using either alone or using both the J-T valve and the turbo expander simultaneously. Isenthalpic or isentropic expansion can be conducted in the all-liquid phase, all-vapor phase, or mixed phases, and can be conducted to facilitate a phase change from a vapor stream or liquid stream to a multiphase stream (a stream having both vapor and liquid phases) or to a single-phase stream different from its initial phase. In the description of the drawings herein, the reference to more than one expansion device in any drawing does not necessarily mean that each expansion device is the same type or size.
The term “gas” is used interchangeably herein with “vapor,” and is defined as a substance or mixture of substances in the gaseous state as distinguished from the liquid or solid state. Likewise, the term “liquid” means a substance or mixture of substances in the liquid state as distinguished from the gas or solid state.
A “heat exchanger” broadly means any device capable of transferring heat energy or cold energy from one medium to another medium, such as between at least two distinct fluids. Heat exchangers include “direct heat exchangers” and “indirect heat exchangers.” Thus, a heat exchanger may be of any suitable design, such as a co-current or counter-current heat exchanger, an indirect heat exchanger (e.g. a spiral wound heat exchanger or a plate-fin heat exchanger such as a brazed aluminum plate fin type), direct contact heat exchanger, shell-and-tube heat exchanger, spiral, hairpin, core, core-and-kettle, printed-circuit, double-pipe or any other type of known heat exchanger. “Heat exchanger” may also refer to any column, tower, unit or other arrangement adapted to allow the passage of one or more streams therethrough, and to affect direct or indirect heat exchange between one or more lines of refrigerant, and one or more feed streams.
As used herein, the term “heavy hydrocarbons” refers to hydrocarbons having more than four carbon atoms. Principal examples include pentane, hexane and heptane. Other examples include benzene, aromatics, or diamondoids.
As used herein, the term “indirect heat exchange” means the bringing of two fluids into heat exchange relation without any physical contact or intermixing of the fluids with each other. Core-in-kettle heat exchangers and brazed aluminum plate-fin heat exchangers are examples of equipment that facilitate indirect heat exchange.
As used herein, the term “natural gas” refers to a multi-component gas obtained from a crude oil well (associated gas) or from a subterranean gas-bearing formation (non-associated gas). The composition and pressure of natural gas can vary significantly. A typical natural gas stream contains methane (C1) as a significant component. The natural gas stream may also contain ethane (C2), higher molecular weight hydrocarbons, and one or more acid gases. The natural gas may also contain minor amounts of contaminants such as water, nitrogen, iron sulfide, wax, and crude oil.
As used herein, the term “separation device” or “separator” refers to any vessel configured to receive a fluid having at least two constituent elements and configured to produce a gaseous stream out of a top portion and a liquid (or bottoms) stream out of the bottom of the vessel. The separation device/separator may include internal contact-enhancing structures (e.g. packing elements, strippers, weir plates, chimneys, etc.), may include one, two, or more sections (e.g. a stripping section and a reboiler section), and/or may include additional inlets and outlets. Exemplary separation devices/separators include bulk fractionators, stripping columns, phase separators, scrub columns, and others.
As used herein, the term “scrub column” refers to a separation device used for the removal of heavy hydrocarbons from a natural gas stream.
Certain embodiments and features have been described using a set of numerical upper limits and a set of numerical lower limits. It should be appreciated that ranges from any lower limit to any upper limit are contemplated unless otherwise indicated. All numerical values are “about” or “approximately” the indicated value, and take into account experimental error and variations that would be expected by a person having ordinary skill in the art.
All patents, test procedures, and other documents cited in this application are fully incorporated by reference to the extent such disclosure is not inconsistent with this application and for all jurisdictions in which such incorporation is permitted.
Aspects disclosed herein describe a process for pretreating and pre-cooling natural gas to a liquefaction process for the production of LNG by the addition of a high pressure compression and high pressure expansion process prior to liquefying the natural gas. A portion of the compressed and expanded gas is used to cool one or more process streams associated with pretreating the feed gas. More specifically, the invention describes a process where heavy hydrocarbons are removed from a natural gas stream to form a pretreated natural gas stream. The pretreated natural gas is compressed to pressure greater than 1,500 psia (10,340 kPa), or more preferably greater than 3,000 psia (20,680 kPa). The hot compressed gas is cooled by exchanging heat with the environment to form a compressed pretreated gas. The compressed pretreated gas is near-isentropically expanded to a pressure less than 3,000 psia (20,680 kPa), or more preferably to a pressure less than 2,000 psia (13,790 kPa) to form a first chilled pretreated gas, where the pressure of the first chilled pretreated gas is less than the pressure of the compressed pretreated gas. The first chilled pretreated gas is separated into at least one refrigerant stream and a non-refrigerant stream. The at least one refrigerant stream is directed to at least one heat exchanger where it acts to cool a process stream and form a warmed refrigerant stream. The warmed refrigerant stream is mixed with the non-refrigerant stream to form a second chilled pretreated gas. The second chilled pretreated gas may be directed to one or more SMR liquefaction trains, or the second chilled pretreated gas may be directed to one or more expander-based liquefaction trains where the gas is further cooled to form LNG.
The HPCE process module 212 may comprise a first compressor 213 which compresses the pretreated natural gas stream 210 to form an intermediate pressure gas stream 214. The intermediate pressure gas stream 214 may flow through a second heat exchanger 215 where the intermediate pressure gas stream 214 is cooled by indirectly exchanging heat with the environment to form a cooled intermediate pressure gas stream 216. The second heat exchanger 215 may be an air cooled heat exchanger or a water cooled heat exchanger. The cooled intermediate pressure gas stream 216 may then be compressed within a second compressor 217 to form a high pressure gas stream 218. The pressure of the high pressure gas stream 218 may be greater than 1,500 psia (10,340 kPa), or more preferably greater than 3,000 psia (20,680 kPa). The high pressure gas stream 218 may flow through a third heat exchanger 219 where the high pressure gas stream 218 is cooled by indirectly exchanging heat with the environment to form a cooled high pressure gas stream 220. The third heat exchanger 219 may be an air cooled heat exchanger or a water cooled heat exchanger. The cooled high pressure gas stream 220 may then be expanded within an expander 221 to form a first chilled pretreated gas stream 222. The pressure of the first chilled pretreated gas stream 222 may be less than 3,000 psia (20,680 kPa), or more preferably less than 2,000 psia (13,790 kPa), and the pressure of the first chilled pretreated gas stream 222 is less than the pressure of the cooled high pressure gas stream 220. In a preferred aspect, the second compressor 217 may be driven solely by the shaft power produced by the expander 221, as indicated by the dashed line 223. The first chilled pretreated gas stream 222 may be separated into a refrigerant stream 224 and a non-refrigerant stream 225. The refrigerant stream 224 may flow through the first heat exchanger 205 where the refrigerant stream 224 is partially warmed by indirectly exchanging heat with the column overhead stream 203, thereby forming a warmed refrigerant stream 226. The warmed refrigerant stream 226 may mix with the non-refrigerant stream 225 to form a second chilled pretreated gas stream 227. The second chilled pretreated gas stream 227 may then be liquefied in, for example, an SMR liquefaction train 240 through indirect heat exchange with an SMR refrigerant loop 228 in a fourth heat exchanger 229. The resultant LNG stream 230 may then be stored and/or transported as needed.
It should be noted that the refrigerant stream 224 may be used to cool or chill any of the process streams associated with the pretreatment apparatus 200. For example, one or more of the column overhead stream 203, the two-phase stream 206, the cold pretreated gas stream 208, the liquid stream 209, and the pretreated natural gas stream 210 may be configured to exchange heat with the refrigerant stream 224. Furthermore, other process streams not associated with the pretreatment apparatus 200 may be cooled through heat exchange with the refrigerant stream 224. The refrigerant stream 224 may be split into two or more sub-streams that are used to cool various process streams.
In an aspect, the SMR liquefaction process may be enhanced by the addition of the HPCE process upstream of the SMR liquefaction process. More specifically, in this aspect, pretreated natural gas may be compressed to a pressure greater than 1,500 psia (10,340 kPa), or more preferably greater than 3,000 psia (20,680 kPa). The hot compressed gas is then cooled by exchanging heat with the environment to form a compressed pretreated gas. The compressed pretreated gas is then near-isentropically expanded to pressure less than 3,000 psia (20,680 kPa), or more preferably to a pressure less than 2,000 psia (13,790 kPa) to form a first chilled pretreated gas, where the pressure of the first chilled pretreated gas is less than the pressure of the compressed pretreated gas. The first chilled pretreated gas stream is separated into a refrigerant stream and a non-refrigerant stream. The refrigerant stream is warmed by exchanging heat with a column overhead stream in order to help partially condense the column overhead stream and produce a warmed refrigerant stream. The warmed refrigerant stream is mixed with the non-refrigerant stream to produce a second chilled pretreated gas. The second chilled pretreated gas may then be directed to multiple SMR liquefaction trains, arranged in parallel, where the chilled pretreated gas is further cooled therein to form LNG.
The combination of the HPCE process with pretreatment of the natural gas and liquefaction within multiple SMR liquefaction trains has several advantages over the conventional SMR process where natural gas is sent directly to the SMR liquefaction trains for both heavy hydrocarbon removal (final pretreatment step) and liquefaction. For example, the pre-cooling of the natural gas using the HPCE process allows for an increase in LNG production rate within the SMR liquefaction trains for a given horsepower within the SMR liquefaction trains.
In contrast,
The disclosed HPCE module comprises a single scrub column used to remove the heavy hydrocarbons from the natural gas that is then fed to all the liquefaction trains. This design increases the required power of the HPCE module by 10 to 15% compared to a design where heavy hydrocarbon removal is not included. However, integrating the heavy hydrocarbon removal within the HPCE module instead of within each SMR liquefaction train reduces the weight of each SMR liquefaction train and may result in a total reduction in equipment count and overall topside weight of an FLNG system. Another advantage is that the liquefaction pressure can be greater than the cricondenbar of the feed gas, which results in increased liquefaction efficiency. Furthermore, the proposed design is more flexible to feed gas changes than the integrated scrub column design.
Another advantage of the disclosed HPCE module is that the required storage of refrigerant is reduced since the number of SMR liquefaction trains has been reduced by one. Also, since a large fraction of the warm temperature cooling of the gas occurs in the HPCE module, the heavier hydrocarbon components of the mixed refrigerant can be reduced. For example, the propane component of the mixed refrigerant may be eliminated without any significant reduction in efficiency of the SMR liquefaction process.
Another advantage is that for a SMR liquefaction process which receives chilled pretreated gas from the disclosed HPCE module, the volumetric flow rate of the vaporized refrigerant of the SMR liquefaction process can be more than 25% less than that of a conventional SMR liquefaction process receiving warm pretreated gas. The lower volumetric flow of refrigerant may reduce the size of the main cryogenic heat exchanger and the size of the low pressure mixed refrigerant compressor. The lower volumetric flow rate of the refrigerant is due to its higher vaporizing pressure compared to that of a conventional SMR liquefaction process.
Known propane-precooled mixed refrigeration processes and dual mixed refrigeration (DMR) processes may be viewed as versions of an SMR liquefaction process combined with a pre-cooling refrigeration circuit, but there are significant differences between such processes and aspects of the present disclosure. For example, the known processes use a cascading propane refrigeration circuit or a warm-end mixed refrigerant to pre-cool the gas. Both these known processes have the advantage of providing 5% to 15% higher efficiency than the SMR liquefaction process. Furthermore, the capacity of a single liquefaction train using these known processes can be significantly greater than that of a single SMR liquefaction train. The pre-cooling refrigeration circuit of these technologies, however, comes at the cost of added complexity to the liquefaction process since additional refrigerants and a substantial amount of extra equipment is introduced. For example, the DMR liquefaction process's disadvantage of higher complexity and weight may outweigh its advantages of higher efficiency and capacity when deciding between a DMR liquefaction process and an SMR liquefaction process for an FLNG application. The known processes have considered the addition of a pre-cooling process upstream of the SMR liquefaction process as being driven principally by the need for higher thermal efficiencies and higher LNG production capacity for a single liquefaction train. The disclosed HPCE process combined with the SMR liquefaction process has not been realized previously because it does not provide the higher thermal efficiencies that the refrigerant-based pre-cooling process provides. As described herein, the thermal efficiency of the HPCE process with the SMR liquefaction is about the same as a standalone SMR liquefaction process. The disclosed aspects are believed to be novel based at least in part on its description of a pre-cooling process that aims to reduce the weight and complexity of the liquefaction process rather than increase thermal efficiency, which in the past has been the biggest driver for the addition of a pre-cooling process for onshore LNG applications. As an additional point, the integrated scrub column design is traditionally seen as the lowest cost option for heavy hydrocarbon removal of natural gas to liquefaction. However, the integration of heavy hydrocarbon removal with a HPCE process, as disclosed herein, provides a previously unrealized advantage of potentially reducing total equipment count and weight when multiple liquefaction trains is the preferred design methodology. For the newer applications of FLNG and remote onshore application, footprint, weight, and complexity of the liquefaction process may be a bigger driver of project cost. Therefore the disclosed aspects are of particular value.
In an aspect, an expander-based liquefaction process may be enhanced by the addition of an HPCE process upstream of the expander-based process. More specifically, in this aspect, a pretreated natural gas stream may be compressed to pressure greater than 1,500 psia (10,340 kPa), or more preferably greater than 3,000 psia (20,680 kPa). The hot compressed gas may then be cooled by exchanging heat with the environment to form a compressed pretreated gas. The compressed pretreated gas may be near-isentropically expanded to a pressure less than 3,000 psia (20,680 kPa), or more preferably to a pressure less than 2,000 psia (13,790 kPa) to form a first chilled pretreated gas, where the pressure of the first chilled pretreated gas is less than the pressure of the compressed pretreated gas. The first chilled pretreated gas stream is separated into refrigerant stream and a non-refrigerant stream. The refrigerant stream is warmed by exchanging heat with a column overhead stream in order to help partially condense the column overhead stream and produce a warmed refrigerant stream. The warmed refrigerant stream is mixed with the non-refrigerant stream to produce a second chilled pretreated gas. The second chilled pretreated gas is directed to an expander-based process where the gas is further cooled to form LNG. In a preferred aspect, the second chilled pretreated gas may be directed to a feed gas expander-based process.
One proposed method to eliminate the warm temperature pinch-point 510 is to pre-cool the feed gas with an external refrigeration system such as a propane cooling system or a carbon dioxide cooling system. For example, U.S. Pat. No. 7,386,996 eliminates the warm temperature pinch-point by using a pre-cooling refrigeration process comprising a carbon dioxide refrigeration circuit in a cascade arrangement. This external pre-cooling refrigeration system has the disadvantage of significantly increasing the complexity of the liquefaction process since an additional refrigerant system with all its associated equipment is introduced. Aspects disclosed herein reduce the impact of the warm temperature pinch-point 510 by pre-cooling the feed gas stream by compressing the feed gas to a pressure greater than 1,500 psia (10,340 kPa), cooling the compressed feed gas stream, and expanding the compressed gas stream to a pressure less than 2,000 psia (20,690 kPa), where the expanded pressure of the feed gas stream is less than the compressed pressure of the feed gas stream. This process of cooling the feed gas stream results in a significant reduction in the in the required mass flow rate of the expander-based process cooling streams. It also improves the thermodynamic efficiency of the expander-based process without significantly increasing the equipment count and without the addition of an external refrigerant. This process may also be integrated with heavy hydrocarbon removal in order to remove the heavy hydrocarbon upstream of the liquefaction process. Since the gas is now free of heavy hydrocarbons that would form solids, the pretreated gas can be liquefied at a pressure above its cricondenbar in order to improve liquefaction efficiency.
In a preferred aspect, the expander-based process may be a feed gas expander-based process. This feed gas expander process comprises a first closed expander-based refrigeration loop and a second closed expander-based refrigeration loop. The first expander-based refrigeration loop may be principally charged with methane from a feed gas stream. The first expander-based refrigeration loop liquefies the feed gas stream. The second expander-based refrigeration loop may be charged with nitrogen as the refrigerant. The second expander-based to refrigeration loop sub-cools the LNG streams. Specifically, a produced natural gas stream may be treated to remove impurities, if present, such as water, and sour gases, to make the natural gas suitable for cryogenic treatment. The treated natural gas stream may be directed to a scrub column where the treated natural gas stream is separated into a column overhead stream and a column bottom stream. The column overhead stream may be partially condensed within a first heat exchanger by indirectly exchanging heat with a cold pretreated gas stream and a refrigerant stream to thereby form a two phase stream. The two phase stream may be directed to a separator where the two phase stream is separated into the cold pretreated gas stream and a liquid stream. The cold pretreated gas stream may be warmed within the first heat exchanger by exchanging heat with the column overhead stream to form a pretreated natural gas stream. The liquid stream may be pressurized within a pump and then directed to the scrub column to provide reflux to the scrub column. The pretreated natural gas stream may be directed to an HPCE process as disclosed herein, where it is compressed to a pressure greater than 1,500 psia (10,340 kPa), or more preferably greater than 3,000 psia (20,680 kPa). The hot compressed gas stream may then be cooled by exchanging heat with the environment to form a compressed treated natural gas stream. The compressed treated natural gas stream may be near-isentropically expanded to a pressure less than 3,000 psia (20,680 kPa), or more preferably to a pressure less than 2,000 psia (12,790 kPa) to form a first chilled treated natural gas stream, where the pressure of the first chilled treated natural gas stream is less than the pressure of the compressed treated natural gas stream. The first chilled natural gas stream may be separated into the refrigerant stream and a non-refrigerant stream. The refrigerant stream may be partially warmed within the first heat exchanger by exchanging heat with the column overhead stream to form a warmed refrigerant stream. The warmed refrigerant stream may mix with the non-refrigerant stream to form a second chilled natural gas stream. The second chilled treated natural gas may be directed to the feed gas expander process where the first expander-based refrigeration loop acts to liquefy the second chilled treated natural gas to form a pressurized LNG stream. The second expander refrigeration loop then acts to subcool the pressurized LNG stream. The subcooled pressurized LNG stream may then be expanded to a lower pressure in order to form an LNG stream.
The combination of the HPCE process with pretreatment of the natural gas and liquefaction of the pretreated gas within an expander-based process has several advantages over a conventional expander-based process. Including the HPCE process therewith may increase the efficiency of the expander-based process by 5 to 25% depending of the type of expander-based process employed. The feed gas expander process described herein may have a liquefaction efficiency similar to that of an SMR process while still providing the advantages of no external refrigerant use, ease of operation, and reduced equipment count. Furthermore, the refrigerant flow rates and the size of the recycle compressors are expected to be significantly lower for the expander-base process combined with the HPCE process. For these reasons, the production capacity of a single liquefaction train according to disclosed aspects may be greater than 30 to 50% above the production capacity of a similarly sized conventional expander-based liquefaction process. The combination of HPCE process with heavy hydrocarbon removal upstream of an expander-based liquefaction process has the additional benefit of providing the option to liquefy the gas at pressures above its cricondenbar to improve liquefaction efficiency. Expander-based liquefaction processes are particularly sensitive to liquefaction pressures. Therefore, the HPCE process described herein is well suited for removing heavy hydrocarbons while also increasing the liquefaction efficiency and production capacity of expander-based liquefaction processes.
As illustrated in
The second warm refrigerant stream 746 is compressed in one or more compression units 750, 752 to a pressure greater than 1,500 psia, or more preferably, to a pressure of approximately 3,000 psia, to thereby form a compressed refrigerant stream 754. The compressed refrigerant stream 754 is then cooled against an ambient cooling medium (air or water) in a cooler 756 to produce the compressed, cooled refrigerant stream 744. The compressed, additionally cooled refrigerant stream 748 is near isentropically expanded in an expander 758 to produce the expanded, cooled refrigerant stream 736. The expander 758 may be a work expansion device, such as a gas expander, which produces work that may be extracted and used for compression.
The first heat exchanger zone 738 may include a plurality of heat exchanger devices, and in the aspects shown in
Within the sub-cooling loop 734, an expanded sub-cooling refrigerant stream 764 (preferably comprising nitrogen) is discharged from an expander 766 and drawn through the sub-cooling heat exchanger 762 and the main heat exchanger 760. The expanded sub-cooling refrigerant stream 764 is then sent to a compression unit 768 where it is re-compressed to a higher pressure and warmed. After exiting compression unit 768, the resulting recompressed sub-cooling refrigerant stream 770 is cooled in a cooler 772. After cooling, the recompressed to sub-cooling refrigerant stream 770 is passed through the main heat exchanger 760 where it is further cooled by indirect heat exchange with the expanded, cooled refrigerant stream 736 and the expanded sub-cooling refrigerant stream 764. After exiting the first heat exchanger area 738, the re-compressed and cooled sub-cooling refrigerant stream is expanded through the expander 766 to provide the expanded sub-cooling refrigerant stream 764 that is re-cycled through the first heat exchanger zone as described herein. In this manner, the second chilled pretreated gas stream 727 is further cooled, liquefied and sub-cooled in the first heat exchanger zone 738 to produce a sub-cooled gas stream 774. The sub-cooled gas stream 774 may be expanded to a lower pressure to produce the LNG stream (not shown).
The column overhead stream 1114 flows through first heat exchanger 1106, thereby forming a pretreated natural gas stream 1140. Prior to flowing through the first heat exchanger 1106, the pressure and temperature of the column overhead stream 1114 may be reduced using a pressure-reducing device such as a Joule-Thomson valve 1142. The pretreated natural gas stream 1140 is sent to a compression and cooling unit, which in an aspect may comprise a high pressure compression and expansion (HPCE) process module 1150. The HPCE process module 1150 may comprise a first compressor 1152 which compresses the pretreated natural gas stream 1140 to form an intermediate pressure gas stream 1154. The intermediate pressure gas stream 1154 may flow through a second heat exchanger (not shown) where the intermediate pressure gas stream 1154 is cooled by indirectly exchanging heat with an ambient environment. The second heat exchanger may be an air cooled heat exchanger or a water cooled heat exchanger. The intermediate pressure gas stream 1154 may then be compressed within a second compressor 1156 to form a high pressure gas stream 1158. The pressure of the high pressure gas stream 1158 may be greater than 1,500 psia (10,340 kPa), or more preferably greater than 3,000 psia (20,680 kPa). The high pressure gas stream 1158 may flow through a third heat exchanger 1160 where the high pressure gas stream 1158 is cooled by indirectly exchanging heat with an ambient environment, thereby forming a cooled high pressure gas stream 1162. The third heat exchanger 1160 may be an air cooled heat exchanger or a water cooled heat exchanger. The cooled high pressure gas stream 1162 may then be expanded within an expander 1164 to form a chilled pretreated gas stream 1166. Chilled pretreated gas stream 1166 may also be referred to herein as a cooled pretreated gas stream. The pressure of the chilled pretreated gas stream 1166 may be less than 3,000 psia (20,680 kPa), or more preferably less than 2,000 psia (13,790 kPa), and the pressure of the chilled pretreated gas stream 1166 is less than the pressure of the cooled high pressure gas stream 1162. In a preferred aspect, the second compressor 1156 may be driven solely by shaft power produced by the expander 1164. In other disclosed aspects, including those aspects in which the HPCE process module 1150 includes only one compressor, the expander 1164 may be connected to a generator (not shown) to generate power.
A portion of the chilled pretreated gas stream 1166 is directed to the first heat exchanger 1106 as a recycle stream 1168, where it and side stream 1104 are cooled by column overhead stream 1114 and/or a gaseous separator drum overhead stream 1176 as described below. The resulting cooled recycle stream 1170 passes through a pressure and temperature reducing device, such as a Joule-Thomson valve 1172, and is directed Into a separator drum 1174. The separator drum separates the cooled recycle stream 1170 into the gaseous separator drum overhead stream 1176 and a scrub column reflux stream 1178. Gaseous separator drum overhead stream 1176 may be combined with the column overhead stream 1114 (i.e., upstream of the first heat exchanger). Alternatively, the gaseous separator drum overhead stream 1176 may be combined with the pretreated natural gas stream 1140 (i.e., downstream of the first heat exchanger), such that the gaseous separator drum overhead stream 1176 passes through the first heat exchanger 1106 as a separate stream from the column overhead stream 1114. This alternative scenario may provide more flexibility in matching cooling curves within the first heat exchanger 1106, while passing the combined two streams through the first heat exchanger 1106 reduces complexity of the system. The scrub column reflux stream 1178 is directed to a top portion of the scrub column 1112, where it provides sufficient cooling to liquefy and separate heavy hydrocarbons within the scrub column 1112. The remainder of the chilled pretreated gas stream 1166 is directed to further processing, which in a preferred aspect is a natural gas liquefaction module 1180. The liquefaction module 1180 may employ any type of liquefaction technology to produce LNG stream 1182, such as single mixed refrigerant (SMR), dual mixed refrigerant (DMR), expander-based technologies using nitrogen and/or methane, or other liquefaction techniques. Such liquefaction techniques are considered to be within the scope of the disclosed aspects.
The column overhead stream 1214 flows through first heat exchanger 1206, thereby forming a pretreated natural gas stream 1240. The pretreated natural gas stream 1240 is sent to a feed compressor 1252 which compresses the pretreated natural gas stream 1240 to form an intermediate pressure gas stream 1254. The intermediate pressure gas stream 1254 may flow through a second heat exchanger 1255 where the intermediate pressure gas stream 1254 is cooled by indirectly exchanging heat with an ambient environment, thereby forming a chilled or cooled pretreated gas stream 1266. The second heat exchanger may be an air cooled heat exchanger or a water cooled heat exchanger. The pressure of the cooled pretreated gas stream 1266 may be less than 3,000 psia (20,680 kPa), or more preferably less than 2,000 psia (13,790 kPa).
A portion of the cooled pretreated gas stream 1266 is directed to the first heat exchanger 1206 as a recycle stream 1268, where it and the natural gas stream are cooled by the column overhead stream 1214 and/or a gaseous separator drum overhead stream 1276 as described below. The resulting cooled recycle stream 1270 passes through a pressure and temperature reducing device, such as a Joule-Thomson valve 1272, and is directed into a separator drum 1274. The separator drum 1274 separates the cooled recycle stream 1270 into the gaseous separator drum overhead stream 1276 and a scrub column reflux stream 1278. Gaseous separator drum overhead stream 1276 may be combined with the column overhead stream 1214 (i.e., upstream of the first heat exchanger 1206) Alternatively, as depicted in
The aspects disclosed in
An advantage of the gas pretreatment process of the disclosed aspects is that it is more applicable to a wide range of feed gas compositions.
Another advantage is that because of the enhanced heavy hydrocarbons recovery from the stabilizer 1118/1218, the condensate stream at 1122/1222 is greater. This enables a processor to take advantage of favorable price or demand conditions for condensate sale. Therefore, the disclosed aspects provide a flexible approach to gas processing to be responsive to changes in commodity price and demand.
Additionally, the aspects disclosed herein can be used in any LNG liquefaction location, they have especial utility in circumstances where space is at a premium for LNG liquefaction, such as offshore liquefaction, onshore remote facilities, and the like.
While the foregoing is directed to aspects of the present disclosure, other and further aspects of the disclosure may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.
This application claims the priority benefit of United States Provisional Patent Application No. 62/902,455, filed Sep. 19, 2019, entitled PRETREATMENT, PRE-COOLING, AND CONDENSATE RECOVERY OF NATURAL GAS BY HIGH PRESSURE COMPRESSION AND EXPANSION. This application is related to the following: United States Non-Provisional patent application Ser. No. 16/410,607, filed May 13, 2019, titled PRETREATMENT AND PRE-COOLING OF NATURAL GAS BY HIGH PRESSURE COMPRESSION AND EXPANSION, which claims the priority benefit of U.S. Provisional Patent Application No. 62/681,938 filed Jun. 7, 2018, titled PRETREATMENT AND PRE-COOLING OF NATURAL GAS BY HIGH PRESSURE COMPRESSION AND EXPANSION; U.S. Non-Provisional patent application Ser. No. 15/348,533, filed Nov. 10, 2016, titled PRE-COOLING OF NATURAL GAS BY HIGH PRESSURE COMPRESSION AND EXPANSION; U.S. Provisional Patent No. 62/902,460 (2019EM397), filed on an even date herewith, titled PRETREATMENT AND PRE-COOLING OF NATURAL GAS BY HIGH PRESSURE COMPRESSION AND EXPANSION; and U.S. Provisional Patent No. 62/902,459 (2019EM396), filed on an even date herewith, titled PRETREATMENT AND PRE-COOLING OF NATURAL GAS BY HIGH PRESSURE COMPRESSION AND EXPANSION, the entirety of all of which are incorporated by reference herein.
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| Number | Date | Country | |
|---|---|---|---|
| 20210088274 A1 | Mar 2021 | US |
| Number | Date | Country | |
|---|---|---|---|
| 62902455 | Sep 2019 | US |
