Liquid natural gas regasification processes and systems

Abstract

Liquid natural gas (LNG) regasification systems and processes. In one example an LNG regasification process includes separating an LNG feed stream into a first rich LNG stream and a second rich LNG stream. The first rich LNG stream may be heated to an at least partially vaporized state and introduced into an absorber, with first and second reflux flows also introduced into the absorber. An overhead stream may be collected from the absorber that is a lean LNG enriched in methane and reduced in ethane relative to an LNG feed stream. The first reflux flow may be the second rich LNG stream, and the second reflux flow may be recycled lean LNG.

Description

GAZ0028-WO-PCTLIQUID NATURAL GAS REGASIFICATION PROCESSES AND SYSTEMSTechnical Field

[0001] Liquid natural gas (LNG) regasification processes and systems. More particularly although not necessarily exclusively LNG regasification processes and systems using an absorber and a demethanizer to separate methane from ethane and other heavier hydrocarbons.Background

[0002] Natural gas can be transported and stored as LNG, such as for long distance transportation and / or when a pipeline is not a viable option for transportation. Cooling natural gas down to a temperature in the range of approximately -155 °C to -170 °C condenses it into LNG and reduces its volume approximately 600 fold from its gaseous state.

[0003] Regasification is the process of converting LNG back to its gaseous state. Regasification systems and processes are typically located at an import terminal where an LNG carrier (a tank ship designed for transporting LNG) unloads the LNG for regasification.Summary

[0004] In one example a liquid natural gas (LNG) regasification process includes separating an LNG feed stream into a first rich LNG stream and a second rich LNG stream. The LNG feed stream, the first rich LNG stream, and the second rich LNG stream each include a mixture of at least methane and ethane. The process further includes heating the first rich LNG stream to an at least partially vaporized state. The first rich LNG stream in the at least partially vaporized state is introduced into an absorber. A first reflux flow in a liquid state is also introduced into the absorber,GAZ0028-WO-PCTthe first reflux flow is the second rich LNG stream. A second reflux flow is also introduced in a liquid state into the absorber. An overhead stream is collected from the absorber, the overhead stream including a lean LNG enriched in methane and reduced in ethane relative to the LNG feed stream. The lean LNG is used as the second reflux flow.Brief Description of Figures

[0005] FIG. 1 shows a schematic example of an LNG regasification system.

[0006] FIG. 2 shows an example of an LNG regasification process.Detailed Description

[0007] An aspect of the disclosed systems and methods is a realization that, as part of LNG regasification, it may be desirable to separate methane in the LNG from other components of the LNG. For instance, LNG arriving at an import terminal is typically composed primarily of methane (e.g. approximately 80-95 vol%) but also includes heavier hydrocarbons such as ethane, propane, and butane. This mixture of methane with heavier hydrocarbons may be characterized as "rich" LNG.

[0008] Aspects of this disclosure therefore include an LNG regasification process that separates rich LNG into a lean LNG and an NGL. More particularly, in at least some examples, the LNG regasification process may use a dual-reflux absorber in combination with a demethanizer to separate rich LNG into a lean LNG and an NGL.

[0009] As part of the disclosed regasification processes the ethane and other heavier hydrocarbons may be separated from the methane, resulting in at least two streams. For example, the regasification process may produce a first stream of "lean" LNG that is enriched in methane and reduced in ethane and other heavier hydrocarbons relative to the rich LNG and a secondGAZ0028-WO-PCTstream of natural gas liquid ("NGL") that is enriched in ethane and other heavier hydrocarbons and reduced in methane relative to the rich LNG. In examples, the lean LNG stream may be, for instance, at least 95 vol%, at least 97 vol%, or at least 99 vol% methane, and the NGL stream may be, for instance, less than 5 vol%, less than 3 vol%, or less than 1 vol% of methane.

[0010] In an example, a rich LNG feed stream (e.g. rich LNG that has been off-loaded at an import terminal or withdrawn from a storage tank) is separated into a first rich LNG stream and a second rich LNG stream. The first rich LNG stream is heated to an at least partially vaporized state by a heat exchanger and introduced in the at least partially vaporized state into an absorber. The second rich LNG stream is introduced in a liquid state as a first reflux flow into the absorber. A lean LNG stream is also introduced in a liquid state as a second reflux into the absorber.

[0011] In some instances, the absorber may be a column. As vapors from the at least partially vaporized first rich LNG stream rise in the column, the first and second reflux flows may absorb at least some of the ethane and other heavier hydrocarbons from the vapor as the reflux flows descend to the bottom of the column, with at least some of the methane in the vapor continuing to rise in the column. An overhead stream and a bottom stream may be collected from the absorber. In some implementations the overhead stream may be a stream collected from the top or a relatively higher location of the absorber and the bottom stream may be a stream collected from the bottom or a relatively lower location of the absorber. In some particular examples, the overhead stream may be mainly methane (e.g. at least 99 vol% methane, at least 99.5 vol% methane, or at least 99.9 vol% methane) and a small amount of ethane (e.g. less than 1 vol% ethane, less than 0.5 vol% ethane, or less than 0.1 vol% ethane). In these or other particular examples, the bottom stream may be mainly ethane and heavier hydrocarbons (e.g. atGAZ0028-WO-PCTleast 99 vol% ethane and heavier hydrocarbons, at least 99.5 vol% ethane and heavier hydrocarbons, at least 99.85 vol% ethane and heavier hydrocarbons) with a small amount of methane (e.g. less than 1 vol% methane, less than 0.5 vol% methane, or less than 0.15 vol% methane). The dual reflux absorber may produce an overhead stream that is a lean LNG enriched in methane and reduced in ethane and other heavier hydrocarbons. The dual reflux absorber may also product a bottom stream enriched in ethane and other heavier hydrocarbons and reduced in methane.

[0012] Continuing with this illustrative example, the bottom stream from the absorber may be subsequently introduced into a demethanizer. The demethanizer may be a second column. In the demethanizer the heated bottom stream from the absorber results in a vapor rising to the top of the demethanizer column that is enriched in methane and reduced in ethane and other heavier hydrocarbons relative to the bottom stream from the absorber. An overhead stream and a bottom stream may be collected from the demethanizer. The overhead stream from the demethanizer may be a lean LNG enriched in methane and reduced in ethane and other heavier hydrocarbons and may be combined with the overhead stream collected from the absorber. The bottom stream from the demethanizer may be an NGL enriched in ethane and other heavier hydrocarbons and reduced in methane relative to the bottom stream from the absorber.

[0013] The heat exchanger that is used to at least partially vaporize the first rich LNG stream of the LNG feed stream may also be used to cool the overhead streams from the absorber and demethanizer. A part of the cooled overhead streams from the absorber and demethanizer may be recycled back to the absorber as the second lean LNG reflux flow.GAZ0028-WO-PCT

[0014] The use of an absorber with first and second reflux flows in the above example may provide for enhanced recovery of ethane and other heavier hydrocarbons from the LNG feed stream. In some implementations the LNG regasification processes and systems using such a dualreflux flow absorber may provide for at least 97+ vol%, at least 98+ vol%, or at least 99+ vol% recovery of ethane and other heavier hydrocarbons from the LNG feed stream into the bottom stream collected from the demethanizer. In some implementations the use of the second rich LNG stream of the LNG feed stream as a first reflux flow in addition to the lean LNG as a second reflux flow provides for greater separation of methane from the ethane and heavier hydrocarbons in the absorber than would be provided by use of the lean LNG as a single reflux flow alone.

[0015] The use of an absorber with first and second reflux flows in the above example may also provide for greater process efficiency and reduced power requirements, with the use of the second rich LNG stream as the first reflux flow reducing the amount of lean LNG that is required to be recycled for the second reflux flow.

[0016] In some implementations the LNG regasification processes and systems may be operable in multiple operating states. For instance, in a first operating state the lean LNG may be delivered to a sendout pipeline, in a second operating state the lean LNG may be delivered to a holding tank, and in a third operating state the lean LNG may be delivered to both the sendout pipeline and the holding tank, thereby providing for flexibility in how the lean LNG is utilized depending on current pipeline demand for lean LNG product. For instance, when pipeline demand is relatively low, more lean LNG may be delivered to the holding tank and less lean LNG may be delivered to the sendout pipeline, and when pipeline demand is relatively high, more leanGAZ0028-WO-PCTLNG may be delivered to the sendout pipeline and less lean LNG may be delivered to the holding tank.

[0017] In some implementations the LNG regasification processes and systems may be configured for additional efficiencies. For instance, when in the first operating state in which the lean LNG is delivered to a sendout pipeline, the heat exchanger used to heat the first rich LNG stream of the LNG feed stream and to cool the overhead streams from the absorber and the demethanizer may also be used to heat an LNG sendout stream of the lean LNG being delivered to the sendout pipeline using the heat from the overhead streams. As such, refrigeration in the lean LNG in the sendout stream may be recovered (e.g. used to cool the overhead streams from the absorber and demethanizer) before being delivered to the sendout pipeline. In some implementations a vaporizer downstream of the heat exchanger vaporizes the lean LNG sendout stream. In such implementations, by first passing the sendout stream through the heat exchanger, the efficiency and send out capacity of the vaporizer may be improved due to the pre-heating performed by the heat exchanger prior to vaporization.

[0018] As another example, when in the second operating state, the lean LNG being delivered to the holding tank may be expanded in a liquid expander before delivery to the holding tank. The liquid expander may recover power from the lean LNG before being delivered to the holding tank, with the recovered power being used for the regasification system or exported for other uses. In some implementations the use of the liquid expander may also reduce boil off gas from the holding tank.GAZ0028-WO-PCT

[0019] FIG. 1 is a schematic illustration of one example of an LNG regasification system. In this example the system includes an absorber 102 that is arranged to receive a first rich LNG stream 106 of an LNG feed stream 108 at a first inlet 104 of the absorber 102. The absorber 102 is also arranged to receive a first reflux flow of a second rich LNG stream 112 of the LNG feed stream 108 at a second inlet 110 of the absorber 102. The absorber 102 is also arranged to receive a second reflux flow of lean LNG stream 240 at a third inlet 114 of the absorber 102. The absorber 102 receives the first rich LNG stream 106 in an at least partially vaporized state and the two reflux flows in liquid states. In some implementations as partially vaporized state may be present when the vapor fraction of the stream is greater than 0% and the stream is heated above the saturation condition and less than 100% (which would be fully vaporized). The absorber 102 in this example is operable to output at an overhead outlet 116 an overhead stream 118 enriched in methane and reduced in ethane relative to the LNG feed stream 108. The absorber 102 in this example is operable to output at a bottom outlet 120 a bottom stream 122 enriched in ethane and reduced in methane relative to the LNG feed stream 108. The use of the absorber 102 with first and second reflux flows in this example may provide for enhanced recovery of ethane and other heavier hydrocarbons from the LNG feed stream 108. In some implementations the use of the second rich LNG stream 112 of the LNG feed stream 108 as a first reflux flow in addition to a second lean LNG stream 240 as reflux flow provides for greater separation of methane from the ethane and heavier hydrocarbons in the absorber 102 than would be provided by use of a single lean LNG stream as reflux flow alone. In some implementations the use of the absorber 102 with first and second reflux flows may also provide for greater process efficiency and reduced powerGAZ0028-WO-PCTrequirements, with the use of the second rich LNG stream 112 as the first reflux flow reducing the amount of lean LNG (discussed further below) that is required to be recycled for the second reflux flow.LNG Feed Stream

[0020] In the example of FIG. 1 LNG feed stream 108 enters the system at inlet 124. LNG feed stream 108 may be a rich LNG feed stream composed primarily of methane (e.g. approximately 80-95 vol% methane) but also including heavier hydrocarbons such as ethane (e.g. approximately 2-12 vol% ethane), propane (e.g. approximately 1-4 vol% propane), and butane and heavier hydrocarbons (e.g. approximately 0-1 vol% butane and heavier hydrocarbons in total). LNG feed stream 108 may also include nitrogen in small amounts (e.g. 0-3 vol% nitrogen). The composition and relative percentages of the components of the LNG feed stream 108 may vary based or region in which the LNG originated, based on how the LNG was collected, and / or based on how the LNG was processed prior to being received in the LNG regasification system. LNG feed stream 108 may be a mixture of at least methane and ethane. The LNG feed stream 108 may come directly from an LNG carrier (e.g. a shipping vessel) arriving at an import facility, from temporary storage tanks at the import facility, or may be delivered to the regasification system in other manners. The LNG feed stream 108 may be in a liquid state.

[0021] LNG feed stream 108 is fed from inlet 124 to pump 126. From pump 126 LNG feed stream 108 is separated into first rich LNG stream 101 and second rich LNG stream 112. In some implementations most of the LNG feed stream 108 is directed into first rich LNG stream 101 with the remainder of the LNG feed stream 108 directed into second rich LNG stream 112 (e.g. at least 60 vol%, at least 70 vol%, at least 80 vol%, at least 90 vol%, or at least 95 vol% of LNG feed streamGAZ0028-WO-PCT108 is directed into first rich LNG stream 101). In the example shown in FIG. 1, the relative amount of flow directed into the first and second rich LNG streams 101, 112 from LNG feed stream 108 may be varied by flow control valves 125, 128. As discussed in further detail below, in some implementations, the relative flow rates of the first and second LNG steams 101, 112 may be adjusted in response to a change in composition of the LNG feed stream 108.

[0022] In the example of FIG. 1, after being separated into the first and second rich LNG streams 101, 112, the first rich LNG stream 101 is heated to an at least partially vaporized state. The first rich LNG stream 101 passes from pump 126 to feed preheater 140 and then is heated to an at least partially vaporized state by heat exchanger 130. The heat exchanger 130 is arranged to receive the first rich LNG stream 101, and also arranged to receive a lean LNG sendout stream 188 (discussed further below) and a combined overhead stream 134 from the absorber 102 and demethanizer 138 (also discussed further below). The heat exchanger 130 is operable to exchange heat from the combined overhead stream 134 to the first rich LNG stream 101 and to the LNG sendout stream 188. The heat exchanger 130 condenses the combined overhead stream 134, heats the LNG sendout stream 188, and at least partially vaporizes the first rich LNG stream 101. Heat exchanger 130 may be a brazed aluminum type heat exchanger, a shell and tube heat exchanger, or another type of heat exchanger. Heat exchanger 130 may be a single unit or a functional assembly of several heat exchangers.

[0023] Downstream of the heat exchanger 130 the first rich LNG stream 106 is introduced in the at least partially vaporized state into the absorber 102 at first inlet 104. In the example shown in FIG. 1 the temperature at which the first rich LNG stream 106 is introduced into the absorber 102 is controlled by bypass valve 142, which regulates the flow rate of a bypass streamGAZ0028-WO-PCT144, which is part of the first rich LNG stream 106 that bypasses heat exchanger 130. Temperature controller 146 monitors the temperature of the first rich LNG stream 106 prior to introduction into absorber 102 and controls bypass valve 142 such that less or more of first rich LNG stream 106 passes through bypass stream 144 instead of heat exchanger 130 prior to introduction into the absorber 102, depending on whether the temperature of first rich LNG stream 106 needs to be raised or lowered prior to introduction into the absorber 102. For instance, if the temperature of the first rich LNG stream 106 monitored at temperature controller 146 is above a desired temperature for the first rich LNG stream 106 to be introduced into the absorber 102, the temperature controller 146 may open or further open bypass valve 142 to increase the flow rate of first rich LNG stream 106 that bypasses the heat exchanger 130 via bypass stream 144. Conversely, if the temperature of the first rich LNG stream 106 monitored at temperature controller 146 is below a desired temperature for the first rich LNG stream 106 to be introduced into the absorber 102, the temperature controller 146 may close (partially or entirely) bypass valve 142 to decrease the flow rate of first rich LNG stream 106 that bypasses the heat exchanger 130 via bypass stream 144.Absorber

[0024] As noted above, in the example of FIG. 1, the first rich LNG stream 106 is introduced in an at least partially vaporized state into the absorber 102. In some implementations the first rich LNG stream 106 is introduced in a completely vaporized state into the absorber 102. In some implementations the first rich LNG stream 106 is introduced into the absorber 102 at a temperature above the vaporization temperature of the LNG stream 106 (e.g. above approximately -256° F).GAZ0028-WO-PCT

[0025] The second rich LNG stream 112 is introduced as a first reflux flow in a liquid condition into the absorber 102 at second inlet 110. The first reflux flow is introduced into the absorber 102 above the first rich LNG stream 106. In this particular example the first reflux flow is a mid-reflux for lower sections of the absorber 102. The second reflux flow is introduced in a liquid condition into the absorber 102 at third inlet 114. The second reflux flow as lean LNG is introduced into the absorber 102 above the first reflux flow. The second reflux flow may be a recycled portion of the combined overhead streams 134 of the absorber 102 and the demethanizer 138, as discussed in further detail below. The first and second reflux flows increase absorption and separation of ethane and heavier hydrocarbons in the absorber 102, thus increasing the ethane and heavier hydrocarbon concentration in absorber 102 bottom stream 122 and increasing the methane concentration in absorber 102 overhead stream 118.

[0026] In at least some implementations, in response to a change in composition of the LNG feed stream 108, the flow rates at which the first rich LNG stream 106 and the first reflux flow (second rich LNG stream 112) are introduced into the absorber 102 may be adjusted. In the example of FIG. 1, flow control valve 128 allows adjusting the flow rate at which the first rich LNG stream 106 and flow control valve 125 allows adjusting the flow rate of the first reflux flow (via second rich LNG stream 112) are introduced into the absorber 102. The adjustments may be made automatically or manually and may be made in response to a determination that the composition of the LNG feed stream 108 has changed (e.g. as determined by a system operator based on either specific measurements of the LNG feed stream 108 or based on knowledge of the source of the LNG feed stream 108). As one example, the composition of the LNG feed stream 108 may change from a relatively lean LNG feed stream to a relatively rich LNG feed stream (i.e. the percentage ofGAZ0028-WO-PCTethane and other heavier hydrocarbons relative to methane in the LNG feed stream may go up). In such an example, increasing the flow rate of the first reflux flow (via the second rich LNG stream 112) may provide additional absorption capacity in the absorber 102 reflux flows to capture the higher percentage of heavier hydrocarbons into the bottom stream 122. As a second example, the composition of the LNG feed stream 108 may change from a relatively rich LNG feed stream to a relatively lean LNG feed stream (i.e. the percentage of methane relative to ethane and other heavier hydrocarbons in the LNG feed stream may go up). In this second example, less reflux flow in the absorber 102 may be necessary to effectively separate out the ethane and heavier hydrocarbons into bottom stream 122, and thus the flow rate of the first reflux flow (via the second rich LNG stream 112) may be decreased accordingly.

[0027] In at least some implementations the absorber 102 may operate at a pressure in the range of 145 to 400 pounds-per-square inch absolute (psia), or 170 to 375 psia, or 195 to 350 psia. In at least some implementations the absorber 102 may operate at a temperature in the range of -60° to -225° F, or -85° to -200° F, or -110° to -175° F.

[0028] An overhead stream 118 is collected from the absorber 102, which is a lean LNG enriched in methane and reduced in ethane relative to the LNG feed stream 108. The overhead stream 118 collected from the absorber 102 is combined with the overhead stream 136 collected from the demethanizer 138, resulting in combined overhead stream 134. As noted above and discussed in further detail below, the lean LNG from the combined overhead stream 134 may be used as the second reflux flow introduced into the absorber 102 at third inlet 114.

[0029] The bottom stream 122 collected from the absorber 102 may be enriched in ethane and other heavier hydrocarbons and reduced in methane relative to LNG feed stream 108.GAZ0028-WO-PCTFrom the absorber 102, bottom stream 122 may be fed to feed pump 148, then to feed preheater 150, and then introduced into demethanizer 138.Demethanizer

[0030] The demethanizer 138 in FIG. 1 is arranged to receive the bottom stream 122 from the absorber 102 and to output a bottom stream 158 and an overhead stream 136. The bottom stream 158 from the demethanizer 138 is a natural gas liquid (NGL) enriched in ethane (and other heavier hydrocarbons) and reduced in methane relative to the bottom stream 122 from the absorber 102. The overhead stream 136 from the demethanizer 138 is enriched in methane and reduced in ethane (and other heavier hydrocarbons) relative to the bottoms stream 122 from the absorber 102.

[0031] In some implementations the demethanizer 138 may operate in a pressure range of 220 to 560 psia, or 245 to 535 psia, or 270 to 510 psia as measured at an upper portion of the demethanizer 138. The demethanizer 138 may operate at a temperature range of -100 to -195° F, or -115 to -180° F, or -130 to -165° F as measured at an upper portion of the demethanizer 138. The demethanizer 138 may operate at a temperature range of -12 to +95° F, or +3 to +80° F, or +18 to +65° F as measured at a lower portion of the demethanizer 138.

[0032] In the example shown in FIG. 1 temperature of the demethanizer 138 is regulated using side reboiler 152 and bottom reboiler 154. The reboilers 152, 154 may use heat sources that are typically available at LNG terminals, which typically provide operating temperatures greater than +70° F. The reboilers 152, 154 may alternatively use other heat sources. The heating media used by the reboilers 152, 154 may be a mixture of ethylene glycol and water, propylene glycol and water, hot oil or other combinations of heating fluids commercially available.GAZ0028-WO-PCT

[0033] In some implementations the demethanizer 138 may be operated in multiple operating modes. For instance, the demethanizer 138 may be operated in a first operating mode and a second operating mode, with the demethanizer 138 operated at a higher pressure in the second operating mode than in the first operating mode. For instance, when operated in the first operating mode, the demethanizer 138 may be operated at a pressure below 350 psia (or below 325 psia or below 300 psia) as measured at an upper portion of the demethanizer 138, and when operated in the second operating mode, the demethanizer 138 may be operated at a pressure in the range of 400- 600 psia (or 375 - 625 psia, or 350-650 psia) as measured at an upper portion of the demethanizer 138.

[0034] In some instances, the demethanizer 138 may be operated in the first lower pressure operating mode when there is a low heat level available for the reboilers 152, 154 and may be operated in the second higher pressure operating mode when there is excess fuel gas available for heating of the reboiler 152, 154 medium. In some implementations operating in the second higher pressure operating mode may improve ethane and other heavier hydrocarbon recovery in the demethanizer 138 and may also reduce compression power requirements (e.g. compression power requirements at absorber overhead compressor 156).

[0035] In the example of FIG. 1 an overhead stream 136 is collected from the demethanizer 138 that is enriched in methane and reduced in ethane and other heavier hydrocarbons relative to the bottom stream 122 from the absorber. The overhead stream 136 from the demethanizer 138 is combined with the overhead stream 118 from the absorber 102. A compressor 156 compresses the overhead stream 118 from the absorber 102 prior to combining it with the overhead stream 136 from the demethanizer 138 into combined overhead stream 134.GAZ0028-WO-PCTIn some implementations compressor 156 compresses the overhead stream 118 to a pressure within a range of 280-300 psia, or 255-325 psia, or 230-350 psia. In the example of FIG. 1 compressor 156 is controlled by pressure controller 166.

[0036] In the example of FIG. 1 a bottom stream 158 is collected from the demethanizer 138. The bottom stream 158 is a natural gas liquid (NGL) that is enriched in ethane and other heavier hydrocarbons and reduced in methane relative to the LNG feed stream 108 and relative to the bottom stream 122 of the absorber 102. In at least some implementations the LNG regasification system described above recovers at least 97 vol%, at least 98 vol%, or at least 99 vol% of the ethane and other heavier hydrocarbons from the LNG feed stream 108 into the bottom stream 158 from the demethanizer 138.

[0037] FIG. 1 shows two options for sendout of NGL product from bottom stream 158 from demethanizer 138. One of the options shown in FIG. 1 is that pump 160 can pump the NGL in bottom stream 158 from the demethanizer 138 to an NGL terminal 162 for delivery as NGL product. The other options shown in FIG. 1 involves delivery of NGL in bottom stream 158 to deethanizer 164 and using ethane delivery pump 228 and heavier hydrocarbon delivery pump 230 to deliver ethane product to ethane terminal 232 and heavier hydrocarbon to product terminal 234 respectively. Either option (162 or 232 / 234) may be selected depending on demand for a particular type of NGL product. In other implementations a system may include only one of these options or may include other functionality for sendout of NGL product.Lean LNG

[0038] In the example of FIG. 1 lean LNG is collected in the overhead stream 118 from the absorber 102 and the overhead stream 136 from the demethanizer 138 into combined overheadGAZ0028-WO-PCTstream 134. The lean LNG is then passed through heat exchanger 130 and condensed. A lean LNG collection chamber 168 is arranged to receive the lean LNG of the overhead stream 134. The subcooled condensed lean LNG 242 feeds into the lean LNG collection chamber 168 at inlet 170. In some implementations the lean LNG collection chamber 168 may be a surge drum. In other implementations the lean LNG collection chamber 168 may be another type of holding chamber configured to temporarily hold lean LNG. Lean LNG collection chamber 168 may operate in a pressure range of 260 to 500 psia (or 235 to 525 psia, or 210 to 550 psia) and a temperature range of -180 to 260° F (or -205 to 285° F or -230 to 310° F). In the example shown in FIG. 1, the lean LNG collection chamber 168 includes a vapor vent 246 as Normal No Flow (NNF). The vapor vent 246 in this example is a pressure controlled valve. In some implementations, when vapor is present, vapor vent 246 facilitates subcooling stream 242.

[0039] In the system of FIG. 1 several fluid pathways fluidly couple the lean LNG collection chamber to other components of the system such that the system is operable to selectively flow the lean LNG from the lean LNG collection chamber along one or more of those fluid pathways to various destinations.

[0040] A first fluid pathway including fluid pathway segments 172, 174, 176, 178, 240 fluidly couples the lean LNG collection chamber to the third inlet 114 of the absorber 102 such that lean LNG can be recycled as the second reflux flow into the absorber 102. The first fluid pathway also includes feed preheater 140 at which lean LNG is cooled before being fed to absorber 102.GAZ0028-WO-PCT

[0041] A second fluid pathway including fluid pathway segments 172, 174, 186, 188 fluidly couples the lean LNG collection chamber 168 to a vaporizer 182 and a lean LNG sendout 184 for sending a lean LNG sendout stream 188 to a pipeline using sendout pump 226.

[0042] A third fluid pathway including fluid pathway segments 172, 190, 192, 194, 196 fluidly couples the lean LNG collection chamber 168 to a liquid expander 198 and a holding tank 200, with an optional send out of a portion of stream 194 to a regasification unit as stream 224.

[0043] A fourth fluid pathway including fluid pathway segment 202 fluidly couples the holding tank 200 to the vaporizer 182 and the lean LNG sendout 184, either by recycling the lean LNG from the holding tank 200 back to the lean LNG collection chamber 168 and then to the vaporizer 182 and lean LNG sendout 184 via the second fluid pathway including fluid pathway segments 172, 174, 186, 188, or by bypassing the lean LNG collection chamber 168 via bypass segment 204 and then via part of the second fluid pathway including fluid pathway segments 186 and 188.

[0044] A fifth fluid pathway including fluid pathway segments 172, 190, 206, 208, 210 fluidly couples the lean LNG collection chamber 168 to the demethanizer 138 as reflux.

[0045] The LNG regasification system of FIG. 1 is configured to operate in several different operating states in which some of these fluid pathways are open and permit flow of lean LNG to various components of the system and other fluid pathways are closed and prevent flow of lean LNG from the collection chamber 168 along those pathways. Although not shown in FIG. 1, the LNG regasification system may include control valves, additional pumps not shown in FIG. 1, or other functionality facilitating opening and closing of the fluid pathways from the collection chamber 168.GAZ0028-WO-PCT

[0046] In a first operating state of the LNG regasification system, the lean LNG is delivered to a sendout pipeline. In such a first operating state the second fluid pathway including fluid pathway segments 172, 174, 186, 188 fluidly couple the lean LNG collection chamber 168 to the vaporizer 182 and the lean LNG sendout 184 for sending a lean LNG sendout stream 188 to the sendout pipeline. The system in FIG. 1 allows for LNG sendout via lean LNG sendout stream 188 of 0-100% of the lean LNG from collection chamber 168 depending on pipeline demand at the time.

[0047] In a second operating state of the LNG regasification system, the lean LNG is delivered to the holding tank 200. In such a second operating state the third fluid pathway including fluid pathway segments 172, 190, 192, 194, 196 fluidly couple the lean LNG collection chamber 168 to the liquid expander 198 and the holding tank 200. In the example of FIG. 1 a pressure controller and adjusting valve assembly 218 manages the discharge pressure of the liquid expander 198 to maintain the expander outlet at a subcooled state. In the example of FIG.1 the holding tank 200 generates boil off gas 220 and remaining as intank LNG 244 which accumulates until send out is required. When additional send out capacity is needed, lean intank LNG 244 may be subsequently delivered back out of the holding tank 200 along pathway segment 202 to the collection chamber 168 by in-tank pump 222, or may bypass recycling back to the collection chamber 168 via pathway segment 204 for delivery back to lean LNG sendout 184.

[0048] As another alternative, instead of being delivered to holding tank 200, lean LNG may be directed from liquid expander 198 to LNG regasification terminal 224.GAZ0028-WO-PCT

[0049] In a third operating state of the LNG regasification system, the lean LNG is delivered to both the sendout pipeline (via fluid pathway including fluid pathway segments 172, 174, 186, 188) and the holding tank (via fluid pathway segments 172, 190, 192, 194, 196).

[0050] In a fourth operating state of the LNG regasification system, the lean LNG is delivered to both the sendout pipeline 184 (via fluid pathway including fluid pathway segments 172, 174, 186, 188) and the holding tank 200 (via fluid pathway segments 172, 190, 192, 194, 196), and at least a portion of the lean LNG delivered to the holding tank 200 is subsequently delivered to the sendout pipeline 184 after delivery to the holding tank 200. The portion of the lean LNG delivered to the holding tank 200 that is subsequently delivered to the sendout pipeline 184 may flow via fluid pathway segment 202 back to collection chamber 168 and then to sendout pipeline 184 via segments 172, 174, 186, 188, or may bypass returning to the collection chamber 168 by flowing via segments 202, 204, and then via segments 186, 188 to sendout pipeline 184.

[0051] In the example of FIG. 1, the multiple operating states at which the system can be operated allows for flexibility in the lean LNG sendout rate, from 0% to 100% of the design capacity of the vaporizer 182.

[0052] In any and all of the first, second, third, and fourth operating states described above the system may continue to recycle part of the lean LNG from the collection chamber 168 to the third inlet 114 of the absorber 102 as the second reflux flow via fluid pathway segments 172, 174, 176, 178, 240.

[0053] In any and all of the first, second, third, and fourth operating states described above the system may also recycle part of the lean LNG from the collection chamber 168 to an inlet 212 of the demethanizer 138 as a reflux flow via fluid pathway segments 172, 206, 208, andGAZ0028-WO-PCT210. The reflux flow in the demethanizer 138 facilitates increasing ethane and other heavier hydrocarbon concentrations in demethanizer bottom stream 158 and increasing methane concentration in demethanizer overhead stream 136. The reflux flow into the demethanizer 138 in the FIG. 1 example is controlled by pump 214 and may optionally be cooled by cooler 216. In other implementations cooler 216 is unnecessary and feed preheater 38, heat exchanger 130, side reboiler 152, and bottom reboiler 154 may provide adequate temperature conditions in the demethanizer 138.Process

[0054] FIG. 2 shows an example of an LNG regasification process. The LNG regasification process can be performed using the LNG regasification system shown in FIG. 1 or may be performed with a different LNG regasification system. Similarly, while the LNG regasification system of FIG. 1 may be used to perform the LNG regasification process of FIG. 2, the LNG regasification system of FIG. 1 may also or alternatively be used to perform different LNG regasification processes.

[0055] In the LNG regasification process of FIG. 2, at step 250, an LNG feed stream is separated into a first rich LNG stream and a second rich LNG stream. The LNG feed stream is a mixture of at least methane and ethane. When the system of FIG. 1 is used, LNG feed stream from inlet 124 is separated into a first rich LNG stream 101 and a second rich LNG stream 112.

[0056] At step 252, the first rich LNG stream is heated to an at least partially vaporized condition. When the system of FIG. 1 is used for the process of FIG. 2, feed preheater 140 and then heat exchanger 130 are used to heat the first rich LNG stream 101 to the at least partially vaporized condition.GAZ0028-WO-PCT

[0057] At step 254, the first rich LNG stream, a first reflux flow, and a second reflux as lean LNG stream flow are introduced into an absorber. The first rich LNG stream is introduced in the at least partially vaporized condition, while the first and second reflux flows are introduced in liquid conditions into the absorber. The first reflux flow is the second rich LNG stream that was separated from the LNG freed stream. The first reflux flow may be introduced into the absorber above the first rich LNG stream, and the second reflux flow may be introduced into the absorber above the first reflux flow. The second reflux flow is lean LNG. A relative flow rate at which the first rich LNG stream and the first reflux flow are introduced into the absorber may be adjusted in response to a change in composition of the LNG feed. When the system of FIG. 1 is used, the first rich LNG stream 106 is introduced into the absorber 102 at inlet 104, the first reflux flow (the second rich LNG stream 112) is introduced into the absorber 102 at inlet 110, and the second reflux flow is introduced into the absorber 102 at inlet 114, with flow control valves 125, 128 facilitating adjustment of relative flow rates of the first rich LNG stream and the first reflux flow.

[0058] At step 256, a bottom stream from the absorber is collected from the absorber and introduced into a demethanizer. The demethanizer may be operated in a first operating mode and operated in a second operating mode, with the second operating mode the demethanizer operating at a higher pressure than the first operating mode. As one example, in the first operating mode the demethanizer is operated at a pressure below 350 psia and in the second operating mode the demethanizer is operated at a pressure in the range of 400 - 600 psia. When the system of FIG. 1 is used, the bottom stream 122 from the absorber 102 is introduced into the demethanizer 138 by feed pump 148, and the operation of reboilers 152, 154 may be adjusted to change the operating mode of the demethanizer 138 between lower and higher pressure modes.GAZ0028-WO-PCT

[0059] At step 258, a bottom stream is collected from the demethanizer. The bottom stream from the demethanizer is an NGL enriched in ethane and reduced in methane relative to the LNG feed stream. In at least some implementations of the process shown in FIG. 2, the LNG regasification process recovers at least 99 vol% (or at least 97 vol% or at least 98 vol%) of the ethane (and any heavier hydrocarbons) from the LNG feed stream in the bottom stream from the demethanizer. When the system of FIG. 1 is used, the bottom stream 158 from demethanizer 138 is collected and may be delivered to NGL terminal 162 or to de-ethanizer 164.

[0060] At step 260, an overhead stream is collected from the absorber, an overhead stream is collected from the demethanizer, and the overhead streams are combined. The overhead stream(s) are a lean LNG enriched in methane and reduced in ethane relative to the LNG feed stream. When the system of FIG. 1 is used, the overhead streams 118, 136 are collected from the absorber 102 and demethanizer 136 respectively and combined into combined steam 134. As discussed above, depending on the operating state of the LNG regasification system / process, the lean LNG collected in the overhead stream(s) may be recycled and / or delivered to various destinations.Performance

[0061] The example of an LNG regasification system and process shown in FIGS. 1 and 2 and described above provide an efficient and flexible system and process for regasification of LNG and recovery of ethane and heavier hydrocarbons.

[0062] In these examples, the use of an absorber with dual reflux streams provides for high levels of ethane recovery (e.g. at least 97+ vol%, at least 98+ vol%, or at least 99+ vol%). When lean LNG product is sent out directly to pipeline via lean LNG sendout 184, heat exchangerGAZ0028-WO-PCT130 is used to recover refrigeration from the lean LNG that is used to condense the lean LNG overhead streams 118, 136 from the absorber 102 and the demethanizer 138. When lean LNG product is sent to holding tank 200, liquid expander 198 is used to recover energy from the lean LNG product and to minimize flash gas / boil off gas in the holding tank 200. At times of peak lean LNG product demand, the in-tank pump 222 of holding tank 200 can be operated to send out lean LNG product 244 along with send out pump 226.

[0063] In these examples, the use of an absorber 102 with multiple reflux streams, the use of liquid expander 198 to recover power from the lean LNG product prior to delivery to holding tank 200, and the use of heat exchanger 130 to recover refrigeration from the lean LNG product prior to sendout at lean LNG sendout 184 all provide for increased process efficiency with reduced power consumption. The use of heat exchanger 130 to recover refrigeration from the lean LNG product prior to sendout at lean LNG sendout 184 also reduces the duty required of vaporizer 182, further increasing sendout vaporizer 182 capacity.

[0064] In these examples, the adjustability of the rates at which first rich LNG stream 106 and second rich LNG stream 112 are delivered to absorber 102 allows for efficient and effective processing of a wide range of rich LNG feed compositions.

[0065] In these examples, the multiple operating states at which the system can be operated allows for flexibility in the lean LNG sendout rate, from 0% to 100% of the design capacity of the vaporizer 182. When necessary, peak sendout can be supplied from holding tank 200 in addition to direct sendout from collection chamber 168.GAZ0028-WO-PCT

[0066] In these examples, when high temperature heat is available for the demethanizer 138 reboilers 152, 154, the demethanizer 138 may be operated at pressures of up to 550 psia, which improves recovery and reduces the absorber overhead compressor power requirements.

[0067] The above examples are included for demonstration purposes only and not as limitations on the scope of the invention. Other variations in the construction, configuration, and performance of the LNG regasification systems and processes may be made without departing from the scope or spirit of the inventions set out in the following claims, and those of skill in the art will recognize that the foregoing descriptions were provided by way of example only.

Claims

GAZ0028-WO-PCTClaims:

1. A liquid natural gas (LNG) regasification process comprising:(a) separating an LNG feed stream into a first rich LNG stream and a second rich LNG stream, wherein the LNG feed stream, the first rich LNG stream, and the second rich LNG stream comprise a mixture of at least methane and ethane;(b) heating the first rich LNG stream to an at least partially vaporized state;(c) introducing the first rich LNG stream in the at least partially vaporized state into an absorber;(d) introducing a first reflux flow in a liquid state into the absorber, the first reflux flow comprising the second rich LNG stream;(e) introducing a second reflux flow in a liquid state into the absorber; and(f) collecting an overhead stream from the absorber, wherein the overhead stream comprises a lean LNG enriched in methane and reduced in ethane relative to the LNG feed stream, wherein the lean LNG is used as the second reflux flow.

2. The LNG regasification process of claim 1 wherein the first reflux flow is introduced into the absorber above the first rich LNG stream, and wherein the second reflux flow is introduced into the absorber above the first reflux flow.GAZ0028-WO-PCT3. The LNG regasification process of claim 1 wherein, in a first operating state of the LNG regasification process, the lean LNG is delivered to a sendout pipeline, and, in a second operating state of the LNG regasification process, the lean LNG is delivered to a holding tank.

4. The LNG regasification process of claim 3 wherein, in the first operating state, a heat exchanger heats an LNG sendout stream comprising the lean LNG being delivered to the sendout pipeline using heat from the overhead stream collected from the absorber.

5. The LNG regasification process of claim 4 wherein, in the first operating state, a vaporizer downstream of the heat exchanger vaporizes the LNG sendout stream.

6. The LNG regasification process of claim 3 wherein, in the second operating state, the lean LNG being delivered to the holding tank is expanded in a liquid expander before delivery to the holding tank.

7. The LNG regasification process of claim 3 wherein, in a third operating state of the LNG regasification process, the lean LNG is delivered to both the sendout pipeline and the holding tank.

8. The LNG regasification process of claim 3 wherein, in a fourth operating state of the LNG regasification process, the lean LNG is delivered to both the sendout pipeline and the holding tank, and at least a portion of the lean LNG delivered to the holding tank is subsequentlyGAZ0028-WO-PCTdelivered to the sendout pipeline after delivery to the holding tank, and another portion of the lean LNG is delivered to the sendout pipeline without first being delivered to the holding tank.

9. The LNG regasification process of claim 1 further comprising, in response to a change in composition of the LNG feed stream, adjusting a relative flow rate at which the first rich LNG stream and the first reflux flow are introduced into the absorber.

10. The LNG regasification process of claim 1 further comprising:introducing a bottom stream from the absorber into a demethanizer;collecting an overhead stream from the demethanizer and combining the overhead stream from the demethanizer with the overhead stream from the absorber; andcollecting a bottom stream from the demethanizer, wherein the bottom stream from the demethanizer comprises a natural gas liquid (NGL) enriched in ethane and reduced in methane relative to the LNG feed stream, and wherein the LNG regasification process recovers at least 99 vol% of the ethane from the LNG feed stream in the bottom stream from the demethanizer.

11. The LNG regasification process of claim 10 further comprising operating the demethanizer in a first operating mode and operating the demethanizer in a second operating mode, wherein, in the second operating mode the demethanizer is operated at a higher pressure than in the first operating mode.GAZ0028-WO-PCT12. The LNG regasification process of claim 11 wherein, in the first operating mode, the demethanizer is operated at a pressure below 350 psia, and, in the second operating mode, the demethanizer is operated at a pressure in a range of 400 - 600 psia.

13. A liquid natural gas (LNG) regasification process comprising:(a) separating an LNG feed stream comprising a mixture of at least methane and ethane into a first rich LNG stream and a second rich LNG stream;(b) heating the first rich LNG stream to an at least partially vaporized state and introducing the first rich LNG stream in the at least partially vaporized state into an absorber;(c) introducing a first reflux flow in a liquid state into the absorber, the first reflux flow comprising the second rich LNG stream;(d) introducing a second reflux flow in a liquid state into the absorber;(e) introducing a bottom stream from the absorber into a demethanizer;(f) collecting an overhead stream from the absorber and an overhead stream from the demethanizer, wherein the collected overhead streams comprise a lean LNG enriched in methane and reduced in ethane relative to the LNG feed stream;(g) operating the LNG regasification process in a first operating state in which the lean LNG is delivered to a sendout pipeline; and(h) operating the LNG regasification process in a second operating state in which the lean LNG is delivered to a holding tank.GAZ0028-WO-PCT14. A liquid natural gas (LNG) regasification system comprising: an absorber arranged to receive at a first inlet of the absorber a first rich LNG stream of an LNG feed in an at least partially vaporized condition, to receive at a second inlet of the absorber a first reflux flow comprising a second rich LNG stream of the LNG feed in a liquid condition, and to receive at a third inlet of the absorber a second reflux flow in a liquid condition; the absorber operable to output at an overhead outlet an overhead stream comprising a lean LNG enriched in methane and reduced in ethane relative to the LNG feed; the absorber operable to output a bottom stream enriched in ethane and reduced in methane relative to the LNG feed.

15. The LNG regasification system of claim 14 further comprising a demethanizer arranged to receive the bottom stream from the absorber and to output a bottom stream and an overhead stream, the bottom stream from the demethanizer comprising a natural gas liquid (NGL) enriched in ethane and reduced in methane relative to the bottom stream from the absorber, the system arranged to combine the overhead stream from the demethanizer with the overhead stream from the absorber.

16. The LNG regasification system of claim 14 further comprising a heat exchanger arranged to receive the overhead stream, the first rich LNG stream, and a lean LNG sendout stream, the heat exchanger operable to exchange heat from the overhead stream to the first rich LNG stream and to the LNG sendout stream.GAZ0028-WO-PCT17. The LNG regasification system of claim 16 further comprising a lean LNG collection chamber arranged to receive the lean LNG of the overhead stream, wherein a first fluid pathway fluidly couples the lean LNG collection chamber to the third inlet of the absorber.

18. The LNG regasification system of claim 17 further comprising a second fluid pathway fluidly coupling the lean LNG collection chamber to a vaporizer and a lean LNG sendout, wherein the second fluid pathway comprises the lean LNG sendout stream.

19. The LNG regasification system of claim 18 further comprising a third fluid pathway fluidly coupling the lean LNG collection chamber to a liquid expander and a holding tank.

20. The LNG regasification system of claim 19 further comprising a fourth fluid pathway fluidly coupling the holding tank to the vaporizer and the lean LNG sendout, wherein the system is operable to selectively flow the lean LNG from the lean LNG collection chamber along one or more of the first, second, third, and fourth fluid pathways.

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