Patent Application
20240377128
The present disclosure generally relates to simplified and efficient recovery of natural gas liquid (NGL) within a liquefied natural gas (LNG) liquefaction process. In particular, the systems and methods of the present disclosure can allow for a flexible transition between ethane removal and recovery operations.
Natural gas is a commonly used resource comprised of a mixture of naturally occurring hydrocarbon gases typically found in deep underground natural rock formations or other hydrocarbon reservoirs. More particularly, natural gas is primarily comprised of methane (CH4) and often includes other components, such as, ethane (C2H6), propane (C3H8), carbon dioxide (CO2), nitrogen (N2), hydrogen sulfide (H2S), and/or the like.
Cryogenic liquefaction generally converts the natural gas into a convenient form for transportation and storage. More particularly, under standard atmospheric conditions, natural gas exists in vapor phase and is subjected to certain thermodynamic processes to produce liquefied natural gas (LNG). Liquefying natural gas greatly reduces its specific volume, such that large quantities of natural gas can be economically transported and stored in liquefied form. The natural gas liquid (NGL) received from pipelines with high concentrations of NGL components, which are separated during the LNG process. During component separation, heavy hydrocarbon components (C6+) are also removed to prevent solid deposition within the facility.
Heavy hydrocarbon components in the NGL are typically removed by a recovery plant upstream, which can operate a demethanizer at lower pressure and uses compression to deliver methane-rich gas to a pressure required in the downstream liquefaction process. Such standalone NGL plants often need additional equipment to switch between for the recovery and rejection of certain components, which involves a change of equipment increasing costs and facility downtime to allow for alignment and operating condition adjustments. It is with these observations in mind, among others, that various aspects of the present disclosure were conceived and developed.
Implementations described and claimed herein address the foregoing problems by providing systems and methods for obtaining a desired natural gas liquid (NGL) product from a liquefied natural gas (LNG) facility having an NGL recovery unit integrated therein. A gas feed stream is received and cooled using a demethanizer within the NGL recovery unit to produce a vapor including light hydrocarbon components and a liquid including NGL components. The vapor is transferred to an LNG liquefaction unit for production as a light hydrocarbon product. The liquid is transferred to a deethanizer within the NGL recovery unit to obtain an ethane product and a desired NGL product.
In another implementation, a liquefied natural gas (LNG) facility can have a flexible natural gas liquid (NGL) recovery unit integrated therein. The NGL recovery unit can be operable to switch between an ethane recovery operation and an ethane rejection operation without requiring a change of equipment. As such, the flexible NGL recovery unit can be used to produce a desired product based on current market demands.
Other implementations are also described and recited herein. Further, while multiple implementations are disclosed, still other implementations of the presently disclosed technology will become apparent to those skilled in the art from the following detailed description, which shows and describes illustrative implementations of the presently disclosed technology. As will be realized, the presently disclosed technology is capable of modifications in various aspects all without departing from the spirit and scope of the presently disclosed technology. Accordingly, the drawings and detailed description are to be regarded as illustrative in nature and not limiting.
Aspects of the present disclosure involve systems and methods for providing an efficient and simplified process of recovering natural gas liquids (NGLs) within an LNG liquefaction process. The systems and methods described herein integrate a NGL recovery process into the LGN liquefaction process and provides additional flexibility to switch between an ethane recovery operation and an ethane rejection operation. NGL recovery is typically performed in a separate, standalone facility upstream from the LGN facility. By integrating the NGL recovery process into the LGN liquefaction process at the LGN facility, the efficiency of NGL separation can be enhanced and power consumption reduced, improving overall process efficiency. Additionally, liquefied natural gas (LNG) facilities sometimes involve different equipment designs for ethane recovery operations and ethane rejection operations. Switching between ethane recovery and rejection operations in such facilities can often become demanding due to the different equipment necessary for each operation. The differences in design can require additional equipment alignment and operating condition adjustments, which can increase down time during operation changes. As described herein, the presently disclosed technology addresses these concerns with an ability to switch between ethane recovery and ethane rejection while integrating the NGL recovery process into the LGN facilities.
In one aspect, NGL hydrocarbon components (including C2+) are separated from a natural gas feed stream using a recovery unit integrated into an LNG liquefaction process. The natural gas feed stream can include a combination of methane (CH4), ethane (C2H6), propane (C3H8), and additional hydrocarbons (C5+) in various composition ratios. In addition to separating NGL components from light hydrocarbon components, heavy hydrocarbon components, including C6+ (“heavies”), are also removed in order to prevent solid deposition downstream within the LNG process. LNG facilities as described herein can include at least a demethanizer, a turboexpander, one or more exchanges, and a deethanizer. Furthermore, the processes and methods described herein can integrate an NGL recovery unit into an LNG liquefaction process and allow flexibility to seamlessly switch between NGL recovery and liquefied petroleum gas (LPG) recovery.
Examples, various features, and advantageous details thereof are explained more fully with reference to the exemplary, and therefore non-limited, examples illustrated in the accompanying drawings and detailed in the following description. Descriptions of known starting materials and processes can be omitted so as not to unnecessarily obscure the disclosure in the detail. It should be understood, however, that the detailed description and the specific examples, while indicating the preferred examples, are given by way of illustration only and not by way of limitation. Various substitutions, modifications, additions and/or rearrangements within the spirit and/or scope of the underlying inventive concept will become apparent to those skilled in the art from this disclosure.
The liquefaction process described herein may incorporate one or more of several types of cooling systems and methods including, but not limited to, a demethanizer, a turboexpander, one or more exchangers, and a deethanizer.
Indirect heat exchange, as used herein, refers to a process involving a cooler stream cooling a substance without actual physical contact between the cooler stream and the substance to be cooled. Specific examples of indirect heat exchange include, but are not limited to, heat exchange undergone in a shell-and-tube heat exchanger, a core-in-shell heat exchanger, and a brazed aluminum plate-fin heat exchanger. The specific physical state of the refrigerant and substance to be cooled can vary depending on demands of the refrigeration system and type of heat exchanger chosen.
Expansion or pressure reduction cooling refers to cooling which occurs when the pressure of a gas, liquid or a two-phase system is decreased by passing through a pressure reduction means. In some implementations, the expansion means may be a Joule-Thomson expansion valve. In other implementations, the expansion means may be either a hydraulic or gas expander. Because expanders recover work energy from the expansion process, lower process stream temperatures are possible upon expansion.
As used herein, the terms “comprises,” “comprising,” “includes,” “including,” “has,” “having” or any other variation thereof, are intended to cover a non-exclusive inclusion. For example, a process, product, article, or apparatus that comprises a list of elements is not necessarily limited only those elements but can include other elements not expressly listed or inherent to such process, process, article, or apparatus. Further, unless expressly stated to the contrary, “or” refers to an inclusive or and not to an exclusive or. For example, a condition A or B is satisfied by any one of the following: A is true (or present) and B is false (or not present), A is false (or not present) and B is true (or present), and both A and B are true (or present).
Further, any one of the features in the present description may be used separately or in combination with any other feature. For example, references to the term “implementation” means that the feature or features being referred to are included in at least one aspect of the present description. Separate references to the term “implementation” in this description do not necessarily refer to the same implementation and are also not mutually exclusive unless so stated and/or except as will be readily apparent to those skilled in the art from the description. For example, a feature, structure, process, step, action, or the like described in one implementation may also be included in other implementations, but is not necessarily included. Thus, the present description may include a variety of combinations and/or integrations of the implementations described herein. Additionally, all aspects of the present inventive concept as described herein are not essential for its practice.
Some LNG projects introduce pipelines as a source of feed gas to an LNG Optimized Cascade Process (OCP). The Optimized Cascade Process can be based on three multi-staged, cascading refrigerants circuits using pure refrigerants, brazed aluminum heat exchangers and insulated cold box modules. In at least one example, pure refrigerants of propane (or propylene), ethylene, and methane may be utilized. Numerous configurations of LNG systems exist and may be used in conjunction with the analysis processes described herein.
In at least one instance, the Optimized Cascade Process (OCP) can further include an integrated NGL recovery process within the LNG liquefaction process which can provide a flexible and stable means for switching between ethane recovery and ethane rejection operations based on current market demands. Conventionally, methods to remove heavy hydrocarbon components (C6+) (“heavies”) have been integrated into the OCP. Such methods can include high pressure heavy removal units (HRUs). The methods and systems disclosed herein provides an NGL recovery unit that allows for the recovery of NGL products while simultaneously removing heavies from the stream. Such systems and methods are achieved by introducing a flexible NGL recovery unit into the liquefaction process. The flexible NGL recovery unit can include at least a demethanizer, turboexpander, one or more exchangers, and a deethanizer. Specifically, a feed gas stream can be sent to a side reboiler in order to extract refrigeration from the demethanizer and cool the feed stream. Once the feed gas is cooled and at least partially condensed by a refrigerant. In at least one example, the refrigerant can be selected from propane or other equivalent heavy refrigerant from a mixed refrigerant system. If required, the feed gas stream chilling can be additionally supplemented by one or more additional side reboilers. The two-phase stream can then be separated further to produce a vapor and a liquid, wherein the freezing components (such as the heavy hydrocarbon components) are removed from the vapor phase and retained in the liquid phase. The separated liquid can be recycled to the demethanizer as a bottom feed and the vapor phase can be further divided. The smaller of the two vapor streams can be chilled, condensed, and subcooled by a by a second refrigerant. In at least one example, the second refrigerant can be an ethylene or equivalent medium refrigerant from a mixed refrigerant system. The cooled stream can then be fed back to the demethanizer as reflux. In at least one example, deep subcooling (to about −85° C.) of the reflux can improve the quality of separation in the column, allowing for increased ethane recovery while preventing propane loss.
The second vapor stream obtained from the separator can be sent to a turbo-expander where isentropic expansion takes place through the expander, allowing the gas to cool and at least partially liquefy. The new two-phase stream can then be reverted to the demethanizer as a top feed. Overhead vapor of the demethanizer, consisting mainly of methane, can be compressed by the expander and sent to an LNG liquefaction unit. A stream containing NGL can exit the bottom of the demethanizer and proceed to a deethanizer. At the top of the deethanizer column, ethane and other light hydrocarbons can be separated from the rest of the NGL components. The systems described herein can be operated in either of an ethane rejection mode or ethane recovery mode and can seamlessly switch between the operations without requiring a change of equipment. For example, when operating in an ethane recovery mode, the ethane present in the natural gas feed stream can be recovered as a product. In the alternative, when operated in ethane rejection mode, nearly all of the ethane from the natural gas feed stream can be rejected into the LNG. The operating conditions required for ethane recovery operations and ethane rejection operations only slightly vary, as described in greater detail below. In ethane recovery operations, ethane vapor from the deethanizer is warmed and sent to pipeline. In the alternative, during ethane rejection operations, ethane vapor from the deethanizer is sent to the methane compressor third stage suction and is rejected as LNG product. Finally, liquids containing propane and heavier hydrocarbon components can be recovered at the bottom of the deethanizer and sent to a fractionation unit for further processing.
The presently described systems and methods may be implemented in a cascade LNG system employing a cascade-type refrigeration process using one or more predominately pure component refrigerants. The refrigerants utilized in cascade-type refrigeration processes can have successively lower boiling points which facilitate heat removal from the natural gas stream that is being liquefied. Additionally, cascade-type refrigeration processes can include some level of heat integration. For example, a cascade-type refrigeration process can cool one or more refrigerants having a higher volatility through indirect heat exchange with one or more refrigerants having a lower volatility. In addition to cooling the natural gas stream through indirect heat exchange with one or more refrigerants, cascade and mixed-refrigerant LNG systems can employ one or more expansion cooling stages to simultaneously cool the LNG while reducing its pressure.
In one implementation, the LNG process may employ a cascade-type refrigeration process that uses a plurality of multi-stage cooling cycles, each employing a different refrigerant composition, to sequentially cool the natural gas stream to lower temperatures. For example, a first refrigerant may be used to cool a first refrigeration cycle. A second refrigerant may be used to cool a second refrigeration cycle. A third refrigerant may be used to cool a third refrigeration cycle. Each refrigeration cycle may include a closed cycle or an open cycle. The terms “first”, “second”, and “third” refer to the relative position of a refrigeration cycle. For example, the first refrigeration cycle is positioned just upstream of the second refrigeration cycle while the second refrigeration cycle is positioned upstream of the third refrigeration cycle and so forth. While at least one reference to a cascade LNG process comprising three different refrigerants in three separate refrigeration cycles is made, this is not intended to be limiting. It is recognized that a cascade LNG process involving any number of refrigerants and/or refrigeration cycles may be compatible with one or more implementations of the presently disclosed technology. Other variations to the cascade LNG process are also contemplated. It will also be appreciated that the presently disclosed technology may be utilized in non-cascade LNG processes. One example of a non-cascade LNG process involves a mixed refrigerant LNG process that employs a combination of two or more refrigerants to cool the natural gas stream in at least one cooling cycle.
To begin a detailed description of an example cascade LNG facility 100 in accordance with the implementations described herein, reference is made to
In one implementation, the main components of the propane refrigeration cycle 30 include a multi-stage propane compressor 31, a propane cooler/condenser 32, a high-stage propane chillers 33A and 33B, an intermediate-stage propane chiller 34, and a low-stage propane chiller 35. The main components of ethylene refrigeration cycle 50 include an ethylene compressor 51, an ethylene cooler 52, a high-stage ethylene chiller 53, a low-stage ethylene chiller/condenser 55, and an ethylene economizer 56. The main components of methane refrigeration cycle 70 include a methane compressor 71, a methane cooler 72, and a main methane economizer 73. The main components of expansion section 80 include a high-stage methane expansion valve and/or expander 81, a high-stage methane flash drum 82, an expander/intermediate-stage methane expansion valve 83, an intermediate-stage methane flash drum 84, an expander/low-stage methane expansion valve 85, and a low-stage methane flash drum 86. While “propane,” “ethylene,” and “methane” are used to refer to respective first, second, and third refrigerants, it should be understood that these are examples only, and the presently disclosed technology may involve any combination of suitable refrigerants.
Referring to
The cooled natural gas stream from the high-stage propane chiller 33A flows through a conduit 114 to a separation vessel. At the separation vessel, water and in some cases a portion of the propane and/or heavier components are removed. In some cases where removal is not completed in upstream processing, a treatment system 40 may follow the separation vessel. The treatment system 40 removes moisture, mercury and mercury compounds, particulates, and other contaminants to create a treated stream. The stream exits the treatment system 40 through a conduit 116. The stream then enters the intermediate-stage propane chiller 34. At the intermediate-stage propane chiller 34, the stream is cooled in indirect heat exchange 41 via indirect heat exchange with a propane refrigerant stream. The resulting cooled stream output into a conduit 118 is routed to the low-stage propane chiller 35, where the stream can be further cooled through indirect heat exchange means 42. The resultant cooled stream exits the low-stage propane chiller 35 through a conduit 120. Subsequently, the cooled stream in the conduit 120 is routed to the high-stage ethylene chiller 53.
A vaporized propane refrigerant stream exiting the high-stage propane chillers 33A and 33B is returned to a high-stage inlet port of the propane compressor 31 through a conduit 306. An un-vaporized propane refrigerant stream exits the high-stage propane chiller 33B via a conduit 308 and is flashed via a pressure reduction system 43, illustrated, for example, in
In one implementation, a stream of ethylene refrigerant in a conduit 202 enters the high-stage propane chiller 33B. At the high-stage propane chiller 33B, the ethylene stream is cooled through indirect heat exchange 39. The resulting cooled ethylene stream is routed in the conduit 204 from the high-stage propane chiller 33B to the intermediate-stage propane chiller 34. Upon entering the intermediate-stage propane chiller 34, the ethylene refrigerant stream may be further cooled through indirect heat exchange 45 in the intermediate-stage propane chiller 34. The resulting cooled ethylene stream exits the intermediate-stage propane chiller 34 and is routed through a conduit 206 to enter the low-stage propane chiller 35. In the low-stage propane chiller 35, the ethylene refrigerant stream is at least partially condensed, or condensed in its entirety, through indirect heat exchange 46. The resulting stream exits the low-stage propane chiller 35 through a conduit 208 and may be routed to a separation vessel 47. At the separation vessel 47, a vapor portion of the stream, if present, is removed through a conduit 210, while a liquid portion of the ethylene refrigerant stream exits the separation vessel 47 through a conduit 212. The liquid portion of the ethylene refrigerant stream exiting the separation vessel 47 may have a representative temperature and pressure of about −24° F. (about −31° C.) and about 285 psia (about 1,965 kPa). However, other temperatures and pressures are contemplated.
Turning now to the ethylene refrigeration cycle 50 in the LNG facility 100, in one implementation, the liquefied ethylene refrigerant stream in the conduit 212 enters an ethylene economizer 56, and the stream is further cooled by an indirect heat exchange 57 at the ethylene economizer 56. The resulting cooled liquid ethylene stream is output into a conduit 214 and routed through a pressure reduction system 58, such as an expansion valve. The pressure reduction system 58 reduces the pressure of the cooled predominantly liquid ethylene stream to flash or vaporize a portion of the stream. The cooled, two-phase stream in a conduit 215 enters the high-stage ethylene chiller 53. In the high-stage ethylene chiller 53, at least a portion of the ethylene refrigerant stream vaporizes to further cool the stream in the conduit 120 entering an indirect heat exchange 59. The vaporized and remaining liquefied ethylene refrigerant exits the high-stage ethylene chiller 53 through conduits 216 and 220, respectively. The vaporized ethylene refrigerant in the conduit 216 may re-enter the ethylene economizer 56, and the ethylene economizer 56 warms the stream through an indirect heat exchange 60 prior to entering a high-stage inlet port of the ethylene compressor 51 through a conduit 218. Ethylene is compressed in multi-stages (such as, three-stage) at the ethylene compressor 51 driven by, for example, a gas turbine driver (not illustrated). The stages of compression may exist in a single unit or a plurality of separate units mechanically coupled to a single driver.
The cooled stream in the conduit 120 exiting the low-stage propane chiller 35 is routed to the high-stage ethylene chiller 53, where it is cooled via the indirect heat exchange 59 of the high-stage ethylene chiller 53. The remaining liquefied ethylene refrigerant exiting the high-stage ethylene chiller 53 in a conduit 220 may re-enter the ethylene economizer 56 and undergo further sub-cooling by an indirect heat exchange 61 in the ethylene economizer 56. The resulting sub-cooled refrigerant stream exits the ethylene economizer 56 through a conduit 222 and passes a pressure reduction system 62, such as an expansion valve, whereupon the pressure of the refrigerant stream is reduced to vaporize or flash a portion of the refrigerant stream. The resulting, cooled two-phase stream in a conduit 224 enters the low-stage ethylene chiller/condenser 55.
A portion of the cooled natural gas stream exiting the high-stage ethylene chiller 53 is routed through a conduit 122 to enter an indirect heat exchange 63 of the low-stage ethylene chiller/condenser 55. In the low-stage ethylene chiller/condenser 55, the cooled stream is at least partially condensed and, often, subcooled through indirect heat exchange with the ethylene refrigerant entering the low-stage ethylene chiller/condenser 55 through the conduit 224. The vaporized ethylene refrigerant exits the low-stage ethylene chiller/condenser 55 through a conduit 226, which then enters the ethylene economizer 56. In the ethylene economizer 56, vaporized ethylene refrigerant stream is warmed through an indirect heat exchange 64 prior to being fed into a low-stage inlet port of the ethylene compressor 51 through a conduit 230. As shown in
The condensed and, often, sub-cooled liquid natural gas stream exiting the low-stage ethylene chiller/condenser 55 in a conduit 124 can also be referred to as a “pressurized LNG-bearing stream.” This pressurized LNG-bearing stream exits the low-stage ethylene chiller/condenser 55 through the conduit 124 prior to entering a main methane economizer 73. In the main methane economizer 73, methane-rich stream in the conduit 124 may be further cooled in an indirect heat exchange 75 through indirect heat exchange with one or more methane refrigerant streams (such as, 76, 77, 78). The cooled, pressurized LNG-bearing stream exits the main methane economizer 73 through a conduit 134 and is routed to the expansion section 80 of the methane refrigeration cycle 70. In the expansion section 80, the pressurized LNG-bearing stream first passes through a high-stage methane expansion valve or expander 81, whereupon the pressure of this stream is reduced to vaporize or flash a portion thereof. The resulting two-phase methane-rich stream in a conduit 136 enters into a high-stage methane flash drum 82. In the high-stage methane flash drum 82, the vapor and liquid portions of the reduced-pressure stream are separated. The vapor portion of the reduced-pressure stream (also called the high-stage flash gas) exits the high-stage methane flash drum 82 through a conduit 138 and enters into the main methane economizer 73. At the main methane economizer 73, at least a portion of the high-stage flash gas is heated through the indirect heat exchange means 76 of the main methane economizer 73. The resulting warmed vapor stream exits the main methane economizer 73 through the conduit 138 and is routed to a high-stage inlet port of the methane compressor 71, as shown in
The liquid portion of the reduced-pressure stream exits the high-stage methane flash drum 82 through a conduit 142 and re-enters the main methane economizer 73. The main methane economizer 73 cools the liquid stream through indirect heat exchange 74 of the main methane economizer 73. The resulting cooled stream exits the main methane economizer 73 through a conduit 144 and is routed to a second expansion stage, illustrated as an example in
The liquid stream exiting the intermediate-stage methane flash drum 84 through the conduit 148 passes through an expander/low-stage expansion valve 85, whereupon the pressure of the liquefied methane-rich stream is further reduced to vaporize or flash a portion of the stream. The resulting cooled two-phase stream is output in a conduit 156 and enters a low-stage methane flash drum 86, which separates the vapor and liquid phases. The liquid stream exiting the low-stage methane flash drum 86 through a conduit 158 comprises the liquefied natural gas (LNG) product at near atmospheric pressure. This LNG product may be routed downstream for subsequent storage, transportation, and/or use.
A vapor stream exiting the low-stage methane flash drum 86 (also called the low-stage methane flash gas) in a conduit 160 is routed to the main methane economizer 73. The main methane economizer 73 warms the low-stage methane flash gas through an indirect heat exchange 78 of the main methane economizer 73. The resulting stream exits the main methane economizer 73 through a conduit 164. The stream is then routed to a low-stage inlet port of the methane compressor 71.
The methane compressor 71 comprises one or more compression stages. In one implementation, the methane compressor 71 comprises three compression stages in a single module. In another implementation, one or more of the compression modules are separate but mechanically coupled to a common driver. Generally, one or more intercoolers (not shown) are provided between subsequent compression stages.
As shown in
The LNG facility as described in
For instance, integration point A can be at conduit 116 so the NGL recovery unit can receive the stream from the treatment system 40. Integration point B can be at conduit 116 such that the NGL recovery unit can send the stream to the indirect heat exchanger 41. Integration points C and D can be at conduit 120 so the NGL recover unit can receive a cooled stream exiting from the low-stage propane chiller 35 and/or route the cooled stream to the high-stage ethylene chiller 53. Integration point F can be at conduit 216 such that the NGL recover unit can receive the liquified ethylene refrigerant exiting the high-stage ethylene chiller 53 and/or send it to the ethylene economizer 56. Integration point E can be at conduit 215 so the NGL recover unit can receive the liquid ethylene stream from the pressure reduction system 58 and/or send the cooled, two-phase stream to the high-stage ethylene chiller 53. Integration point J can be at conduit 112 for conveying the cooled methane refrigerant stream from the methane cooler 72 to the propane refrigeration cycle 30 and/or at conduit 308 for conveying the un-vaporized propane refrigerant stream from the high-stage propane chiller 33B to the pressure reduction system 43. Integration point K can be at conduit 130 so the NGL recover unit can receive the methane refrigerant stream from the heat exchanger 37 of the high-stage propane chiller 33B and send the methane refrigerant stream to the main methane economizer 73 and/or at conduit 318 for routing the vaporized propane refrigerant stream exiting the low-stage propane chiller 35 to the low-stage inlet port of the propane compressor 31. Integration point H can be at conduit 226 for conveying the vaporized ethylene refrigerant from the low-stage ethylene chiller/condenser 55 to the ethylene economizer 56. Integration point G can be at conduit 224 for conveying the cooled two-phase stream resulting from the pressure reduction system 62 to the low-stage ethylene chiller/condenser 55. Integration point I at conduit 138 such that the NGL recover unit can receive warmed vapor stream exiting the main methane economizer 73 and route it to the high-stage inlet port of the methane compressor 71; and/or any combinations thereof.
As such, a dry gas stream can be transferred to an integrated NGL recovery unit 518 integrated with the LNG facility 500 at any of the integration points A-I, individually or in any combination. The NGL recovery unit 518 can include at least one or more compressor/expanders, a vessel, a column, and a plurality of shell and tube heat exchangers. A detailed illustration of an exemplary NGL recovery unit 518 is provided below.
As shown in
In some instances, a liquid stream leaving the bottom of the demethanizer (e.g., insertion point B), comprising mostly NGL liquids, can be sent to a deethanizer 558. The operating conditions of the deethanizer including, but not limited to, column pressure, bottoms temperatures, stages of separation, feed locations, and product locations, can be adjusted to optimize the refrigeration level, meet product specifications, and provide flexibility for feed gas variations. At the top of the deethanizer column 558, ethane and other light hydrocarbon components can be separated from the rest of the NGL components. As indicated above, the NGL recovery unit 518 can operate in both an ethane recovery operation and an ethane rejection operation. Various operating conditions may be altered in order to switch between an ethane recovery operation and an ethane rejection operation. For example, the NGL recovery unit 518 can be adjusted to extract ethane from the NGL and divert the streams as desired. The operational changes between the ethane recovery operations and ethane rejection operations are described in detail below. The liquids containing propane and heavier hydrocarbon components (C6+), are recovered from the bottom of the deethanizer 558 and sent to the fractionation unit as described herein.
After processing in the NGL recovery unit 518, the gas stream can be routed through the propane refrigeration unit for a second time. After the second pass through the propane refrigeration unit, the gas stream can be routed back through the NGL recovery unit 518 to optimize the recovery of the desired NGL components from the stream. The stream can then be transferred to an ethylene refrigeration unit 520. The ethylene refrigeration unit 520 can include at least one or more compressor/expanders, a pump, a vessel, a column, a cold box, a shell and tube heat exchanger, or a plurality of air coolers.
In some instances, an ethylene refrigeration unit 520 can include at least one of an ethylene condenser and an ethylene absorber coupled with an ethylene accumulator, one or more ethylene chillers, a propane/methane/ethylene chiller, one or more propane feed/ethylene chillers, or one or more refrigerant compressors.
After treatment in the ethylene refrigeration unit 520, the stream can be transferred back to the NGL recovery unit 518 for a third time, finally producing two separated streams. A first stream can proceed to an NGL fractionation unit 524 where the stream is separated into an ethane (C2H6) stream, a propane (C3H8) stream 528, a butane (C4H10) steam 530, and/or a gasoline stream 532, each of which can be diverted to a corresponding storage unit for later use. The NGL fractionation unit 524 can include a plurality of pumps, a plurality of vessels, a plurality of columns, a plurality of shell and tube heat exchangers, and a plurality of air coolers. A detailed illustration of an exemplary NGL fractionation unit 524 is depicted in
In some instances, the fractionation unit 524 can include at least one of, and any combination of, a deethanizer, a deethanizer reflux drum, a depropanizer, a depropanizer reflux drum, a debutanizer, or a debutanizer reflux drum 5250.
In some scenarios, a second stream can be produced by the NGL recovery unit 518 and can be routed through the ethylene refrigeration unit 520 a second time. After the stream is processed through the ethylene refrigeration unit 520 the stream can be directed to a liquefaction/methane refrigeration unit. The liquefaction/methane refrigeration unit can include at least one or more compressor/expanders, one or more pumps, a cold box, and a plurality of air coolers. In some instances, the methane refrigeration unit 536 can include at least one or more methane flash drums and/or one or more refrigerant compressors.
In at least one example, the stream can pass through the ethylene refrigeration unit 520 and the liquefaction/methane refrigeration unit a second time. After exiting the liquefaction/methane refrigeration unit two streams can be produced. A first stream, including fuel gas, can enter a fuel gas system (e.g., from insertion point B) where the gas is stored until needed. A second stream, including desired liquefied natural gas (LNG), can enter an LNG storage/loading unit 544 where the LNG can be stored for later use (e.g., between insertion points E and F). In at least one example, the LNG stream can exit the LNG storage/loading unit and pass through the liquefaction/methane refrigeration unit a second time, as a boil-off-gas (BOG) stream. The BOG stream can be subjected to compression (0.3 MW) and can return to the low stage methane compressor.
The LNG liquefaction process can include integrated NGL recovery 518 and fractionation 524 processes. The integrated NGL processes can be completed using a demethanizer operated at a high pressure. In at least one example, the demethanizer can be operated about 32 bar. In at least one instance, the demethanizer can include a subcooled feed gas as reflux, which can be supplemented by a lean reflux stream to provide additional flexibility and potential liquefaction efficiency. The LNG process as described can include an expander and recompressor to affect the gas streams. The feed gas can be subcooled in reflux for the demethanizer. The LNG process 500 is capable of switching between an ethane recovery operation and an ethane rejection operation without changing out equipment, which can incur both time delays and additional costs. In some instances, the ethane recovery operations can be performed having about 87% ethane recovery or greater and about 95% propane recovery or greater. In an additional example, the ethane rejection operations can produce an efficiency of about 95% propane recovery or greater.
A detailed illustration of the flow changes between an ethane recovery and an ethane rejection operation are illustrated in
While the present disclosure has been described with reference to various implementations, it will be understood that these implementations are illustrative and that the scope of the present disclosure is not limited to them. Many variations, modifications, additions, and improvements are possible. More generally, implementations in accordance with the present disclosure have been described in the context of particular implementations. Functionality may be separated or combined in blocks differently in various implementations of the disclosure or described with different terminology. These and other variations, modifications, additions, and improvements may fall within the scope of the disclosure as defined in the claims that follow.
