How monoethanolamine removes CO2 and H2S comes down to one chemical fact: monoethanolamine (MEA) is a primary amine, and primary amines react directly with carbon dioxide to form a carbamate, the fastest and most efficient acid-gas absorption route known in the ethanolamine family. MEA (CAS 141-43-5, formula C2H7NO) has been the workhorse amine in gas treating for nearly a century because it combines the highest basicity of the three ethanolamines, the lowest molecular weight, and therefore the largest moles of amine per kilogram of solvent.
When dissolved in water at 15 to 35 per cent by weight and circulated through an absorber column, MEA pulls both CO2 and H2S out of natural gas, refinery off-gas and power-plant flue gas, and releases them in a heated regenerator so the lean amine can be reused. Getting the chemistry, concentrations and plant design right determines whether your unit meets its gas specification, controls degradation and keeps operating costs in check. This guide explains the reaction mechanisms, the absorber–regenerator cycle, the differences between natural gas treating, refinery applications and post-combustion carbon capture, the main degradation pathways, and what to specify when you buy MEA for a gas treating application. If you are still choosing between amines, our companion guide MEA vs DEA vs TEA compares all three.
Monoethanolamine (MEA) in gas treating at a glance
| Property | Monoethanolamine (MEA) |
|---|---|
| Chemical name | 2-Aminoethanol |
| CAS number | 141-43-5 |
| Formula / MW | C2H7NO / 61.08 g/mol |
| Amine type | Primary amine |
| Appearance | Colourless, slightly viscous liquid |
| Odour | Mild ammonia-like odour |
| Density | ~1.018 g/cm3 at 20 °C |
| Freezing point | ~10 °C |
| Boiling point | ~170 °C |
| Viscosity | ~21 mPa·s at 20 °C |
| Relative basicity | Highest of the three ethanolamines (pKa ~9.5) |
| Typical absorber concentration | 15–30 wt% aqueous solution in gas treating |
| Leading gas treating uses | CO2 removal, H2S removal, carbon capture (post-combustion) |
| Key watch-out | Corrosive; degrades with O2, COS, CS2; highest regeneration energy of common amines |
What is monoethanolamine, and why does it absorb CO2 and H2S?
Monoethanolamine is the simplest member of the ethanolamine family. Its molecule contains a primary amine group (–NH2) and a hydroxyl group (–OH) on a two-carbon chain. The amine group carries two hydrogen atoms on the nitrogen, which is the structural feature that makes MEA so reactive with acid gases.
Carbon dioxide and hydrogen sulphide are both acid gases: they dissolve in water to give acidic solutions, and they react with bases. MEA, as a strong base with a pKa of about 9.5, accepts protons from both gases readily. The key difference between the two reactions is the mechanism.
How MEA reacts with CO2
Carbon dioxide reacts with primary amines by two routes. In the first, and faster, route, CO2 reacts directly with the amine to form a carbamate:
This reaction is fast and does not require water. The carbamate is a stable salt in which the carbon dioxide is chemically bound. In the second, slower route, CO2 dissolves in water to form carbonic acid, which then reacts with MEA to form a bicarbonate:
The carbamate route is the one that matters most in the absorber. It accounts for the high rate of CO2 uptake that makes MEA faster than secondary amines (such as diethanolamine) and far faster than tertiary amines (such as methyldiethanolamine, MDEA), which cannot form carbamates and rely entirely on the slower bicarbonate route.
How MEA reacts with H2S
Hydrogen sulphide reacts with MEA by a simpler acid-base mechanism. H2S is a weak acid, and the amine immediately accepts its proton to form an amine bisulphide salt:
This reaction is very fast — faster than the CO2 carbamate reaction — because it is a simple proton transfer with no covalent bond formation. The selectivity between CO2 and H2S therefore depends mainly on whether CO2 has time to complete its slower carbamate or bicarbonate reaction. In a short-contact-time absorber designed for selective H2S removal, the CO2 reaction may be kinetically limited while H2S removal is essentially complete. For most natural gas treating applications, however, both gases need to be removed, and selectivity is less important than total removal capacity.
Note
MEA is non-selective between CO2 and H2S when contact time is sufficient. If you need to remove H2S selectively while leaving CO2 largely in the gas (for example, to preserve CO2 for enhanced oil recovery), a tertiary amine such as MDEA or a tertiary-amine blend is a better choice. MEA is the right choice when you need to remove both gases to specification, or when CO2 partial pressure is low and fast kinetics are the priority.
How does the MEA absorber–regenerator cycle work?
The gas treating plant based on MEA is a closed loop that continuously absorbs acid gases in a cold column, releases them in a hot column and recycles the amine. The cycle has five main steps.
One closed loop
Sweet gas leaves the absorber top; concentrated CO2 (and H2S if present) leaves the regenerator top.
- Feed gas entry and the absorberSour gas — whether natural gas from a wellhead, refinery off-gas or power-plant flue gas — enters the bottom of a vertical absorber column. Lean MEA solution (amine depleted of acid gas, called lean amine) enters near the top and flows downward over trays or structured packing. Gas and liquid contact each other in counter-current flow. As the sour gas rises, MEA absorbs CO2 and H2S. The treated gas, called sweet gas, leaves from the top. The liquid MEA, now loaded with absorbed acid gas, leaves from the bottom as rich amine.
- Rich amine heat recoveryRich amine is warm from the exothermic absorption reactions. Before entering the regenerator, it passes through a lean–rich heat exchanger, where it picks up heat from the hot lean amine returning from the regenerator bottom. This heat integration step is one of the most important energy-saving measures in an MEA unit, because the single largest operating cost is steam for regeneration.
- The regenerator (stripper)Rich amine enters the top of a heated regenerator column, also called a stripper. At temperatures of about 120 °C, the equilibrium shifts: the carbamate and bicarbonate reactions reverse, releasing CO2 and H2S as gases from the liquid. Steam from a reboiler at the bottom of the column drives the stripping. The gas leaving the regenerator top is a concentrated stream of CO2 (and H2S if present), along with water vapour, which is condensed and returned. The CO2-rich gas can be compressed for sequestration, enhanced oil recovery or industrial use; the H2S-rich stream goes to a Claus sulphur-recovery unit.
- Lean amine returnHot lean amine from the regenerator bottom passes through the lean–rich heat exchanger, cooling down while heating the incoming rich amine, then through a cooler to bring it to absorber inlet temperature (typically 40 to 55 °C), and back to the absorber top. Cooling the lean amine below the absorber temperature improves CO2 loading capacity but must be balanced against refrigeration costs.
- Reclaimer and make-upA slipstream of lean amine is continuously routed through a reclaimer — a kettle-type vessel where heat-stable salts and high-boiling degradation products are concentrated and removed, and fresh MEA and water are added as make-up to maintain the amine concentration and volume. The reclaimer blowdown contains amine degradation products and must be disposed of as chemical waste.
Key numbers for MEA units
Absorber column temperatures are typically 40–55 °C at the inlet and 50–65 °C at the outlet (exothermic heat of absorption raises the temperature mid-column, creating a temperature bulge); regenerator reboiler temperature is typically 115–125 °C; lean amine loading is typically below 0.15 mol CO2 per mol MEA; rich amine loading is typically 0.45–0.55 mol CO2 per mol MEA.
CO2 removal vs H2S removal: how does the chemistry differ in the same plant?
Both CO2 and H2S are absorbed in the same MEA solution, but the reaction chemistry and process implications are different. The table below summarises the key differences between CO2 and H2S removal in an MEA unit.
| Feature | CO2 Removal | H2S Removal |
|---|---|---|
| Primary reaction | Carbamate formation (fast) | Salt formation (rapid) |
| Secondary reaction | Bicarbonate (slower, needs water) | — |
| Reaction rate | Fast — CO2 + MEA → carbamate in seconds | Very fast |
| Selectivity | Non-selective vs H2S at low partial pressure | Can be selective with process design |
| Typical MEA conc. | 15–30 wt% aqueous | Same solution removes both |
| Regeneration temp. | ~120 °C (stripping column) | Same regeneration loop |
| Product on regeneration | Pure CO2 gas released; MEA recycled | H2S released; processed to sulphur |
| Main degradation risk | O2, COS, CS2, SO2 attack the amine | COS and CS2 convert MEA to stable salts |
In a natural gas treating plant that must remove both CO2 and H2S, both reactions happen simultaneously in the absorber. The H2S is absorbed first and fastest; the CO2 absorption continues along the remaining column height. Plant designers size the column to achieve the required removal of both gases. In a carbon capture unit dealing with flue gas from a power plant, there is essentially no H2S, and the column is sized entirely for CO2 at very low partial pressure, which requires the maximum amine driving force and often longer columns than equivalent natural gas treating units.
MEA in different applications: natural gas, refinery and carbon capture
The MEA absorber–regenerator cycle is the same in all three main application areas, but feed gas composition, CO2 partial pressure, impurity profile and target removal differ enough to change the detailed design and operating conditions. The table below compares the three.
| Parameter | Natural Gas Plants | Refinery Units | Carbon Capture (Post-Comb.) |
|---|---|---|---|
| Feed gas | Raw natural gas | FCC/coker/SR off-gas | Flue gas (coal, gas, biomass) |
| CO2 partial pressure | Low–medium | Low–medium | Very low (<0.15 bar) |
| H2S in feed | Yes (sweetening) | Sometimes | No (CO2 only) |
| MEA conc. | 15–25 wt% | 20–30 wt% | 25–35 wt% |
| O2 in feed | Trace | Trace–low | Up to 5–14 vol% (air-fired) |
| Degradation risk | Low–moderate | Moderate (COS, CS2) | High (O2, SO2, NOx) |
| Reclaimer needed | Periodically | Yes | Yes — frequent |
| Typical removal target | >98% H2S; CO2 as needed | Spec. by product slate | >90% CO2 |
For buyers sourcing MEA for any of these plants, the grade and specification requirements are discussed in the buying section below. Chelora Amines supplies monoethanolamine for all three application areas from ready stock in Mumbai, with COA and SDS dispatched with every batch.
What causes MEA to degrade, and how is degradation controlled?
Degradation is the single most important operating challenge in MEA gas treating units. MEA is a reactive amine, and that reactivity — so useful for CO2 and H2S absorption — also makes it vulnerable to irreversible reactions with other components in the gas or the environment.
Oxidative degradation
Oxygen is the most common and damaging degradant in carbon capture applications. Flue gas from coal or gas-fired power plants contains 3 to 14 per cent oxygen by volume. When oxygen meets MEA at elevated temperature, it attacks the amine through a chain-reaction mechanism, producing a range of degradation products including organic acids, aldehydes and ammonia. These products either consume amine capacity permanently or form heat-stable amine salts (HSAS) that occupy the amine but cannot be regenerated. Oxidative degradation is lower in natural gas treating, where oxygen is usually at trace levels, but becomes the dominant degradation pathway in post-combustion carbon capture. Antioxidants such as sodium sulphite can be added to the solution to reduce oxidative attack.
Thermal degradation
At temperatures above about 130 °C — which can occur in the reboiler or in poorly designed internals — MEA reacts with CO2 and with itself to form cyclic products such as oxazolidone and various oligomers. Keeping the reboiler temperature below 125 °C and avoiding hot spots in the regenerator limits thermal degradation. The reclaimer handles heat-stable salts and high-boiling oligomers; severe cases may require vacuum reclaiming or replacement of part of the amine inventory.
Reaction with carbonyl sulphide (COS) and carbon disulphide (CS2)
COS and CS2 are sometimes present in natural gas, refinery gas and some industrial gas streams. Both react irreversibly with MEA to form stable sulphur-containing compounds that cannot be regenerated. This is a significant limitation compared with diethanolamine (DEA), which tolerates COS and CS2 far better. If the feed gas contains significant COS or CS2, a DEA unit or a hybrid amine system is usually preferred over MEA. If MEA must be used, gas pre-treatment — for example, COS hydrolysis — can reduce the impurity level before the amine absorber.
Heat-stable amine salts (HSAS)
Strong acids — organic acids from oxidative degradation, sulphate from SO2 in flue gas, formate, oxalate — react with MEA to form salts that are stable at regenerator temperatures and cannot be released back to free amine. These HSAS accumulate in the circulating amine, reducing the capacity for acid-gas absorption and increasing corrosion. They are removed in the reclaimer, typically by treating with sodium hydroxide or sodium carbonate to displace the HSAS and liberate free amine. The reclaimer blowdown contains the salt solution.
Important
MEA is corrosive to carbon steel at high concentrations, high temperatures and high loading. Well-designed MEA units use carbon steel with appropriate corrosion inhibitors (typically film-forming inhibitors) in the hot sections, and maintain amine concentration and loading within the design limits. Stainless steel is used in the reboiler and other hot, high-velocity sections. Copper, brass and aluminium alloys should not be used in MEA service. Always review the SDS and corrosion guidelines for MEA-specific material selection.
How did MEA become the standard gas treating amine?
Monoethanolamine has been the dominant amine for acid-gas removal for nearly a century. Its rise to dominance reflects a combination of early adoption, low cost and chemical properties that remain hard to match.
The first commercial amine scrubbing patents were filed in the 1920s, and the first commercial amine acid-gas removal units, installed in the United States in the early 1930s, originally used triethanolamine (TEA). TEA proved too slow and was soon displaced by MEA and diethanolamine (DEA) as the preferred treating amines, because both offered faster reaction rates and higher equilibrium loading. MEA, with its primary amine group and low molecular weight, proved the most reactive and the most economic in terms of amine per cubic metre of gas treated.
Through the mid-twentieth century, MEA units proliferated in natural gas processing, refinery hydrogen plants and synthesis gas purification. The petroleum industry's need to sweeten raw natural gas — removing H2S to pipeline specification and CO2 to meet heating value requirements — created a large and growing market that MEA dominated.
From the 1980s onwards, MDEA and tertiary amine blends took over some of the market for selective H2S removal and for applications where the lower regeneration energy of tertiary amines was important. But MEA retained its position wherever fast CO2 absorption at low partial pressure was needed, and the rise of carbon capture and storage (CCS) from the 2000s onwards created a major new application that plays to MEA's strengths.
The IEA (International Energy Agency) at iea.org (opens in a new tab) lists MEA-based post-combustion capture as one of the most mature CO2 capture technologies available for deployment at scale from fossil fuel power plants. Commercial-scale CCS projects using MEA or MEA-blend solvents have been operating since the 1990s in natural gas processing and since 2014 in post-combustion capture at the Boundary Dam power station in Canada.
What should you check when buying MEA for gas treating?
Before ordering MEA for an absorber unit, read the certificate of analysis against the specification points below. Full answers, including plant-type differences, are in the questions that follow.
Verify on the COA
- Assay: minimum 99 per cent MEA by weight
- Water content: typically below 0.5 per cent
- Colour: APHA below 20 for high-quality material
- Diethanolamine and triethanolamine: usually 0.1 to 0.5 per cent each at most
Also agree with your supplier
- Grade: commercial or laboratory purity
- Pack: 200-litre HDPE drums, IBC totes or bulk tankers
- Documents: COA and a current SDS with every lot
- Carbon capture: limits on total nitrogen-containing impurities
How monoethanolamine removes CO2 and H2S: what do gas treating engineers and buyers ask most often?
Why is MEA preferred over DEA or MDEA for CO2 removal at low partial pressure?
MEA is preferred at low CO2 partial pressure because its primary amine group reacts directly with CO2 to form a carbamate, without needing the intermediate bicarbonate route that secondary and tertiary amines depend on. This gives MEA a faster reaction rate, which allows it to absorb CO2 efficiently even when the driving force (CO2 partial pressure) is small — as in post-combustion flue gas at around 0.1 to 0.15 bar CO2 partial pressure.
Diethanolamine (DEA) absorbs CO2 by both the carbamate and bicarbonate routes and is somewhat slower; MDEA, a tertiary amine, relies entirely on the bicarbonate route and is much slower at low pressure. For CCS applications where a high percentage of CO2 must be captured from dilute flue gas, MEA or MEA-blend solvents are the standard choice.
What concentration of MEA is used in gas treating?
Aqueous MEA solutions for gas treating are typically 15 to 30 per cent by weight. Natural gas sweetening commonly uses 15 to 25 per cent MEA. Carbon capture units tend towards 25 to 35 per cent to maximise absorption capacity per unit of solvent circulation. Higher concentrations increase capacity but also increase corrosion rates, particularly in the hot regenerator sections, and accelerate degradation. Most operators choose their MEA concentration based on a balance between absorption performance and corrosion risk, guided by the experience of their plant design and corrosion inhibitor supplier.
How is the CO2 loading of MEA measured and what does it mean?
CO2 loading is the moles of CO2 absorbed per mole of MEA in the circulating solution. Lean amine — the MEA leaving the regenerator and entering the absorber — typically has a loading below 0.15 mol/mol in a well-designed plant. Rich amine — leaving the absorber bottom — is typically 0.45 to 0.55 mol/mol. The difference between lean and rich loading, called the working capacity, determines how much acid gas can be removed per unit of circulating amine. Higher lean loading reduces working capacity and can allow CO2 slip to the product gas; lower lean loading requires more stripping steam. Loading is measured by titration or by wet chemical analysis of the solution, and is monitored regularly in plant operation.
Why does MEA need a reclaimer, and how often should it be cleaned?
MEA degrades over time through oxidative, thermal and chemical reactions that produce heat-stable amine salts and high-boiling compounds that cannot be regenerated in the normal stripping cycle. These accumulate in the circulating amine, reducing its acid-gas absorption capacity and increasing corrosion. A reclaimer — typically a kettle evaporator fed by a slipstream of lean amine — heats the solution to concentrate and separate the non-regenerable impurities from the recoverable MEA. Reclaimer frequency depends on the application: in carbon capture with high-oxygen flue gas, reclaiming may be continuous or very frequent (weekly or bi-weekly); in natural gas treating with low oxygen, reclaiming may be monthly or quarterly. Reclaimer blowdown contains degraded amine and must be disposed of as chemical waste.
What specifications should be checked when buying MEA for gas treating?
For gas treating, the key MEA specifications to verify on the certificate of analysis are: assay (minimum 99 per cent MEA by weight), water content (typically below 0.5 per cent), colour (APHA below 20 for high-quality material), and the content of other ethanolamines (diethanolamine and triethanolamine should be below specification limits, usually 0.1 to 0.5 per cent each). For carbon capture, some operators also specify limits on total nitrogen-containing impurities, which can form nitrosamines in the presence of nitrogen oxides in flue gas. Chelora Amines dispatches a full COA and current SDS with every batch.
Can MEA be used to remove CO2 from biogas or hydrogen production?
Yes. MEA scrubbing is one of the standard methods for upgrading biogas — removing CO2 from the methane-CO2 mixture to produce biomethane of natural-gas quality. It is also used to remove CO2 from hydrogen produced by steam methane reforming, where it has been applied since the 1960s. In biogas upgrading, the low CO2 partial pressure favours MEA's fast kinetics; the low oxygen content (unlike combustion flue gas) limits oxidative degradation. The compact, well-proven absorber–regenerator design and the low cost of MEA make it competitive with membrane or pressure-swing adsorption alternatives for many biogas plants. The relevant process and chemistry are the same as in natural gas treating.
Does Chelora Amines supply MEA suitable for gas treating?
Yes. Monoethanolamine is held in ready stock at the Chelora Amines warehouse in Mumbai. We supply commercial and laboratory purity grades in 200-litre HDPE drums, IBC totes and bulk tankers, and each lot leaves with its own certificate of analysis and a current SDS. Our chemists can advise on grade, concentration and compatible materials for your plant. Send us the volume, purity and delivery requirement and expect a quotation the same day or the next.
Related guide
Choosing an amine for another job? Read MEA vs DEA vs TEA: Which Ethanolamine Is Right for Your Application? for properties, grades and uses in detergents, cement, metalworking and personal care.