Acid Gas: Definition, H2S, CO2, and Sweetening Process

What Is Acid Gas?

Acid gas describes any gas component that dissolves in water to produce an acidic solution; in the oil and gas industry, the term refers primarily to hydrogen sulfide (H2S) and carbon dioxide (CO2), which are co-produced with hydrocarbon streams in sour and high-CO2 reservoirs, corrode steel equipment, and require removal through gas sweetening processes before pipeline delivery or liquefaction.

How Acid Gas Behaves in Oilfield Systems

Both H2S and CO2 are weak acids in thermodynamic terms but highly destructive in oilfield engineering because steel infrastructure is their primary contact surface. When H2S dissolves in water (formation water, condensed water vapor, or process water), it produces hydrogen sulfide acid (H2S(aq)), which dissociates to release hydrogen ions and hydrosulfide ions (HS-). These ions attack carbon steel through a mechanism known as sulfide stress cracking (SSC): hydrogen ions generated by the corrosion reaction absorb into the steel lattice, diffuse to grain boundaries, and cause hydrogen-induced cracking (HIC) or stress-oriented hydrogen-induced cracking (SOHIC) under tensile stress. At temperatures below 80°C (175°F) and H2S partial pressures above 0.34 kPa (0.05 psia), NACE International Standard MR0175/ISO 15156 mandates use of sour-service-rated materials with controlled hardness (maximum 22 HRC or 250 Vickers hardness) in casing, production tubing, wellhead components, and all wetted pressure-containing parts. This standard, maintained by NACE International (now merged into AMPP — Association for Materials Protection and Performance), is referenced universally across international jurisdictions.

CO2 behaves differently. When CO2 dissolves in water, it produces carbonic acid (H2CO3), which drives "sweet corrosion" (named to distinguish it from the sour corrosion caused by H2S). Sweet corrosion creates mesa-type pitting on steel surfaces: localized pits with flat bottoms and steep sides form where the thin iron carbonate (FeCO3) corrosion product film breaks down. CO2 partial pressure (pCO2) is the standard screening parameter: pCO2 below 7 psi (48 kPa) is generally considered low risk; 7 to 30 psi (48 to 207 kPa) is moderate risk requiring monitoring and inhibition; above 30 psi (207 kPa) is severe and requires corrosion-resistant alloys (CRA) such as 13Cr stainless steel, duplex stainless, or nickel alloys for tubing selection. Temperature also modulates CO2 corrosion: protective FeCO3 scale forms more readily above 60°C (140°F), partially passivating the steel surface, while at lower temperatures the protective scale is less stable and pitting rates are higher.

When both H2S and CO2 are present simultaneously, their combined effect is not simply additive. H2S at even trace concentrations (above 1 ppm) may suppress the mesa corrosion pattern of CO2 and instead promote uniform corrosion or SSC, depending on relative partial pressures, temperature, pH, and the presence of elemental sulfur. Sour service design therefore treats H2S as the governing constraint for material selection whenever both gases are present. The drilling fluid program for sour wells must also account for H2S influx during drilling: weighted muds with sufficient pH (above 10) can partially scavenge H2S by converting it to the less volatile bisulfide ion, and chemical H2S scavengers (triazine compounds, zinc-based reagents) are added to mud systems as a secondary barrier against H2S entry to surface. Proper well control procedures for sour kicks require modified diverter configurations and closed-loop handling of displaced gas to protect rig crew from H2S exposure.

Acid Gas Across International Jurisdictions

The regulatory treatment of acid gas varies by country, reflecting differences in reservoir geology, population density, environmental policy, and national oil company technical standards.

Canada (Alberta and British Columbia)

Alberta has some of the most comprehensive sour gas regulations in the world, driven by a long history of sour gas production from the Foothills, Peace River Arch, and Rimbey-Meadowbrook reef trend. The Alberta Energy Regulator (AER) Directive 071 (Emergency Preparedness and Response Requirements for the Petroleum Industry) sets mandatory requirements for H2S contingency planning, including establishment of emergency planning zones (EPZ) around sour wells based on sulphur release rate calculations, public notification, and evacuation protocol documentation. AER Directive 036 (Drilling Controls) governs H2S monitoring equipment, standby hours requirements for drilling in sour formations, and kick detection in sour zones. H2S Alive certification (ENFORM's standardized 8-hour training course) is mandatory for all field workers who may be exposed to H2S in Alberta; this certification is recognized across western Canada. Major sour gas processing facilities in Alberta include the Shell Waterton Gas Plant, the Rimbey Gas Plant, and the Ram River Gas Plant, all of which process sour streams containing multiple percent H2S. Alberta has also been the global test bed for acid gas injection (AGI): Shell Canada's Jumping Pound AGI scheme in the 1990s was the first large-scale commercial injection of H2S into a subsurface disposal formation, and dozens of smaller AGI schemes have been approved by the AER since then, covering approximately 10 facilities that co-inject H2S and CO2 into carbonate and sandstone formations. In British Columbia, the BC Energy Regulator governs sour Montney wells in the Dawson Creek and Fort St. John areas, where H2S concentrations in some completion intervals require full sour-service wellbore designs and detailed H2S response plans.

United States (Gulf of Mexico and Permian Basin)

US regulatory oversight of acid gas spans federal and state jurisdictions. Offshore on the Gulf of Mexico Outer Continental Shelf (OCS), the Bureau of Safety and Environmental Enforcement (BSEE) regulates H2S under 30 CFR Part 250, requiring operators to submit H2S contingency plans, install H2S detection systems on rigs and platforms, and use sour-service equipment per NACE MR0175 in any zone where H2S exceeds 0.05 psia partial pressure. OSHA Process Safety Management standard (29 CFR 1910.119) applies to onshore gas processing facilities handling H2S above threshold quantities. The US Environmental Protection Agency (EPA) classifies H2S as a hazardous air pollutant (HAP) and acid gas emissions from sweetening plants are regulated under the National Emission Standards for Hazardous Air Pollutants (NESHAP). In the Permian Basin, the Bone Spring and Wolfcamp formations in the Delaware Basin contain elevated CO2 concentrations (up to 10% by volume in some wells) requiring CO2 separation at the wellsite or tolerated within pipeline specifications. The Permian Basin Midland side has H2S in the Spraberry Trend, particularly in deeper intervals. The Texas Railroad Commission (TRRC) regulates sour gas operations in Texas, requiring H2S safety plans and reporting. CO2 from natural sources (such as the Bravo Dome CO2 field in New Mexico) is captured and piped to Permian Basin enhanced oil recovery (EOR) operations, where management of CO2 in produced gas streams is a routine operational challenge.

Norway and the North Sea

The Petroleum Safety Authority Norway (Ptil) governs all well and process safety on the Norwegian Continental Shelf (NCS) under the Petroleum Activities Act and the Framework Regulations, Management Regulations, and Activities Regulations. NORSOK Standard D-010 (Well Integrity in Drilling and Well Operations) provides detailed technical requirements for well barriers, materials selection, and operating procedures in H2S environments, and is mandatory for NCS operations. Several NCS fields contain significant acid gas: the Åsgard Field in the Norwegian Sea produces gas with H2S content requiring sweetening before pipeline export; Sleipner Vest in the North Sea contains natural gas with approximately 9% CO2, which is removed by amine scrubbing on the Sleipner T platform before export. Since 1996, StatoilHydro (now Equinor) has injected the separated CO2 from Sleipner into the Utsira Formation saline aquifer at approximately one million tonnes per year, making Sleipner the world's first offshore commercial CO2 storage project. Sleipner has become a global reference case for offshore carbon capture and storage (CCS). The Snøhvit LNG project in the Barents Sea (Hammerfest, northern Norway) produces natural gas with 5 to 6% CO2; the CO2 is removed at the Melkøya LNG terminal and injected into the Tubåen Formation saline aquifer beneath the seabed, at approximately 700,000 tonnes per year.

Australia

Australia hosts two of the world's most significant acid gas management projects due to its major LNG export developments. The Gorgon LNG project on Barrow Island, operated by Chevron Australia, is Australia's flagship CCS project: the Gorgon field gas contains approximately 14% CO2, which must be removed before LNG liquefaction. The Gorgon CCS project targets injection of up to 3.4 million tonnes per year of CO2 into the Dupuy Formation deep saline aquifer beneath Barrow Island, though early operational performance fell below design capacity due to reservoir pressure buildup complications. Barrow Island's Class A nature reserve status on a government-protected island made CO2 venting environmentally unacceptable, making subsurface storage the only viable option. The Ichthys LNG project (operated by INPEX) processes gas with approximately 8% CO2 from the Browse Basin; its CO2 management approach involves partial CO2 use in reservoir pressure maintenance and partial venting with offset mitigation. The National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) regulates offshore H2S and acid gas management under the Offshore Petroleum and Greenhouse Gas Storage Act 2006. Onshore, the Northern Territory gas resources in the McArthur Basin have elevated CO2 content in exploration targets, and any future development will require CCS or CO2 reinjection under Australia's national greenhouse gas reporting obligations.

Middle East (Saudi Arabia, Kuwait, Abu Dhabi, and Qatar)

The Middle East contains vast sour gas resources in deep Jurassic and Triassic carbonate reservoirs. Saudi Aramco's deep Khuff Formation gas (supplying the Master Gas System) contains H2S at concentrations up to 10% by volume and CO2 at several percent in some structural closures, requiring large sour gas processing trains at Hawiyah and Haradh NGL recovery plants. Saudi Aramco's gas sweetening capacity processes billions of standard cubic feet per day using amine systems and Claus sulfur recovery units, producing elemental sulfur exported globally. Kuwait Oil Company (KOC) manages sour Jurassic gas from the Jurassic Marrat and Najmah reservoirs. Abu Dhabi National Oil Company (ADNOC) develops sour gas from the Shah Gas field (H2S content up to 23% by volume, one of the world's sourest gas developments), requiring massive sour service infrastructure investments and sulfur recovery trains. Qatar's North Field, the world's largest single hydrocarbon reservoir, produces relatively low H2S gas (typically below 0.5%) but CO2 at 2 to 3% by volume, which is managed through amine treating at onshore LNG trains and exported gas specifications. Regulatory oversight in GCC countries is primarily through national oil company technical standards and concession agreements rather than independent statutory regulators, with technical specifications aligned to API, NACE, and SPE international standards.