Processes and systems for high H2S gas processing having reduced sulfur production

Patent metadata

Field	Value
Publication number	US-11319792-B2
Application number	US-201916441089-A
Country	US
Kind code	B2
Filing date	Jun 14, 2019
Priority date	Jun 15, 2018
Publication date	May 3, 2022
Grant date	May 3, 2022

Abstract

Disclosed are methods and systems for reducing elemental sulfur production in a gas production plant that includes receiving produced fluids high in hydrogen sulfide, removing hydrogen sulfide and converting hydrogen sulfide to elemental sulfur in a Claus unit. An acid gas stream is diverted from a feed line to the Claus unit in the gas processing plant and directed to a multistage acid gas compressor. An elemental sulfur production rate is reduced without reducing a production rate of the produced fluids. The compressed acid gas stream can be injected into a subterranean formation. In some embodiments, the gas production plant is integrated with an oil processing and gas injection plant.

First claim

What is claimed is:

1. A system for reducing elemental sulfur production in a gas production plant that includes receiving produced fluids high in hydrogen sulfide, removing hydrogen sulfide and converting hydrogen sulfide to elemental sulfur, comprising:
a. a gas processing plant for receiving a feed stream comprising gas containing from 4 ppm to 60% hydrogen sulfide by volume, wherein the gas processing plant includes:
i. at least one amine unit for removing hydrogen sulfide from the feed stream; and
ii. a Claus unit connected to a hydrogen sulfide gas outlet of the at least one amine unit for receiving a Claus unit feed containing from 50 to 85% hydrogen sulfide by volume and producing elemental sulfur;

b. piping for diverting an acid gas stream from a feed line to the Claus unit in the gas processing plant and directing the diverted acid gas stream to an acid gas compressor; and
c. the acid gas compressor having multiple stages and multiple after-coolers after each stage for increasing a pressure of the diverted acid gas stream and forming a compressed acid gas stream;
wherein an elemental sulfur production rate is reduced without reducing a production rate of the produced fluids.

2. The system of claim 1 wherein the diverted acid gas stream is a dense phase fluid when discharged from the acid gas compressor, and further comprising a dense phase pump for pumping the dense phase fluid.

3. The system of claim 2 further comprising an acid gas injection unit through which the dense phase fluid is pumped into an acid gas injection well.

4. The system of claim 1 further comprising an acid gas injection unit for injecting the compressed acid gas stream into a subterranean formation.

5. The system of claim 1 further comprising an upstream separator for separating produced fluids from a subterranean reservoir into an associated gas stream, an oil stream and a water stream; and an oil processing and gas injection plant for receiving a portion of the associated gas stream and a portion of an oil stream from the upstream separator, wherein the oil processing and gas injection plant comprises:
a. at least one gas-oil separator for receiving the portion of the oil stream from the upstream separator;
b. at least one compressor for increasing a pressure of one or more gas streams as separated by the at least one gas-oil separator to form a compressed sour gas stream;
c. at least one stabilizer for removing dissolved gases including hydrogen sulfide from the oil stream wherein the removed dissolved gases are compressed in the at least one compressor;
d. piping for feeding the portion of the associated gas stream from the upstream separator to a most downstream compressor of the at least one compressors such that the compressed sour gas stream and the portion of the associated gas stream are combined to form a compressed sour gas injection unit feed stream; and
e. a sour gas injection unit for injecting a portion of the compressed sour gas injection unit feed stream into a subterranean formation.

6. The system of claim 5 further comprising an eductor for receiving a portion of the associated gas stream from the upstream separator as a high pressure stream and the diverted acid gas stream from the feed line to the Claus unit as a low pressure stream such that a pressure-boosted stream leaves the eductor and is fed to the acid gas compressor, wherein the pressure-boosted stream has a lower concentration of hydrogen sulfide than the diverted acid gas stream.

7. The system of claim 5 wherein a portion of the portion of the associated gas stream from the upstream separator is fed to an intermediate stage of the acid gas compressor wherein a stream leaving the acid gas compressor has a lower concentration of hydrogen sulfide than the diverted acid gas stream, a pressure to match the compressed sour gas injection unit feed stream and wherein the stream leaving the acid gas compressor is combined with the compressed sour gas injection unit feed stream to form a stream to be injected into the subterranean formation.

8. The system of claim 4 , 6 or 7 further comprising a control system for controlling a composition of a stream to be injected into the subterranean formation to achieve a desired composition for enhanced oil recovery, wherein the control system comprises a control valve for adjusting an amount of acid gas stream to be diverted, a control valve for adjusting an amount of the portion of the portion of the associated gas stream from the upstream separator fed to an intermediate stage of the acid gas compressor, and/or a control valve for adjusting an amount of the portion of the associated gas stream from the upstream separator as the high pressure stream received by the eductor.

9. A method for reducing elemental sulfur production in a gas production plant that includes receiving produced fluids high in hydrogen sulfide, removing hydrogen sulfide and converting hydrogen sulfide to elemental sulfur, comprising:
a. receiving a feed stream comprising gas containing from 4 ppm to 60% hydrogen sulfide by volume and removing hydrogen sulfide from the feed stream in at least one amine unit to produce a sweet gas stream and an acid gas stream containing from 50 to 85% hydrogen sulfide by volume;
b. producing elemental sulfur from the acid gas stream in a Claus unit connected to the at least one amine unit by a feed line to the Claus unit;
c. diverting an acid gas stream from the feed line to the Claus unit to an acid gas compressor having multiple stages and multiple after-coolers after each stage; and
d. increasing a pressure of the diverted acid gas stream in the acid gas compressor to form a compressed acid gas stream;
wherein an elemental sulfur production rate is reduced without reducing a production rate of the produced fluids.

10. The method of claim 9 wherein the diverted acid gas stream is a dense phase fluid when discharged from the acid gas compressor, and further comprising pumping the dense phase fluid into the subterranean formation through an injection well.

11. The method of claim 9 further comprising injecting the compressed acid gas stream into a subterranean formation.

12. The method of claim 9 further comprising separating produced fluids from a subterranean reservoir into an associated gas stream containing from 4 ppm to 60% hydrogen sulfide by volume, an oil stream and a water stream in an upstream separator; and receiving a portion of the associated gas stream and a portion of the oil stream from the upstream separator in an oil processing and gas injection plant, wherein the oil processing and gas injection plant comprises:
a. at least one gas-oil separator for receiving the portion of the oil stream from the upstream separator;
b. at least one compressor for increasing a pressure of one or more gas streams as separated by the at least one gas-oil separator to form a compressed sour gas stream;
c. at least one stabilizer for removing dissolved gases including hydrogen sulfide from the oil stream wherein the removed dissolved gases are compressed in the at least one compressor;
d. piping for feeding the portion of the associated gas stream from the upstream separator to a most downstream compressor of the at least one compressors such that the compressed sour gas stream and the portion of the associated gas stream are combined to form a compressed sour gas injection unit feed stream; and
e. a sour gas injection unit for injecting the compressed sour gas injection unit feed stream into a subterranean formation.

13. The method of claim 12 further comprising, receiving in an eductor a portion of the associated gas stream from th

Assignees

• Chevron Usa Inc

Inventors

• Chinn Daniel
• Hetrick Brent A
• Bhuwania Nitesh
• Husain Shabbir
• Mishael Sam J

Classifications

• B01D2257/304

  Hydrogen sulfide · CPC title

• B01D2256/24

  Hydrocarbons · CPC title

• B01D53/1468

  Removing hydrogen sulfide · CPC title

• B01D2252/204

  Amines · CPC title

• C01B17/0404 Primary

  by processes comprising a dry catalytic conversion of hydrogen sulfide-containing gases, e.g. the Claus process · CPC title