DEA unit, Oil & Gas Glossary

A DEA unit, short for diethanolamine treating system, is a closed-loop amine absorption process that strips hydrogen sulfide (H2S), carbon dioxide (CO2), and carbonyl sulfide (COS) from raw natural gas, producing pipeline-quality sweet gas suitable for delivery into TC Energy NGTL or Pembina sales systems. The unit centers on two pressure vessels: a contactor (absorber) where lean DEA solution flows downward across trays or structured packing against upward-flowing sour gas, scrubbing acid components into the aqueous amine phase, and a regenerator (stripper) where rich amine is reboiled at roughly 120 to 130 degrees C (248 to 266 degrees F) to drive off absorbed acid gas before lean solvent returns to the contactor. DEA solutions in Western Canadian gas plants typically run at 25 to 35 weight percent in deionized water, with circulation rates calibrated to expected acid-gas loading expressed as moles acid gas per mole amine, commonly held below 0.45 mol/mol to limit corrosion. Compared with monoethanolamine (MEA), DEA tolerates higher loadings, is less corrosive at equivalent acid-gas concentrations, and degrades more slowly in COS service, making it the workhorse amine for sour streams in the Montney, Duvernay, and Foothills sour-gas trends where inlet H2S can range from a few hundred ppm to several percent by volume. Stripped acid gas exits the regenerator overhead and is routed to a Claus sulfur recovery unit, into an acid-gas injection well permitted under AER Directive 065 and Directive 051, or to incineration governed by the sulfur-recovery limits in AER Directive 060. Sweet gas leaving the contactor still requires dehydration in a glycol unit to meet the pipeline water-content spec of 65 mg per standard cubic metre (about 4 lb per MMscf), so the amine, glycol, and sulfur-recovery trains together form the heart of every Canadian sweetening plant from Caroline to Gold Creek. Operators continually monitor amine strength, heat-stable salt content, foaming tendency, and rich-amine corrosion in the regenerator overhead and reboiler tubes, because uncontrolled DEA degradation produces oxazolidones and bis-hydroxyethyl piperazine compounds that destroy treating capacity and accelerate carbon-steel wall loss.

Key Takeaways

Acid Gas Selectivity: DEA absorbs H2S, CO2, and COS through reversible exothermic chemical reactions, with H2S kinetics faster than CO2 absorption. Most WCSB sour-gas plants size contactors for total acid-gas loading near 0.40 to 0.45 mol/mol, balancing absorption capacity against the corrosion risk in the regenerator overhead and lean-rich heat exchanger that intensifies above 0.50 mol/mol loading.
Regenerator Heat Duty: Stripping the rich solution requires roughly 250 to 350 kJ per mole of acid gas removed, supplied by a steam or hot-oil reboiler at 120 to 130 degrees C (248 to 266 degrees F). For a 5 MMm3/d (180 MMscfd) sour-gas plant treating 1 percent H2S, reboiler duty commonly runs 8 to 12 MW, making energy the single largest operating cost after amine make-up.
Disposal Pathway: Acid gas off the regenerator can be sent to a Claus sulfur plant recovering elemental sulfur, injected as a supercritical stream into a depleted reservoir under AER Directive 065, or flared and incinerated within AER Directive 060 sulfur emission limits, which cap total annual sulfur emissions per plant based on inlet sulfur tonnage.
Corrosion and Degradation: Heat-stable salts formed from formate, oxalate, thiocyanate, and chloride contaminants permanently bind DEA and accelerate corrosion. Operators run amine reclaimers or filtration packages and target heat-stable salt content below 2 percent of total amine to extend tower life and avoid the 12 to 18 month full inventory replacements that follow runaway degradation.
Foaming Mitigation: Hydrocarbon condensate carryover, fine solids, or surfactant contamination causes amine foaming, which destroys mass transfer and triggers contactor flooding. Plants inject silicone-based defoamer at 5 to 20 ppm, install upstream inlet separators, and monitor differential pressure across the contactor as the leading indicator of incipient foam events that can cut throughput by half within minutes.

Amine Absorption Chemistry and Contactor Design

Inside the contactor, DEA reacts with H2S through a fast proton-transfer reaction forming the bisulfide salt, while CO2 reacts more slowly through carbamate formation requiring two amine molecules per CO2. The H2S kinetics are essentially instantaneous, allowing selective absorption at controlled residence times when CO2 slip is desired downstream of the sweetener. A typical WCSB sweetening tower runs 20 to 24 valve trays or structured packing equivalent, with the rich solution leaving the bottom at roughly 50 to 60 degrees C (122 to 140 degrees F) after picking up the heat of reaction. Pressure runs 5,000 to 8,000 kPa (725 to 1,160 psi) to match upstream compression, and amine circulation rate is set so the lean loading entering the top sits near 0.01 to 0.05 mol/mol, giving sweet-gas H2S specs of 16 ppm or lower as required for sales gas delivery into the NGTL system. Tower diameter is sized to keep superficial gas velocity below 75 percent of jet flood at the top tray, with a 1.5 to 2.0 m (5 to 6.5 ft) sump for surge volume and degassing.

Regenerator and Reboiler Operations

Rich amine leaves the contactor bottom, flashes in a low-pressure separator to release co-absorbed hydrocarbons, then passes through the lean-rich exchanger heating to 90 to 100 degrees C (194 to 212 degrees F) before entering the regenerator. The regenerator runs at 100 to 200 kPa (15 to 30 psi) overhead pressure and is reboiled by saturated steam or hot oil, with reboiler skin temperatures held below 175 degrees C (347 degrees F) to limit thermal degradation. Acid gas, water vapour, and trace amine exit overhead, condense in the reflux drum, and the cooled acid gas at 35 to 45 degrees C (95 to 113 degrees F) is routed to disposal while reflux water returns to the column to maintain water balance.

Fast Facts

The Caroline gas plant west of Sundre, Alberta, operated by Shell from 1993 and now part of the Pieridae Energy portfolio, treats one of the highest-H2S streams in North America with inlet sulfur concentrations approaching 35 percent by volume. The amine and Claus trains there recover more than 2,500 tonnes per day of elemental sulfur at peak rates, producing roughly 0.9 million tonnes annually that historically loaded out by unit train to the Vancouver port for sale into Asian agricultural and tire markets. The plant is one of the largest single-point sulfur recoveries in Canadian history.

A DEA unit sits inside a wider sour-gas processing chain. The sour gas entering the contactor defines amine selection and circulation. Downstream, the sulfur recovery unit converts stripped acid gas into elemental sulfur through the Claus reaction. Where sulfur economics fail, acid gas injection disposes of the regenerator overhead into a depleted reservoir under AER Directive 065. Sweet gas leaving the unit then enters a glycol dehydration tower to meet pipeline water-content specifications before sales.

WCSB Field Scenario: Foothills Sour Gas Sweetening

An operator running a 3 MMm3/d (106 MMscfd) sour gas plant in the Caroline area treats inlet gas at 4.2 percent H2S and 2.8 percent CO2 through a 35 weight percent DEA system. The contactor measures 2.4 m (8 ft) diameter by 24 valve trays at 6,200 kPa (900 psi), with amine circulation set at 4.5 m3/min (1,190 USgpm). Rich loading averages 0.42 mol/mol entering the regenerator, where a 9 MW hot-oil reboiler strips acid gas overhead to a four-stage Claus train recovering 165 tonnes of sulfur per day. Total installed cost for the sweetening, sulfur, and tail gas trains was approximately CAD 240 million in 2019 dollars, with annual sustaining capital near CAD 4 million.

After 18 months of operation, heat-stable salts climbed to 4.5 percent of total amine, triggering throughput derate and reboiler tube fouling. A side-stream reclaimer commissioned at CAD 2.8 million reduced HSS to 1.2 percent within 90 days, restored 100 percent of nameplate capacity, and extended the next full amine inventory replacement from the projected three years to a planned eight-year cycle.