SRB (Sulfate-Reducing Bacteria): Definition, Oilfield Souring, and Corrosion

What Are Sulfate-Reducing Bacteria (SRB)?

Sulfate-reducing bacteria (SRB) are anaerobic microorganisms that use sulfate (SO₄²⁻) as a terminal electron acceptor in their metabolism, reducing it to hydrogen sulfide (H₂S) and bicarbonate: SO₄²⁻ + organic carbon → H₂S + HCO₃⁻. SRB are ubiquitous in oil and gas production environments — they colonise injection water systems, produced water handling facilities, storage tanks, subsea infrastructure, and reservoir formations. Their metabolic activity causes three serious and expensive production problems: reservoir souring (H₂S generation that contaminates originally sweet gas and oil), microbiologically influenced corrosion (MIC) of steel surfaces, and biogenic scale formation through iron sulfide precipitation. SRB-driven souring has converted dozens of originally sweet fields into sour gas producers after seawater injection.

SRB and Reservoir Souring Mechanism

Sweet reservoirs (H₂S <4 ppm in produced gas) can sour progressively after seawater waterflood begins. Seawater contains 2,700 mg/L sulfate — a rich electron acceptor for SRB. The reservoir pore water and crude oil provide electron donors (volatile fatty acids, low-molecular-weight organic acids produced by fermentation). Where injected seawater meets formation water and SRB thrive (temperatures 20–60°C, pH 6–8, anaerobic conditions), sulfate is reduced to H₂S. The H₂S front moves through the reservoir with the waterflood front — first H₂S breakthrough typically occurs 3–8 years after injection start, depending on reservoir temperature, SRB population, and waterflood velocity.

Once souring begins, the H₂S concentration in produced gas increases over years to decades. A field that was sweet at first production may reach 1,000–5,000 ppm H₂S (requiring H₂S removal at the facility) or even higher. This has cascading consequences: H₂S at >10 ppm is immediately dangerous to life; it requires NACE-compliant sour service steel and elastomers (adding 15–25% to material costs); it must be treated (amine scrubbing, incineration) before gas sales; and it complicates well interventions, requiring H₂S monitoring and detection equipment at all times. The economic impact of souring a large platform from sweet to sour can exceed $100–500 million in facility modifications.

SRB Synonyms and Related Terminology

SRB is also referred to as:

• Sulfate-reducing bacteria — full name, both spellings (sulphate/sulfate) are used
• Sulfate-reducing microorganisms (SRM) — broader term that includes sulfate-reducing archaea (SRA) active at higher temperatures (>80°C) beyond SRB's upper range
• Desulfovibrio — the most common genus of SRB in oilfield environments
• Anaerobic corrosion agents — used in corrosion engineering context to describe their role in MIC

Related terms: Sour Gas, H2S, Corrosion, Waterflood

Frequently Asked Questions About SRB

How does nitrate injection control SRB and reservoir souring?

Nitrate injection exploits microbial competition. Nitrate-reducing bacteria (NRB) and nitrate-reducing, sulfide-oxidising bacteria (NR-SOB) use nitrate (NO₃⁻) or nitrite (NO₂⁻) as a preferred electron acceptor over sulfate. When nitrate is added to the injection water, NRB and NR-SOB outcompete SRB for the available electron donors (organic acids, H₂) in the reservoir. This competition reduces the SRB population and thus H₂S production. NR-SOB can also directly oxidise H₂S back to elemental sulfur, providing an additional souring suppression mechanism. Nitrate injection (NSSIP) has been deployed successfully at Halfdan, Skjold, and Siri fields in the North Sea and several Gulf of Mexico platforms, consistently reducing H₂S concentrations by 50–95% compared to untreated systems. Nitrate dose is typically 50–300 mg/L in injection water, at a cost of $0.10–0.50 per bbl of injection water — modest against the cost of souring.

What is microbiologically influenced corrosion (MIC) and how serious is it?

MIC from SRB occurs when SRB form biofilms on steel surfaces in anaerobic conditions. The biofilm creates a corrosive microenvironment: SRB produce H₂S, which reacts with iron to form iron sulfide (FeS) — an aggressive galvanic corrosion couple that accelerates metal dissolution. SRB biofilms also exclude oxygen, creating an anaerobic zone beneath the biofilm that further promotes SRB metabolism. The resulting pitting corrosion can penetrate 1–5 mm/year of carbon steel — a 6 mm pipeline wall can fail from pitting in 2–5 years. MIC has been the root cause of multiple pipeline failures, topside vessel perforations, and subsea equipment failures in production facilities globally. Detection requires specialist microbiological monitoring, corrosion coupon exposure, and smart pig inspections focused on pitting depth — general corrosion monitoring (inhibitor residuals, iron counts) misses MIC because it is localised, not uniform.

At what reservoir temperature do SRB become inactive?

Mesophilic SRB (the most common oilfield species, including Desulfovibrio) are active at 20–60°C and inactive above 65–70°C. This is why reservoirs at temperatures above 70°C are generally protected from biological souring — the high temperature sterilises SRB populations. However, thermophilic sulfate-reducing archaea (SRA) are active at 70–110°C, and in deep, hot reservoirs with seawater injection, SRA can cause souring in the temperature range where mesophilic SRB cannot survive. This has been observed in Norwegian North Sea deep reservoirs and some Middle East fields. The transition from SRB to SRA as souring agents in hotter reservoirs requires different biocide chemistry and monitoring — standard SRB culture tests (run at 30–35°C) will not detect SRA that only grow at 60–90°C. Monitoring must include thermophilic SRB/SRA culture protocols.

Why SRB Matters in Oil and Gas

Sulfate-reducing bacteria are one of the most economically damaging microorganisms in the global oil and gas industry. Reservoir souring — the conversion of sweet fields to sour gas producers through SRB activity — has added hundreds of millions of dollars of processing, material, and operational costs to North Sea, Gulf of Mexico, and Middle East seawater-injection fields. MIC from SRB has caused pipeline failures, production outages, and liability events across every producing basin. Understanding SRB biology, monitoring SRB populations systematically, and implementing souring control programmes before the first H₂S breakthrough (not after) is the difference between managing a known risk and responding to an expensive, long-term production problem.