Integration of LNG regasification with refinery and power generation

• US 8,316,665 B2
• Filed: 03/21/2006
• Issued: 11/27/2012
• Est. Priority Date: 03/30/2005
• Status: Expired due to Fees

• Current Assignee: Fluor Technologies Corporation (Fluor Corporation)
• Original Assignee: Fluor Technologies Corporation (Fluor Corporation)
• Inventors: Mak, John
• Primary Examiner(s): Flanigan, Allen J.
• Assistant Examiner(s): THOMPSON, JASON N
• Application Number:
  US11/908,766
• Publication Number:
  US 20080307789A1
• Time in Patent Office: 2,443 Days
• Field of Search: 626/18, 626/20, 626/23, 626/30
• US Class Current: 62/620
• CPC Class Codes: F17C 2221/033 Methane, e.g. natural gas, CNG, LNG, GNL, GNC, PLNG
• CPC Class Codes: F17C 2223/0161 cryogenic, e.g. LNG, GNL, PLNG
• CPC Class Codes: F17C 2223/033 Small pressure, e.g. for liquefied gas
• CPC Class Codes: F17C 2225/0123 gaseous, e.g. CNG, GNC
• CPC Class Codes: F17C 2225/035 High pressure, i.e. between 10 and 80 bars
• CPC Class Codes: F17C 2227/0135 Pumps
• CPC Class Codes: F17C 2227/0323 in a closed loop
• CPC Class Codes: F17C 2227/0332 by burning a combustible
• CPC Class Codes: F17C 2227/0393 using a vaporiser
• CPC Class Codes: F17C 2265/015 by separating
• CPC Class Codes: F17C 2265/05 Regasification
• CPC Class Codes: F17C 2270/0136 Terminals
• CPC Class Codes: F25J 2210/12 Refinery or petrochemical off-gas
• CPC Class Codes: F25J 2210/62 Liquefied natural gas [LNG]; Natural gas liquids [NGL]; Liquefied petroleum gas [LPG]
• CPC Class Codes: F25J 2215/62 Ethane or ethylene
• CPC Class Codes: F25J 2215/64 Propane or propylene
• CPC Class Codes: F25J 2270/904 by liquid or gaseous cryogen in an open loop
• CPC Class Codes: F25J 3/0219 Refinery gas, cracking gas, coke oven gas, gaseous mixtures containing aliphatic unsaturated CnHm or gaseous mixtures of undefined nature
• CPC Class Codes: F25J 3/0238 separation of CnHm with 2 carbon atoms or more
• CPC Class Codes: F25J 3/0242 separation of CnHm with 3 carbon atoms or more
• CPC Class Codes: Y02E 20/16 : Combined cycle power plant [CCPP], or combined cycle gas turbine [CCGT]

Abstract

Contemplated plants thermally integrate operation of a refinery component, and most preferably of a hydrocarbon splitter with LNG regasification to provide refrigeration duty and with a power cycle to provide the reboiler duty of the component. It should be noted that such configurations advantageously allow operation of the splitter at a reduced temperature and at reduced pressure, thereby increasing separation efficiency, while the power output is boosted using air intake chilling. Most notably, such process advantages are achieved by satisfying the heating duty of LNG regasification.

Claims

1. A plant, comprising:

a hydrocarbon source configured to provide a processed hydrocarbon feed enriched in C2 and/or C3 hydrocarbons;

a C2 or C3 hydrocarbon splitter having a reboiler and an overhead condenser fluidly coupled to the hydrocarbon source and configured to receive the processed hydrocarbon feed;

a first closed heat exchange circuit comprising a first heat exchange fluid and thermally coupled to a liquefied natural gas stream and the hydrocarbon splitter such that the first heat exchange fluid receives refrigeration content from the liquefied natural gas stream and provides refrigeration content to the overhead condenser; and

a second closed heat exchange circuit comprising a second heat exchange fluid and thermally coupled to a heat source, the hydrocarbon splitter, and the liquefied natural gas stream such that heat from the heat source is provided to the second heat exchange fluid and transferred from the second heat exchange fluid to the reboiler and the liquefied natural gas stream.

2. The plant of claim 1 wherein the heat source is selected from the group consisting of an air intake chiller, a heat recovery unit, a flue gas heat exchanger, a fired heater, and a seawater exchanger.

3. The plant of claim 1 wherein the hydrocarbon splitter is a C2 splitter.

4. The plant of claim 1 wherein the hydrocarbon splitter is configured to operate at a pressure of less than 100 psia.

5. The plant of claim 1 wherein the hydrocarbon splitter is configured to operate at a pressure of between about 30 psia and about 60 psia.

6. The plant of claim 1 wherein the first heat exchange circuit is configured and coupled to the liquefied natural gas stream such the liquefied natural gas stream is heated from a temperature of about −

250°

F. to a temperature of about −

100°

F. to −

60°

F.

7. The plant of claim 1 wherein the second heat exchange circuit is configured and coupled to the liquefied natural gas stream such the liquefied natural gas stream is heated from a temperature of about −

100°

F. to −

60°

F. to a temperature of about 40°

F.

8. The plant according to claim 1 further comprising a separation column that is fluidly coupled to the splitter such that the separation column provides a bottom product to the splitter.

9. The plant of claim 8 wherein the separation column further includes a reflux condenser that is thermally coupled to the first heat exchange circuit.

10. The plant of claim 8 wherein the hydrocarbon splitter is a C3 splitter and wherein the separation column is a deethanizer.

11. A method of operating a C2 or C3 hydrocarbon splitter, comprising

feeding a processed hydrocarbon feed enriched in C2 and/or C3 hydrocarbons as a feed gas to the C2 or C3 hydrocarbon splitter;

providing refrigeration duty to an overhead condenser of the C2 or C3 hydrocarbon splitter from a first heat exchange fluid in a first closed heat exchange circuit that is cooled via heat exchange with a liquefied natural gas; and

providing reboiler duty of the C2 or C3 hydrocarbon splitter using a second heat exchange fluid in a second closed heat exchange circuit that is heated via heat exchange with a heat source and cooled via heat exchange with the liquefied natural gas.

12. The method of claim 11 wherein the heat source is selected from the group consisting of an air intake chiller, a heat recovery unit, a flue gas heat exchanger, a fired heater, and a seawater exchanger.

13. The method of claim 11 wherein the hydrocarbon splitter is a C2 splitter.

14. The method of claim 11 wherein the hydrocarbon splitter is operated at a pressure of less than 100 psia.

15. The method of claim 11 wherein the hydrocarbon splitter is operated at a pressure of between about 30 psia and about 60 psia.

16. The method of claim 11 wherein the first heat exchange circuit heats the liquefied natural gas stream from a temperature of about −

250°

F. to a temperature of about −

100°

F. to −

60°

F.

17. The method of claim 11 wherein the second heat exchange circuit heats the liquefied natural gas stream from a temperature of about −

100°

F. to −

60°

F. to a temperature of about 40°

F.

18. The method of claim 11 wherein a separation column is fluidly coupled to the splitter to thereby provide a bottom product to the splitter.

19. The method of claim 18 wherein the separation column further includes a reflux condenser that is thermally coupled to the first heat exchange circuit.

20. The method of claim 18 wherein the hydrocarbon splitter is a C3 splitter and wherein the separation column is a deethanizer.

21. A method of operating a plant comprising a power generating section and a liquefied natural gas regasification section, comprising:

using refrigeration content in the liquefied natural gas to provide overhead condensation duty of a column using a first heat exchange fluid in a first closed heat exchange circuit that transfers refrigeration from the liquefied natural gas to an overhead exchanger; and

using heat from the power generating section to provide reboiling duty of the column using a second heat exchange fluid in a second closed heat exchange circuit that transfers heat from the power generating section to a reboiler of the column; and

using the first and second heat exchange fluids to regasify the liquefied natural gas.