Method of removing carbon dioxide during liquid natural gas production from natural gas at gas pressure letdown stations

• US 10,288,347 B2
• Filed: 08/15/2014
• Issued: 05/14/2019
• Est. Priority Date: 08/15/2014
• Status: Active Grant

• Current Assignee: 1304338 Alberta, Ltd., 1304342 Alberta, Ltd.
• Original Assignee: 1304338 Alberta, Ltd., 1304342 Alberta, Ltd.
• Inventors: Lourenco, Jose, Millar, MacKenzie
• Primary Examiner(s): Duke, Emmanuel
• Application Number:
  US15/504,003
• Publication Number:
  US 20170241709A1
• Time in Patent Office: 1,733 Days
• CPC Class Codes: C10L 2290/06 Heat exchange, direct or indirect
• CPC Class Codes: C10L 2290/08 Drying or removing water
• CPC Class Codes: C10L 2290/48 Expanders, e.g. throttles or flash tanks
• CPC Class Codes: C10L 2290/54 Specific separation steps for separating fractions, components or impurities during preparation or upgrading of a fuel
• CPC Class Codes: C10L 2290/545 Washing, scrubbing, stripping, scavenging for separating fractions, components or impurities during preparation or upgrading of a fuel
• CPC Class Codes: C10L 3/104 Carbon dioxide
• CPC Class Codes: C10L 3/106 of water
• CPC Class Codes: F25J 1/0022 Hydrocarbons, e.g. natural gas
• CPC Class Codes: F25J 1/0035 by gas expansion with extraction of work
• CPC Class Codes: F25J 1/0037 of a return stream
• CPC Class Codes: F25J 1/004 by flash gas recovery F25J1/0267 takes precedence
• CPC Class Codes: F25J 1/0042 by liquid expansion with extraction of work
• CPC Class Codes: F25J 1/0201 using only internal refrigeration means, i.e. without external refrigeration
• CPC Class Codes: F25J 1/0232 integration within a pressure letdown station of a high pressure pipeline 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 2205/04 in the feed line, i.e. upstream of the fractionation step
• CPC Class Codes: F25J 2205/50 using absorption, i.e. with selective solvents or lean oil, heavier CnHm and including generally a regeneration step for the solvent or lean oil
• CPC Class Codes: F25J 2210/06 Splitting of the feed stream, e.g. for treating or cooling in different ways
• CPC Class Codes: F25J 2215/04 Recovery of liquid products
• CPC Class Codes: F25J 2220/64 Separating heavy hydrocarbons, e.g. NGL, LPG, C4+ hydrocarbons or heavy condensates in general
• CPC Class Codes: F25J 2220/66 : Separating acid gases, e.g. CO2, SO2, H2S or RSH
• 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 2230/32 : Compression of the product stream
• 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 2260/10 : Integration in a gas transmission system at a pressure reduction, e.g. "let down" station
• CPC Class Codes: F25J 2270/04 : Internal refrigeration with work-producing gas expansion loop
• CPC Class Codes: F25J 3/0209 : Natural gas or substitute natural gas
• CPC Class Codes: F25J 3/0233 : separation of CnHm with 1 carbon atom or more
• CPC Class Codes: F25J 3/0266 : separation of carbon dioxide production of carbon dioxide in general C01B32/00
• CPC Class Codes: F25J 3/0615 : Liquefied natural gas
• CPC Class Codes: F25J 3/08 : Separating gaseous impurities from gases or gaseous mixtures or from liquefied gases or liquefied gaseous mixturescold traps B01D8/00
• CPC Class Codes: Y02C 20/40 : of CO2

Abstract

A method is described for removing carbon dioxide during Liquid Natural Gas production from natural gas at gas pressure letdown stations. The above method removes carbon dioxide from a Liquid Natural Gas production stream by using hydrocarbon fractions taken from a gas for consumption stream as a carbon dioxide stripping adsorption agent for a stripping column used to remove carbon dioxide.

Claims

1. A method of removing carbon dioxide during Liquid Natural Gas production natural gas at a gas pressure let down station, comprising:

passing high pressure natural gas through a first heat exchanger to pre-cool the high pressure natural gas entering the pressure let down station;

passing the pre-cooled high pressure natural gas through a separator to remove condensates from the high pressure natural gas exiting the first heat exchanger;

passing the high pressure natural gas through a natural gas dewatering unit to remove water from the high pressure natural gas exiting the separator;

passing the dewatered high pressure natural gas through a second heat exchanger to pre-cool the dewatered high pressure natural gas;

splitting the dewatered high pressure natural gas into a Liquid Natural Gas production stream and a gas for consumption stream;

passing the Liquid Natural Gas production steam through a third heat exchanger to pre-cool the Liquid Natural Gas production stream;

passing the Liquid Natural Gas production stream through a carbon dioxide stripping column to remove carbon dioxide;

passing the gas for consumption stream through a first pressure reduction unit to depressurize the gas for consumption stream;

passing the gas for consumption stream through a second separator to recover condensed hydrocarbon fractions from the gas for consumption stream; and

passing the condensed hydrocarbon fractions from the gas for consumption stream to the stripping column for use as a carbon dioxide stripping adsorption agent;

passing the Liquid Natural Gas production stream through one or more further heat exchangers to further cool the Liquid Natural Gas production stream to facilitate Liquid Natural Gas production;

passing the Liquid Natural Gas production stream through a second pressure reduction unit to depressurize the Liquid Natural Gas production stream; and

passing the Liquid Natural Gas production stream through a third separator to achieve separation of Liquid Natural Gas (LNG) and vapors.

2. The method of claim 1, wherein the one or more further heat exchangers include a fourth heat exchanger and a fifth heat exchanger.

3. The method of claim 1, wherein a precooling stream passing through the first heat exchanger is provided by vapour fractions drawn from the second and third separator.

4. The method of claim 1, wherein the temperature of the LNG production stream before the stripper is controlled on demand to meet process requirements.

5. The method of claim 1, wherein the line carrying condensed hydrocarbon fractions to the stripping column has a bypass line that bypasses the stripping column, such that the quantity of condensed hydrocarbon fractions entering the stripping column is controlled by diverting excess condensed hydrocarbon fractions to the bypass line.