Natural gas sweetening process

The removal of acid gases such as hydrogen sulphide (H2S) and carbon dioxide (CO2) from process gas streams is required in LNG plants. There are many treating processes available(Chemical,physical,Hybrid,permeation......etc). However, no single process is ideal for all applications. The initial selection of a particular process may be based on feed parameters such as composition, pressure, temperature and the nature of the impurities, as well as product specifications. Final selection is ultimately based on process economics, reliability, versatility and environmental constraints. Clearly the selection procedure is not a trivial matter and any tool that provides a reliable mechanism for process design is highly desirable.

Acid gas removal processes using absorption technology and chemical solvents are popular, particularly those using aqueous solutions of alkanolamines The absorption/desorption processes to remove CO2 from feed natural gas are designed with DEA (diethanolamine) aqueous solution which is generally used in the oil & gas industries.

The conventional process configuration for a gas treating system that uses aqueous alkanolamine solutions consists of absorption and desorption (amine regeneration) processes. The sour gas feed is contacted with amine solution counter-currently in a trayed or packed absorber. Acid gases are absorbed into the solvent that is then heated and fed to the top of the regeneration tower. Stripping steam produced by the reboiler causes the acid gases to desorb from the amine solution as it passes down the column. A condenser provides reflux and the acid gases are recovered overhead as a vapour product. Lean amine solution is cooled and recycled back to the absorber.

A partially stripped, semi-lean amine stream may be withdrawn from the regenerator and fed to the absorber in the split-flow modification to the conventional plant flowsheet. A three-phase separator or flash tank may be installed at the outlet of the absorber to permit the recovery of dissolved and entrained hydrocarbons and to reduce the hydrocarbon content of the acid gas product.

PROCESS DESCRIPTION

The purpose of this acid gas removal unit (A-1000) is to remove CO2 from the natural gas feed to the liquefaction unit to prevent it from freezing out at low temperature and to meet the LNG product specification.

Basically, the Unit A-1000 consists of absorption (A-C-1001) and regeneration (A-C-1002) columns. The feed to the unit A-1000 is natural gas from the pressure boundary replacing a plant pressure control station downstream of natural gas wellhead in an actual plant. The feed gas enters the unit at 62 bara and 15 ℃ and is fed to the feed gas knock-out vessel (A-V-1001), where liquid hydrocarbons or other contaminants will be dropped out to avoid contamination and foaming of the amine solution. Any liquids from A-V-1001 are sent to the atmospheric pressure boundary which is a battery limit of this project and has no more process to treat the liquids. The gas is then pre-heated in the feed gas heater (A-E-1006) to 25 ℃ with heating medium coming from the pressure boundary. This project does not include the heating medium production process and treats as a battery limit.

The feed gas flows into the absorber (A-C-1001) entering the column below tray 1. Lean solvent enters the top of the absorber and flows counter-currently to the feed gas, thereby absorbing the acid gas.

 The treated gas leaving the top of the absorber flows through the treated gas cooler (A-E-1005) which cools the gas to 45 ℃. The treated gas then flows through the Drier Pre-cooler (L-E-4015) in the Liquefaction Unit (L-4000) which cools more to 22 ℃ and passes to the feed gas separator (D-V-2003) in the molecular sieve dehydration unit (D-2000).

 The treated gas from Unit A-1000 must meet a CO2 specification of 50 ppmv maximum. The normal CO2content of the treated gas exiting Unit A-1000 is expected to be 20-40 ppm, or less.

 The rich amine solution (acid gas loaded) leaves the bottom of the absorber A-C-1001 and is reduced in pressure to 9 bara through level control valve (A-LCV-1002) before entering the rich amine flash drum (A-V-1003) to flash off hydrocarbons which are entrained and dissolved in the solution. The flashed vapours are vented to the flare system which is assumed as pressure boundary in this process design.

 The CO2 rich solvent is then heated in the Rich/Lean Amine Exchanger (A-E-1001A/B) to about 100 ℃where it is counter-currently contacted with hot solvent from the regenerator A-C-1002 before it enters A-C-1002 near the top of the column.

 In the regenerator A-C-1002, the acid gas components (CO2) are stripped from the solvent at elevated temperature (120 ℃ at the bottom) and low pressure (1.8 bara) using steam generated in the Regenerator Re-boilers (A-E-1002). The duty of the re-boiler is delivered via the heating medium coming from the pressure boundary.

 The regenerated lean amine solvent is withdrawn from the bottom of the regenerator (A-C-1002) and flows through A-E-1001A/B and pumped (A-P-1003A/B) to the Lean Amine Cooler (A-E-1004) which is a trim cooler to regulate the regenerated lean amine temperature (~ 53 ℃) in a narrow temperature range before storage . The lean solvent exiting A-E-1004 is stored at the atmospheric pressure in the Amine Storage Tank (A-T-1001). The regenerated lean amine is then pumped from A-T-1001 to A-C-1001 by Amine charge pump (A-P-1001 A/B).

 The Acid gas and steam are water-washed by the sour water reflux from the Reflux Pump (A-P-1002 A/B) on the top trays in the regenerator A-C-1002. This stream is then cooled to 45.5 Deg C in the Regenerator Overhead Condenser (A-E-1003) before the condensed sour water is separated in the Regenerator Reflux Drum (A-V-1002). The water is pumped back to A-C-1002 by A-P-1002 A/B while the acid gas is sent to the pressure boundary to control the pressure at 1.5 bara and the pressure boundary is a battery limit of this project. The control valve (A-PCV-1004 A/B) on the acid gas outlet from V-1102 is used to control the Regenerator pressure. The continuous demineralised water make-up stream also feeds A-V-1002 through the flow control valve (A-FCV-1007).

 Read original by Larbi Hammoun