1. Overview: Why cleanup matters before upgrading
Raw biogas leaves a digester or landfill at 45–65% CH₄ with a long list of trace contaminants that would foul, corrode, or poison downstream upgrading equipment if not removed first. The cleanup train sits between the biogas source and the CO₂-removal upgrader:
| Contaminant | Typical raw level | Downstream spec | Why it matters |
|---|---|---|---|
| H₂S | 100–5,000 ppmv | ≤4 ppmv (pipeline) / ≤0.1 (fuel cell) | Corrosion, OSHA Health, poisons most CO₂-removal media |
| Siloxanes | 5–50 mg Si/m³ (LFG) | ≤0.1 mg Si/m³ (pipeline RNG) / ≤0.01 (SOFC) | SiO₂ deposition on engines, turbines, fuel-injectors |
| Water vapor | Saturated (~100% RH) | Pipeline dew point ≤ −10°F | Liquid drop-out, hydrate formation, corrosion with H₂S |
| VOCs (BTEX, halocarbons) | 10–500 ppmv (LFG) | Variable by use | Engine fouling, exhaust toxicity, GAC poisoning |
| O₂ (air ingress) | 0.1–2% | ≤0.2–1% pipeline | Corrosion in pipeline, regulatory rejection at injection |
| NH₃ | 50–500 ppmv (dairy/food) | Variable | NOx formation in combustion, fuel-cell poisoning |
2. H₂S Removal: Dry Iron-Oxide Scavengers
Dry-bed iron-oxide scavengers are the dominant H₂S removal technology for biogas projects below ~10 MMscfd. Above that scale, liquid redox (LO-CAT) or biological scavengers (Thiopaq) become competitive. This section covers the dry-bed approach used in calc RNG-04.
Chemistry — irreversible Fe-S conversion
Industry scavenger media comparison
| Media | Capacity (kg H₂S/kg) | Bulk density (kg/m³) | $/kg media | Notes |
|---|---|---|---|---|
| Iron sponge (Fe₂O₃ on wood chip) | 0.20 | 720 | $1.50 | Classical; needs saturated gas + O₂ slip for regen |
| SulfaTreat (SLB iron-oxide on clay) | 0.18 | 880 | $4.00 | Non-pyrophoric, easier change-out vs iron sponge |
| SulfaTrap (Crystatech Fe/Zn oxide) | 0.30 | 850 | $5.00 | Higher capacity; newer formulation |
| Enhanced iron sponge (MV Tech BAM) | 0.28 | 800 | $2.50 | Vendor claim 13 lb H₂S/ft³; verify on actual biogas |
All vendor capacities are 2024–26 industry-screening order-of-magnitude. Real-biogas breakthrough tests routinely vary ±30% from vendor literature due to moisture, channeling, vendor lot variation. For FID-grade procurement, run a vendor pilot on actual biogas.
Sizing equation
EBCT and superficial velocity targets
| Parameter | Target range (Waineo 2019, GPSA §21) | What goes wrong outside range |
|---|---|---|
| EBCT | 60–300 s | <60: incomplete reaction; >300: oversized bed (capex penalty) |
| Superficial velocity | 5–10 ft/min | <5: bed under-utilized; >10: channeling, ΔP, breakthrough |
| L/D ratio | 1.5–4 | <1.5: channeling risk; >4: high ΔP |
| Pressure drop | 1–10 psi typical | >10: review bed geometry or parallel beds |
Lead-lag vs single-bed configuration
Modern biogas H₂S systems are nearly always configured as lead-lag (two beds in series). The lead bed receives raw gas; when it breaks through, it is changed out and the previous lag bed becomes the new lead. This provides continuous H₂S removal even during change-outs and uses media more efficiently — only the lead bed is consumed each cycle.
Iron-sponge regeneration in practice
In theory, iron sponge can be regenerated in situ by oxidation: 2 Fe₂S₃ + 3 O₂ → 2 Fe₂O₃ + 6 S. This forms elemental sulfur on the wood chips and restores some capacity. In practice:
- Regeneration requires 0.05–0.5% O₂ slip in feed gas, which closed-digester biogas (sealed system) does not contain.
- Adding air for regen is hazardous (creates explosive atmosphere downstream if not perfectly managed).
- Each regen cycle reduces effective capacity ~30%; after 2 regenerations, capacity is depleted.
- Result: most biogas iron-sponge installations run once-through (no regen) — losing the cost advantage that LFG/upstream installations enjoy.
Size an H₂S scavenger bed for your biogas
→ RNG-04: H₂S Scavenger Bed Sizing3. Siloxane Removal: GAC Adsorption
Cyclic (D3, D4, D5, D6) and linear (L2-L5) siloxanes are the second mandatory cleanup step for landfill-gas RNG and a precautionary step for WWTP/food-waste RNG. Coal-based GAC is the workhorse adsorbent; silica gel offers regenerability at higher capex.
Specifications by downstream use
| Application | Si limit (mg Si/m³) | Notes |
|---|---|---|
| Pipeline RNG (SoCalGas Rule 30) | 0.1 | Total siloxane silicon basis |
| IC engine (typical mfr) | 5–15 | Per engine manufacturer warranty |
| Capstone microturbine | 0.03 | SiO₂ deposition on turbine blade |
| Solid Oxide Fuel Cell (SOFC) | 0.01 | Catalyst poisoning |
| Boiler / direct combustion | 50 | Low sensitivity; periodic tube cleaning |
Why silicon basis (not "total siloxane")
Specifications are written in mg Si/m³ because SiO₂ deposition is the failure mode, and the silicon mass fraction varies by siloxane species:
| Siloxane species | MW (g/mol) | Si mass fraction |
|---|---|---|
| D3 (hexamethylcyclotrisiloxane) | 222.5 | 0.379 |
| D4 (octamethylcyclotetrasiloxane) | 296.6 | 0.379 |
| D5 (decamethylcyclopentasiloxane) | 370.8 | 0.379 |
| L2 (hexamethyldisiloxane) | 162.4 | 0.346 |
| L3 (octamethyltrisiloxane) | 236.5 | 0.356 |
Typical landfill-gas siloxane mix is ~70% D5 + 20% D4 + 10% L2-L5, with weighted Si fraction ~0.37–0.38. The conversion: mg total siloxane × 0.37 ≈ mg Si.
GAC adsorbent capacities (real biogas)
| Adsorbent | Capacity (kg Si/kg) | Bulk density (kg/m³) | Notes |
|---|---|---|---|
| Coal-based GAC (industry typical) | 0.08 | 500 | Mesopore-rich, best for D5; workhorse |
| Coconut-shell GAC | 0.05 | 480 | Micropore-dominant, less effective for D5 |
| Wood-chemically-activated GAC | 0.15 | 350 | High-performance; vendor premium |
| Impregnated GAC (Cu/Ag) | 0.06 | 520 | Lower Si cap; supports combined H₂S co-removal |
| Silica gel (regenerable) | 0.10 | 720 | Regen at 200°C hot N₂; higher capex, lower opex |
Relative-humidity penalty
Water vapor competes with siloxanes for adsorption sites on GAC. Per Schweigkofler 2001, capacity falls linearly from 100% of dry value at RH ≤30% to 50% at RH 100%:
The practical implication: biogas must be chilled to ≤10°C and dehydrated to ≤30% RH before the siloxane bed. Without this, a 6-month design life shrinks to 3 months and CAPEX-per-MWh-equivalent doubles.
EBCT and configuration
Per Soreanu et al. 2011 (Renewable Energy 36:1535) and Cabot/Norit field data, GAC siloxane removal targets EBCT 60–300 s with superficial velocity 5–30 ft/min. Most installations use lead-lag for continuous service. Online breakthrough monitoring per ASTM D7833 or ASTM D8455 (or ISO 2613-2:2023) at the lag-bed outlet is standard practice for fuel-cell and microturbine applications.
Size a siloxane GAC bed for your biogas
→ RNG-05: Siloxane Removal Bed Sizing4. Moisture & VOC Removal
Raw biogas leaves the digester at 100% RH and the temperature of the digester (35–55°C). Cooling the gas condenses water, which simultaneously precipitates many of the VOCs. The condensate goes to plant drain or recycled-back-to-digester.
Glycol dehydration alternative
For biogas projects ≥ ~2 MMscfd, TEG (triethylene glycol) absorption towers achieve much deeper dew-point control than refrigeration alone. Pipeline-spec dew point of −10°F (or lower for cold climates) typically requires TEG.
| Dehydration method | Dew-point achieved | CAPEX scale | Best fit |
|---|---|---|---|
| Refrigeration chiller (4–10°C) | ~30–35°F (saturated at outlet) | Low | Pre-pretreatment for GAC; not pipeline-grade |
| Refrigeration + reheat | ~10–20°F | Low-medium | Engine fuel; moderate compression service |
| TEG glycol tower | −10 to −40°F | Medium-high | Pipeline injection; cold-climate gas |
| Molecular sieve (4A, 3A) | −40 to −150°F | High | LNG production; cryogenic processing downstream |
VOC removal — concurrent with other steps
Most VOCs (BTEX, halocarbons) are removed simultaneously with siloxane on activated carbon, since they share similar adsorption affinities. For applications sensitive to specific VOCs (e.g., halogenated compounds that produce HCl on combustion), a dedicated polishing carbon bed downstream of the siloxane bed is sometimes added.
Oxygen ingress control
Most pipeline tariffs limit O₂ to 0.2–1%. Sources of O₂ in biogas:
- Atmospheric leakage at landfill gas wellheads (especially with strong vacuum collection) — biggest issue for LFG projects.
- Air-stripping of dissolved O₂ in fresh manure/sludge feed — usually minor.
- Process air injection for iron-sponge regeneration — should be eliminated for pipeline-grade systems.
For LFG, well-head flow balancing to maintain slight positive pressure relative to atmosphere is the primary O₂ control. Catalytic O₂ removal (CatOx) using a Pd/Pt catalyst can knock 1–2% O₂ to ~0.1% but adds CAPEX, OPEX, and a heat-management headache.
5. Putting It Together: Typical Cleanup Trains
Landfill gas (high H₂S, high siloxane, moderate O₂)
Dairy biogas (high H₂S, very low siloxane, no O₂)
WWTP digester gas (moderate H₂S, low siloxane)
Food waste digester (very high H₂S, moderate siloxane, possible NH₃)
6. Standards & References
- GPSA Engineering Data Book 14e (2017) §21 (Sulfur Recovery) + §22 (Acid Gas Treating)
- American Biogas Council "H₂S Removal for Biogas" — Daniel Waineo P.E. (April 2019)
- Schlumberger / M-I SWACO SulfaTreat technical literature
- Crystatech / TDA Research SulfaTrap data sheets
- MV Technologies BAM enhanced iron sponge product data
- Schweigkofler, M. & Niessner, R. (2001) — "Removal of siloxanes in biogases" Environ. Sci. Technol. 35:3680–3685
- Soreanu, G. et al. (2011) — "Approaches concerning siloxane removal from biogas — A review" Renewable Energy 36:1535–1554
- ASTM D5504-20 — Total Sulfur in Gas by SCD
- ASTM D7833 — Siloxanes in landfill gas / digester gas via GC-MS
- ASTM D8455 (2022+) — Siloxane via solid-sorbent collection
- ISO 2613-2:2023 — Siloxane in biomethane
- EPA Landfill Methane Outreach Program (LMOP) technical guidance
- 49 CFR §192.624 / pipeline tariff H₂S spec (typical ≤ 4 ppmv interstate)
- SoCalGas Rule No. 30 — California biomethane pipeline gas-quality tariff
- 40 CFR 80.1426 — RFS2 D3/D5 RNG feedstock pathway criteria