Biogas desulphurisation can be done inside the digester (precipitating sulphides with iron salts or using conductive nanoparticles) or downstream, in the gas line (impregnated activated carbon, biofilters, chemical scrubbers). The correct technical decision is not choosing one or the other: it is understanding which fits your plant’s H2S regime, the engine or biomethane-grid specification, and the total 5-year cost. This article describes the four main methods, their operating ranges, the thresholds that trigger each one and an operational case with real numbers.
Biogas desulphurisation is one of the most important hidden costs in plants with sulphur-rich substrates, and at the same time it is one of the processes where the most poorly made default technical decisions are seen: the plant inherited one system or another from the original engineering, and no one questioned again whether it was still the right one when the digester diet changed.
The problem is not that H2S is hard to remove. The problem is that there are four reasonable technologies, each with its operating range, its OPEX cost and its Achilles heel, and the economic difference between the right option and the wrong one can mean exceeding €40,000 a year in a medium-sized plant.
This article describes the four main methods (iron salts in the digester, activated carbon, biofilters, scrubbers), the operating thresholds that trigger each one, the H2S specifications required by cogeneration and the biomethane grid, and a simple protocol to decide which fits your plant.
Why H2S is the silent enemy of biogas
Hydrogen sulphide (H2S) is the natural by-product of anaerobic digestion when the substrate contains sulphur. And almost all common substrates contain sulphur.
Proteins contain cysteine and methionine (sulphur-bearing amino acids). Slurry carries sulphates from the animal diet. Industrial wastewater can bring sulphates at high concentrations. The sulphate-reducing bacteria (SRB) present in the anaerobic consortium reduce that sulphur to sulphide, part of which leaves as gas in the biogas.
The typical H2S ranges by substrate are as follows:
| Substrate | Typical H2S in biogas | Main cause |
|---|---|---|
| Pig slurry | 800-3,500 ppmv | Dietary sulphate + cysteine/methionine |
| WWTP sludge | 200-1,200 ppmv | Water with industrial sulphates upstream |
| Fruit and vegetable waste | 50-300 ppmv | Low sulphur input |
| Vinasse | 2,000-6,000 ppmv | Sulphates from the sugar process |
| Balanced agro-industrial co-digestion | 300-1,500 ppmv | Attenuated mix |
H2S has three operational impacts that accumulate at the same time:
- Accelerated corrosion in cogeneration engines, pipes, heat exchangers and the flare. The sulphide combines with the combustion water to form sulphuric acid that attacks lubricating oils and metal surfaces.
- Intra-digester inhibition when the dissolved sulphides in the digestate exceed 200 mg S/L: methanogenesis slows down without explicit decoupling and specific productivity drops by 8-15%.
- Regulatory non-compliance for biomethane injection into the grid. EN 16723-1 (natural gas) sets a maximum of 5 mg S/m³ of total sulphur (equivalent to ≈3.3 ppmv H2S).
Desulphurisation in the digester: iron salts and nanoparticles
The oldest and most economical strategy in the sector is to attack the problem before it forms: precipitate the sulphides inside the digester so they don’t leave in the gas phase. Three approaches work.
Ferric chloride (FeCl3) and ferrous chloride (FeCl2)
Iron salts dissolved in water that are dosed into the digester. The Fe²⁺ or Fe³⁺ reacts with the sulphide forming insoluble iron sulphide (FeS), which precipitates and leaves with the digestate. The typical dose is 0.5 to 2 mg of Fe per mg of expected S to remove.
Advantages: cheap (≈€0.3-0.6/kg FeCl3), it reduces H2S in biogas by between 40 and 70%, and it simultaneously reduces dissolved sulphides below the intra-digester inhibition threshold.
Limitations: the salt adds chlorides to the digestate (an agronomic problem if it exceeds 4-6 g Cl/L), it corrodes equipment if the dosing is not well designed, and the effective dose varies greatly with the digester diet (it requires quarterly recalibration).
Zero-valent iron (Fe⁰) and encapsulated iron nanoparticles
A more recent approach: introduce iron in reduced metallic form, not as a dissolved salt. The mechanism combines sulphide precipitation with an additional effect on direct interspecies electron transfer (DIET) in the methanogenic consortium.
Iron nanoparticles encapsulated in a carbonaceous matrix (Smallops proprietary technology) are a variant where the Fe⁰ is protected against premature oxidation and released in a controlled way in the digester. Operational efficacy data measured at an industrial plant: 99% H2S removal in biogas when dosed at 2-3 kg/t VS.
Advantages: very high H2S removal, no chloride input, and a favourable secondary effect on methanogenic kinetics via DIET.
Limitations: a higher cost per kg than iron salts. The decision to apply nanoparticles must go through the additives protocol that filters when it pays off versus a conventional salt.
Desulphurisation in the gas line: activated carbon, biofilters, scrubbers
The complementary strategy, and in most cases a necessary one, is to let the H2S form and remove it afterwards, on the biogas’s way to the engine or the upgrading unit. Three technologies cover the market.
Impregnated activated carbon
The biogas passes through a bed of activated carbon treated with salts (typically KI, KOH or KMnO4) that catalyse the oxidation of H2S to elemental sulphur, which is retained in the carbon’s pores.
Typical operating capacity: 0.15 to 0.40 g of S per g of activated carbon, depending on the brand and the regime.
Advantages: a very mature technology, low CAPEX, effective removal down to fine polishing (<5 ppmv), ideal as a final stage before cogeneration or biomethane.
Limitations: the carbon saturates and must be replaced or regenerated periodically. OPEX shoots up when the inlet H2S concentration exceeds 500-800 ppmv: the bed saturates in weeks and the replacement cost becomes prohibitive.
Biofilters (biological desulphurisation)
A biological support bed colonised by sulphide-oxidising bacteria (typically Thiobacillus) that oxidise the H2S to elemental sulphur or sulphate in the controlled presence of oxygen (micro-aeration at 2-6%).
Advantages: very low OPEX (the bacteria are not “consumed”), 80-95% efficacy in slurry and WWTP biogas. Suitable for medium H2S concentrations (500-3,000 ppmv) in continuous flows.
Limitations: it requires control of the micro-aeration (excess oxygen kills bacteria or is explosive), it does not reach the fine polishing that the biomethane grid demands (it usually leaves 50-150 ppmv residual), and it has an initial acclimation time of 4-8 weeks.
Chemical scrubbers (washing with NaOH or chelated Fe)
The biogas is washed in an absorption column with a reactive liquid that captures the H2S. The two most widespread variants are washing with caustic soda (NaOH) and the chelated-iron system (Fe-EDTA or Fe-NTA).
Advantages: high efficacy (>99%) and it can handle very high H2S concentrations (up to 10,000 ppmv). The chelated-Fe system is regenerable: the sulphur is recovered as a sellable by-product.
Limitations: high CAPEX, OPEX dependent on reagent consumption (NaOH) or regeneration energy (chelated Fe). A technology that only pays off in large plants with very high H2S.
How to choose: digester vs gas line decision matrix
The correct question is not “which technology is best”. It is: “which technology is the right one for my H2S regime, my biogas destination and my economic horizon”. This matrix summarises the most efficient combination for the four typical scenarios.
| Scenario | H2S in biogas | Biogas destination | Recommended combination |
|---|---|---|---|
| Low and stable | <500 ppmv | Cogeneration | Activated carbon in the line only |
| Medium | 500-1,500 ppmv | Cogeneration | Fe in the digester + polishing activated carbon |
| High | 1,500-3,500 ppmv | Cogeneration | Fe in the digester + biofilter |
| Any | Any | Biomethane grid | Dual treatment: digester + scrubber + final carbon |
In plants that treat slurry biogas, the usual scenario is “high” or “medium”. In plants that produce biogas at WWTPs, it is typically “low” or “medium”. And when the destination is the biomethane grid, the decision is no longer “one or the other” but “all at once” because the regulatory limit of 5 mg S/m³ is not reached with a single stage.
H2S specifications for cogeneration and biomethane
The two biogas valorisation routes impose very different thresholds of allowable H2S. Designing the desulphurisation without knowing the exact threshold is the main cause of cost overruns in this area.
Cogeneration with an internal combustion engine
The allowable threshold varies with the engine manufacturer, but a conservative operating range is <250 ppmv at the inlet to keep warranties, and <100 ppmv to maximise the service life of the lubricating oil and the internal components.
Operating above 250 ppmv reduces the oil-change intervals from the standard 1,500-2,000 hours to 800-1,000 hours, which translates into approximately €12,000-18,000 extra a year in a 500 kWe plant in oil and labour alone. In the medium term, the real cost is the loss of operating hours through premature wear.
Injection into the biomethane grid (EN 16723)
The European standard EN 16723-1 (biomethane for the natural gas grid) sets a maximum of 5 mg S/m³ of total sulphur, equivalent to ≈3.3 ppmv of H2S. It is an order of magnitude stricter than cogeneration.
This threshold is only reached with fine polishing treatment, typically high-quality activated carbon or a regenerable chemical scrubber. Any plant considering the jump to biomethane must redesign its desulphurisation line: cogeneration solutions are rarely sufficient.
Operational case: 800 kWe plant with pig slurry and vinasse
An 800 kWe cogeneration plant (mesophilic 38 °C), mixed diet: 60% pig slurry, 25% local vinasse, 15% maize silage.
Initial symptom. Average H2S in biogas 2,800 ppmv (high zone due to the slurry + vinasse combination). Inherited system: activated carbon in the line only, with an annual consumption of 9 tonnes at €2.1/kg → desulphurisation OPEX cost: €18,900 a year in carbon alone.
In addition: engine oil changes every 900 hours (vs 1,800 nominal), additional oil and labour spending +€14,500 a year. Total cost attributable to suboptimal desulphurisation: €33,400/year.
Operational Excellence Diagnosis
The analytical characterisation identified that the vinasse contributed 70% of the system’s total sulphur (high sulphate content from the sugar process). The methanogenic consortium was also operating with dissolved sulphides around 240 mg S/L, in an incipient inhibition zone. Historical specific productivity: 0.31 Nm³ CH4/kg VS (≈10% below the diet’s theoretical potential).
Technical intervention
Two coordinated changes.
One: incorporate desulphurisation in the digester with encapsulated iron dosing at 2.5 kg/t VS. A dual mechanism: sulphide precipitation (reduces the biogas H2S) + DIET effect on methanogenesis (recovers productivity).
Two: keep activated carbon in the line as a final polishing stage, not as the main mechanism. Reducing the load on the carbon extends its service life 3x.
Result at 6 months
Consolidated results at 6 months
H2S in biogas: 2,800 → 28 ppmv (–99%)
Dissolved sulphides in digestate: 240 → 95 mg S/L (stable zone)
Specific productivity recovered: 0.31 → 0.35 Nm³ CH4/kg VS (+13%)
Activated carbon consumption: 9 → 3 tonnes/year (–67%)
Engine oil-change interval: 900 → 1,700 hours
Attributable net annual saving: ≈ €26,000 direct + extra methane production through stabilisation
Frequently asked questions about biogas desulphurisation
Is it better to desulphurise in the digester or in the gas line?
It depends on the H2S regime and the biogas destination. For concentrations below 500 ppmv and cogeneration, activated carbon in the line is the most efficient option. For medium and high concentrations (>500 ppmv), combining digester desulphurisation (iron salts or Fe nanoparticles) with a subsequent polishing is more economical over 5 years. For biomethane injection into the grid, practically all plants need combined treatment because of the regulatory requirements (≈3.3 ppmv maximum).
How does H2S affect the cogeneration engine?
H2S in biogas is transformed during combustion into sulphuric acid that contaminates the lubricating oil and accelerates the corrosion of internal components. Operating above 250 ppmv at the inlet reduces the oil-change interval from 1,500-2,000 hours to 800-1,000 hours, with an additional cost of approximately €12,000-18,000 a year in a 500 kWe plant. In the long term, it also reduces the engine’s service life.
What is the correct FeCl3 dose for desulphurisation?
The typical dose of ferric chloride (FeCl3) is 0.5 to 2 mg of Fe per mg of expected S to remove. The exact dose depends on the digester pH (it affects the fraction of dissolved vs gaseous sulphide), the phosphate concentration (it competes for the Fe³⁺) and the real sulphur regime. A quarterly analytical characterisation is the minimum practice for the dose to remain efficient and not translate into reagent cost overruns or excess chlorides in the digestate.
What H2S specification does the biomethane grid require?
The European standard EN 16723-1, which regulates biomethane for injection into the natural gas grid, sets a maximum of 5 mg/m³ of total sulphur, equivalent to approximately 3.3 ppmv of H2S. It is a much stricter threshold than that of cogeneration (250 ppmv) and is only reached with fine polishing treatment: high-quality activated carbon or a regenerable chemical scrubber. Any plant considering the jump to biomethane must redesign its desulphurisation line from scratch.
Is your desulphurisation sized for your plant’s current diet?
A poor desulphurisation strategy costs between €20,000 and €40,000 a year in medium-sized plants. Request a Smallops Operational Excellence Diagnosis: we characterise the real H2S regime, calculate the total 5-year cost and propose the most efficient digester-line combination for your case.
References and standards
EN 16723-1:2016. Natural gas and biomethane for use in transport and biomethane for injection in the natural gas network.
Wellinger, A. & Lindberg, A. (2005). Biogas Upgrading and Utilisation. IEA Bioenergy Task 24. ieabioenergy.com/wp-content/uploads/2001/12/Biogas-upgrading.pdf
Zicari, S.M. (2003). Removal of Hydrogen Sulfide from Biogas using Cow-manure Compost. Cornell University. ecommons.cornell.edu/handle/1813/8782
Khoshnevisan, B. et al. (2017). A critical review on livestock manure biorefinery technologies. Renewable and Sustainable Energy Reviews, 135, 110033. doi.org/10.1016/j.rser.2020.110033