Origins of Hydrogen Sulfide (H2S) in Oil and Gas

Understanding the origins of hydrogen Sulfide in reservoirs, during production, and in surface facilities is essential for prediction, prevention, and effective treatment.

H₂S in hydrocarbon systems arises from three primary categories of sources: biogenic (microbial), thermochemical (high-temperature abiotic reactions), and thermogenic (thermal maturation of organic matter). While these can overlap or occur sequentially in a reservoir’s history, they operate under distinctly different conditions and produce characteristic signatures. This article provides a detailed examination of each, with particular emphasis on bacterial mechanisms, the types of microorganisms involved, and how they are introduced or stimulated in oil and gas operations.

Overview of Hydrogen Sulfide Sources

H₂S can be present from the time of reservoir charging (geological origins) or generated later during production (often operationally induced).

Geological/thermogenic sources dominate in deep, hot reservoirs and are independent of current microbial activity. Thermochemical sulfate reduction (TSR) produces some of the highest H₂S concentrations observed (sometimes >50–90% in the gas phase). Biogenic sources, driven by sulfate-reducing microorganisms, are especially important in shallower or cooler reservoirs and become dramatically amplified by waterflooding and other injection practices. Minor contributions can come from aquathermolysis during thermal heavy-oil recovery or from sulfur-containing additives and biofilms in surface equipment.

Distinguishing the dominant source in a given field guides everything from materials selection and corrosion management to the choice of H₂S scavenging or removal technologies.

Thermogenic and Thermal Maturation Sources

During burial and thermal maturation of source rocks (catagenesis), sulfur-rich kerogen (particularly Type II-S kerogen from marine depositional environments) undergoes cracking. Organic sulfur compounds (thiols, sulfides, thiophenes) break down, releasing H₂S along with hydrocarbons. This process occurs at temperatures typically associated with the oil and wet-gas windows (roughly 60–150°C or higher, depending on time and kinetics).

Thermogenic H₂S is often associated with oil that has high sulfur content. It partitions into both the liquid and gas phases. While significant, thermogenic contributions rarely produce the extreme H₂S levels seen in some TSR-dominated fields. In many basins, early thermogenic H₂S may have been lost or diluted over geological time, or it may mix with later-generated H₂S.

Thermal decomposition of sulfate minerals (e.g., gypsum or anhydrite) at very high temperatures can also release H₂S, but this is generally less important than TSR in petroleum systems.

Thermochemical Sulfate Reduction (TSR): High-Temperature Abiotic Generation

TSR is the dominant source of very high H₂S concentrations in many deep carbonate reservoirs. It is a purely chemical (abiotic) process in which hydrocarbons react with dissolved or mineral sulfate (typically anhydrite or gypsum) at elevated temperatures, producing H₂S, CO₂, calcite (or other carbonates), water, and sometimes elemental sulfur or metal sulfides.

General reaction (simplified):
Sulfate + hydrocarbons → H₂S + CO₂ + calcite + H₂O (± residual organics or S)

Key requirements include:

• Presence of sulfate minerals or high-sulfate brines.
• Hydrocarbons (especially liquid or wet gas; methane reacts more slowly).
• Sufficient temperature (onset often cited around 100–140°C; significant rates typically >120–150°C).
• Water as a medium and catalyst.
• Time (reactions are kinetically slow but can be autocatalytic once H₂S is present).

TSR is strongly associated with carbonate-evaporite sequences (e.g., Smackover Formation in the US Gulf Coast, Khuff Formation in the Middle East, Nisku and other Devonian carbonates in Western Canada, and basins in China and Central Asia). In these settings, anhydrite layers or nodules provide the sulfate, and migrating hydrocarbons or in-situ oil/gas serve as the reductant. Resulting H₂S can reach extremely high levels, rendering the gas highly sour and economically challenging.

Because TSR occurs over geological timescales at reservoir temperatures, it creates “naturally sour” reservoirs. Production does not “create” the H₂S but simply brings it to surface. Isotopic signatures (δ³⁴S of H₂S close to that of the original sulfate with relatively small fractionation) and high associated CO₂ help distinguish TSR from biogenic sources.

Biogenic H₂S: Microbial Sulfate Reduction – The Dominant Operational Source

The most operationally significant and often preventable source of H₂S is bacterial (or archaeal) sulfate reduction, also called biogenic sulfate reduction (BSR). This is the primary driver of “reservoir souring” — the increase in H₂S concentrations observed over time in many waterflooded fields.

Sulfate-reducing microorganisms (SRMs) — primarily bacteria (SRB) but also archaea (SRA) — use sulfate (SO₄²⁻) as a terminal electron acceptor for anaerobic respiration. In the absence of oxygen, they oxidize organic compounds (or sometimes H₂) and reduce sulfate to sulfide, which equilibrates to H₂S or HS⁻ depending on pH.

Core biochemistry (dissimilatory sulfate reduction):
Sulfate is first activated to adenosine-5′-phosphosulfate (APS). APS is reduced to sulfite, and sulfite is further reduced to sulfide by dissimilatory sulfite reductase (Dsr). The overall process yields energy via electron transport and proton motive force. Simplified net reactions include:

• With acetate (common intermediate): CH₃COO⁻ + SO₄²⁻ → 2HCO₃⁻ + HS⁻
• General with organic matter: 2CH₂O + SO₄²⁻ + H⁺ → HS⁻ + 2CO₂ + 2H₂O

In oil reservoirs, SRMs rarely degrade complex hydrocarbons directly. Instead, they rely on syntrophic partnerships with fermentative and hydrocarbon-degrading bacteria that break down alkanes and other oil components into volatile fatty acids (VFAs such as acetate, propionate, butyrate), H₂, and CO₂. These intermediates become the direct substrates for SRB.

Key Types of Sulfate-Reducing Bacteria and Archaea in Oil and Gas Systems

• Desulfovibrio species (e.g., Desulfovibrio desulfuricans, D. longus): Gram-negative, mesophilic, curved or vibrioid rods. Among the most frequently isolated from oilfield produced waters. Highly versatile; use lactate, pyruvate, H₂, and some alcohols. Common in moderate-temperature systems and surface facilities.
• Desulfotomaculum species: Gram-positive, spore-forming rods. Spores confer resistance to heat, desiccation, and biocides, making them resilient survivors in drilling and completion fluids. Important for introduction into reservoirs.
• Desulfobacter and Desulfobacterium species: Acetate-oxidizing specialists. Particularly relevant where acetate accumulates from oil biodegradation or fermentation.
• Desulfacinum, Thermodesulfobacterium, and Thermodesulfovibrio: Thermophilic genera found in hotter reservoirs or produced waters. Extend the temperature range of biogenic activity.
• Archaeoglobus (e.g., Archaeoglobus fulgidus): Sulfate-reducing archaea. Hyperthermophilic; found in very hot oil reservoirs and hydrothermal-influenced systems. Less common than bacterial SRB but significant in deep, high-temperature environments.

Other H₂S-producing microbes exist (sulfur-reducing bacteria that reduce elemental sulfur, certain thiosulfate or sulfite reducers, and putrefactive bacteria that liberate H₂S from sulfur-containing amino acids), but SRMs using dissimilatory sulfate reduction are by far the dominant contributors in petroleum systems.

Environmental Conditions Favoring SRB Activity

• Strictly anaerobic (redox potential typically below –100 to –200 mV).
• Temperature window: Most mesophilic SRB active ~10–45°C; thermophilic strains up to ~80–100°C. Above ~100–120°C, microbial activity generally ceases and TSR may dominate.
• Sulfate availability (often the limiting factor until injection introduces it).
• Electron donors (VFAs, H₂, or hydrocarbons via syntrophy).
• Suitable pH (typically 5.5–9.0, though many oilfield SRB are halotolerant or halophilic) and salinity.
• Nutrients (N, P) and trace elements; these are frequently not limiting in reservoirs but can influence rates.

Biofilms are critical: SRB live in complex consortia protected by extracellular polymeric substances. Biofilms on pipe walls, in tank bottoms, or within reservoir pore spaces shield cells from biocides and oxygen spikes while concentrating substrates and sulfide.

How SRB Are Introduced and Stimulated in Oilfield Operations

SRB are ubiquitous in nature (marine sediments, seawater, soils, aquifers). Many reservoirs contain indigenous low-level populations in formation water or attached to rock surfaces. However, the dramatic increase in H₂S — “reservoir souring” — is frequently triggered by human activity.

Primary Introduction and Stimulation Pathways

1. Waterflooding and injection: The single most important factor in many fields. Seawater contains ~2,700–2,800 mg/L sulfate. When injected into reservoirs that previously had low sulfate or limited electron acceptors, it provides both the electron acceptor and, often, microbes or nutrients. Mixing of injected water with formation water can also create favorable conditions or transport SRB deeper into the reservoir. Classic examples include numerous North Sea fields, where H₂S levels rose from near-zero to hundreds or thousands of ppm over years of seawater injection.
2. Drilling, completion, and workover fluids: Water-based muds, brines, and completion fluids can introduce SRB if pits or tanks become contaminated. Spore-forming Desulfotomaculum are particularly adept at surviving and later germinating. Fluid invasion into the near-wellbore region seeds the formation.
3. Produced water reinjection: Recycles SRB, H₂S already present, VFAs, and other nutrients back into the reservoir, creating a feedback loop that sustains or increases souring.
4. Surface facilities and infrastructure: Stagnant water in tanks, separators, dead legs, and pipelines allows biofilm development. Sludge and sediments at tank bottoms provide protected anaerobic niches rich in organics and sulfate. H₂S generated here can partition into export crude or gas, or cause localized corrosion.
5. Other operational factors: Hydraulic fracturing fluids (if they contain organics or sulfate), stimulation treatments, or even poor housekeeping that allows oxygen ingress followed by consumption (creating anaerobic zones).

In short, while some reservoirs are naturally sour from TSR or thermogenic processes, many others become sour — or significantly more sour — because production operations inadvertently supply sulfate, carbon sources, and transport or stimulate SRB populations.

Case Illustration — North Sea Reservoir Souring

Multiple fields experienced progressive increases in produced H₂S after seawater injection began. Monitoring showed SRB proliferation, and mitigation strategies (nitrate injection to promote competing nitrate-reducing bacteria, or sulfate removal) were deployed with varying success. This pattern has been replicated in offshore and onshore waterflood projects worldwide.

Distinguishing Sources and Diagnostic Approaches

Operators use multiple lines of evidence:

• Isotopic analysis (δ³⁴S of H₂S versus sulfate or kerogen): Biogenic H₂S shows large negative fractionation; TSR shows smaller fractionation close to the source sulfate signature.
• Associated gases and geochemistry: High CO₂ often accompanies TSR. Temperature history and burial modeling indicate whether conditions ever reached TSR thresholds.
• Microbiological surveys: qPCR, culturing, or metagenomics detect SRB/SRA abundance and activity (e.g., dsr genes).
• Production history: Sudden or progressive rise in H₂S after waterflood points strongly to biogenic souring.
• Geological context: Presence of evaporites + high temperature + carbonates favors TSR.

Implications for Safety, Operations, and Treatment

Regardless of origin, H₂S must be managed. Naturally sour reservoirs require sour-service metallurgy and robust sweetening from day one. Operationally induced biogenic souring may be mitigated by preventing introduction (sulfate removal from injection water, biocide programs, nitrate injection) or by treating produced fluids.

Effective H₂S removal technologies — whether liquid scavengers, solid adsorbents, or custom scrubber systems — remain essential across all scenarios. Understanding the source helps optimize treatment location (downhole, wellhead, or facility), predict ongoing generation rates, and select compatible chemistries.

Conclusion

H₂S in oil and natural gas originates from fundamentally different processes depending on geology, temperature, and operational history. Thermogenic cracking and especially thermochemical sulfate reduction create naturally sour reservoirs in deep, hot carbonate-evaporite settings. Biogenic production by sulfate-reducing bacteria and archaea — particularly when stimulated by seawater or produced-water injection — is responsible for much of the souring observed during the producing life of many fields.

The bacteria themselves are diverse (Desulfovibrio, Desulfotomaculum, Desulfobacter, thermophilic genera, and Archaeoglobus among the key players), resilient, and highly adapted to the anaerobic, sulfate- and organic-rich niches created or expanded by oilfield practices. They enter reservoirs through drilling and injection fluids, proliferate in biofilms, and generate H₂S through well-characterized dissimilatory sulfate reduction pathways that rely on syntrophic microbial communities.

For operators and technology providers alike, mapping the dominant H₂S source(s) in each asset is the foundation of safe, efficient, and cost-effective management. As waterflooding, enhanced oil recovery, and deeper drilling continue, the microbial dimension of souring will remain a critical focus area alongside geological understanding and advanced treatment solutions.