Configurations and methods for offshore LNG regasification and BTU control

• US 8,110,023 B2
• Filed: 12/13/2005
• Issued: 02/07/2012
• Est. Priority Date: 12/16/2004
• Status: Expired due to Fees

• Current Assignee: Fluor Technologies Corporation (Fluor Corporation)
• Original Assignee: Fluor Technologies Corporation (Fluor Corporation)
• Inventors: Mak, John, Graham, Curt
• Primary Examiner(s): LAWRENCE JR, FRANK M
• Application Number:
  US11/721,226
• Publication Number:
  US 20090277219A1
• Time in Patent Office: 2,247 Days
• Field of Search: 952/37, 962/43, 585/800, 585/802, 585/833, 626/13, 629/13
• US Class Current: 95/237
• 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 2225/0115 dense or supercritical, i.e. at high pressure and high density
• 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 2227/0185 comprising several pumps or compressors
• CPC Class Codes: F17C 2227/0309 using another fluid
• CPC Class Codes: F17C 2227/0318 using seawater
• CPC Class Codes: F17C 2227/0332 by burning a combustible
• CPC Class Codes: F17C 2227/0393 using a vaporiser
• CPC Class Codes: F17C 2227/0395 using a submerged heat exchanger
• CPC Class Codes: F17C 2260/056 Improving fluid characteristics
• CPC Class Codes: F17C 2265/015 by separating
• CPC Class Codes: F17C 2265/05 Regasification
• CPC Class Codes: F17C 2270/0105 Ships
• CPC Class Codes: F17C 2270/0121 Platforms
• CPC Class Codes: F17C 2270/0123 Terminals
• CPC Class Codes: F17C 2270/0136 Terminals
• CPC Class Codes: F17C 5/06 : for filling with compressed gases
• CPC Class Codes: F17C 9/02 : with change of state, e.g. vaporisation
• CPC Class Codes: F25J 2200/02 : in a single pressure main column system
• CPC Class Codes: F25J 2200/04 : in a dual pressure main column system
• CPC Class Codes: F25J 2200/70 : Refluxing the column with a condensed part of the feed stream, i.e. fractionator top is stripped or self-rectified
• CPC Class Codes: F25J 2200/74 : Refluxing the column with at least a part of the partially condensed overhead gas
• CPC Class Codes: F25J 2200/78 : Refluxing the column with a liquid stream originating from an upstream or downstream fractionator column
• CPC Class Codes: F25J 2205/04 : in the feed line, i.e. upstream of the fractionation step
• CPC Class Codes: F25J 2215/62 : Ethane or ethylene
• CPC Class Codes: F25J 2230/08 : Cold compressor, i.e. suction of the gas at cryogenic temperature and generally without afterstage-cooler
• CPC Class Codes: F25J 2230/60 : the fluid being hydrocarbons or a mixture of hydrocarbons
• CPC Class Codes: F25J 2240/02 : Expansion of a process fluid in a work-extracting turbine (i.e. isentropic expansion), e.g. of the feed stream
• CPC Class Codes: F25J 2245/02 : Recycle of a stream in general, e.g. a by-pass stream
• CPC Class Codes: F25J 3/0209 : Natural gas or substitute natural gas
• CPC Class Codes: F25J 3/0214 : Liquefied natural gas
• CPC Class Codes: F25J 3/0233 : separation of CnHm with 1 carbon atom or more
• 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

Abstract

LNG is pumped to supercritical pressure and vaporized, preferably in an offshore location to thereby form a natural gas stream with an intermediate temperature. A first portion of that stream is then processed in an onshore location to remove at least some non-methane components to thereby form a lean LNG, which is then combined with a second portion of that stream to form a sales gas having desired chemical composition. The intermediate temperature and the split ratio of the gas stream in first and second portion are a function of the concentration of the non-methane components in the LNG.

Claims

1. A method of providing a natural gas product, comprising:

providing vaporized supercritical LNG, optionally from an offshore location to an onshore terminal;

splitting the vaporized supercritical LNG into a first and second stream;

processing the first stream to remove at least some non-methane components from the first stream to form a lean natural gas product, wherein the step of processing includes a first turbo-expansion of at least a portion of the first stream;

compressing the lean natural gas product using at least in part energy from the first turbo-expansion; and

combining the compressed lean natural gas product with the second stream to thereby form a sales gas with predetermined content of non-methane components.

2. The method of claim 1 wherein the step of providing the vaporized supercritical LNG includes vaporizing the supercritical LNG to a predetermined temperature of equal or less than 20°

F., wherein the temperature is a function of a concentration of non-methane components in the LNG.

3. The method of claim 1 wherein in the step of splitting the vaporized supercritical LNG in first and second streams is a function of a concentration of non-methane components in the LNG.

4. The method of claim 1 wherein the first stream is processed in an absorber that further produces an absorber bottom product, and wherein the bottom product is further processed in at least one downstream column to thereby produce at least one of an ethane product and a propane and heavier product.

5. The method of claim 4 wherein the at least one downstream column is operated at a pressure that is lower than an operating pressure of the absorber.

6. The method of claim 4 wherein the at least one downstream column is operated as a demethanizer or deethanizer and provides an overhead product that is recycled to the absorber as at least one of a reflux stream and a bottom product.

7. The method of claim 1 wherein the step of processing further includes a second turbo-expansion of the at least portion of the first stream, wherein the first turbo-expansion provides reflux condenser duty of downstream columns, and wherein the second turbo-expansion provides refrigeration duty in the absorber for recovery of the non-methane components.

8. A facility comprising:

a source of LNG and a pump fluidly coupled to the source, wherein the pump is configured to produce LNG at supercritical pressure;

a regasification unit coupled to the pump and configured to regasify the supercritical LNG to a predetermined temperature; and

a controller operationally linked with the regasification unit and enabled to set the temperature of the regasified LNG as a function of a concentration of non-methane components in the LNG.

9. The facility of claim 8 wherein the LNG source is selected from the group consisting of a LNG carrier, a submerged LNG tank, and a floating LNG tank.

10. The facility of claim 8 wherein the regasification unit comprises a unit selected from the group consisting of an open rack seawater vaporizer, a submerged combustion fuel fired vaporizer, an ambient air vaporizer, an intermediate fluid vaporizer, and a Rankine cycle vaporizer.

11. The facility of claim 8 wherein the predetermined temperature is between about −

20°

F. to about 20°

F.

12. The facility of claim 8 wherein the controller comprises a central processing unit programmed to control the temperature as a function of previously provided information on chemical composition of the LNG.

13. A LNG processing plant comprising:

a portion, optionally offshore, configured to pump LNG to supercritical pressure and to regasify the pressurized LNG;

an onshore portion configured to process one portion of the regasified LNG to remove at least a portion of non-methane content in the LNG to thereby form a lean natural gas product; and

wherein the onshore portion is further configured to produce a sales gas from the lean natural gas product and another portion of the regasified LNG.

14. The LNG processing plant of claim 13 wherein the onshore portion comprises an absorber that receives the one portion of the regasified LNG to thereby produce the lean natural gas.

15. The LNG processing plant of claim 14 further comprising a turbo-expander that expands the one portion of the regasified LNG before entry into the absorber, and further comprising a compressor that is operationally coupled to the expander and compresses the lean natural gas product.

16. The LNG processing plant of claim 14 further comprising a downstream column that is configured to receive an absorber bottom product and to produce an ethane and propane and heavier product.

17. The LNG processing plant of claim 14 further comprising a downstream column that is configured to operate as a demethanizer or deethanizer, to receive an absorber bottom product, and to produce at least one of a reflux stream and a bottom feed stream to the absorber.

18. The LNG processing plant of claim 14 further comprising a flow combining element that is configured to combine the lean natural gas product and the another portion of the regasified LNG to thereby form the sales gas.

19. A LNG processing plant comprising:

a source that provides regasified LNG at supercritical pressure, wherein the LNG has a first quantity of non-methane components;

a flow divider that is configured to produce a first and a second stream from the regasified LNG;

an absorber that is configured to produce a lean natural gas product from a turbo-expanded portion of the first stream;

a compressor that compresses the lean natural gas product, wherein the compressor is configured to use energy from the turbo-expansion of the first stream; and

a flow combining element that is configured to produce a sales gas from the compressed lean natural gas product and the second stream, wherein the sales gas has a quantity of non-methane components that is less than the first quantity.

20. The plant of claim 19 further comprising a control unit that is configured to control at least one of a temperature of the regasified LNG and a ratio of first and a second streams, wherein the temperature and the ratio are set as a function of a concentration of non-methane in the regasified LNG.