H₂S absorption

H₂S is a weak acid that reacts with any amine (primary, secondary, or tertiary) by a rapid proton-transfer mechanism - no bond formation required:

R₃N + H₂S → R₃NH⁺ + HS⁻   (fast, diffusion-limited)

This reaction is so fast that it is controlled by mass transfer (diffusion of H₂S to the gas-liquid interface), not by reaction kinetics. All amine types absorb H₂S at essentially the same rate under equivalent driving force.

CO₂ absorption

CO₂ must form a new covalent bond with the amine nitrogen (primary/secondary) or go through the slow water-hydration step (tertiary). This makes CO₂ absorption intrinsically slower than H₂S and dependent on amine type:

Primary/secondary: CO₂ + RNH₂ → carbamate (fast - milliseconds)

Tertiary: CO₂ + H₂O → H₂CO₃ → bicarbonate (slow - seconds to minutes)

⚡ 1. Absorption rate (second-order rate constant k₂)

The rate at which the amine reacts with CO₂ in the liquid film determines absorber efficiency. For primary amines (NBEA, MEA), k₂ is 5,000–8,000 L/mol·s at 25 °C. For secondary amines (BDEA, DEA), k₂ is 1,000–3,000 L/mol·s. For tertiary amines (DMEA, DEAE, MDEA), the effective k₂ is 0.1–10 L/mol·s - dominated by the water hydration step. A higher k₂ means a shorter absorber column or higher throughput for the same separation.

📦 2. Theoretical loading capacity (mol acid gas / mol amine)

Primary and secondary amines form carbamates - one CO₂ molecule reacts with two amine molecules (one to form carbamate, one to accept the proton), giving a theoretical loading of 0.5 mol CO₂/mol amine. Tertiary amines form bicarbonate - one amine accepts one proton per CO₂ molecule - giving a theoretical loading of 1.0 mol CO₂/mol amine. In practice, rich loadings rarely exceed 0.45–0.5 for primary/secondary or 0.7–0.8 for tertiary due to corrosion and viscosity limits. Higher loading capacity directly reduces the required solvent circulation rate.

🔥 3. Heat of absorption (kJ/mol CO₂)

Carbamate formation releases 80–100 kJ/mol CO₂ more heat than bicarbonate formation (~50 kJ/mol). This additional heat must be supplied in the regenerator reboiler to reverse the reaction - which is why primary amine systems require 160–200 kJ/mol CO₂ of reboiler duty while tertiary amine systems need only 80–100 kJ/mol CO₂. For a plant removing 1,000 tonne/day of CO₂, this difference represents approximately 40–60 MW of reboiler duty - a dominant operating cost.

💧 4. Solvent vapor loss (boiling point and vapor pressure)

Alkanolamine lost to the treated gas stream is both an operational cost (make-up requirement) and an environmental liability (amine emissions to atmosphere). Higher boiling point and lower vapor pressure directly reduce solvent carry-over. BDEA (bp 274 °C, vp <0.01 hPa) loses 20–30× less solvent per unit volume of gas treated than MEA (bp 171 °C, vp ~0.5 hPa). For offshore gas treating where overboard discharge is restricted, BDEA's low volatility provides a compelling advantage.

🛡️ 5. Corrosivity and degradation rate

Rich amine solutions at high loading are corrosive to carbon steel - primarily due to dissolved CO₂ forming carbonic acid at the metal surface, and to carbamate ion activity at the steel surface. Primary amines at rich loadings above 0.4 mol/mol in carbon steel equipment require corrosion inhibitor (vanadium pentoxide 0.1–0.5%) or stainless steel internals. Tertiary amines (DMEA, DEAE) are less corrosive at equivalent loading because the bicarbonate formed is less aggressive than carbamate. BDEA's secondary amine carbamate shows intermediate corrosivity.

NBEA - primary amine, gas treating niche uses

• Foaming-resistant blends: The butyl chain's partial hydrophobicity improves the surface tension behavior of the amine solution, reducing the tendency to foam when contacted with hydrocarbon-rich gas streams (associated gas, gas condensate). MEA-based systems contacting C5+ hydrocarbons frequently foam; NBEA-containing blends are more resistant.
• Primary amine contribution in blends: Where a fast-absorbing primary amine is needed but MEA's high vapor pressure is undesirable, NBEA's higher boiling point (199 °C vs 171 °C for MEA) reduces absorber overhead amine carry-over.
• Small-volume specialty treating: For small skid-mounted sweetening units processing sour gas with moderate H₂S and CO₂, NBEA at 25–35% provides effective treating in a single-solvent system.

BDEA - secondary amine, gas treating niche uses

• Offshore low-loss treating: BDEA's vapor pressure (<0.01 hPa) is among the lowest of any commercial alkanolamine. Offshore gas treating on FPSOs (floating production, storage, offloading vessels) and platform facilities where amine discharges to sea are tightly regulated benefit significantly from BDEA as a partial replacement for DEA or MEA.
• Bulk CO₂ removal with moderate selectivity: BDEA's secondary amine character gives moderate H₂S selectivity - more than primary amines but less than tertiary. For feed gases where CO₂ must be reduced but not eliminated, BDEA-based systems avoid the corrosion problems of MEA at high loadings.
• High-temperature regenerator systems: BDEA's bp 274 °C allows it to operate at regenerator temperatures up to 130–135 °C without excessive vapor loss - a constraint that limits DMEA usage in high-temperature regenerators.

💨 Vapor losses (treated gas carry-over)

Amine vaporizes into the sweet gas stream above the absorber. Proportional to vapor pressure - MEA loses ~50–150 g/1000 Nm³; BDEA loses <1–5 g/1000 Nm³. Controlled by water wash section and demister pad. The boiling point advantage of BDEA and DEAE over MEA translates directly to lower make-up cost at large-volume treating units.

🌊 Liquid carry-over (mist/aerosol)

Fine amine droplets entrained in the gas stream - particularly from foaming events. Typical losses: 5–50 ppmw of amine in treated gas. Controlled by high-efficiency wire mesh demisters, vane packs, and cyclonic separators at the absorber overhead. Foaming control is the most effective measure.

🔥 Thermal/oxidative degradation

Amine is consumed by chemical reaction rather than physical loss. Degradation products accumulate in the solvent inventory. Reclaiming removes them and recovers usable amine. Estimated at 0.5–3 kg/tonne CO₂ removed for MEA; 0.2–1 kg/tonne for MDEA or BDEA in O₂-free natural gas service.

🔩 Mechanical losses

Amine lost during maintenance activities - pump seals, heat exchanger cleaning, sample taking, spills. Controlled by good housekeeping procedures, closed sampling systems, and recovery of amine from maintenance waste. Typically 0.1–0.5 kg/tonne CO₂ removed - small but preventable.

🏭 Atmospheric amine emissions

Atmospheric reactions of alkanolamines with NOₓ produce nitramines and nitrosamines in trace quantities. Norwegian Environment Agency (Miljødirektoratet) studies on large MEA-based CO₂ capture plants identified this as a concern at the multi-hundred MW scale. At typical gas treating unit emissions rates, concentrations in the vicinity of the plant are well below health thresholds. Regulatory guidance varies by jurisdiction - verify with local environmental authority for large-scale plants.

🌊 Marine discharge (offshore)

OSPAR (Convention for the Protection of the Marine Environment of the North-East Atlantic) and MARPOL regulations restrict the overboard discharge of amine-containing produced water and condensate. Operators on the Norwegian Continental Shelf and UK North Sea must comply with strict amine discharge limits. Using low-volatility amines (BDEA, DEAE) reduces vapor carry-over to produced fluids, minimizing the amine content in process water streams requiring discharge management.

Q: How does the H₂S/CO₂ ratio in feed gas affect solvent selection?

A high H₂S/CO₂ ratio (above 0.3 mol/mol) in the feed gas is the key trigger for considering selective H₂S removal with a tertiary amine (DEAE, MDEA). Selective removal concentrates H₂S in the acid gas for Claus recovery while allowing CO₂ to slip, reducing Claus plant load and increasing sulfur recovery efficiency. A low H₂S/CO₂ ratio (below 0.1) suggests that both gases need to be removed in roughly equal proportions - a primary or secondary amine, or an activated tertiary blend, is more appropriate. When H₂S is absent entirely (pure CO₂ removal), the selectivity argument disappears and the choice is purely kinetics vs regeneration energy.

Q: What is the typical solvent circulation rate for an NBEA-based sweetening unit?

Solvent circulation rate is expressed as the liquid-to-gas (L/G) ratio in volume terms. For NBEA at 30 wt% in a conventional bubble-cap or structured-packing absorber processing natural gas at 50 bar, a typical L/G of 0.8–1.5 L liquid per Nm³ gas is needed for bulk CO₂ removal to 2% product spec. This is comparable to MEA at similar concentration. The exact rate depends on rich loading target, gas composition, absorber packing height, and temperature profile - process simulation is required for detailed sizing. Contact Sinolook Chemical's technical team for simulation support using NBEA-specific thermodynamic parameters.

Q: Can BDEA be used in existing DEA-designed amine units without modification?

A partial switch from DEA to BDEA requires careful evaluation. BDEA has significantly higher molecular weight (161 vs 105 g/mol for DEA) - a weight-equivalent substitution delivers 35% fewer moles of amine, reducing absorption capacity. BDEA's higher viscosity at concentration may also affect heat exchanger pressure drop and pump performance. However, BDEA's much lower vapor pressure reduces amine carry-over losses, which may be the primary driver for the switch. A simulation-based re-rate of the unit at the proposed BDEA concentration is essential before committing to a solvent change. Blending BDEA into an existing DEA inventory at 20–30% as a first step is a lower-risk approach that allows operational experience to be gained before full solvent replacement.

Q: What analytical methods are used to monitor amine concentration and quality in an operating unit?

Standard monitoring for an alkanolamine gas treating unit includes: (1) total amine concentration by acid-base titration (daily) - measures total alkalinity; (2) CO₂ and H₂S loading (rich and lean) by Chittick apparatus or potentiometric titration (daily during startup, weekly during normal operation); (3) heat-stable salt content by ion chromatography (monthly) - monitors for formate, acetate, thiosulfate, oxalate accumulation; (4) individual amine components by GC or HPLC when running blended systems (monthly) - verifies blend composition has not shifted; (5) iron, nickel, and chromium by ICP-OES (monthly) - early warning of corrosion; (6) amine in treated gas by GC or detector tube (monthly) - verify absorber overhead losses.

Q: What packing sizes are recommended for absorbers using NBEA or BDEA solvents?

For NBEA and BDEA-based solvents at the concentrations and viscosities typical in gas treating service, standard structured packing (Sulzer MellapakPlus 252.Y or Koch-Glitsch FLEXIPAC 2X equivalent) at 25–50 mm corrugation pitch provides a good balance of mass transfer efficiency and hydraulic capacity. BDEA at high concentration (>35 wt%) has elevated viscosity compared to MEA - structured packing with wider channel angles (45° vs the standard 60°) improves liquid distribution and reduces the risk of maldistribution. Bubble-cap trays are an alternative for high-fouling or high-foaming services where packing plugging is a concern. Packing selection and column sizing should be confirmed by rigorous hydraulic simulation using the actual amine physical property data.