Acid Gas

Acid gas refers to gas components that dissolve in water to form acidic solutions, principally hydrogen sulfide (H₂S) and carbon dioxide (CO₂). In the oil and gas industry, the term is used in two related contexts: to describe the H₂S and CO₂ content of raw produced natural gas (as in "this well produces sour gas with 8% acid gas"), and specifically to describe the H₂S- and CO₂-rich stream separated from natural gas during amine sweetening operations at a gas plant (as in "the amine unit produces an acid gas stream that is fed to the Claus unit"). H₂S is the more dangerous of the two components: it is highly toxic above 100 ppm (immediately dangerous to life at 300 ppm), corrosive to steel in the presence of water (causing sulfide stress cracking, HSC), and, when burned, produces sulfur dioxide (SO₂), a regulated air emission. CO₂ is non-toxic but corrosive in the presence of water (carbonic acid), accelerates pipeline corrosion, reduces the heating value of gas, and is a greenhouse gas subject to emissions regulations in Canada. Managing acid gas is one of the major engineering and regulatory challenges in western Canadian gas production, where H₂S concentrations range from near zero in sweet Montney gas to more than 30% in some deep Foothills carbonates.

Key Takeaways

H₂S toxicity and regulatory limits drive well control, personal protective equipment, and facility design requirements for sour gas operations. OSHA and the Canadian Occupational Health and Safety regulations set the occupational exposure limit for H₂S at 1 ppm (8-hour time-weighted average) and 5 ppm (ceiling, short-term exposure). Gas that contains more than 1 ppm H₂S at the wellhead is classified as sour gas in Alberta under AER Directive 056 (Energy Development Applications and Schedules). Gas with H₂S concentrations above 1% requires Class I H₂S emergency response planning. The AER defines H₂S content classification zones around producing wells and facilities, requiring public notification, evacuation plans, and emergency shut-in capability based on the H₂S concentration and the flow rate of the well. In the high-H₂S Foothills wells of the BC and Alberta Foothills, H₂S concentrations exceeding 30% (300,000 ppm) require specialized well control equipment, full breathing apparatus for all personnel at the wellsite, and downwind monitoring stations during well testing.
CO₂ in produced gas reduces its heating value and increases its density. Natural gas sales specifications typically require CO₂ content below 2% by volume (some pipelines allow up to 4%). CO₂ above specification reduces the gas's energy content per cubic metre and therefore its sales price per GJ, since gas is sold by energy content rather than volume. In the presence of water, CO₂ forms carbonic acid (H₂CO₃), which is corrosive to carbon steel pipelines and facilities at concentrations above about 0.5 bar partial pressure. Deep sour wells with high CO₂ partial pressure require corrosion-resistant alloys (chromium steel tubing, 13 Cr completion tubulars) or chemical injection (corrosion inhibitor injection at the wellhead) to manage internal corrosion. CO₂ is also regulated as a greenhouse gas under Canada's Greenhouse Gas Pollution Pricing Act, with carbon pricing applying to facility emissions above the benchmark intensity.
Amine sweetening is the standard process for removing H₂S and CO₂ from sour natural gas at gas processing plants. The sour gas contacts a liquid alkanolamine solvent (most commonly methyldiethanolamine, MDEA, or a blend of primary and tertiary amines) in an absorber column. The amine selectively absorbs H₂S and CO₂ from the gas through reversible chemical reactions: H₂S + amine → ammonium bisulfide-like ionic species; CO₂ + amine + water → carbonate-amine complex. The rich amine (loaded with acid gas) flows to a regeneration stripper where heat reverses the reactions, releasing the concentrated acid gas stream and regenerating lean amine for recirculation. The acid gas stream from the top of the stripper contains primarily H₂S and CO₂, typically at 40 to 85% H₂S depending on the feed gas composition and amine selectivity.
The concentrated acid gas stream from amine sweetening must be disposed of safely. Three main disposal routes exist: the Claus process (thermal and catalytic conversion of H₂S to elemental sulfur, which is a saleable byproduct); acid gas injection (AGI, compression and injection of the H₂S-CO₂ stream into a deep disposal reservoir or saline aquifer, avoiding sulfur recovery and SO₂ emissions entirely); and flaring (burning the acid gas to produce SO₂ and CO₂, which is permitted in limited quantities but is subject to AER flaring regulations and increasingly restricted as operators face emission-reduction obligations). The choice depends on H₂S concentration, plant size, and access to a suitable injection formation. In Alberta, acid gas injection has grown significantly since the 1990s as a method to avoid sulfur handling costs and SO₂ air emissions for smaller-volume acid gas streams where the Claus process is uneconomic.
Acid gas injection (AGI) into deep saline aquifers or depleted reservoirs in Alberta has been demonstrated at more than 35 sites as of the mid-2020s. The Alberta Energy Regulator's Directive 065 (Resources Applications for Conventional Oil and Gas Reservoirs) governs the regulatory approval of AGI schemes. Injection of H₂S into a saline aquifer traps the H₂S in dissolved or mineral form over geological time, providing permanent secure disposal. CO₂ injected alongside H₂S also provides geological storage of greenhouse gas, though CO₂ alone (without H₂S) is more commonly injected in carbon capture and storage (CCS) projects. The combination of H₂S and CO₂ in a single stream makes separation (to put the CO₂ into a CCS project while burning the H₂S in a Claus unit) technically complex and expensive, so most current AGI projects inject both components together.

The Claus Process: Converting H₂S to Sulfur

The Claus process is the dominant industrial method for converting H₂S from gas plant amine systems into elemental sulfur. It consists of two stages: the thermal stage (a furnace where one-third of the H₂S is burned with air to produce SO₂ and water: 2H₂S + 3O₂ → 2SO₂ + 2H₂O) followed by the catalytic stage (two or three catalytic reactors where the remaining H₂S reacts with the SO₂ to produce elemental sulfur and water: 2H₂S + SO₂ → 3S + 2H₂O). Overall, the process converts H₂S to liquid elemental sulfur that is sent to a liquid sulfur pit, solidified, and sold as a commodity to the fertilizer, chemical, and petroleum refining industries.

Claus unit efficiency is measured by the recovery of H₂S as sulfur versus emission as SO₂ from the tail gas. A standard two-reactor Claus unit achieves approximately 96 to 97% sulfur recovery. The remaining 3 to 4% exits as SO₂ in the tail gas, which must be treated in a tail gas treating unit (TGTU) to bring SO₂ emissions below AER and Environment and Climate Change Canada (ECCC) limits. Modern three-reactor Claus units with TGTU achieve 99.9% sulfur recovery, reducing SO₂ tail gas emissions to less than 250 ppm. In Alberta, large gas plants in the Kaybob, Edson, and Fox Creek areas operate Claus units with TGTUs to meet SO₂ emission limits set by AER Environmental Protection Orders.

In western Canada, sulfur production from sour gas processing is a significant commodity: Alberta produced approximately 2.6 million tonnes of elemental sulfur per year in recent years, second only to Saudi Arabia globally. This sulfur is solidified into blocks at the plant site, loaded onto rail cars, and shipped to ports at Vancouver and Prince Rupert for export. The majority goes to fertilizer manufacturers in Asia, where sulfur is used to produce sulfuric acid for phosphate fertilizer production.

Fast Facts

The Leduc Devonian carbonate discovery of 1947 opened a highly productive oil and gas province in Alberta but also revealed the extent of the province's sour gas problem: many Devonian reef pools contain H₂S concentrations of 1 to 20%, requiring sweetening before pipeline delivery. The first major sour gas plants in Alberta were built in the late 1940s and 1950s alongside the developing Devonian carbonate fields. By the 1960s, Alberta had become one of the world's major sulfur producers, with Claus plants at Turner Valley, Savanna Creek, and Jumping Pound. The Lodgepole blowout of 1982, where a sour gas well in west-central Alberta blew out and released H₂S for 67 days before being brought under control, resulted in the deaths of two workers and the evacuation of surrounding communities. It remains the most significant sour gas safety incident in Canadian history and drove major revisions to sour well drilling and testing regulations in Alberta. The AER's current Directive 056 and the Emergency Response Plan requirements for sour operations reflect the regulatory framework established largely in the aftermath of Lodgepole.

Acid Gas in the WCSB Context

The distribution of acid gas concentrations across the WCSB reflects the geologic history of the formations. Sweet gas (below 1% H₂S) dominates in the shallow Montney, Viking, Mannville, and Cardium formations where the reservoirs have been flushed by meteoric water over geological time and the original H₂S has been reduced or stripped from the reservoir. Sour gas (above 1% H₂S) is concentrated in the deep Devonian carbonate play trends, particularly the Nisku, Slave Point, Leduc, and Wabamun formations in a northeast-southwest belt through central Alberta, and in the deep Jurassic and Triassic carbonates of the Alberta and BC Foothills, where H₂S concentrations can exceed 30% in individual wells.

The Peace River Arch area and the Foothills belt contain the highest-H₂S wells in the WCSB. The Jumping Pound, Savanna Creek, and Waterton fields in the Foothills of southwest Alberta, and the deep Triassic carbonates of northeast BC (Halfway, Doig, Baldonnel formations), are known for H₂S concentrations requiring emergency response planning zones with radii of 5 to 10 kilometres around the wellbore or plant. Exploration and development in these areas requires detailed acid gas H₂S risk assessments before drilling, real-time downhole H₂S monitoring during drilling and testing, and multi-agency emergency response coordination between operators, the AER, and municipal emergency services.

Acid gas is also called sour gas in the field context (though sour gas technically refers to the raw gas, while acid gas often refers specifically to the H₂S-CO₂ stream after amine treatment). Related terms include hydrogen sulfide (H₂S, the toxic, corrosive, and flammable component of sour gas; the primary acid gas species of concern for health and safety in sour gas operations; present at concentrations from less than 1 ppm to more than 30% in WCSB wells depending on the formation), amine treating (the gas plant process that removes H₂S and CO₂ from sour natural gas using liquid alkanolamine solvents; produces a concentrated acid gas stream that must be processed in a Claus unit or injected underground), acid gas injection (AGI, the disposal of amine plant acid gas streams by compression and injection into deep saline aquifers or depleted reservoirs, avoiding sulfur recovery and SO₂ air emissions; increasingly used in Alberta for smaller acid gas volumes where the Claus process is uneconomic), Claus process (the two-stage thermal and catalytic process that converts H₂S in acid gas to elemental sulfur; the dominant H₂S disposal method at large sour gas plants in western Canada, producing sulfur sold as a commodity to fertilizer manufacturers), and sweetening (the removal of H₂S and CO₂ from sour natural gas to meet pipeline sales specifications; the process that converts sour raw gas to sweet pipeline-quality gas, generating the acid gas stream as a byproduct).

How an Unexpected H₂S Concentration Shut Down a Montney Test and Triggered an Emergency Response in Northeast BC

An operator was flow testing a deep Montney Formation well in the Blueberry River area of northeast British Columbia. The well was permitted and designed as a sweet gas well: offset wells in the same stratigraphic interval had H₂S below 1 ppm, and the operator's pre-drill H₂S risk assessment had classified the well as non-sour. No sour service completion equipment was on location, and the field emergency response plan did not include H₂S emergency procedures.

During the initial cleanup flow on the third day of testing, the wellsite technician's personal H₂S monitor alarmed at 10 ppm at the wellhead Christmas tree. All personnel evacuated to the upwind muster station. The surface read-out from a downhole optical fiber H₂S monitor (which had been installed during completion as a routine data-gathering tool rather than a safety requirement) showed H₂S concentrations of 0.8% (8,000 ppm) in the produced gas stream, a level more than 8,000 times higher than any adjacent well in the formation.