Sour

Sour refers to crude oil or natural gas that contains hydrogen sulfide (H₂S) at concentrations above a threshold that requires special handling. For natural gas in Canada, the threshold is 5.7 milligrams of H₂S per cubic metre of gas (equivalent to about 4 parts per million by volume); gas above this level is classified as sour. For crude oil, sourness is defined in terms of total sulfur content and dissolved H₂S, with the threshold varying by market specification. Sour gas and sour crude require treatment before pipeline entry or refinery processing, special metallurgy in all contact equipment to resist hydrogen embrittlement, and enhanced safety procedures because H₂S is acutely toxic at concentrations above 100 parts per million.

Key Takeaways

Hydrogen sulfide is produced biogenically (by sulfate-reducing bacteria acting on formation water) and thermogenically (by thermal cracking of organic sulfur compounds in source rock at high temperature). Deep, hot reservoirs in carbonate formations are particularly prone to high H₂S concentrations; Alberta's Foothills carbonate fields contain H₂S at concentrations from 10 to 35 percent by volume in some reservoirs.
The oil and gas industry uses the NACE MR0175 / ISO 15156 standard to specify material requirements for equipment in H₂S service. Carbon steel that is acceptable for sweet service can fail by sulfide stress cracking (SSC) in sour conditions within hours if the H₂S partial pressure and stress level are not controlled. Low-alloy steels, nickel-base alloys, and controlled hardness carbon steels are selected based on the sour severity of each service.
Gas sweetening (amine treating) is the standard process for removing H₂S and CO₂ from sour gas. The sour gas contacts a liquid amine solution (MEA, DEA, or MDEA) in an absorber column. The amine chemically reacts with and absorbs the acid gases. The acid gas-laden amine is then regenerated by heating, releasing the H₂S and CO₂ as a concentrated acid gas stream that is processed in a Claus sulfur recovery unit.
The Claus process converts the H₂S in the acid gas stream to elemental sulfur, which is a marketable product. Canadian sour gas plants produce a significant fraction of the world's elemental sulfur. Sulphur from Alberta is shipped to fertilizer manufacturers worldwide as a feedstock for sulfuric acid production. The Peace River Arch and Deep Basin gas plants near Fox Creek and Edson are among the world's largest sulfur producers.
Sour crude oil requires additional hydrotreating in the refinery to remove the sulfur before the products (gasoline, diesel, jet fuel) can meet fuel quality specifications. High-sulfur crude fetches a lower price than sweet crude because of the additional refinery processing cost. The price differential between West Texas Intermediate (sweet, benchmark) and comparable sour crudes reflects this refining premium.

What Makes Oil or Gas "Sour"?

In everyday language, sour means acidic. In the oilfield, sour means something more specific: contaminated with hydrogen sulfide. The term dates to the early days of oil refining, when crude with high sulfur content produced a product that smelled bad and caused corrosion in copper strip tests used to assess fuel quality. The chemistry behind the name is real: H₂S in water produces a weak acid (hydrosulfuric acid), and the smell of hydrogen sulfide (rotten eggs) is one of the most recognizable and unpleasant odors known.

H₂S is dangerous far below the concentration at which it becomes detectable by smell. At 10 parts per million (ppm), it smells like rotten eggs. At 100 ppm, the nose becomes numb and the odor disappears, which is the cruel irony of H₂S: at the concentrations that kill, you can no longer smell it. At 500 ppm, loss of consciousness occurs within minutes. At 1,000 ppm, collapse is nearly instantaneous. Sour gas operations require continuous air monitoring, H₂S detector badges for all personnel, escape routes marked upwind, and breathing air available at multiple stations.

Alberta has some of the world's most thorough regulations for sour gas operations. AER Directive 071 governs sour gas well licencing and emergency response plans. A sour well that could release H₂S above 5 ppm at the property boundary of any occupied building must have an emergency response plan filed with the AER and rehearsed before drilling commences. The emergency planning zone (EPZ) radius depends on the well's calculated release rate.

Fast Facts

The Jumping Pound gas field west of Calgary, discovered in 1944, was the first major sour gas development in Canada. With H₂S concentrations of 8 to 12 percent by volume, Jumping Pound required the construction of what was then the world's largest gas sweetening plant. Imperial Oil and then Shell Canada operated the plant through the mid-20th century. The field produced significant quantities of elemental sulfur as a byproduct of gas sweetening, which was initially treated as a waste product and stockpiled in large yellow piles near the plant. The development of sulfur markets for fertilizer production turned the waste into a revenue stream. The Jumping Pound experience established the operational and regulatory template for sour gas development that was applied to larger and sourer fields like Waterton and Caroline in subsequent decades.

Sulfide Stress Cracking and Sour Service Materials

When hydrogen sulfide dissolves in water at a metal surface, it accelerates the absorption of hydrogen atoms into the metal lattice through a process called hydrogen charging. In ordinary sour service this causes hydrogen-induced cracking (HIC), in which hydrogen atoms diffuse to internal defects and recombine as hydrogen gas, creating internal pressure that causes planar cracks. In harder or more stressed metal, the same hydrogen causes sulfide stress cracking (SSC), in which the hydrogen embrittles the metal along grain boundaries and existing stress concentrations cause sudden brittle fracture.

SSC is particularly dangerous because it can cause failure at stresses well below the material's nominal yield strength, and failure can occur suddenly with no warning deformation. A tubing joint that has been in sour service for months can fail catastrophically if someone runs a slip on it during a workover and the localized stress exceeds the SSC threshold.

NACE MR0175 (now ISO 15156) defines three environmental severity regions based on H₂S partial pressure and pH of the water phase. Each region has a maximum allowable hardness for carbon and low-alloy steel (Region 3 limits steel hardness to 22 HRC) and lists acceptable alloys. Operators must specify the region for each piece of equipment based on the worst-case operating conditions and verify that all materials in contact with the sour fluid meet the regional requirements.

Sour Crude Oil: Pricing and Refining Implications

The global benchmark sweet crude is West Texas Intermediate (WTI) with sulfur content of about 0.24 percent by weight. Arabian Light crude from Saudi Arabia has sulfur content of about 1.8 percent and is considered medium-sour. Arabian Heavy is about 2.8 percent sulfur. Canadian oil sands bitumen diluted for pipeline transport (dilbit) typically has sulfur content of 3.5 to 4.5 percent and requires significant hydrotreating before the products meet fuel quality specs.

The price discount for sour crude relative to sweet crude fluctuates with refinery economics. US Gulf Coast refineries that were built to process heavy sour crude from Venezuela and the Middle East can actually prefer sour crudes when the price discount is large, because their cokers and hydrotreaters are sized for the additional processing. Light sweet crudes require these refineries to run at reduced throughput or blend sour with sweet to fill their units. The market for sour and sweet crude is therefore not simply that sweet is always better: it depends on which refineries are buying and what their processing units can handle.

Sour gas or sour crude is contrasted with sweet gas or sweet crude (which have H₂S below the threshold). The process of removing H₂S is called sweetening or gas treating. Related terms include hydrogen sulfide (H₂S, the toxic, flammable, and corrosive gas responsible for sourness in oil and gas; produced biogenically and thermogenically; the threshold contaminant defining sour service in regulatory and engineering contexts), gas sweetening (the process of removing H₂S and CO₂ from sour gas by absorption into a liquid amine solution; the treated gas is called sweet gas; the recovered acid gases are processed in a Claus sulfur recovery plant), sulfide stress cracking (SSC, the brittle failure of steel or other alloys caused by hydrogen charging in the presence of H₂S; prevented by material selection per NACE MR0175 / ISO 15156), Claus process (the industrial process that converts H₂S in acid gas streams to elemental sulfur through catalytic oxidation; used in all major sour gas processing plants), and emergency planning zone (EPZ, the geographic area around a sour well or sour gas plant within which emergency response procedures must be pre-planned; size is determined by the worst-case H₂S release rate calculation).

When Incorrect Tubing Hardness Documentation Shut In a Foothills Gas Field for Three Weeks

A gas battery in the Foothills of western Alberta was gathering gas from seven producing wells into a central compression and treating facility. The reservoir was mildly sour at 1.2 percent H₂S by volume. The battery had been operating for four years without significant incident.

During a workover on one of the producing wells, a tubing joint with a hairline crack (not visible on surface inspection) was run downhole. The joint had been recorded as acceptable grade for the nominal H₂S level. However, the batch number of the tubing joint had been incorrectly recorded in inventory: it was actually from a higher-hardness run that met API 5CT specifications for sweet service but whose hardness of 26 HRC exceeded the NACE MR0175 Region 1 limit of 22 HRC for the actual sour service conditions. The crack, pre-existing from a quenching defect during manufacture, propagated under the combined stress of the wellbore pressure and H₂S charging.

The tubing joint parted at 1,340 metres depth. The blowout preventer closed on the parted string, but produced sour gas vented for 40 minutes through the annular BOP vent before the well was killed. The H₂S plume drifted southeast in light winds, reaching a nearby lease road. One third-party pump truck driver who had not been briefed on H₂S emergency procedures received a non-fatal H₂S exposure. Emergency response was activated, the field was shut in, and regulatory inspections halted all seven wells for 22 days pending full materials audit and emergency response plan update.

The lost production from 22 days of field shut-in was approximately 180,000 cubic metres of gas and 2,400 cubic metres of condensate, worth approximately CAD 680,000 at prevailing prices. The materials audit found two additional tubing joints in inventory with incorrect hardness documentation. Total cost including workover, regulatory compliance, emergency response, and production loss was CAD 2.1 million. The failure traced to a single data entry error in the tubular tracking system at the time of original delivery. Ensuring that all sour service equipment is documented with confirmed hardness certification and material test reports, not just mill certificates, was the key corrective action.