MEA vs MDEA vs AMP for Gas Sweetening: Selection Matrix by Acid Gas Load

Acid gas load is defined as the molar ratio of absorbed H₂S plus CO₂ to free amine. In alkanolamine-based gas sweetening, lean loading determines the thermodynamic removal floor, while rich loading governs circulation rate, regenerator size, and corrosion current. Monoethanolamine (MEA) is a primary amine with intrinsically fast absorption kinetics but a practical rich loading ceiling near 0.35–0.45 mol/mol in carbon steel contactors. N-methyldiethanolamine (MDEA) is a tertiary amine that accepts high acid gas loadings of 0.7–1.0 mol/mol with reduced corrosion and lower regeneration heat, but its CO₂ hydration path is kinetically slower. 2-amino-2-methyl-1-propanol (AMP) is a sterically hindered primary amine whose unstable carbamate intermediate yields a bicarbonate-dominated absorption path, providing industrial rich loadings of 0.55–0.85 mol/mol and lower regeneration energy than MEA. The selection matrix by acid gas load therefore separates these solvents by rich loading capacity, lean loading floor, corrosion current, and regeneration energy rather than by a single property ranking.

Why Is Rich Acid Gas Loading the Primary Constraint in MEA Absorption Trains?

MEA is typically applied as a 15–20 wt% aqueous solution. At absorber temperatures near 40–50 °C, its primary amine group reacts with CO₂ to form a carbamate, giving a maximum stoichiometric CO₂ uptake of 0.5 mol CO₂/mol amine. The practical rich loading is held below this value because carbamate decomposition products and bulk CO₂ partial pressure increase corrosion current in carbon steel hot rich amine piping. In producing units with carbon steel regenerators, the rich acid gas load is limited to 0.35–0.45 mol/mol, and the lean acid gas load is kept between 0.08 and 0.15 mol/mol. The MEA regeneration reboiler consumes 3.5–4.2 GJ/tonne CO₂ when the feed gas contains 8–12 mol% CO₂. The selection matrix by acid gas load places MEA where deep CO₂ removal below 50 ppmv must be achieved and the feed gas is not dominated by acid gas loadings exceeding the carbamate corrosion envelope. Materials in wet H₂S service are qualified under ISO 15156, and gas composition in these calculations is typically determined by ASTM D1945 and ISO 6974-1:2014.

In natural gas field systems treating 8–12 mol% CO₂ and 200–500 ppmv H₂S, MEA is often selected when downstream cryogenic processing requires a CO₂ residual below 50 ppmv measured by ASTM D1945. The absorber train in such service commonly uses a 20–24-tray or packed column with a lean amine feed temperature held 5–8 °C above the inlet gas dew-point temperature to prevent hydrocarbon condensation. Rich amine from the absorber bottom is flashed at 4–6 bar to remove dissolved hydrocarbons before the lean/rich exchanger. The exchanger shell and hot rich amine piping are frequently fabricated from 316L stainless steel in service above 90 °C. Carbon steel rich amine piping can require continuous corrosion inhibitor injection once the acid gas loading exceeds 0.45 mol/mol and the regenerator overhead temperature approaches 100 °C. A reclaimer drawing 2–3% of lean circulation is installed to control heat stable salts, with reclaimer bulk temperature maintained below 127 °C using 0.4–0.6 MPa steam.

MDEA and the Separation of Claus-Ready Acid Gas Streams

MDEA at 40–50 wt% in water is applied where selective H₂S removal must leave the bulk of CO₂ in the treated gas. H₂S is absorbed by a proton-transfer reaction that is essentially instantaneous, while CO₂ requires hydration to bicarbonate, a path that is 3–5 times slower than carbamate formation in MEA under identical absorber conditions. The selector unit therefore uses 20–30 high-performance valve trays or a short packed bed to separate H₂S kinetically. Rich acid gas loadings of 0.7–1.0 mol/mol are practical because the tertiary amine does not form a stable carbamate, and the attendant iron dissolution in carbon steel is lower. Reboiler duties range from 2.2–3.0 GJ/tonne CO₂, which reduces steam consumption relative to MEA. The operational ceiling is regenerator temperature: thermal degradation to bicine and formamide becomes measurable above 127 °C in the reboiler tube skin, so low-pressure steam at 160–180 °C is normally tempered to maintain a bulk reboiler temperature below 125 °C.

Refinery fuel gas desulfurization with 1–5 mol% H₂S and variable CO₂ often uses MDEA in a split-flow arrangement to produce an acid gas rich in H₂S for a Claus plant. The absorber is frequently designed with 24–30 valve trays and a feed gas temperature of 35–45 °C. In these units, the acid gas load at the bottom of the absorber is controlled between 0.7 and 0.9 mol/mol to avoid amine flashing and foaming in the rich flash drum. The lean MDEA loading is reduced to 0.005–0.04 mol/mol by steam stripping; below 0.005 mol/mol, the solvent tends to pull water from the acid gas, while above 0.04 mol/mol, H₂S removal efficiency declines for low-sulfur refinery fuel gas. Hydrocarbon liquid carryover is kept below 0.05 vol% by maintaining the rich flash drum residence time at 10–20 minutes, and a 5–10 µm absolute lean amine filter is used on a 10% slipstream to reduce foaming.

If AMP Is Selected for Bulk CO₂ Removal in Ammonia Syngas

AMP at 20–30 wt% is selected where the feed gas has high CO₂ partial pressure above 1.5 bar and the treated gas specification is in the 100–200 ppmv range. The hindered primary amine forms a carbamate intermediate that is not stable; the intermediate hydrolyzes to bicarbonate, allowing a theoretical CO₂ loading of 1.0 mol/mol of amine. Industrial rich loadings are limited to 0.55–0.85 mol/mol because the equilibrium lean loading after steam stripping and the mass transfer coefficient at 40–50 °C degrade above this window. Regeneration energy is 2.5–3.3 GJ/tonne CO₂, and the solvent circulation rate in a 25 MMscfd ammonia syngas train is reduced by 25–40% compared with MEA at the same CO₂ removal duty. The absorber in this service is typically a packed tower using structured packing with a superficial gas velocity of 0.8–1.2 m/s. The operating boundary is oxygen ingress; AMP should not be exposed to feed gas containing more than 0.1 mol% O₂ because oxidative degradation forms ammonia and organic acids that increase heat stable salt concentration.

Lean Loading Ceiling in Deep CO₂ Removal Trains

Deep CO₂ removal in LNG pre-treatment imposes a lean loading ceiling that excludes single-component MDEA in many facilities. A MEA lean solution at 0.08–0.15 mol/mol and 15 wt% amine, regenerated at 1.8–2.2 bar overhead pressure, can meet a treated gas CO₂ content below 50 ppmv when the absorber has 20–24 trays. MDEA at 45 wt% with a lean loading below 0.01 mol/mol may require an absorber height increase of 30–50% because of slow CO₂ hydration; this is often uneconomic for liquefaction trains. AMP can achieve 100–200 ppmv, but published data for this specific configuration below 50 ppmv is limited, and vacuum regeneration or a blended piperazine-AMP solvent is typically required.

Gas containing carbonyl sulfide above 0.1 ppmv or carbon disulfide should not be routed to MEA without a reclaimer, because these sulfur species react irreversibly with primary amines and raise heat stable salt content above 1.0 wt%. MDEA and AMP are more resistant but still require thermal reclaiming or ion exchange when heat stable salt levels exceed 2.0 wt% in CO₂-rich service. The acid gas load selection matrix then incorporates contaminant load, because the same solvent that provides a rich loading advantage may generate unacceptable reclaiming frequency under sour gas contaminant stress.