Gas Sweetening with Amines — MDEA, MEA, DEA, and Mixed Solvents

Introduction

Natural gas leaving the reservoir is rarely clean. Sour gas contains hydrogen sulfide (H₂S) and/or carbon dioxide (CO₂) — both acid gases that must be removed before the gas can be sold, transported, or used as feedstock. The treated gas is sweet.

The reasons are concrete: H₂S is lethal at concentrations as low as 100 ppm, both H₂S and CO₂ corrode carbon steel pipelines via carbonic acid and sulphide stress cracking, and pipeline tariffs typically demand H₂S below 4 ppmv and CO₂ below 2 mol%. Refinery feedstocks have similar specs. LNG plants are even more demanding — typically below 50 ppmv CO₂ to prevent freeze-out at cryogenic temperatures.

The dominant treating technology is amine absorption. An aqueous amine solution captures the acid gases in an absorber, the rich amine flows to a regenerator where heat strips the acid gases out, and the lean amine returns to the absorber. The chemistry is reversible, the technology is mature, and most upstream and midstream gas treating plants run on it.

This post covers amine selection, absorber and regenerator design, the property package question, and the operating issues — corrosion, foaming, heat-stable salts — that turn a designed unit into a chronic operations problem.

The Amine Family

Amines are categorised by the number of hydrogen atoms substituted on the nitrogen:

The key operational distinction: MEA and DEA react with both H₂S and CO₂ at fast rates, removing both species in the absorber. MDEA reacts rapidly with H₂S but slowly with CO₂ — this kinetic selectivity is the foundation of "selective sweetening" plants where H₂S is removed but CO₂ slips through.

Kinetic selectivity is exploited in two main applications:

• H₂S-rich, CO₂-rich feed where the goal is to keep CO₂ in the gas stream — for example, when CO₂ is intentionally retained as ballast or fuel
• Tail gas treating in sulphur recovery units, where a low-CO₂-loading regenerator overhead improves the Claus plant operation

When to Use Which Amine

The industry has largely converged on MDEA-based formulations for new gas treating units. MEA is increasingly relegated to refinery use and existing legacy plants; DEA remains common for general sour gas service, especially in regions with established maintenance and supply chains.

Absorber Design

The absorber is a vertical column where lean amine flows down and sour gas flows up. Key design parameters:

Operating Pressure and Temperature

Absorbers run at sales-gas pressure — typically 50–80 barg for production gas, higher for export. Higher pressure favours acid gas absorption (Henry's law). Inlet gas temperature is typically 30–50°C; below 30°C, the higher viscosity of cold amine slows mass transfer; above 50°C, equilibrium becomes unfavourable.

Number of Stages

For sales-spec sweetening (4 ppm H₂S), 15–20 actual trays or about 15–20 m of structured packing is typical. LNG-spec ultra-low CO₂ requires 25–30 trays.

Amine Circulation Rate

Calculated from the acid gas mass balance and the target lean and rich amine loadings:

Lean loading α_lean (mol acid gas / mol amine): typically 0.005–0.05
Rich loading α_rich (mol acid gas / mol amine): typically 0.30–0.45 for MDEA, 0.40–0.50 for DEA, 0.30 max for MEA

Amine circulation = m_acid_gas / (α_rich - α_lean)

Higher rich loading reduces circulation rate but increases corrosion. Industry practice caps rich-side acid gas loadings at:

Pushing higher is technically possible but accelerates corrosion sharply.

Diameter

Sized for vapour velocity per Souders-Brown:

v_max = K × √((ρ_L - ρ_V) / ρ_V)

For amine absorbers with structured packing, K ≈ 0.090–0.120 ft/s (0.027–0.037 m/s). Trayed columns: K ≈ 0.13–0.18 ft/s. Margin for foaming events should be retained.

Regenerator (Stripper) Design

The regenerator strips acid gas from rich amine using heat, producing lean amine ready for re-injection. Key parameters:

Reboiler Duty

The dominant operating cost. Total reboiler duty = sensible heat (heating amine from rich-amine return temperature to bottom temperature) + stripping steam generation (water vaporisation that carries acid gas overhead) + acid gas desorption heat (reverse of the heat of absorption).

Typical specific reboiler duties:

MEA is the highest energy consumer; MDEA the lowest. For a large gas plant, the difference between MEA and MDEA can be tens of thousands of US dollars per day in steam cost.

Reboiler Temperature

Capped to prevent thermal degradation of the amine:

Above these limits, amine degradation accelerates — producing heat-stable salts (HSS) that cannot be regenerated and accumulate in the loop, plus various organic byproducts that promote foaming and corrosion.

Stripping Steam Ratio

Lean loading is set by the stripping steam ratio — typically 1.0–1.5 kg steam per kg of regenerated amine for MDEA. Higher ratio gives lower lean loading and deeper stripping but increases reboiler duty.

The Lean-Rich Heat Exchanger

Lean amine leaves the regenerator at ~120°C and must be cooled to absorber feed temperature (~40°C). Rich amine leaves the absorber at ~50°C and must be heated to near regenerator feed temperature (~95°C) before entering the regenerator top.

The lean-rich exchanger is sized for an LMTD of typically 20–30°C (small approach because the streams are close to parallel). It is the dominant heat-recovery component — a poor-design lean-rich exchanger can double the reboiler duty.

Standard configuration: plate-and-frame for lean-rich (high heat transfer coefficient, compact), or shell-and-tube for high-fouling services. Lean amine on the cleaner side (shell or plate); rich amine on the side with provision for cleaning.

Property Package — Why PR Doesn't Work

Amine systems involve aqueous chemistry with ionised species — the protonation of amine by H₂S and CO₂ is a chemical reaction, not just physical absorption. Cubic EOS like PR or SRK have no concept of this chemistry and produce numerically plausible but qualitatively wrong results.

The right tools are:

These packages are calibrated against decades of pilot and field data. They model the protonation/deprotonation equilibria, kinetics of CO₂ reaction with amines (which determines selectivity), and the temperature-dependent vapour pressure of the rich amine.

Using PR EOS for an amine absorber is one of the most common simulation errors and produces outputs that look reasonable until they are compared against operating plant data.

Operating Issues

The amine plant in steady state is straightforward. The amine plant in real operation faces several recurring issues:

Foaming

The most common operational problem. Caused by hydrocarbon contamination (carryover from upstream separators), iron sulphide fines, fine solids, or surfactant contamination. Foam reduces tray efficiency, can cause amine carryover at the absorber top, and triggers high-DP shutdowns.

Mitigations: a pre-flash drum to remove flashed hydrocarbons before the regenerator, a mechanical filter on the lean amine (typically 10 micron), a carbon filter to remove organic surfactants, and anti-foam injection as a last resort (use sparingly — silicone-based anti-foams cause downstream issues).

Corrosion

The corrosion mechanism depends on the amine and the acid gas:

• CO₂ corrosion is general thinning, accelerated by high rich loading and high temperature
• H₂S sulfide stress cracking (SSC) is an embrittlement problem affecting carbon steel under tensile stress
• Wet sour service triggers NACE MR0175 / ISO 15156 material requirements

Standard practice is carbon steel for the bulk plant, 316 stainless for the regenerator overhead and reflux drum, and stress relieving of welds in NACE service. For high-CO₂ MEA service, sometimes upgrade to 316L throughout.

Heat-Stable Salts (HSS)

Permanent reaction products that accumulate in the loop and cannot be regenerated. Sources: O₂ ingress (oxidation), high-temperature degradation, contamination. Above ~5 wt% HSS, amine performance drops sharply and corrosion accelerates.

Mitigations: O₂ exclusion (nitrogen blanket on storage tanks), reboiler temperature discipline, and amine reclaiming (typically once per 1–3 years; ion exchange or vacuum distillation to remove HSS).

Lean Loading Discipline

Lean amine loading directly affects absorber performance. A 0.005 mol/mol drift in lean loading can be the difference between meeting sales spec and being out of spec. Lean loading is monitored by online conductivity and titration, with a target hold tighter than ±0.005.

Practical Pitfalls

• Using PR EOS for amine simulation. Will produce numbers; will not produce useful numbers. Always use a chemistry-aware property package.
• Sizing the amine flow rate too tight. Operational variability (water cut, CO₂ slugs, temperature fluctuations) means the design point flow may not be enough during upset. Build in 15–20% turndown and turnup capability.
• Skipping the carbon filter. Mechanical filters catch solids; organic surfactants pass through. After 6–12 months, foam events become chronic without carbon filtration.
• Pushing reboiler temperature. Every degree above the recommended limit accelerates thermal degradation. Operations may be tempted to "open the steam valve" to chase a low lean-loading target — the long-term cost is HSS accumulation.
• Inadequate inlet separation. The most common upstream cause of amine plant trouble is hydrocarbon liquid carryover into the absorber. A coalescing inlet separator is not optional.
• Forgetting about mercaptans. Amines do not effectively remove RSH (mercaptans). For pipeline gas where total sulphur spec includes mercaptans, downstream molecular sieves or scavenger are required.
• Underestimating O₂ ingress. Atmospheric oxygen in the storage tank degrades amine and forms HSS. Nitrogen blanket and sealed sample valves are mandatory, not optional.

Conclusion

Amine gas sweetening is a mature, robust technology — but only within its design envelope. The four levers are amine selection, absorber design, regenerator energy, and the lean-rich heat integration. Getting these right is the engineering. Keeping them right requires operational discipline: foam control, corrosion management, HSS removal, and lean loading hold.

The decision tree is straightforward: MDEA-based for new units, DEA for general retrofit and capex-constrained projects, MEA for legacy and very specific bulk-removal services. The simulation tool is non-negotiable: use the chemistry-aware property package. The operational vigilance is non-negotiable: a pre-flash drum, a carbon filter, an O₂-exclusion regime, and a reclaiming schedule.

Plants designed within these constraints run reliably for decades. Plants designed against them limp through their service life — meeting sales spec on a good day, struggling on a bad one.