Hydrogen Sulfide Removal: Amine Treating

Hydrogen sulfide, carbon dioxide, mercaptans and other contaminants are often found in natural gas streams. Hydrogen Sulfide (H2S) is a highly toxic gas that is corrosive to carbon steels. Carbon Dioxide (CO2) is also corrosive to equipment and reduces the btu value of gas. Gas sweetening processes remove these contaminants so the gas is marketable and suitable for transportation.

Amine Solutions

Amine treatment plants from Newpoint gas are a proven technology that removes H2S and CO2 from natural gas and hydrocarbon liquid streams through absorption and chemical reaction. Each of the amines offer distinct advantages to specific treating problems. Our amine treating processes include:

  1. MEA - Monoethanolamine is generally used in low pressure treating applications and in operations requiring stringent outlet gas specifications.
  2. DGA - Diglycolamine is used when there is a need for carbonyl sulfide and mercaptan removal in addition to H2S and CO2 removal from gas and liquid streams.
  3. DEA - Diethanolamine is typically used in medium to high pressure treating. DEA does not require reclaiming as MEA and DGA do.
  4. MDEA - Methyldiethanolamine has a higher affinity for H2S than CO2.
  5. FORMULATED (SPECIALTY) SOLVENTS - A variety of blended or specialty solvents are available on the market.

Amine Sweetening Process

Newpoint gas Amine sweetening plants are based on proven gas sweetening technology. The systems are efficient and effective.

  1. Sour gas enters the contactor tower and rises through the descending amine solution.
  2. Purified gas flows from the top of the tower.
  3. The amine solution is now considered rich and is carrying absorbed acid gases. It leaves the tower for the heat exchanger and/or flash tank.
  4. Rich amine is heated by hot, regenerated lean amine in the heat exchanger.
  5. Rich amine is then further heated in the regeneration still column by heat supplied from the reboiler. The steam rising through the still liberates H2S and C02 and therefore regenerates the amine.
  6. Steam and acid gases separated from the rich amine are condensed and cooled, respectively, in the reflux condenser.
  7. Condensed steam is separated in the reflux accumulator and returned to the still. Acid gases may be flared or directed to an acid gas recovery system.
  8. The hot, regenerated, lean amine is cooled in a solvent aerial cooler and circulated to the contactor tower, completing the cycle.
  9. A variety of heat sources may be used for the still reboiler: direct-fired, waste heat, hot oil, and steam systems.

Typical Amine Plant with Standard Features

  1. 100% Pump Standby
  2. Code Vessels
  3. Shell and Tube or Plate Frame Heat Exchangers
  4. Code Piping
  5. Total Custom Electrical Systems and Instrumentation
  6. Deep Bed Carbon Full Flow Filtration
  7. Engineered Corrosion Control
  8. 100% X-Rayed and Stress
  9. Relieved Major Vessels
  10. DCS Electronic Controls
  11. External Cage Level
  12. Controllers
  13. High Efficiency Reboilers

Related links and further information:

For more information on Newpoint's carbon dioxide (CO2) removal system from natural gas using membranes, call us at  (979) 690-8749 or contact@newpointgas.com



Web Design by SoluServ || Internet Marketing by TayloredIdeas