DYNAMIC CONTROL OF REFLUX RATE IN HYDROCARBON DISTILLATION

Abstract

A reflux rate of a demethanizer is dynamically controlled. An ethane content of a hydrocarbon feed stream, a residue stream, and a bottoms stream are used by a controller to determine an ethane recovery value. The hydrocarbon feed stream includes methane, ethane, and propane and is fractionated by the demethanizer. The residue stream includes ethane. The bottoms stream includes propane. The controller controls the flow of reflux to the demethanizer, such that the determined ethane recovery value is equal to or greater than a specified target ethane recovery set point. The controller determines an objective value as a ratio of power consumption to the determined ethane recovery value. The controller controls the amount of cooling provided to the hydrocarbon feed stream, thereby adjusting power consumption and reducing the objective value while maintaining the ethane recovery value at or above the specified target ethane recovery set point.

Claims

1. A method for dynamically controlling a reflux rate of a demethanizer, the method comprising: receiving, by a controller, an ethane content of each of a hydrocarbon feed stream, a residue stream, and a bottoms stream, wherein the hydrocarbon feed stream comprises methane, ethane, and propane, wherein the residue stream comprises at least a portion of the ethane from the hydrocarbon feed stream, wherein the bottoms stream comprises at least a portion of the propane from the hydrocarbon feed stream, wherein the hydrocarbon feed stream enters and is fractionated by the demethanizer; determining, by the controller, an ethane recovery value at least based on the received ethane contents of the hydrocarbon feed stream, the residue stream, and the bottoms stream; receiving, by the controller, a flow rate of reflux provided to the demethanizer; transmitting, by the controller, a flow signal to a reflux flow control valve to adjust the flow rate of reflux provided to the demethanizer, such that the determined ethane recovery value is equal to or greater than a specified target ethane recovery set point; receiving, by the controller, a power consumption of a refrigeration cycle providing cooling to the hydrocarbon feed stream; determining, by the controller, an objective value as a ratio of the determined power consumption to the determined ethane recovery value; and after adjusting the flow rate of reflux provided to the demethanizer, transmitting, by the controller, a signal to reduce power consumed by the refrigeration cycle to reduce the objective value, while maintaining the determined ethane recovery value at or above the specified target ethane recovery set point.

2. The method of claim 1, wherein determining the ethane recovery value comprises calculating the ethane recovery value as: $\mathrm{Ethane}\mathrm{Recovery}=1-\frac{\mathrm{Ethane}\mathrm{content}\mathrm{of}\mathrm{Residue}\mathrm{Gas}+\mathrm{Ethane}\mathrm{content}\mathrm{of}\mathrm{Bottoms}}{\mathrm{Ethane}\mathrm{content}\mathrm{Hydrocarbon}\mathrm{Feed}}.$

3. The method of claim 2, wherein the refrigeration cycle comprises a compressor and a refrigerant flowing through and being pressurized by the compressor, and the transmitted signal causes a flow rate of the refrigerant flowing through and being pressurized by the compressor to reduce, thereby reducing the power consumed by the refrigeration cycle.

4. The method of claim 3, comprising fractionating, by the demethanizer, the hydrocarbon feed stream, wherein fractionating the hydrocarbon feed stream comprises: separating the hydrocarbon feed stream into a vapor phase and a liquid phase; flowing the liquid phase to the demethanizer as feed; flowing a first portion of the vapor phase through a turboexpander; flowing the first portion of the vapor phase from the turboexpander to the demethanizer as feed; and flowing a second portion of the vapor phase to the demethanizer as reflux.

5. The method of claim 4, wherein fractionating the hydrocarbon feed stream comprises transferring heat from the residue gas stream exiting the demethanizer to the second portion of the vapor phase entering the demethanizer.

6. The method of claim 4, wherein fractionating the hydrocarbon feed stream comprises generating, by the turboexpander, electrical power in response to the first portion of the vapor phase flowing through and expanding across the turboexpander, and at least a portion of the electrical power generated by the turboexpander is provided to the compressor to pressurize the refrigerant.

7. A method comprising: transferring, by a cooler, heat from a hydrocarbon feed stream to a refrigerant cycling through a refrigeration cycle, wherein the hydrocarbon feed stream comprises methane, ethane, and propane; fractionating, by a distillation unit comprising a demethanizer and a de-ethanizer, the hydrocarbon feed stream to produce a residue gas stream, an ethane product stream, and a bottoms stream, wherein the residue gas stream is produced by the demethanizer and comprises at least a portion of the methane, the ethane product stream is produced by the de-ethanizer and comprises at least a portion of the ethane, the bottoms stream is produced by the de-ethanizer and comprises at least a portion of the propane, and fractionating the feed stream comprises: separating the hydrocarbon feed stream into a vapor phase and a liquid phase; flowing the liquid phase to the demethanizer as feed; flowing a first portion of the vapor phase through a turboexpander; generating, by the turboexpander, electrical power in response to the first portion of the vapor phase flowing through and expanding across the turboexpander; flowing the first portion of the vapor phase from the turboexpander to the demethanizer as feed; at least partially condensing a second portion of the vapor phase; flowing the at least partially condensed second portion to the demethanizer as reflux; and flowing a liquid stream from the demethanizer to the de-ethanizer as feed; determining an objective value as a ratio of power consumption by the refrigeration cycle to ethane recovery by the distillation unit; and adjusting a flow rate of the at least partially condensed second portion flowing to the demethanizer as reflux, a flow rate of the refrigerant flowing through the cooler, or both to minimize the objective value while maintaining the ethane recovery at or above a specified target ethane recovery set point.

8. The method of claim 7, comprising measuring an ethane content of each of the hydrocarbon feed stream, the residue stream produced by the demethanizer, and the bottoms stream produced by the de-ethanizer.

9. The method of claim 8, wherein the ethane recovery value is calculated as: $\mathrm{Ethane}\mathrm{Recovery}=1-\frac{\mathrm{Ethane}\mathrm{content}\mathrm{of}\mathrm{Residue}\mathrm{Gas}+\mathrm{Ethane}\mathrm{content}\mathrm{of}\mathrm{Bottoms}}{\mathrm{Ethane}\mathrm{content}\mathrm{Hydrocarbon}\mathrm{Feed}}.$

10. The method of claim 9, wherein adjusting the flow rate of the refrigerant flowing through the cooler comprises reducing the flow rate of the refrigerant flowing through the cooler, thereby reducing the power consumption by the refrigeration cycle.

11. The method of claim 10, wherein fractionating the feed hydrocarbon stream comprises transferring heat from the residue gas stream exiting the demethanizer to the second portion of the vapor phase entering the demethanizer.

12. The method of claim 10, wherein at least a portion of the electrical power generated by the turboexpander is used to pressurize the refrigerant cycling through the refrigeration cycle.

13. A system comprising: a demethanizer configured to fractionate a hydrocarbon feed stream based on volatility to produce a residue gas stream and a bottoms stream, wherein the hydrocarbon feed stream comprises methane, ethane, and propane, the residue gas stream comprises at least a portion of the methane, and the bottoms stream comprises at least a portion of the ethane and at least a portion of the propane; a refrigeration cycle comprising a refrigerant and a cooler, wherein the cooler is configured to transfer heat from the hydrocarbon feed stream to the refrigerant to provide cooling to the hydrocarbon feed stream upstream of the demethanizer; a reflux flow control valve configured to control a flow rate of reflux provided to the demethanizer; and a controller communicatively coupled to the reflux flow control valve and to the refrigeration cycle, wherein the controller is configured to: determine an objective value as a ratio of power consumption by the refrigeration cycle to ethane recovery by the de-ethanizer; and transmit a reflux signal to the reflux flow control valve to adjust the flow rate of the reflux provided to the demethanizer, a refrigeration signal to the refrigeration cycle to adjust a flow rate of the refrigerant flowing through the cooler, or both to minimize the objective value while maintaining the ethane recovery at or above a specified target ethane recovery set point.

14. The system of claim 13, comprising: a knockout drum downstream of the cooler and upstream of the demethanizer, wherein the knockout drum is configured to receive the hydrocarbon feed stream from the cooler and separate the hydrocarbon feed stream into a vapor phase and a liquid phase; a turboexpander configured to receive a first portion of the vapor phase, wherein the turboexpander is configured to generate electrical power in response to the first portion of the vapor phase expanding through the turboexpander, wherein the demethanizer is configured to receive the first portion of the vapor phase from the turboexpander as feed; and a de-ethanizer configured to receive the bottoms stream as feed, wherein the de-ethanizer is configured to fractionate the bottoms stream based on volatility to produce an ethane product stream and a propane product stream, wherein the ethane product stream comprises at least a portion of the ethane from the hydrocarbon feed stream, wherein the propane product stream comprises at least a portion of the propane from the hydrocarbon feed stream.

15. The system of claim 14, comprising a cross exchanger configured to transfer heat between the residue gas exiting the demethanizer and the second portion of the vapor phase entering the demethanizer.

16. The system of claim 15, comprising: a first composition analyzer configured to determine an ethane content of the hydrocarbon feed stream; a second composition analyzer configured to determine an ethane content of the residue stream; and a third composition analyzer configured to determine an ethane content of the propane product stream.

17. The system of claim 16, wherein the controller is configured to determine the ethane recovery as: $\mathrm{Ethane}\mathrm{Recovery}=1-\frac{\mathrm{Ethane}\mathrm{content}\mathrm{of}\mathrm{Residue}\mathrm{Gas}+\mathrm{Ethane}\mathrm{content}\mathrm{of}\mathrm{Bottoms}}{\mathrm{Ethane}\mathrm{content}\mathrm{Hydrocarbon}\mathrm{Feed}}.$

18. The system of claim 17, wherein the refrigeration cycle comprises a refrigerant flow control valve, and the controller is configured to transmit the refrigeration signal to the refrigerant flow control valve to reduce the flow rate of the refrigerant flowing through the cooler, thereby reducing power consumed by the refrigeration cycle.

19. The system of claim 17, wherein the refrigeration cycle comprises a compressor configured to pressurize the refrigerant, and the turboexpander is coupled to the compressor for providing at least a portion of the generated electrical power to the compressor for pressurizing the refrigerant.

20. The system of claim 17, comprising a pressure sensor configured to measure a pressure of the hydrocarbon feed stream and a temperature sensor configured to measure a temperature of the hydrocarbon feed stream, wherein the power consumption by the refrigeration cycle depends at least on the ethane content of the hydrocarbon feed stream, the pressure of the hydrocarbon feed stream, and the temperature of the hydrocarbon feed stream.

Description

DESCRIPTION OF DRAWINGS

[0005] FIG. 1 is a schematic diagram of an example hydrocarbon distillation system.

[0006] FIG. 2 is a schematic diagram of an example refrigeration cycle that can provide cooling to the system of FIG. 1.

[0007] FIG. 3A is a flow chart of an example method for controlling operation of the system of FIG. 1.

[0008] FIG. 3B is a flow chart of an example method for controlling operation of the system of FIG. 1.

[0009] FIG. 4A is a plot showing evaluation of minimizing a target variable in relation to reflux ratio.

[0010] FIG. 4B is a plot showing evaluation of maximizing ethane recovery in relation to reflux ratio.

[0011] FIG. 5A is a plot showing evaluation of minimizing a target variable in relation to reflux ratio at a specified temperature condition.

[0012] FIG. 5B is a plot showing evaluation of maximizing ethane recovery in relation to reflux ratio at a specified temperature condition.

[0013] FIG. 6A is a plot showing evaluation of minimizing a target variable in relation to reflux ratio at a specified pressure condition.

[0014] FIG. 6B is a plot showing evaluation of maximizing ethane recovery in relation to reflux ratio at a specified pressure condition.

[0015] FIG. 7A is a plot showing evaluation of minimizing a target variable in relation to reflux ratio at a specified feed composition condition.

[0016] FIG. 7B is a plot showing evaluation of maximizing ethane recovery in relation to reflux ratio at a specified feed composition condition.

DETAILED DESCRIPTION

[0017] This disclosure describes ethane recovery that includes dynamic control of reflux rate in a demethanizer, for example, of a Gas Subcooled Process (GSP). The described system includes a controller (which can be a standalone process controller or an existing Advanced Process Control (APC)) that is configured to dynamically adjust reflux ratio of the demethanizer based on fluctuations in various process conditions, such as feed inlet temperature, feed inlet pressure, ambient conditions, refrigeration conditions/performance, feed composition, or any combinations of these. The controller can be configured to adjust reflux ratio of the demethanizer based on various target objectives. For example, in cases in which the feed flow rate to the demethanizer is substantially equal to maximum flow, the target objective of the controller can be set, such that the reflux ratio of the demethanizer is adjusted to achieve ethane recovery within a target range while minimizing energy consumption. As another example, in cases in which the feed flow rate to the demethanizer is less than the maximum flow, the target objective of the controller can be set, such that the reflux ratio of the demethanizer is adjusted to achieve maximum ethane recovery. In some implementations, the controller is configured to adjust reflux ratio of the demethanizer by targeting a minimum of the following parameter: power consumption divided by ethane recovery. In cases in which an existing APC is used to dynamically control reflux ratio of the demethanizer, the reflux ratio can be set as a Manipulated Variable (MV) while the remaining process conditions can be set as Disturbance Variables (DV).

[0018] FIG. 1 depicts an example system 100 for hydrocarbon distillation. The system 100 includes a demethanizer 120 and a de-ethanizer 140. The demethanizer 120 and the de-ethanizer 140 are part of a fractionation train that fractionates a hydrocarbon feed stream 101 into various process streams, for example, a residue gas stream 122, an ethane product stream 142, and a C3+ product stream 144. The hydrocarbon feed stream 101 includes a hydrocarbon or a mixture of hydrocarbons. For example, the hydrocarbon feed stream 101 includes methane, ethane, and propane. In some implementations, the hydrocarbon feed stream 101 includes hydrocarbons having a larger molecular weight (heavier) than propane. The residue gas stream 122 includes at least a portion (for example, a majority) of the methane from the hydrocarbon feed stream 101. The ethane product stream 142 includes at least a portion of the ethane from the hydrocarbon feed stream 101. The C3+ product stream 144 includes at least a portion of the propane (and any hydrocarbons heavier than propane) from the hydrocarbon feed stream 101.

[0019] The system 100 includes a cooler 102, a knockout drum 104, a turboexpander 106, a cross exchanger 108, and a reflux flow control valve 110. The cooler 102 is configured to cool the hydrocarbon feed stream 101. The knockout drum 104 is downstream of the cooler 102 and is configured to receive the cooled hydrocarbon feed stream 101 from the cooler 102. The knockout drum 104 is configured to separate the hydrocarbon feed stream 101 into a vapor phase 101a and a liquid phase 101b. The demethanizer 120 is configured to receive the liquid phase 101b from the knockout drum 104 as feed. The turboexpander 106 is downstream of the knockout drum 104 and upstream of the demethanizer 120. The turboexpander 106 is configured to receive a first portion 101a of the vapor phase 101a from the knockout drum 104. As the first portion 101a expands as it flows through the turboexpander 106, the turboexpander 106 generates electrical power. The demethanizer 120 is configured to receive the expanded first portion 101a from the turboexpander 106 as feed. The cross exchanger 108 is downstream of the knockout drum 104 and upstream of the demethanizer 120. The cross exchanger 108 is configured to receive and cool a second portion 101a of the vapor phase 101a from the knockout drum 104. The demethanizer 120 is configured to receive the cooled second portion 101a from the cross exchanger 108 as reflux. The reflux flow control valve 110 is downstream of the cross exchanger 108 and upstream of the demethanizer 120. The reflux flow control valve 110 is configured to control a flow rate of the second portion 101a flowing to the demethanizer 120 as reflux. As used in this disclosure, the term reflux is the second portion 101a that flows to the demethanizer 120. The demethanizer 120 is configured to fractionate the hydrocarbon feed stream 101 to produce the residue gas stream 122 as an overhead product and a bottoms stream 124 as a bottoms product. The de-ethanizer 140 is downstream of the demethanizer 120. The de-ethanizer 140 is configured to receive the bottoms stream 124 from the demethanizer 120. The de-ethanizer 140 is configured to fractionate the bottoms stream 124 to produce the ethane product stream 142 as an overhead product and the C3+ product stream 144 as a bottoms product.

[0020] The cooler 102 is a heat exchanger. The cooler 102 has a first side and a second side. In some implementations, the cooler 102 is a shell-and-tube type heat exchanger. For example, the first side of the cooler 102 can be the tube side, and the second side of the cooler 102 can be the shell side. As another example, the first side of the cooler 102 can be the shell side, and the second side of the cooler 102 can be the tube side. The first side of the cooler 102 can be configured to receive the hydrocarbon feed stream 101 via an inlet. The hydrocarbon feed stream 101 flows through the first side of the cooler 102. The second side of the cooler 102 can be configured to receive a refrigerant 201 via an inlet. The refrigerant 201 flows through the second side of the cooler 102. The cooler 102 is configured to transfer heat from the hydrocarbon feed stream 101 flowing through the first side to the refrigerant 201 flowing through the second side. The hydrocarbon feed stream 101 and the refrigerant 201 do not come into direct contact with one another in the cooler 102. Instead, the cooler 102 provides an intermediary heat transfer area to facilitate transfer of heat from the hydrocarbon feed stream 101 to the refrigerant 102. In some implementations, an operating temperature of the hydrocarbon feed stream 101 entering the first side of the cooler 102 is in a range of from about-42 degrees Celsius (C) to about 38 C. In some implementations, an operating temperature of the hydrocarbon feed stream 101 exiting the first side of the cooler 102 is in a range of from about 48 C. to about 55 C. In some implementations, an operating temperature of the refrigerant 102 entering the second side of the cooler 102 is in a range of from about 65 C. to about 60 C. In some implementations, an operating temperature of the refrigerant 102 exiting the second side of the cooler 102 is in a range of from about 65 C. to about 60 C. In some implementations, the operating temperature of the refrigerant 102 exiting the second side of the cooler 102 is substantially the same as the operating temperature of the refrigerant 102 entering the second side of the cooler 102. For example, the refrigerant 102 can provide cooling duty via latent heat transfer by evaporation of the refrigerant 102.

[0021] The knockout drum 104 is a separator vessel. The knockout drum 104 includes an inlet configured to receive the hydrocarbon feed stream 101 that has been cooled by the cooler 102. The knockout drum 104 is sized to allow the liquid phase 101b to condense and/or separate from the vapor phase 101a of the hydrocarbon feed stream 101. For example, the hydrocarbon feed stream 101 cooled by the cooler 102 can have at least partially condensed, and the knockout drum 104 provides residence time for separating the condensed liquid (liquid phase 101b) from the remaining vapor (vapor phase 101a). The knockout drum 104 includes a first outlet configured to discharge the vapor phase 101a from the knockout drum 104. The knockout drum 104 includes a second outlet configured to discharge the liquid phase 101b from the knockout drum 104. In terms of mass balance, the vapor phase 101a and the liquid phase 101b exiting the knockout drum 104 have a sum total of mass that is equal to the mass of the hydrocarbon feed stream 101 entering the knockout drum 104. In some implementations, the knockout drum 104 operates at an operating temperature in a range of from about 50 C. to about 57 C. In some implementations, the knockout drum 104 operates at an operating pressure in a range of from about 5,515 kilopascals (kPa) to about 6,205 kPa.

[0022] The turboexpander 106 includes a shaft and impellers coupled to the shaft. The turboexpander 106 includes a suction configured to receive the first portion 101a of the vapor phase 101a from the knockout drum 104. As the first portion 101a flows through the turboexpander 106 and expands. The shaft and impellers of the turboexpander 106 rotate in response to the first portion 101a flowing through and expanding across the turboexpander 106. The turboexpander 106 is configured to generate electrical power in response to rotation of the shaft. For example, the turboexpander 106 includes stator coils that generate electrical power in response to rotation of the shaft in relation to the stator coils. In some implementations, at least a portion of the electrical power generated by the turboexpander 106 is provided to different equipment in the system 100, thereby reducing overall power requirements of the system 100.

[0023] In some implementations, the shaft of the turboexpander 106 is coupled to a shaft of a compressor (not shown). In such implementations, the shaft of the compressor can rotate with the shaft of the turboexpander 106. In some implementations, the shaft of the turboexpander 106 is coupled to an impeller of the compressor by a drive shaft. In some implementations, the drive shaft directly couples the shaft of the turboexpander 106 to the impeller of the compressor, such that the turboexpander 106 and the compressor rotate at the same rotational speed. In some implementations, the shaft of the turboexpander 106 is coupled to the impeller of the compressor by a gear train with multiple drive shafts for indirectly coupling the shaft of the turboexpander 106 to the impeller of the compressor, such that the turboexpander 106 and the compressor rotate at different speeds. Because of the coupling of the shaft of the turboexpander 106 to the compressor, the expansion work from the expansion of the first portion 101a flowing through the turboexpander 106 can be transferred to the compressor for pressurizing a process fluid (such as the residue gas stream 122). By transferring expansion work from the turboexpander 106 to the compressor, the electrical power necessary for the compressor to pressurize a process fluid (such as the residue gas stream 122) can be reduced.

[0024] The cross exchanger 108 is a heat exchanger. The cross exchanger 108 has a first side and a second side. In some implementations, the cross exchanger 108 is a shell-and-tube type heat exchanger. For example, the first side of the cross exchanger 108 can be the shell side, and the second side of the cross exchanger 108 can be the tube side. As another example, the first side of the cross exchanger 108 can be the tube side, and the second side of the cross exchanger 108 can be the shell side. The first side of the cross exchanger 108 can be configured to receive the second portion 101a of the vapor phase 101a from the knockout drum 104 via an inlet. The second portion 101 flows through the first side of the cross exchanger 108. The second side of the cross exchanger 108 can be configured to receive at least a portion of the residue gas stream 122 via an inlet. The residue gas stream 122 flows through the second side of the cooler 102. The cross exchanger 108 is configured to transfer heat from the second portion 101a of the vapor phase 101a flowing through the first side to the residue gas stream 122 flowing through the second side. By transferring heat from the second portion 101a of the vapor phase 101a to the residue gas stream 122, the second portion 101a of the vapor phase 101a is cooled. Cooling the second portion 101a of the vapor phase 101a by the cross exchanger 108 can cause the second portion 101a to at least partially condense. In some cases, cooling the second portion 101a of the vapor phase 101a by the cross exchanger 108 causes the second portion 101a to fully condense. The second portion 101a of the vapor phase 101a and the residue gas stream 122 do not come into direct contact with one another in the cross exchanger 108. Instead, the cross exchanger 108 provides an intermediary heat transfer area to facilitate transfer of heat from the second portion 101a to the residue gas stream 122. In some implementations, an operating temperature of the second portion 101a of the vapor phase 101a entering the first side of the cross exchanger 108 is in a range of from about-50 degrees Celsius (C) to about 57 C. In some implementations, an operating temperature of the second portion 101a of the vapor phase 101a exiting the first side of the cross exchanger 108 is in a range of from about 50 C. to about 57 C. In some implementations, an operating temperature of the residue gas stream 122 entering the second side of the cross exchanger 108 is in a range of from about 107 C. to about 104 C. In some implementations, an operating temperature of the residue gas stream 122 exiting the second side of the cross exchanger 108 is in a range of from about 73 C. to about 70 C.

[0025] The reflux flow control valve 110 is a control valve configured to adjust a flow rate of the second portion 101a flowing from the first side of the cross exchanger 108 to the demethanizer 120 as reflux. A percent (%) opening of the reflux flow control valve 110 is adjustable. Adjusting the % opening of the reflux flow control valve 110 adjusts the flow rate of the second portion 101a flowing to the demethanizer 120 as reflux. For example, decreasing the % opening of the reflux flow control valve 110 decreases the flow rate of the second portion 101a flowing to the demethanizer 120 as reflux. As another example, increasing the % opening of the reflux flow control valve 110 increases the flow rate of the second portion 101a flowing to the demethanizer 120 as reflux.

[0026] Although not shown in FIG. 1, the system 100 can include a bypass flowline that branches from the suction line of the turboexpander 106 and connects back to the discharge line of the turboexpander 106. The bypass flowline provides an alternate flow path for at least a portion of the first portion 101a of the vapor phase 101a to bypass the turboexpander 106. A throttle valve can be installed on the bypass flowline. The throttle valve can modulate pressure of the portion of the first portion 101a that flows through the bypass flowline and bypasses the turboexpander 106, such that the operating pressure matches the discharge pressure of the portion of the first portion 101a exiting the turboexpander 106. The throttle valve can be, for example, a Joule-Thomson valve. Inclusion of the bypass flowline and throttle valve can allow for stable operation of the turboexpander 106 even as the reflux rate (and reflux ratio) is dynamically adjusted.

[0027] The demethanizer 120 is a distillation tower. Although not shown, the demethanizer 120 can include equipment and components typical of distillation towers. For example, the demethanizer 120 includes trays, a reboiler, a condenser, and pumps. The demethanizer 120 is configured to fractionate the hydrocarbon feed stream 101 into two or more process streams based on differences in relative volatility of the components of the hydrocarbon feed stream 101. The demethanizer 120 can receive various portions of the hydrocarbon feed stream 101 as feed or reflux. For example, the demethanizer 120 includes a first inlet configured to receive the liquid phase 101b of the hydrocarbon feed stream 101 as feed. As another example, the demethanizer 120 includes a second inlet configured to receive the first portion 101a of the vapor phase 101a of the hydrocarbon feed stream 101 as feed. As another example, the demethanizer 120 includes a third inlet configured to receive the second portion 101a of the vapor phase 101a of the hydrocarbon feed stream 101 as reflux. The demethanizer 120 can, for example, separate the residue gas stream 122 from the hydrocarbon feed stream 101 as an overhead product. The residue gas stream 122 can include the lightest (lowest boiling point and/or lowest molecular weight) components of the hydrocarbon feed stream 101. For example, the residue gas stream 122 includes methane. The demethanizer 120 can, for example, separate the bottoms stream 124 from the hydrocarbon feed stream 101 as a bottoms product. The bottoms stream 124 can include the heaviest (highest boiling point and/or highest molecular weight) components of the hydrocarbon feed stream 101. For example, the bottoms stream 124 includes ethane and propane. In some implementations, the bottoms stream 124 includes a hydrocarbon having a number of carbon atoms of three or greater (C3+), such as butane.

[0028] The de-ethanizer 140 is a distillation tower. Although not shown, the demethanizer 120 can include equipment and components typical of distillation towers. For example, the de-ethanizer 140 includes trays, a reboiler, a condenser, and pumps. The de-ethanizer 140 is configured to fractionate the bottoms stream 124 into two or more process streams based on differences in relative volatility of the components of the hydrocarbon feed stream 101. The de-ethanizer 140 includes an inlet configured to receive the bottoms stream 124 from the demethanizer 120. The de-ethanizer 140 can, for example, separate the ethane product stream 142 from the bottoms stream 124 as an overhead product. The ethane product stream 142 can include the lightest (lowest boiling point and/or lowest molecular weight) components of the bottoms stream 124. For example, the ethane product stream 142 includes ethane. The de-ethanizer 140 can, for example, separate the C3+ product stream 144 from the bottoms stream 124 as a bottoms product. The C3+ product stream 144 can include the heaviest (highest boiling point and/or highest molecular weight) components of the bottoms stream 124. For example, the C3+ product stream 144 includes propane. In some implementations, the C3+ product stream 144 includes a hydrocarbon having a number of carbon atoms of three or greater (C3+), such as butane.

[0029] The system 100 includes flow sensors distributed across the system 100. In some implementations, as shown in FIG. 1, the system 100 includes a first flow sensor 103a, a second flow sensor 103b, a third flow sensor 103c, and a fourth flow sensor 103d. The first flow sensor 103a is installed on a flowline flowing the first portion 101a of the vapor phase 101a from the knockout drum 104 to the turboexpander 106. The first flow sensor 103a is configured to measure a flow rate (such as a volumetric flow rate or a mass flow rate) of the first portion 101a of the vapor phase 101a flowing from the knockout drum 104 to the turboexpander 106. The second flow sensor 103b is installed on a flowline flowing the second portion 101a of the vapor phase 101a from the knockout drum 104 to the first side of the cross exchanger 108. The second flow sensor 103b is configured to measure a flow rate (such as a volumetric flow rate or a mass flow rate) of the second portion 101a of the vapor phase 101a flowing from the knockout drum 104 to the first side of the cross exchanger 108. The third flow sensor 103c is installed on a flowline flowing the residue gas stream 122 from the demethanizer 120 to the second side of the cross exchanger 108. The third flow sensor 103c is configured to measure a flow rate (such as a volumetric flow rate or a mass flow rate) of the residue gas stream 122 flowing from the demethanizer 120 to the second side of the cross exchanger 108. The fourth flow sensor 103d is installed on a flowline flowing the C3+ product stream 144 produced by the de-ethanizer 140. The fourth flow sensor 103d is configured to measure a flow rate (such as a volumetric flow rate or a mass flow rate) of the C3+ product stream 144 produced by the de-ethanizer 140. Although shown in FIG. 1 as having four flow sensors (103a, 103b, 103c, 103d), the system 100 can include a different number of flow sensors (such as one, two, three, five, or more than five) for measuring flow rates of various process streams in the system 100.

[0030] The system 100 includes a pressure sensor 105 installed on a flowline flowing the hydrocarbon feed stream 101 to the cooler 102. The pressure sensor 105 is configured to measure an operating pressure of the hydrocarbon feed stream 101 flowing to the cooler 102. Although shown in FIG. 1 as having one pressure sensor (105), the system 100 can include additional pressure sensors (such as two, three, four, or more than four) for measuring operating pressures of various process streams and/or equipment in the system 100.

[0031] The system 100 includes a temperature sensor 107 installed on a flowline flowing the hydrocarbon feed stream 101 from the cooler 102 to the knockout drum 104. The temperature sensor 107 is configured to measure an operating temperature of the hydrocarbon feed stream 101 flowing from the cooler 102 to the knockout drum 104. Although shown in FIG. 1 as having one temperature sensor (107), the system 100 can include additional temperature sensors (such as two, three, four, or more than four) for measuring operating pressures of various process streams and/or equipment in the system 100.

[0032] The system 100 includes composition analyzers distributed across the system 100. The composition analyzers of the system 100 can include gas composition analyzers, liquid composition analyzers, or both. The composition analyzers of the system 100 can include, for example, gas chromatographs that can determine a composition of a fluid sample of a process stream. Some non-limiting examples of a gas chromatograph include a flame ionization detector (FID), a thermal conductivity detector (TCD), a mass spectrometer, a vacuum ultraviolet detector, a helium ionization detector, an infrared detector, a photoionization detector (PID), and a pulsed discharge ionization detector. In some cases, the composition analyzers of the system 100 measure a concentration of a specific component of a process stream. For example, the composition analyzers of the system 100 can measure an ethane content of a process stream. In some implementations, as shown in FIG. 1, the system 100 includes a first composition analyzer 109a, a second composition analyzer 109b, and a third composition analyzer 109c. The first composition analyzer 109a is installed on a flowline flowing the hydrocarbon feed stream 101 to the cooler 102. The first composition analyzer 109a is configured to determine a composition of the hydrocarbon feed stream 101 flowing to the cooler 102. In some implementations, the first composition analyzer 109a is configured to determine an ethane content of the hydrocarbon feed stream 101 flowing to the cooler 102. The second composition analyzer 109b is installed on a flowline flowing the residue gas stream 122 from the demethanizer 120 to the cross exchanger 108. The second composition analyzer 109b is configured to determine a composition of the residue gas stream 122 flowing from the demethanizer 120 to the cross exchanger 108. In some implementations, the second composition analyzer 109b is configured to determine an ethane content of the residue gas stream 122 flowing from the demethanizer 120 to the cross exchanger 108. The third composition analyzer 109c is installed on a flowline flowing the C3+ product stream 144 produced by the de-ethanizer 140. The third composition analyzer 109c is configured to determine a composition of the C3+ product stream 144 produced by the de-ethanizer 140. In some implementations, the third composition analyzer 109c is configured to determine an ethane content of the C3+ product stream 144 produced by the de-ethanizer 140. Although shown in FIG. 1 as having three composition analyzers (109a, 109b, 109c), the system 100 can include a different number of composition analyzers (such as one, two, four, or more than four) for measuring compositions of various process streams in the system 100.

[0033] The system 100 includes a refrigeration cycle 200. The cooler 102 and the refrigerant 201 are part of the refrigeration cycle 200. The refrigeration cycle 200 includes a refrigerant flow control valve 202 configured to control a flow rate of the refrigerant 201 flowing through the cooler 102. The refrigerant flow control valve 202 can adjust the flow rate of the refrigerant 201 flowing through the cooler 102 to adjust a cooling duty of the cooler 102 for cooling the hydrocarbon feed stream 101. An implementation of the refrigeration cycle 200 is shown in FIG. 2 and is described in more detail later.

[0034] The system 100 includes a controller 190, which includes a processor 192 and a memory 194. The controller 190 is communicatively coupled to various components of the system 100. For example, the controller 190 is communicatively coupled to the flow sensors (103a, 103b, 103c, 103d), the pressure sensor 105, the temperature sensor 107, the composition analyzers (109a, 109b, 109c), the reflux flow control valve 110, and the refrigerant flow control valve 202. The controller 190 can adaptively and dynamically control operation of the system 100. For example, the controller 190 can dynamically control a reflux ratio of the demethanizer 120. Reflux ratio of the demethanizer 120 is directly proportional to the flow rate of reflux (second portion 101a) provided to the demethanizer 120. Thus, adjusting the flow rate of reflux (second portion 101a) provided to the demethanizer 120 is directly related to adjusting the reflux ratio of the demethanizer 120. As used in this disclosure, the term reflux ratio refers to the ratio (by volume or by mass) between the second portion 101a and the sum of the first portion 101a and the second portion 101a (reflux ratio=(flow rate of second portion 101a)/(flow rate of first portion 101a+flow rate of second portion 101a)). By dynamically controlling reflux rate to the demethanizer 120, the controller 190 can adaptively control operation of the system 100 to not only meet ethane specification requirements but also minimize power consumption of the system 100, even when process disturbances are encountered. One non-limiting example of a process disturbance is hot ambient temperature, which can lead to an increased temperature of the hydrocarbon feed stream 101 and a hotter temperature profile of the overall system 100. Another non-limiting example of a process disturbance is low refrigeration performance of the refrigeration cycle 200, which can lead to increased temperature of the hydrocarbon feed stream 101 and a hotter temperature profile of the overall system 100. Another non-limiting example of a process disturbance is a change in ethane-to-methane ratio in the hydrocarbon feed stream 101 due to a variation/disturbance in an upstream system, which can affect ethane recovery by the system 100. Another non-limiting example of a process disturbance is lower than expected arrival pressure of the hydrocarbon feed stream 101, which can lead to reduced cooling from expansion across the turboexpander 106 and a hotter temperature profile of the overall system 100. In some cases, multiple process disturbances are encountered simultaneously.

[0035] The first flow sensor 103a is configured to transmit the measured flow rate (such as a volumetric flow rate or a mass flow rate) of the first portion 101a of the vapor phase 101a flowing from the knockout drum 104 to the turboexpander 106 to the controller 190. The second flow sensor 103b is configured to transmit the measured flow rate (such as a volumetric flow rate or a mass flow rate) of the second portion 101a of the vapor phase 101a flowing from the knockout drum 104 to the first side of the cross exchanger 108 to the controller 190. The third flow sensor 103c is configured to transmit the measured flow rate (such as a volumetric flow rate or a mass flow rate) of the residue gas stream 122 flowing from the demethanizer 120 to the second side of the cross exchanger 108 to the controller 190. The fourth flow sensor 103d is configured to transmit the measured flow rate (such as a volumetric flow rate or a mass flow rate) of the C3+ product stream 144 produced by the de-ethanizer 140 to the controller 190. The pressure sensor 105 is configured to transmit the measured operating pressure of the hydrocarbon feed 101 flowing to the cooler 102 to the controller 190. The temperature sensor 107 is configured to transmit the measured operating temperature of the hydrocarbon feed stream 101 flowing from the cooler 102 to the knockout drum 104 to the controller 190. The first composition analyzer 109a is configured to transmit the determined composition (or determined ethane content) of the hydrocarbon feed stream 101 flowing to the cooler 102 to the controller 190. The second composition analyzer 109b is configured to transmit the determined composition (or determined ethane content) of the residue gas stream 122 flowing from the demethanizer 120 to the cross exchanger 108 to the controller 190. The third composition analyzer 109c is configured to transmit the determined composition (or determined ethane content) of the C3+ product stream 144 produced by the de-ethanizer 140 to the controller 190.

[0036] Based on the data received from the various sensors, the controller 190 can determine an ethane recovery value. The ethane recovery value can be calculated, for example, by Equation 1.

[00001]$\begin{array}{cc}\mathrm{Ethane}\mathrm{Recovery}=1-\frac{\mathrm{Ethane}\mathrm{content}\mathrm{of}\mathrm{Residue}\mathrm{Gas}+\mathrm{Ethane}\mathrm{content}\mathrm{of}\mathrm{Bottoms}}{\mathrm{Ethane}\mathrm{content}\mathrm{Hydrocarbon}\mathrm{Feed}}& \left(1\right)\end{array}$ [0037] where Ethane content of Residue Gas is the received ethane content of the residue gas stream 122, Ethane content of Bottoms is the received ethane content of the C3+ product stream 144, and Ethane content of Hydrocarbon Feed is the received ethane content of the hydrocarbon feed stream 101.

[0038] In some implementations, the controller 190 transmits a reflux flow signal to the reflux flow control valve 110 to adjust a % opening of the reflux flow control valve 110, thereby adjusting the flow rate of the reflux (second portion 101a) provided to the demethanizer 120. Transmitting the reflux flow signal to the reflux flow control valve 110 directly affects the reflux rate (and reflux ratio) of the demethanizer 120. Adjusting the reflux rate provided to the demethanizer 190 can affect the ethane recovery value.

[0039] In some implementations, the controller 190 transmits a refrigerant flow signal to the refrigerant flow control valve 202 to adjust a % opening of the refrigerant flow control valve 202, thereby adjusting the flow rate of the refrigerant 201 flowing through the cooler 102. Transmitting the refrigerant flow signal to the refrigerant flow control valve 202 directly affects power consumption by the refrigeration cycle 200. For example, decreasing the flow rate of the refrigerant 201 flowing through the cooler 102 can reduce the power consumption by the refrigeration cycle 200. As another example, increasing the flow rate of the refrigerant 201 flowing through the cooler 102 can increase the power consumption by the refrigeration cycle 200. Adjusting the flow rate of the refrigerant 201 flowing through the cooler 102 can adjust the extent of cooling of the hydrocarbon feed stream 101, which can affect the ethane recovery value.

[0040] In some implementations, the controller 190 transmits the reflux flow signal to the reflux flow control valve 110 and the refrigerant flow signal to the refrigerant flow control valve 202 to adjust the reflux rate of the demethanizer 120 and to adjust the power consumption of the refrigeration cycle 200, respectively. Transmitting the reflux flow signal and the refrigerant flow signal can affect the ethane recovery value. The controller 190 can be configured to transmit the reflux flow signal, the refrigerant flow signal, or both to ensure that the ethane recovery value remains at or above a specified target ethane recovery set point. A user can input the specified target ethane recovery set point into the controller 190. The specified target ethane recovery set point can be stored, for example, in the memory 194 of the controller 190. The specified target ethane recovery set point can be set, for example, to meet target specifications (such as a minimum ethane production rate) for the ethane product stream 122 produced by the de-ethanizer 140. In some implementations, the specified target ethane recovery set point is in a range of from about 85% to about 100%, about 85% to about 96%, 90% to about 100%, about 92% to about 100%, about 94% to about 100%, about 96% to about 100%, about 98% to about 100%, about 90% to about 99%, about 92% to about 99%, about 94% to about 99%, about 96% to about 99%, about 98% to about 99%, about 90% to about 98%, about 92% to about 98%, about 94% to about 98%, about 96% to about 98%, about 90% to about 96%, about 92% to about 96%, about 94% to about 96%, about 90% to about 94%, about 92% to about 94%, or about 90% to about 92%.

[0041] The controller 190 can be configured to transmit the reflux flow signal, the refrigerant flow signal, or both to minimize power consumption of the refrigeration cycle 200 while maintaining the ethane recovery value to be equal to or greater than the specified target ethane recovery set point. In some cases, the controller 190 transmits the reflux flow signal to the reflux flow control valve 110 to adjust the reflux rate (and reflux ratio) of the demethanizer 120 while maintaining the power consumption of the refrigeration cycle 200 by maintaining the % opening of the refrigerant flow control valve 202. This can be useful in maximizing the ethane recovery value at a specified power consumption of the refrigeration cycle 200. In some cases, the controller 190 transmits the refrigerant flow signal to the refrigerant flow control valve 202 to adjust power consumption of the refrigeration cycle 200 while maintaining the reflux rate (and reflux ratio) of the demethanizer 120 by maintaining the % opening of the reflux flow control valve 110. This can be useful in minimizing power consumption of the refrigeration cycle 200 at a specified ethane recovery value (that is still at or above the specified target ethane recovery set point). In some cases, the controller 190 transmits the reflux flow signal to the reflux flow control valve 110 and then transmits the refrigerant flow signal to the refrigerant flow control valve 202 to maximize efficiency by minimizing power consumption of the refrigeration cycle 200 while still maintaining the ethane recovery value to be equal to or greater than the specified target ethane recovery set point. Because adjustment of the reflux rate (and reflux ratio) of the demethanizer 120 directly affects the flow rate of the first portion 101a flowing through the turboexpander 106, the controller 190 can be configured to adjust the % opening of the reflux flow control valve 110 at a rate that is sufficiently slow as to avoid mechanical disturbances to the turboexpander 106, which is rotating equipment.

[0042] The controller 190 can adjust the reflux rate (and reflux ratio) of the demethanizer 120 in real-time based on a specified target constraint. For example, a specified target constraint can be an ethane content of the residue stream 122 in a range of from about 1.5% to about 2.5% (by weight, volume, or mole) or less than 2.5%. As another example, a specified target constraint can be an inlet temperature of the first portion 101a entering the turboexpander 106 in a range of from about 45.6 C. to about 42.8 C. As another example, a specified target constraint can be an inlet pressure of the first portion 101a entering the turboexpander 106 in a range of from about 5,515 kPa to about 6,205 kPa. As another example, a specified target constraint can be a turndown ratio of about 30%. Turndown ratio is a ratio of maximum to minimum vapor load that the trays of the demethanizer 120 can handle without compromising desired product specifications (for example, of the residue gas stream 122, of the ethane product stream 124, or of the C3+ product stream 144). The controller 190 can, for example, adjust the reflux rate (and reflux ratio) of the demethanizer 120 in real-time based on multiple specified target constraints, for example, any combinations of the example specified target constraints described.

[0043] The controller 190 can adjust the reflux rate (and reflux ratio) of the demethanizer 120 in real-time based on detected fluctuation(s) in the system 100. For example, if the operating pressure of the hydrocarbon feed stream 101 decreases, cooling provided by expansion of the first portion 101a through the turboexpander will decrease, and the operating temperature of the feed provided to the demethanizer 120 will be hotter. In such cases, the controller 190 can increase the reflux rate (and reflux ratio) of the demethanizer 120. As another example, if the operating temperature of the hydrocarbon feed stream 101 increases (for example, due to hotter ambient conditions) while the operating pressure remains the same, the controller 190 can increase the reflux rate (and reflux ratio) of the demethanizer 120 to avoid ethane slippage into the demethanizer 120 overhead (via the residue stream 122). As another example, if the composition of the hydrocarbon feed stream 101 fluctuates to an increased content of hydrocarbons heavier than methane, the controller 190 can decrease the reflux rate (and reflux ratio) of the demethanizer 120 to avoid ethane slippage into the demethanizer 120 overhead (via the residue stream 122). As another example, if the ethane content of the residue stream 122 decreases to below 1.5% (by mole or volume), then the controller 190 can adjust the rate of cooling provided to the hydrocarbon feed stream 101 via cooler 102 by adjusting the % opening of the valve 202 to decrease the flow rate of the refrigerant 201 flowing through the cooler 102. The controller 190 can adjust the reflux rate (and reflux ratio) of the demethanizer 120 and/or the power consumption by the refrigeration cycle 200 in real-time based on specified target constraint(s) and/or detected fluctuation(s) in the system 100. In some implementations, the controller 190 can perform a sensitivity analysis to determine the degree at which any of the specified target constraint(s) and/or detected fluctuation(s) impact ethane recovery by the system 100. For example, if a certain specified target constraint impacts ethane recovery by the system 100 to a greater degree in comparison to a different specified target constraint, the controller 190 can attribute a larger factor to that specified target constraint in adjusting the reflux rate (and reflux ratio) of the demethanizer 120 and/or the power consumption by the refrigeration cycle 200. As another example, if a certain specified target constraint impacts ethane recovery by the system 100 to a lesser degree in comparison to a different specified target constraint, the controller 190 can attribute a smaller factor to that specified target constraint in adjusting the reflux rate (and reflux ratio) of the demethanizer 120 and/or the power consumption by the refrigeration cycle 200. As another example, if a certain fluctuation in process condition impacts ethane recovery by the system 100 to a greater degree in comparison to a different fluctuation in process condition, the controller 190 can attribute a larger factor to that certain fluctuation in process condition in adjusting the reflux rate (and reflux ratio) of the demethanizer 120 and/or the power consumption by the refrigeration cycle 200. As another example, if a certain fluctuation in process condition impacts ethane recovery by the system 100 to a lesser degree in comparison to a different fluctuation in process condition, the controller 190 can attribute a smaller factor to that certain fluctuation in process condition in adjusting the reflux rate (and reflux ratio) of the demethanizer 120 and/or the power consumption by the refrigeration cycle 200. In some implementations, the controller 190 is configured adjust the attributed factor for any of the specified target constraint(s) and/or detected fluctuation(s) based on, for example, historical data or sensitivity analysis.

[0044] FIG. 2 depicts an example refrigeration cycle 200 that can provide cooling to a hydrocarbon distillation system (such as the system 100). The refrigeration cycle 200 includes the cooler 102, the refrigerant flow control valve 202, a knockout drum 204, a compressor 206, a second cooler 208, and an accumulator 210. The refrigerant 201 cycles through the components of the refrigeration cycle 200. In some implementations, the refrigerant 201 includes propane. The refrigerant 201 (as a liquid phase) flows through the second side of the cooler 102. As the refrigerant 201 flows through the second side of the cooler 102, the cooler 102 transfers heat from the hydrocarbon feed stream 101 (shown in FIG. 1) to the refrigerant 201. In effect, the cooler 102 cools the hydrocarbon feed stream 101 via heat transfer with the refrigerant 201. Transfer of heat from the hydrocarbon feed stream 101 to the refrigerant 201 causes the refrigerant to evaporate. The refrigerant 201 (as a vapor phase) flows from the cooler 102 to the knockout drum 204. The refrigerant 201 flows from the knockout drum 204 to the compressor 206. The compressor 206 pressurizes the refrigerant 201. The pressure of the refrigerant 201 exiting the compressor 206 is higher than the pressure of the refrigerant 201 entering the compressor 206. Pressurizing the refrigerant 201 by the compressor 206 results in an increase in temperature of the refrigerant 201. The temperature of the refrigerant 201 exiting the compressor 206 is higher than the temperature of the refrigerant 201 entering the compressor 206. The refrigerant 201 flows from the compressor 206 to the second cooler 208. The second cooler 208 cools the refrigerant 201. Cooling the refrigerant 201 by the second cooler 208 can cause the refrigerant to condense. The refrigerant 201 (as a liquid phase) flows from the second cooler 208 to the accumulator 210. The refrigerant 201 flows from the accumulator 210 to the refrigerant flow control valve 202. The refrigerant 201 flows through the refrigerant flow control valve 202. The refrigerant 201 flows from the refrigerant flow control valve 202 to the second side of the cooler 102. In this way, the refrigerant 201 cycles through the refrigeration cycle 200.

[0045] The refrigerant flow control valve 202 is a control valve configured to adjust a flow rate of the refrigerant 201 flowing to the cooler 102. A % opening of the refrigerant flow control valve 202 is adjustable. Adjusting the % opening of the refrigerant flow control valve 202 adjusts the flow rate of the refrigerant 201 flowing to the cooler 102. For example, decreasing the % opening of the refrigerant flow control valve 202 decreases the flow rate of the refrigerant 201 flowing to the cooler 102. As another example, increasing the % opening of the refrigerant flow control valve 202 increases the flow rate of the refrigerant 201 flowing to the cooler 102.

[0046] The knockout drum 204 is a separator vessel. The knockout drum 204 includes an inlet configured to receive the refrigerant 201 from the cooler 102. The knockout drum 204 is sized to allow any liquid that may have condensed from the refrigerant 201 to settle at the bottom of the knockout drum 204. While condensation of the refrigerant 201 is not typical, the knockout drum 204 is included in the refrigeration cycle 200 as a safety measure to protect the compressor 206 by ensuring liquid is prevented from entering the suction of the compressor 206.

[0047] The compressor 206 is rotating equipment that pressurizes the refrigerant 201. The compressor 206 includes a shaft and impellers coupled to the shaft. The shaft and impellers of the compressor 206 rotate. Rotation of the shaft and impellers of the compressor 206 pressurizes the refrigerant 201. Power is required to rotate the shaft and impellers of the compressor 206. In some implementations, at least a portion of the power supplied to the compressor 206 to pressurize the refrigerant 201 in sourced from the electrical power generated by the turboexpander 106 (shown in FIG. 1). The compressor 206 can be, for example, a single-stage compressor or a multi-stage compressor (such as a two-stage compressor or three-stage compressor).

[0048] The second cooler 208 can be, for example, a fin-fan cooler. The second cooler 208 cools and condenses the refrigerant 201 downstream of the compressor 206. The accumulator 210 is a vessel. The accumulator 210 is sized to ensure sufficient supply of refrigerant 201 as a liquid phase is available for providing cooling duty to the cooler 102 even if a process disturbance is encountered.

[0049] Although shown as including one of each of the cooler 102, the refrigerant flow control valve 202, the knockout drum 204, the compressor 206, the second cooler 208, and the accumulator 210, the refrigeration cycle 200 can optionally include multiple implementations of any of these components. For example, an additional implementation of the cooler 102, the refrigerant flow control valve 202, the knockout drum 204, and the accumulator 210 can branch from the refrigeration cycle 200, in which the additional implementation of the cooler 102 is used to cool another process stream (for example, other than the hydrocarbon feed stream 101) of the system 100. In cases where the refrigeration cycle 200 includes multiple branches for cooling various process streams of the system 100, a larger overall flow rate of the refrigerant 201 cycling through the refrigeration cycle 200 may be required.

[0050] In each of the configurations described with respect to the system 100 (shown in FIG. 1) and their subsystems, process streams (also referred to as streams) are flowed within each subsystem of the system 100 and between subsystems of the system 100. The process streams can be flowed using one or more flow control systems implemented throughout the system 100 (and/or its subsystems). For simplicity and clarity, the following description of the flow control system is described with respect to system 100, but the same concepts apply to the refrigeration cycle 200. A flow control system can include one or more flow pumps to pump the process streams, one or more compressors to pressurize the process streams (such as the refrigerant 201), one or more flow pipes through which the process streams (such as the hydrocarbon feed stream 101) are flowed, and one or more valves (such as the reflux flow control valve 110) to regulate the flow of streams through the pipes.

[0051] In some implementations, a flow control system can be operated manually. For example, an operator can set a flow rate for each pump and/or compressor by changing the position of a valve (open, partially open, or closed) to regulate the flow of the process streams through the pipes in the flow control system. Once the operator has set the flow rates and the valve positions for all flow control systems distributed across the system 100 (and/or its subsystems), the flow control system can flow the streams within a unit or between units under constant flow conditions, for example, constant volumetric or mass flow rates. To change the flow conditions, the operator can manually operate the flow control system, for example, by changing the valve position.

[0052] In some implementations, a flow control system can be operated automatically. For example, the flow control system can be connected to the controller 190 to operate the flow control system. The controller 190 can include a computer-readable medium storing instructions (such as flow control instructions stored by the memory 194) executable by one or more processors (such as the processor 192) to perform operations (such as flow control operations). For example, an operator can set the flow rates by setting the valve positions for all flow control systems distributed across the system 100 (and/or its subsystems) using the controller 190. In such implementations, the operator can manually change the flow conditions by providing inputs through the controller 190. In such implementations, the controller 190 can automatically (that is, without manual intervention) control one or more of the flow control systems, for example, using feedback systems implemented in one or more units and connected to the controller 190. For example, a sensor (such as a pressure sensor, temperature sensor, flow sensor, or a composition analyzer) can be connected to a pipe through which a process stream flows. The sensor can monitor and provide a flow conditions (such as a pressure, temperature, flow rate, or composition) of the process stream to the controller 190. In response to the flow condition deviating from a set point (such as a target value) or exceeding a threshold (such as a threshold value), the controller 190 can automatically perform operations. For example, if the pressure or temperature in the pipe exceeds the threshold pressure value or the threshold temperature value, respectively, the controller 190 can provide a signal to open a valve to relieve pressure or a signal to shut down process stream flow.

[0053] FIG. 3A is a flow chart of an example method 300A for controlling operation of a hydrocarbon distillation system (such as the system 100). The method 300A can, for example, be implemented to dynamically control reflux rate of the demethanizer 120. At block 302, a controller (such as the controller 190) receives an ethane content of each of a hydrocarbon feed stream (such as the hydrocarbon feed stream 101), a residue stream (such as the residue stream 122), and a bottoms stream (such as the C3+ product stream 144). The ethane content of the hydrocarbon feed stream 101 received by the controller 190 at block 302 can, for example, be measured by the first composition analyzer 109a and transmitted to the controller 190. The ethane content of the residue stream 122 received by the controller 190 at block 302 can, for example, be measured by the second composition analyzer 109b and transmitted to the controller 190. The ethane content of the C3+ product stream 144 received by the controller 190 at block 302 can, for example, be measured by the third composition analyzer 109c and transmitted to the controller 190.

[0054] At block 304, the controller 190 determines an ethane recovery value at least based on the received ethane contents of the hydrocarbon feed stream 101, the residue stream 122, and the C3+ product stream 144 (from block 302). The ethane recovery value determined by the controller 190 at block 304 can, for example, be calculated from Equation 1. The controller 190 can compare the ethane recovery value determined at block 304 with the specified target ethane recovery set point, which can be stored in the memory 194 of the controller 190. At block 306, the controller 190 receives a flow rate of reflux provided to the demethanizer 120. For example, the flow rate of reflux received by the controller 190 at block 306 can be the flow rate (such as volumetric or mass flow rate) of the second portion 101a measured and transmitted by the second flow sensor 103b to the controller 190. The controller 190 can perform block 304 in real-time. For example, the controller 190 can determine the ethane recovery value at block 304 within milliseconds of receiving the ethane content of each of the hydrocarbon feed stream 101, the residue stream 122, and the C3+ product stream 144 at block 302, such that the ethane recovery determined at block 304 is available virtually immediately as feedback.

[0055] At block 308, the controller 190 transmits a reflux flow signal to a reflux flow control valve (such as the reflux flow control valve 110) to adjust the flow rate of reflux provided to the demethanizer 120. The reflux flow signal transmitted by the controller 190 to the reflux flow control valve 110 at block 308 causes the reflux flow control valve 110 to adjust its % opening, such that the flow rate of reflux (second portion 101a) provided to the demethanizer 120 is adjusted, and the ethane recovery value (determined at block 304) is maintained to be equal to or greater than the specified target ethane recovery set point. For example, if the controller 190 determines that the ethane recovery value determined at block 304 is less than the specified target ethane recovery set point, the controller 190 can transmit the reflux flow signal to the reflux control valve 110 to increase the flow rate of reflux provided to the demethanizer 120. The controller 190 can repeat blocks 302 and 304 to recalculate the ethane recovery value after adjusting the flow rate of reflux provided to the demethanizer 120 at block 308. For example, the controller 190 can iterate blocks 302, 304, and 308 to maintain the determined ethane recovery value at or above the specified target ethane recovery set point. The controller 190 can perform block 308 in real-time. For example, the controller 190 can transmit the reflux flow signal to the reflux control valve 110 at block 308 within milliseconds of determining the ethane recovery value at block 304 and comparing the ethane recovery value determined at block 304 with the specified target ethane recovery set point. For example, the controller 190 can iterates blocks 302, 304, and 308 in real-time.

[0056] At block 310, the controller 190 receives a power consumption of a refrigeration cycle (such as the refrigeration cycle 200) that provides cooling to the hydrocarbon feed stream 101. The power consumption of the refrigeration cycle 200 provided to the controller 190 can include, for example, the power consumed by the compressor 204 of the refrigeration cycle 200. At block 312, the controller 190 determines an objective value as a ratio of the determined power consumption (block 310) to the determined ethane recovery value (block 304). It is recognized that the units of power consumption may not match the units of the ethane recovery value. However, the units are not significant, as the goal is to simply minimize the magnitude of the determined objective value (block 312).

[0057] After adjusting the flow rate of reflux provided to the demethanizer 120 at block 308, the controller 190 transmits a refrigerant flow signal to reduce power consumed by the refrigeration cycle 200 at block 314. For example, the controller 190 transmits the refrigerant flow signal to the refrigerant flow control valve 202 at block 314, which causes the % opening of the refrigerant flow control valve 202 to reduce, thereby reducing the flow rate of the refrigerant 201 flowing through the second side of the cooler 102 and reducing the power consumption of the refrigeration cycle 200. The controller 190 can perform block 314 in real-time. For example, the controller 190 can transmit the refrigerant flow signal at block 314 within milliseconds of determining the objective value at block 312. Reducing the power consumed by the refrigeration cycle at block 200 reduces the objective value (block 312). The ethane recovery value (block 304) is maintained at or above the specified target ethane recovery set point during block 314. For example, the power consumed by the refrigeration cycle 200 is reduced at block 314 to a point at which the ethane recovery value (block 304) is maintained at or above the specified target ethane recovery set point during block 314. Block 304 can be repeated simultaneously with block 308 to ensure that the ethane recovery value is maintained at or above the specified target ethane recovery set point. For example, the controller 190 can repeat block 304 while performing block 308 in real-time. If reducing the power consumed by the refrigeration cycle 200 at block 314 happens to reduce the ethane recovery value (block 304) to below the specified target ethane recovery set point, block 308 can be repeated to adjust the ethane recovery value back to being equal to or greater than the specified target ethane recovery set point. Blocks 308 and 314 can, for example, be iterated in real-time to maintain ethane recovery to meet target specifications while also minimizing power consumption by the system 100.

[0058] FIG. 3B is a flow chart of an example method 300B for controlling operation of a hydrocarbon distillation system (such as the system 100). At block 320, a cooler (such as the cooler 102) transfers heat from a hydrocarbon feed stream (such as the hydrocarbon feed stream 101) to a refrigerant (such as the refrigerant 201) cycling through a refrigeration cycle (such as the refrigeration cycle 200). At block 322, a distillation unit (such as the system 100) fractionates the hydrocarbon feed stream 101 to produce a residue gas stream (such as the residue gas stream 122), an ethane product stream (such as the ethane product stream 142), and a bottoms stream (such as the C3+ product stream 144). The distillation unit (system 100) includes the demethanizer 120 and the de-ethanizer 140.

[0059] Fractionating the hydrocarbon feed stream 101 at block 322 includes separating the hydrocarbon feed stream 101 into a vapor phase (such as the vapor phase 101a) and a liquid phase (such as the liquid phase 101b) at block 322a. Separating the hydrocarbon feed stream 101 into the vapor phase 101a and the liquid phase 101b at block 322a can be performed, for example, by the knockout drum 104. Fractionating the hydrocarbon feed stream 101 at block 322 includes flowing the liquid phase 101b to the demethanizer 120 as feed at block 322b. Fractionating the hydrocarbon feed stream 101 at block 322 includes flowing a first portion (such as the first portion 101a) of the vapor phase 101a through a turboexpander (such as the turboexpander 106) at block 322c. Fractionating the hydrocarbon feed stream 101 at block 322 includes generating, by the turboexpander 106 electrical power at block 322d in response to the first portion 101a of the vapor phase 101a flowing through and expanding across the turboexpander 106 at block 322c. Fractionating the hydrocarbon feed stream 101 at block 322 includes flowing the first portion 101a of the vapor phase 101a from the turboexpander 106 to the demethanizer 120 as feed at block 322c. Fractionating the hydrocarbon feed stream 101 at block 322 includes at least partially condensing a second portion (such as the second portion 101a) of the vapor phase 101a at block 322f. In some implementations, the second portion 101a of the vapor phase 101a is fully condensed at block 322f. Fractionating the hydrocarbon feed stream 101 at block 322 includes flowing the at least partially condensed second portion 101a to the demethanizer 120 as reflux at block 322g. The second portion 101a flowed to the demethanizer 120 as reflux at block 322f can be at least partially condensed (fully condensed in some cases), for example, by the cross exchanger 108. Fractionating the hydrocarbon feed stream 101 at block 322 includes flowing a liquid stream (such as the bottoms stream 124) from the demethanizer 120 to the de-ethanizer 140 as feed at block 322h.

[0060] At block 324, an objective value is determined as a ratio of power consumption by the refrigeration cycle 200 to ethane recovery by the distillation unit (system 100). The controller 190 can, for example, perform block 324 in real-time. The power consumption of the refrigeration cycle 200 used for determining the objective value at block 324 can include, for example, the power consumed by the compressor 204 of the refrigeration cycle 200. For example, the compressor 204 can transmit a signal representing the power consumption of the compressor 204 to the controller 190. The ethane recovery by the distillation unit (system 100) used for determining the objective value at block 324 can be calculated from Equation 1. The controller 190 can calculate the ethane recovery by the distillation unit from Equation 1 in real-time.

[0061] At block 326, a flow rate of the at least partially condensed second portion 101a flowing to the demethanizer 120 as reflux (block 322f) is adjusted, a flow rate of the refrigerant 201 flowing through the cooler 102 (block 320) is adjusted, or both are adjusted to minimize the objective value (block 324) while maintaining the ethane recovery (block 324) to be at or above the specified target ethane recovery set point. The flow rate of the second portion 101a flowing to the demethanizer 120 as reflux can be adjusted at block 326, for example, the controller 190 transmitting the reflux flow signal to the reflux flow control valve 110. The flow rate of the refrigerant 201 flowing through the cooler 102 can be adjusted at block 326, for example, by the controller 190 transmitting the refrigerant flow signal to the refrigerant flow control valve 202. The controller 190 can perform block 326 in real-time. For example, the controller 190 can transmit the refrigerant flow signal to the refrigerant flow control valve 202 in real-time, within milliseconds after performing block 324. Blocks 324 and 326 can, for example, be iterated to maintain ethane recovery to meet target specifications while also minimizing power consumption by the system 100.

[0062] FIG. 4A is a plot 400A showing evaluation of minimizing a target variable in relation to reflux ratio. FIG. 4B is a plot 400B showing evaluation of maximizing ethane recovery in relation to reflux ratio. For the case whose plots 400A and 400B are shown in FIGS. 4A and 4B, respectively, the feed had an operating temperature of 38 C., an operating pressure of 5,170 kPa, and a C2 to C1 (C2/C1) ratio of 0.285. Plot 400B corresponds to the same case for plot 400A and shows ethane recovery in % (y-axis) instead of the target variable (which is shown on the y-axis of plot 400A of FIG. 4A). The plots 400A and 400B shown in FIGS. 4A and 4B, respectively, shows data for an example base case in which maximum ethane recovery of 96.27% was achieved at a reflux ratio of 0.27. The optimum operation of the base case that minimized power consumption while still achieving the specified target ethane recovery set point was achieved at a reflux ratio of 0.265.

[0063] FIG. 5A is a plot 500A showing evaluation of minimizing a target variable in relation to reflux ratio at a specified temperature condition. For plot 500A, the specified temperature condition was based on hot ambient condition or low refrigeration performance, resulting in a hotter inlet temperature. FIG. 5B is a plot 500B showing evaluation of maximizing ethane recovery in relation to reflux ratio at the specified temperature condition. For the case whose plots 500A and 500B are shown in FIGS. 5A and 5B, respectively, the feed had an operating temperature of 38 C. and an operating pressure of 5,170 kPa. Plot 500B corresponds to the same case for plot 500A at the specified temperature condition and shows ethane recovery in % (y-axis) instead of the target variable (which is shown on the y-axis of plot 500A of FIG. 5A). The plots 500A and 500B shown in FIGS. 5A and 5B, respectively, shows data for an example case in which an increased feed temperature (increased temperature of hydrocarbon feed stream 101) was encountered. The maximum ethane recovery of 92.6% was achieved for this case at a reflux ratio of 0.27. The optimum operation of this case that minimized power consumption while still achieving the specified target ethane recovery set point was achieved at a reflux ratio of 0.25.

[0064] FIG. 6A is a plot showing evaluation of minimizing a target variable in relation to reflux ratio at a specified pressure condition. For plot 600A, the specified pressure condition was based on low arrival pressure of the feed, which could be due to a variety of factors associated with fluctuations in the upstream process. FIG. 6B is a plot showing evaluation of maximizing ethane recovery in relation to reflux ratio at the specified pressure condition. For the case whose plots 600A and 600B are shown in FIGS. 6A and 6B, respectively, the feed had an operating pressure of 4,800 kPa. Plot 600B corresponds to the same case for plot 500A at the specified pressure condition and shows ethane recovery in % (y-axis) instead of the target variable (which is shown on the y-axis of plot 600A of FIG. 6A). The plots 600A and 600B shown in FIGS. 6A and 6B, respectively, shows data for an example case in which a decreased feed pressure (decreased pressure of hydrocarbon feed stream 101) was encountered. The maximum ethane recovery of 96.2% was achieved for this case at a reflux ratio of 0.27. The optimum operation of this case that minimized power consumption while still achieving the specified target ethane recovery set point was achieved at a reflux ratio of 0.26.

[0065] FIG. 7A is a plot showing evaluation of minimizing a target variable in relation to reflux ratio at a specified feed composition condition. For plot 700A, the specified feed composition condition was based on a change in a molar ratio of ethane to methane in the feed. FIG. 7B is a plot showing evaluation of maximizing ethane recovery in relation to reflux ratio at the specified feed composition condition. For the case whose plots 700A and 700B are shown in FIGS. 4A and 4B, respectively, the feed had a C2/C1 ratio of 0.3. Plot 700B corresponds to the same case for plot 700A at the specified feed composition condition and shows ethane recovery in % (y-axis) instead of the target variable (which is shown on the y-axis of plot 700A of FIG. 7A). The plots 700A and 700B shown in FIGS. 7A and 7B, respectively, shows data for an example case in which a change in feed composition (change in ethane-to-methane ratio of hydrocarbon feed stream 101) was encountered. The maximum ethane recovery of 97% was achieved for this case at a reflux ratio of 0.28. The optimum operation of this case that minimized power consumption while still achieving the specified target ethane recovery set point was achieved at a reflux ratio of 0.26.

[0066] Referring back to FIG. 1, the controller 190 includes a processor 192 and a memory 194 that is communicatively coupled to the processor 192. The controller 190 can be used to provide computational functionalities associated with described algorithms, methods, functions, processes, flows, and procedures, as described in this specification, according to an implementation. The illustrated controller 800 is intended to encompass any computing device such as a server, desktop computer, laptop/notebook computer, one or more processors within these devices, or any other processing device, including physical or virtual instances (or both) of the computing device. Additionally, the controller 800 can include a computer that includes an input device, such as a keypad, keyboard, touch screen, or other device that can accept user information, and an output device that conveys information associated with the operation of the controller 800, including digital data, visual, audio information, or a combination of information.

[0067] The controller 190 includes a processor 192. The processor 192 may be a microprocessor, a multi-core processor, a multithreaded processor, an ultra-low-voltage processor, an embedded processor, or a virtual processor. In some embodiments, the processor 192 may be part of a system-on-a-chip (SoC) in which the processor 192 and the other components of the controller 190 are formed into a single integrated electronics package. In some implementations, the processor 190 may include processors from Intel Corporation of Santa Clara, California, from Advanced Micro Devices, Inc. (AMD) of Sunnyvale, California, or from ARM Holdings, LTD., Of Cambridge, England. Any number of other processors from other suppliers may also be used. Although illustrated as a single processor 192 in FIG. 1, two or more processors may be used according to particular needs, desires, or particular implementations of the controller 190. Generally, the processor 192 executes instructions and manipulates data to perform the operations of the controller 190 and any algorithms, methods, functions, processes, flows, and procedures as described in this specification. The processor 192 may communicate with other components of the controller 190 over a bus. The bus may include any number of technologies, such as industry standard architecture (ISA), extended ISA (EISA), peripheral component interconnect (PCI), peripheral component interconnect extended (PCIx), PCI express (PCIe), or any number of other technologies. The bus may be a proprietary bus, for example, used in an SoC based system. Other bus technologies may be used, in addition to, or instead of, the technologies above.

[0068] The controller 190 also includes a memory 194 that can hold data for the controller 190 or other components (or a combination of both) that can be connected to the network. Although illustrated as a single memory 194 in FIG. 1, two or more memories 194 (of the same or combination of types) can be used according to particular needs, desires, or particular implementations of the controller 190 and the described functionality. While memory 194 is illustrated as an integral component of the controller 190, memory 194 can be external to the controller 190. The memory 194 can be a transitory or non-transitory storage medium. In some implementations, such as in PLCs and other process control units, the memory 194 is integrated with the database 806 used for long-term storage of programs and data. The memory 194 can include any number of volatile and nonvolatile memory devices, such as volatile random-access memory (RAM), static random-access memory (SRAM), flash memory, and the like. In smaller devices, such as PLCs, the memory 194 may include registers associated with the processor 192 itself.

[0069] The memory 194 stores computer-readable instructions executable by the processor 192 that, when executed, cause the processor 192 to perform operations, such as determining the ethane recovery value (Equation 1), comparing the determined ethane recovery value with the specified target ethane recovery set point, transmitting the reflux signal, transmitting the refrigerant signal, and determining the objective value. The operations performed by the processor 192 can be performed, for example, in real-time as the demethanizer 120 fractionates the hydrocarbon feed stream 101. There may be any number of controllers 190 associated with, or external to, a computer system containing controller 190, each controller 190 communicating over the network. Further, the term client, user, operator, and other appropriate terminology may be used interchangeably, as appropriate, without departing from this specification. Moreover, this specification contemplates that many users may use one controller 190, or that one user may use multiple controllers 190.

Embodiments

[0070] In an example implementation (or aspect), a method for dynamically controlling a reflux rate of a demethanizer, the method comprising: receiving, by a controller, an ethane content of each of a hydrocarbon feed stream, a residue stream, and a bottoms stream, wherein the hydrocarbon feed stream comprises methane, ethane, and propane, wherein the residue stream comprises at least a portion of the ethane from the hydrocarbon feed stream, wherein the bottoms stream comprises at least a portion of the propane from the hydrocarbon feed stream, wherein the hydrocarbon feed stream enters and is fractionated by the demethanizer; determining, by the controller, an ethane recovery value at least based on the received ethane contents of the hydrocarbon feed stream, the residue stream, and the bottoms stream; receiving, by the controller, a flow rate of reflux provided to the demethanizer; transmitting, by the controller, a flow signal to a reflux flow control valve to adjust the flow rate of reflux provided to the demethanizer, such that the determined ethane recovery value is equal to or greater than a specified target ethane recovery set point; receiving, by the controller, a power consumption of a refrigeration cycle providing cooling to the hydrocarbon feed stream; determining, by the controller, an objective value as a ratio of the determined power consumption to the determined ethane recovery value; and after adjusting the flow rate of reflux provided to the demethanizer, transmitting, by the controller, a signal to reduce power consumed by the refrigeration cycle to reduce the objective value, while maintaining the determined ethane recovery value at or above the specified target ethane recovery set point.

[0071] In an example implementation (or aspect) combinable with any other example implementation (or aspect), determining the ethane recovery value comprises calculating the ethane recovery value as:

[00002]$\mathrm{Ethane}\mathrm{Recovery}=1-\frac{\mathrm{Ethane}\mathrm{content}\mathrm{of}\mathrm{Residue}\mathrm{Gas}+\mathrm{Ethane}\mathrm{content}\mathrm{of}\mathrm{Bottoms}}{\mathrm{Ethane}\mathrm{content}\mathrm{Hydrocarbon}\mathrm{Feed}}.$

[0072] In an example implementation (or aspect) combinable with any other example implementation (or aspect), the refrigeration cycle comprises a compressor and a refrigerant flowing through and being pressurized by the compressor, and the transmitted signal causes a flow rate of the refrigerant flowing through and being pressurized by the compressor to reduce, thereby reducing the power consumed by the refrigeration cycle.

[0073] In an example implementation (or aspect) combinable with any other example implementation (or aspect), the method comprises fractionating, by the demethanizer, the hydrocarbon feed stream, wherein fractionating the hydrocarbon feed stream comprises: separating the hydrocarbon feed stream into a vapor phase and a liquid phase; flowing the liquid phase to the demethanizer as feed; flowing a first portion of the vapor phase through a turboexpander; flowing the first portion of the vapor phase from the turboexpander to the demethanizer as feed; and flowing a second portion of the vapor phase to the demethanizer as reflux.

[0074] In an example implementation (or aspect) combinable with any other example implementation (or aspect), fractionating the hydrocarbon feed stream comprises transferring heat from the residue gas stream exiting the demethanizer to the second portion of the vapor phase entering the demethanizer.

[0075] In an example implementation (or aspect) combinable with any other example implementation (or aspect), fractionating the hydrocarbon feed stream comprises generating, by the turboexpander, electrical power in response to the first portion of the vapor phase flowing through and expanding across the turboexpander, and at least a portion of the electrical power generated by the turboexpander is provided to the compressor to pressurize the refrigerant.

[0076] In an example implementation (or aspect), a method comprising: transferring, by a cooler, heat from a hydrocarbon feed stream to a refrigerant cycling through a refrigeration cycle, wherein the hydrocarbon feed stream comprises methane, ethane, and propane; fractionating, by a distillation unit comprising a demethanizer and a de-ethanizer, the hydrocarbon feed stream to produce a residue gas stream, an ethane product stream, and a bottoms stream, wherein the residue gas stream is produced by the demethanizer and comprises at least a portion of the methane, the ethane product stream is produced by the de-ethanizer and comprises at least a portion of the ethane, the bottoms stream is produced by the de-ethanizer and comprises at least a portion of the propane, and fractionating the feed stream comprises: separating the hydrocarbon feed stream into a vapor phase and a liquid phase; flowing the liquid phase to the demethanizer as feed; flowing a first portion of the vapor phase through a turboexpander; generating, by the turboexpander, electrical power in response to the first portion of the vapor phase flowing through and expanding across the turboexpander; flowing the first portion of the vapor phase from the turboexpander to the demethanizer as feed; at least partially condensing a second portion of the vapor phase; flowing the at least partially condensed second portion to the demethanizer as reflux; and flowing a liquid stream from the demethanizer to the de-ethanizer as feed; determining an objective value as a ratio of power consumption by the refrigeration cycle to ethane recovery by the distillation unit; and adjusting a flow rate of the at least partially condensed second portion flowing to the demethanizer as reflux, a flow rate of the refrigerant flowing through the cooler, or both to minimize the objective value while maintaining the ethane recovery at or above a specified target ethane recovery set point.

[0077] In an example implementation (or aspect) combinable with any other example implementation (or aspect), the method comprises measuring an ethane content of each of the hydrocarbon feed stream, the residue stream produced by the demethanizer, and the bottoms stream produced by the de-ethanizer.

[0078] In an example implementation (or aspect) combinable with any other example implementation (or aspect), the ethane recovery value is calculated as:

[00003]$\mathrm{Ethane}\mathrm{Recovery}=1-\frac{\mathrm{Ethane}\mathrm{content}\mathrm{of}\mathrm{Residue}\mathrm{Gas}+\mathrm{Ethane}\mathrm{content}\mathrm{of}\mathrm{Bottoms}}{\mathrm{Ethane}\mathrm{content}\mathrm{Hydrocarbon}\mathrm{Feed}}.$

[0079] In an example implementation (or aspect) combinable with any other example implementation (or aspect), adjusting the flow rate of the refrigerant flowing through the cooler comprises reducing the flow rate of the refrigerant flowing through the cooler, thereby reducing the power consumption by the refrigeration cycle.

[0080] In an example implementation (or aspect) combinable with any other example implementation (or aspect), fractionating the feed hydrocarbon stream comprises transferring heat from the residue gas stream exiting the demethanizer to the second portion of the vapor phase entering the demethanizer.

[0081] In an example implementation (or aspect) combinable with any other example implementation (or aspect), at least a portion of the electrical power generated by the turboexpander is used to pressurize the refrigerant cycling through the refrigeration cycle.

[0082] In an example implementation (or aspect), a system comprising: a demethanizer configured to fractionate a hydrocarbon feed stream based on volatility to produce a residue gas stream and a bottoms stream, wherein the hydrocarbon feed stream comprises methane, ethane, and propane, the residue gas stream comprises at least a portion of the methane, and the bottoms stream comprises at least a portion of the ethane and at least a portion of the propane; a refrigeration cycle comprising a refrigerant and a cooler, wherein the cooler is configured to transfer heat from the hydrocarbon feed stream to the refrigerant to provide cooling to the hydrocarbon feed stream upstream of the demethanizer; a reflux flow control valve configured to control a flow rate of reflux provided to the demethanizer; and a controller communicatively coupled to the reflux flow control valve and to the refrigeration cycle, wherein the controller is configured to: determine an objective value as a ratio of power consumption by the refrigeration cycle to ethane recovery by the de-ethanizer; and transmit a reflux signal to the reflux flow control valve to adjust the flow rate of the reflux provided to the demethanizer, a refrigeration signal to the refrigeration cycle to adjust a flow rate of the refrigerant flowing through the cooler, or both to minimize the objective value while maintaining the ethane recovery at or above a specified target ethane recovery set point.

[0083] In an example implementation (or aspect) combinable with any other example implementation (or aspect), the system comprises: a knockout drum downstream of the cooler and upstream of the demethanizer, wherein the knockout drum is configured to receive the hydrocarbon feed stream from the cooler and separate the hydrocarbon feed stream into a vapor phase and a liquid phase; a turboexpander configured to receive a first portion of the vapor phase, wherein the turboexpander is configured to generate electrical power in response to the first portion of the vapor phase expanding through the turboexpander, wherein the demethanizer is configured to receive the first portion of the vapor phase from the turboexpander as feed; and a de-ethanizer configured to receive the bottoms stream as feed, wherein the de-ethanizer is configured to fractionate the bottoms stream based on volatility to produce an ethane product stream and a propane product stream, wherein the ethane product stream comprises at least a portion of the ethane from the hydrocarbon feed stream, wherein the propane product stream comprises at least a portion of the propane from the hydrocarbon feed stream.

[0084] In an example implementation (or aspect) combinable with any other example implementation (or aspect), the system comprises a cross exchanger configured to transfer heat between the residue gas exiting the demethanizer and the second portion of the vapor phase entering the demethanizer.

[0085] In an example implementation (or aspect) combinable with any other example implementation (or aspect), the system comprises: a first composition analyzer configured to determine an ethane content of the hydrocarbon feed stream; a second composition analyzer configured to determine an ethane content of the residue stream; and a third composition analyzer configured to determine an ethane content of the propane product stream.

[0086] In an example implementation (or aspect) combinable with any other example implementation (or aspect), the controller is configured to determine the ethane recovery as:

[00004]$\mathrm{Ethane}\mathrm{Recovery}=1-\frac{\mathrm{Ethane}\mathrm{content}\mathrm{of}\mathrm{Residue}\mathrm{Gas}+\mathrm{Ethane}\mathrm{content}\mathrm{of}\mathrm{Bottoms}}{\mathrm{Ethane}\mathrm{content}\mathrm{Hydrocarbon}\mathrm{Feed}}.$

[0087] In an example implementation (or aspect) combinable with any other example implementation (or aspect), the refrigeration cycle comprises a refrigerant flow control valve, and the controller is configured to transmit the refrigeration signal to the refrigerant flow control valve to reduce the flow rate of the refrigerant flowing through the cooler, thereby reducing power consumed by the refrigeration cycle.

[0088] In an example implementation (or aspect) combinable with any other example implementation (or aspect), the refrigeration cycle comprises a compressor configured to pressurize the refrigerant, and the turboexpander is coupled to the compressor for providing at least a portion of the generated electrical power to the compressor for pressurizing the refrigerant.

[0089] In an example implementation (or aspect) combinable with any other example implementation (or aspect), the system comprises a pressure sensor configured to measure a pressure of the hydrocarbon feed stream and a temperature sensor configured to measure a temperature of the hydrocarbon feed stream, wherein the power consumption by the refrigeration cycle depends at least on the ethane content of the hydrocarbon feed stream, the pressure of the hydrocarbon feed stream, and the temperature of the hydrocarbon feed stream.

[0090] While this specification contains many specific implementation details, these should not be construed as limitations on the scope of what may be claimed, but rather as descriptions of features that may be specific to particular implementations. Certain features that are described in this specification in the context of separate implementations can also be implemented, in combination, in a single implementation. Conversely, various features that are described in the context of a single implementation can also be implemented in multiple implementations, separately, or in any sub-combination. Moreover, although previously described features may be described as acting in certain combinations and even initially claimed as such, one or more features from a claimed combination can, in some cases, be excised from the combination, and the claimed combination may be directed to a sub-combination or variation of a sub-combination.

[0091] As used in this disclosure, the terms a, an, or the are used to include one or more than one unless the context clearly dictates otherwise. The term or is used to refer to a nonexclusive or unless otherwise indicated. The statement at least one of A and B has the same meaning as A, B, or A and B. In addition, it is to be understood that the phraseology or terminology employed in this disclosure, and not otherwise defined, is for the purpose of description only and not of limitation. Any use of section headings is intended to aid reading of the document and is not to be interpreted as limiting; information that is relevant to a section heading may occur within or outside of that particular section.

[0092] As used in this disclosure, the term about or approximately can allow for a degree of variability in a value or range, as in within 10%, within 5%, or within 1% of a stated value or of a stated limit of a range.

[0093] As used in this disclosure, the term substantially refers to a majority of, or mostly, as in at least about 50%, 60%, 70%, 80%, 90%, 95%, 96%, 97%, 98%, 99%, 99.5%, 99.9%, 99.99%, or at least about 99.999% or more.

[0094] Values expressed in a range format should be interpreted in a flexible manner to include not only the numerical values explicitly recited as the limits of the range, but also to include all the individual numerical values or sub-ranges encompassed within that range as if each numerical value and sub-range is explicitly recited. For example, a range of 0.1% to about 5% or 0.1% to 5% should be interpreted to include about 0.1% to about 5%, as well as the individual values (for example, 1%, 2%, 3%, and 4%) and the sub-ranges (for example, 0.1% to 0.5%, 1.1% to 2.2%, 3.3% to 4.4%) within the indicated range. The statement X to Y has the same meaning as about X to about Y, unless indicated otherwise. Likewise, the statement X, Y, or Z has the same meaning as about X, about Y, or about Z, unless indicated otherwise.

[0095] As used in this disclosure, the term real-time relates to an actual time during which a process or event occurs. In relation to a computing system, real-time can refer to the capability of the computing system to process input data within milliseconds or nanoseconds, so that output data is available virtually immediately as feedback.

[0096] Particular implementations of the subject matter have been described. Other implementations, alterations, and permutations of the described implementations are within the scope of the following claims as will be apparent to those skilled in the art. While operations are depicted in the drawings or claims in a particular order, this should not be understood as requiring that such operations be performed in the particular order shown or in sequential order, or that all illustrated operations be performed (some operations may be considered optional), to achieve desirable results. In certain circumstances, multitasking or parallel processing (or a combination of multitasking and parallel processing) may be advantageous and performed as deemed appropriate.

[0097] Moreover, the separation or integration of various system modules and components in the previously described implementations should not be understood as requiring such separation or integration in all implementations, and it should be understood that the described components and systems can generally be integrated together or packaged into multiple products.

[0098] Accordingly, the previously described example implementations do not define or constrain the present disclosure. Other changes, substitutions, and alterations are also possible without departing from the spirit and scope of the present disclosure.