Natural gas liquids recovery device and method

• US 8,585,804 B2
• Filed: 05/17/2011
• Issued: 11/19/2013
• Est. Priority Date: 05/31/2010
• Status: Active Grant

• Current Assignee: Nuovo Pignone SPA (Nuovo Pignone International SRL)
• Original Assignee: Nuovo Pignone SPA (Nuovo Pignone International SRL)
• Inventors: Amidei, Simone, Monti, Francesca, Giusti, Andrea, Risat, Mesgina Tsegai
• Primary Examiner(s): LAWRENCE JR, FRANK M
• Application Number:
  US13/109,037
• Publication Number:
  US 20110289962A1
• Time in Patent Office: 917 Days
• Field of Search: 951/17, 961/08, 961/21, 62618-619, 585/800, 585/820
• US Class Current: 95/117
• CPC Class Codes: C10L 3/08 Production of synthetic natural gas
• CPC Class Codes: C10L 3/10 Working-up natural gas or synthetic natural gas
• CPC Class Codes: C10L 3/106 of water
• CPC Class Codes: C10L 3/12 Liquefied petroleum gas liquefying by pressure and cold treatment F25J
• CPC Class Codes: F02C 3/22 the fuel or oxidant being gaseous at standard temperature and pressure F02C3/28 takes precedence
• CPC Class Codes: F02C 6/06 providing compressed gas F02C6/10 takes precedence
• CPC Class Codes: F25J 2205/66 Regenerating the adsorption vessel, e.g. kind of reactivation gas
• CPC Class Codes: F25J 2215/02 Mixing or blending of fluids to yield a certain product
• CPC Class Codes: F25J 2230/22 Compressor driver arrangement, e.g. power supply by motor, gas or steam turbine
• CPC Class Codes: F25J 2230/60 the fluid being hydrocarbons or a mixture of hydrocarbons
• CPC Class Codes: F25J 2235/60 the fluid being (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 2240/80 Hot exhaust gas turbine combustion engine
• CPC Class Codes: F25J 2245/02 Recycle of a stream in general, e.g. a by-pass stream
• CPC Class Codes: F25J 2260/60 Integration in an installation using hydrocarbons, e.g. for fuel purposes
• CPC Class Codes: F25J 2290/42 Modularity, pre-fabrication of modules, assembling and erection, horizontal layout, i.e. plot plan, and vertical arrangement of parts of the cryogenic unit, e.g. of the cold box
• CPC Class Codes: F25J 3/061 Natural gas or substitute natural gas
• CPC Class Codes: F25J 3/0635 separation of CnHm with 1 carbon atom or more
• CPC Class Codes: F25J 3/064 separation of CnHm with 2 carbon atoms or more

Abstract

A natural gas liquids (NGL) recovery system and method for separating NGLs from a feed gas is provided. The method includes receiving the feed gas; increasing a pressure of the feed gas by running the feed gas through a compressor connected to a gas turbine; diverting part of the feed gas from an output of the compressor and feeding the diverted part to a dryer; drying the diverted part to remove water and produce a dry gas; expanding the dry gas in a turbo-expander; separating the expanded gas into the NGL and fuel gas; and providing the fuel gas to the gas turbine as fuel without contamination.

Claims

1. A natural gas liquids (NGL) recovery system comprising:

an inlet configured to receive feed gas from a first location of a transportation pipeline;

a dehydration unit connected to the inlet to receive the feed gas and configured to extract predetermined components from the feed gas to produce a dry gas;

a NGL unit configured to receive the dry gas from the dehydration unit and configured to separate the dry gas into a fuel gas and a NGL mix;

a first outlet connected to the NGL unit and configured to output the fuel gas to a gas turbine to be ignited; and

a second outlet connected to the NGL unit and configured to output the NGL mix back to the transportation pipeline, at a second location situated downstream from the first location.

2. The system of claim 1, wherein the feed gas is at a pressure higher than the cricondenbar.

3. The system of claim 1, wherein the dehydration unit does not include a wet gas cooler followed by a separator to remove the condensed water from the regeneration gas stream, does not include a regeneration gas re-compression system and does not contaminate the dry gas stream.

4. The system of claim 1, wherein the NGL unit comprises:

heat exchangers for changing a temperature of the received dry gas;

a turbo-expander equipped with magnetic bearings connected to the heat exchangers and configured to receive cooled dry gas from the heat exchangers and to isentropically expand the cooled dry gas; and

a separator connected to the turbo-expander and configured to separate a fluid phase from a gas phase of the cooled dry gas.

5. The system of claim 4, wherein the NGL unit further comprises:

a compressor connected to the separator and configured to compress the fuel gas prior to providing the fuel gas to the gas turbine.

6. The system of claim 5, wherein the NGL unit further comprises:

a pump connected to the separator and configured to pump the NGL mix back to the pipeline.

7. The system of claim 1, wherein the NGL unit does not include a demethanizer or a glycol injecting unit.

8. A station for pumping natural gas liquids (NGL) in a transportation pipeline, the station comprising:

a turbo-compressor package connected to a pipeline inlet and configured to raise a low pressure of an input feed gas to a high pressure;

an NGL recovery package connected to the turbo-compressor package and configured to receive the feed gas having the high pressure; and

a filter package configured to receive a fuel gas from the NGL recovery package, to heat and filter the received fuel gas, and to provide the heated and filtered fuel gas to the turbo-compressor as fuel;

wherein the NGL recovery package comprises;

an inlet configured to receive the feed gas from a first location of the transportation pipeline;

a dehydration unit connected to the inlet to receive the feed gas and configured to extract predetermined components from the feed gas to produce a dry gas;

a NGL unit configured to receive the dry gas from the dehydration unit and configured to separate the dry gas into a fuel gas and a NGL mix;

a first outlet connected to the NGL unit and configured to output the fuel gas to the filter package; and

a second outlet connected to the NGL unit and configured to output the NGL mix back to the transportation pipeline, at a second location situated downstream from the first location.

17. The station of claim 8, wherein the feed gas is at a pressure higher than the cricondenbar.

18. The station of claim 8, wherein the dehydration unit does not include a wet gas cooler followed by a separator to remove the condensed water from the regeneration gas stream, does not include a regeneration gas re-compression system and does not contaminate the dry gas stream.

9. A processing system for separating natural gas liquids (NGL), the system comprising:

a turbo-compressor package configured to compress an input feed gas that flows through a transportation pipeline to a first location of the transportation pipeline to raise a low pressure of the input feed gas to a high pressure;

an NGL recovery package connected to the turbo-compressor package and configured to receive the feed gas having the high pressure; and

a filter package configured to receive a fuel gas from the NGL recovery package, to heat and filter the received fuel gas, and to provide the heated and filtered fuel gas to the turbo-compressor as fuel;

wherein the NGL recovery package comprises;

an inlet configured to receive the feed gas having a high pressure;

a dehydration unit connected to the inlet to receive the feed gas and configured to extract predetermined components from the feed gas to produce a dry gas;

a NGL unit configured to receive the dry gas from the dehydration unit and configured to separate the dry gas into a fuel gas and a NGL mix;

a first outlet connected to the NGL unit and configured to output the fuel gas to the filter package; and

a second outlet connected to the NGL unit and configured to output the NGL mix to the transportation pipeline at a second location situated downstream from the first location.

19. The processing system of claim 9, wherein the feed gas is at a pressure higher than the cricondenbar.

20. The processing system of claim 9, wherein the dehydration unit does not include a wet gas cooler followed by a separator to remove the condensed water from the regeneration gas stream, does not include a regeneration gas re-compression system and does not contaminate the dry gas stream.

10. A method for separating natural gas liquids (NGL) from a feed gas, the method comprising:

receiving the feed gas;

increasing a pressure of the feed gas by running the feed gas through a compressor connected to a as turbine;

diverting part of the feed gas from an output of the compressor and feeding the diverted part to a dryer;

drying the diverted part to remove water and produce a dry gas;

expanding the dry gas in a turbo-expander;

separating the expanded gas into the NGL and fuel gas; and

providing the fuel gas to the gas turbine as fuel without contamination.

11. The method of claim 10, wherein the feed gas is at a pressure higher than the cricondenbar.

12. The method of claim 10, wherein receiving the feed gas comprises providing an NGL recovery system having an inlet configured to receive the feed gas at a first location of a transportation pipeline.

13. The method of claim 10, wherein separating the expanded vas into the NGL and fuel gas comprises providing a NGL unit coupled to a dehydration unit and configured to receive the dry gas.

14. The method of claim 10, wherein providing the fuel gas to the gas turbine comprises providing an outlet connected to the NGL unit and configured to output the fuel gas to the gas turbine to be ignited.

15. The method of claim 10, wherein separating the expanded gas into the NGL and fuel gas comprises providing a separator connected to the turbo-expander and configured to separate a fluid phase from a gas phase of the cooled dry gas.

16. The method of claim 13, wherein the NGL unit does not include a demethanizer or a glycol injecting unit.