Amines

Key Takeaways

• Alkanolamine gas sweetening removes H₂S and CO₂ from sour natural gas through a reversible acid-base absorption reaction: the alkaline amine (pKa 8 to 10) reacts with acidic H₂S (pKa 7.0) and CO₂ (forming carbonic acid, pKa 6.35) in the absorber column to form the amine salt, which is then regenerated in the stripper column at 100 to 120°C to release the acid gas and recycle the lean amine, with MDEA preferred for selective H₂S removal because its tertiary nitrogen cannot react directly with CO₂ without water assistance, providing up to 95% H₂S selectivity over CO₂ at high-pressure absorber conditions used in deep Foothills and Montney sweetening plants: MEA, the simplest alkanolamine, reacts rapidly with both H₂S and CO₂ at absorber conditions (40 to 60°C, 3 to 10 MPa) but generates stable carbamate species with CO₂ that require high regeneration energy (steam equivalent 3.5 to 4.5 GJ per tonne CO₂ removed) and cause amine degradation (MEA forms oxazolidone and other irreversible degradation products at 120°C). MDEA, being a tertiary amine (no N-H available for carbamate formation), reacts with CO₂ only through the slow bicarbonate pathway (CO₂ + H₂O + NR₃ → HCO₃⁻ + NHR₃⁺), while reacting rapidly with H₂S (H₂S + NR₃ → NHR₃⁺ + HS⁻), allowing selective H₂S absorption (leaving substantial CO₂ in the treated gas) at high gas pressure and short absorber contact time. WCSB sour gas plants with H₂S greater than 5% and CO₂ less than 3% typically use 40 to 50 wt% MDEA solutions operating at 35 to 45°C absorber temperature, achieving H₂S content in the sweet gas of less than 3.5 ppmv (the AER sales gas specification under Directive 017) while leaving 0.5 to 2.0% CO₂ in the product gas stream, which is acceptable for most WCSB sales gas nominations.
• MDEA selectivity for H₂S over CO₂ in sour gas treating is exploited at WCSB Foothills Devonian reef gas plants where inlet H₂S concentrations of 15 to 35% require sending the absorbed acid gas to a Claus sulfur recovery unit (SRU) for elemental sulfur production, and high CO₂ co-absorption into the amine would dilute the acid gas stream and reduce Claus furnace temperature below the minimum 980°C required for stable operation without supplementary fuel gas firing: In the Claus SRU process, one-third of the H₂S feed is combusted with air to SO₂ (H₂S + 3/2 O₂ → SO₂ + H₂O), then the remaining two-thirds H₂S reacts catalytically with the SO₂ over alumina and titania beds (2H₂S + SO₂ → 3S + 2H₂O) at decreasing temperatures through two to three catalyst stages. The Claus furnace temperature depends on H₂S concentration in the acid gas feed: below approximately 25% H₂S in the acid gas (by volume), the furnace temperature falls below 980°C and stable combustion cannot be maintained without enriching the air feed with oxygen or supplementary firing with natural gas. If the amine plant absorbs significant CO₂ alongside H₂S (which MEA and DEA do efficiently), the acid gas may contain 30 to 50% CO₂, diluting the H₂S to below the minimum Claus furnace stable combustion threshold and requiring oxygen enrichment (adding 30 to 50% O₂ to the Claus combustion air) at additional operating cost of CAD 2.80 to 5.50 per tonne of acid gas processed. MDEA selective sweetening at Foothills plants such as the CNRL Horizon Gas Plant and Shell Waterton Gas Plant maintains acid gas H₂S concentrations of 70 to 85% by keeping CO₂ co-absorption below 5 to 10%, enabling stable Claus SRU operation without oxygen enrichment and reducing acid gas treating operating cost by CAD 1.50 to 3.20 per GJ of sweet gas produced compared to non-selective MEA sweetening.
• Quaternary ammonium clay stabilizers (TMAC, choline chloride, DMDAAC) used in WCSB completion and workover fluids control smectite and mixed-layer clay swelling near the wellbore by substituting the K⁺ or Na⁺ interlayer cations of swelling clays with larger, more strongly adsorbed quaternary ammonium cations that prevent water molecules from entering the clay interlayer, maintaining formation permeability and avoiding post-completion productivity impairment caused by clay swelling during fluid injection: Smectite (montmorillonite) and mixed-layer illite-smectite clays in WCSB Cretaceous sandstones (Viking, Cardium, Mannville) swell by 10 to 300% in volume when contacted by fresh water or low-salinity fracture fluid, because water molecules and sodium cations enter the clay interlayer by osmosis (driven by the difference in water activity between the clay interlayer and the adjacent formation pore water). Quaternary ammonium cations (TMAC: (CH₃)₄N⁺, diameter 5.5 Å; choline chloride: (CH₃)₃N⁺CH₂CH₂OH, diameter 6.1 Å) are permanently positively charged and substantially larger than Na⁺ (diameter 2.3 Å) or K⁺ (diameter 2.8 Å), and once adsorbed on the clay interlayer they are not easily displaced by Na⁺ or Ca²⁺ in subsequent pore water contact, providing durable clay stabilization. At 2 to 5% KCl or 0.5 to 1% choline chloride in completion brine, permeability reduction from clay swelling in Mannville F sand cores (12 to 18% smectite content) is reduced from 45 to 65% (no stabilizer) to 5 to 12% (with choline chloride), a permeability preservation equivalent to 30 to 55% productivity improvement in clay-sensitive completion intervals when the well is returned to production.
• Filming amine corrosion inhibitors (primary and secondary long-chain alkylamines such as octadecylamine C₁₈H₃₇NH₂ and dodecylamine C₁₂H₂₅NH₂) adsorb from produced fluid streams onto carbon steel surfaces through the nitrogen lone pair, forming a monomolecular to bilayer hydrophobic film that displaces water and corrosive CO₂ from the steel surface, providing 85 to 95% corrosion protection efficiency in sweet and mildly sour WCSB gathering and injection pipelines at treatment concentrations of 15 to 75 ppm in the produced water phase: The mechanism of filming amine adsorption on iron oxide-covered steel surfaces involves direct coordination bonding between the amine nitrogen lone pair and iron Lewis acid sites on the Fe₂O₃ or Fe₃O₄ surface layer (adsorption energy approximately 40 to 80 kJ/mol for fatty amines on iron oxide), combined with van der Waals attraction between adjacent alkyl chains in the monolayer (chain-chain interaction energy approximately 4 to 6 kJ/mol per methylene group for C₁₆ to C₁₈ amines). At concentrations above the critical micelle concentration (CMC, typically 20 to 80 ppm for octadecylamine in produced water), the adsorbed film transitions from monolayer to hemimicelle or bilayer structures that are more water-resistant and provide higher corrosion protection efficiency. In Viking Formation produced water gathering lines (central Alberta, CO₂ partial pressure 0.003 to 0.008 MPa, temperature 28 to 38°C, pH 6.4 to 7.0), filming amine at 40 to 60 ppm reduces the pipeline internal corrosion rate from 2 to 5 mm/year (unprotected) to 0.05 to 0.15 mm/year (treated), extending the expected service life of a 100 mm flowline from 4 to 8 years to 50 to 80 years and avoiding the CAD 120,000 to 250,000 replacement cost per kilometre of gathering line.
• Amine gas treating plants require management of amine degradation products (heat-stable salts, degradation amines, carbamate polymers) and contaminants (hydrocarbons, oxygen, corrosion products) that accumulate in the amine circulation loop, reducing the effective amine capacity for H₂S and CO₂ absorption and causing corrosion and foaming problems in the absorber and regenerator columns, requiring periodic reclaiming, filtration, and solvent makeup to maintain amine plant treating efficiency within AER Directive 017 sales gas H₂S specification limits: Heat-stable amine salts (HSAS) form when amine reacts with strong acids (formic acid, acetic acid, oxalic acid, thiosulfate) or oxidation products (sulfone, amide derivatives) in the amine loop to form salts that are not regenerated (decomposed back to free amine) in the stripper at 110 to 120°C, because the protonation of the amine by the strong acid is irreversible at stripper conditions. HSAS accumulate in the amine loop to concentrations of 0.5 to 3.0 wt% (expressed as moles acid per mole amine) before the associated reduction in free amine capacity causes H₂S slippage above the 3.5 ppmv specification, requiring either a mechanical reclaimer (evaporating free amine from the HSAS residue at 145 to 165°C under reduced pressure) or an electrodialysis reclaimer (using ion-exchange membranes to extract the HSAS anion from the amine solution). WCSB gas plants using MDEA for sour Foothills treating typically experience HSAS accumulation rates of 0.05 to 0.15 wt% per month, requiring reclaimer operation for 3 to 7 days per month to maintain HSAS below the 1.0 wt% threshold, with reclaimer operating cost of CAD 8,000 to 20,000 per reclaimer cycle and makeup amine costs of CAD 1,800 to 2,400 per tonne of MDEA (approximately 1.5 to 3.0 tonne per month makeup for a medium-sized 50 MMscf/d plant).