Sour gas and acid natural gas separation membrane process by pre removal of dissolved elemental sulfur for plugging prevention

• US 8,540,804 B2
• Filed: 11/01/2010
• Issued: 09/24/2013
• Est. Priority Date: 11/01/2010
• Status: Active Grant

• Current Assignee: Saudi Arabian Oil Company (Government of Saudi Arabia)
• Original Assignee: Saudi Arabian Oil Company (Government of Saudi Arabia)
• Inventors: Vaidya, Milind M., Ballaguet, Jean-Pierre R., Duval, Sebastien A., Khawajah, Anwar H.
• Primary Examiner(s): Smith, Duane
• Assistant Examiner(s): PATEL, PANKTI R
• Application Number:
  US12/916,701
• Publication Number:
  US 20120103185A1
• Time in Patent Office: 1,058 Days
• Field of Search: None
• US Class Current: 95/214
• CPC Class Codes: B01D 2256/245 Methane
• CPC Class Codes: B01D 2257/102 Nitrogen
• CPC Class Codes: B01D 2257/30 Sulfur compounds
• CPC Class Codes: B01D 2257/304 Hydrogen sulfide
• CPC Class Codes: B01D 2257/504 Carbon dioxide
• CPC Class Codes: B01D 2257/80 Water
• CPC Class Codes: B01D 53/14 by absorption
• CPC Class Codes: B01D 53/229 Integrated processes (Diffusion and at least one other process, e.g. adsorption, absorption)
• CPC Class Codes: C07C 7/11 by absorption, i.e. purification or separation of gaseous hydrocarbons with the aid of liquids
• CPC Class Codes: Y02C 20/40 of CO2

Abstract

Methods for removing sulfur from a gas stream prior to sending the gas stream to a gas separation membrane system are provided. Two schemes are available. When the sulfur content is high or flow is relatively high, a scheme including two columns where one tower is regenerated if the sulfur concentration exceeds a preset value can be used. When the sulfur content is low or flow is relatively low, a scheme including one column and an absorption bed.

Claims

1. A method of removing sulfur from a gas stream comprising the steps of:

a. contacting the gas stream with a solvent to selectively absorb at least a portion of elemental sulfur from the gas stream such that the gas stream has a sulfur concentration that is substantially less than prior to the gas stream being contacted with the solvent;

b. filtering entrained liquid droplets from the gas stream so that sulfur does not become deposited on a gas separation membrane; and

c. passing the gas stream through the gas separation membrane.

2. The method of claim 1, wherein the step of contacting the gas stream with a solvent occurs in a solvent scrubber.

3. The method of claim 1, wherein the step of contacting the gas stream with a solvent occurs when the gas stream is flowing upstream and the solvent is flowing downstream counter currently to the gas stream.

4. The method of claim 1, wherein the step of filtering entrained liquid droplets occurs in a coalescing filter.

5. The method of claim 2, further comprising the step of regenerating the solvent by sending a gas capable of dissolving sulfur through the solvent scrubber.

6. The method of claim 5, wherein the gas capable of dissolving sulfur comprises hydrogen sulfide recovered from the gas separation membrane or recovered from an amine unit regenerator outlet.

7. The method of claim 5, wherein the step of regenerating the solvent scrubber occurs at a pressure operative to compensate for pressure loss in the solvent scrubber and its piping.

8. The method of claim 1, wherein the step of contacting the gas stream with the solvent occurs at a pressure substantially similar to a feed gas pressure of the gas stream.

9. The method of claim 1, further comprising the step of analyzing a sulfur concentration of an overhead stream of the solvent scrubber and sending the gas stream to a second column if the sulfur concentration exceeds a sulfur solubility estimated in retentate and permeate flows by membrane separation process simulation.