What is the difference between PSA and membrane biogas upgrading?

PSA (Pressure Swing Adsorption) is a cyclic process — biogas flows through adsorbent beds at 6–10 bar, CO₂ adsorbs preferentially, then beds depressurize to release captured CO₂. Membrane is a continuous process — biogas flows past selective polymer membranes at 8–12 bar, CO₂ permeates through faster than CH₄. PSA: lower OPEX ($0.50–1.50/MMBtu), 92–98% CH₄ recovery, 6-bed standard. Membrane: higher OPEX ($5–10/MMBtu, membrane replacement dominant), 95–99.5% recovery, lower CH₄ slip preferred for LCFS projects.

Why is methane slip the main CARB LCFS driver?

Methane slip = (1 − η_recovery) × CH₄_feed. The slip CH₄ ends up in off-gas which must be flared (95% combustion efficiency), oxidized in an RTO (99.5% CE), or used as engine fuel. Whatever doesn't combust vents to atmosphere as fugitive CH₄ with GWP 25 (CARB AR4) — making it a major term in pathway carbon intensity. A 2% slip on a 200 scfm × 60% CH₄ biogas feed at 95% flare CE produces ~5 t CH₄/yr atmospheric → ~125 t CO₂e/yr → ~5–10 gCO₂e/MJ CI penalty.

Which upgrading technology gives the best methane recovery?

By technology: water scrubbing 96–99% recovery (limited by physical solubility), PSA 92–98% (varies by bed count: 2-bed 80% / 4-bed 93% / 6-bed 96.5% / 8-bed 98.5%), membrane 88–99.5% (single-stage 90% / two-stage with recycle 97% / three-stage with recycle 99.5% — Evonik SEPURAN G5X claims 99.8%), amine 99.5–99.9% (chemical solvent has highest recovery). For LCFS-critical dairy projects, 3-stage membrane or amine is preferred despite cost premium.

What is the typical pipeline RNG specification?

Most US interstate pipeline tariffs require ≥96% CH₄ with ≤4% combined inerts (CO₂ + N₂), ≤0.5% O₂, ≤4 ppmv H₂S, water dew point ≤−10°F, Wobbe Index 1300–1400 BTU/scf. SoCalGas Rule 30 (the dominant California biomethane tariff) requires CH₄ ≥96.5% with Wobbe 1290–1385 and total siloxane ≤0.1 mg Si/m³. Note: pure RNG (96–99% CH₄) often has Wobbe at or below pipeline minimum because pure CH₄ has lower volumetric HHV than typical pipeline NG with C₂+; blending or propane enrichment may be required.

What is compression power required for biogas upgrading?

Industry-typical biogas upgrading compression power is 0.20–0.30 kWh per Nm³ of biogas feed (covers compressor + intercooler + instrument air + cooling water + controls). PSA at 100 psig (~7 bar) tends to the lower end; membrane at 130 psig (~9 bar) tends to the higher end. For a typical 200 scfm dairy biogas project, this works out to ~70–100 kW continuous → ~570–870 MWh/yr → ~$45,000–70,000/yr at $0.08/kWh.

CO₂ Removal Upgrading Fundamentals

1. Overview: From 60% CH₄ to ≥96% CH₄

After cleanup removes H₂S, siloxanes, moisture, and VOCs, the remaining job is bulk CO₂ removal — taking biogas from ~60% CH₄ / ~40% CO₂ to pipeline-spec ≥96% CH₄. Four technologies dominate the market, each with a distinct economic/recovery profile.

Technology	Typical CH₄ recovery	Typical CH₄ slip	OPEX ($/MMBtu)	Best fit
PSA (Pressure Swing Adsorption)	92–98%	2–8%	$0.50–1.50	Mid-size projects, opex-driven economics
Membrane (polymer)	88–99.5% (config-dependent)	0.5–10%	$5–10	LCFS-critical, slip-sensitive projects
Amine (MEA, MDEA, K₂CO₃)	99.5–99.9%	0.1–0.5%	$3–8	Large plants, ≥10 MMscfd, lowest slip
Water scrubbing	96–99%	1–4%	$2–4	Wet feedstock, Europe-typical, simple

The big tradeoff: PSA wins on OPEX per MMBtu (lowest among the four for projects below ~10 MMscfd). Membrane wins on LCFS pathway CI (lower slip → fewer fugitive CO₂e tonnes → more LCFS credits). For dairy/landfill RNG projects where avoided-baseline methane credit dominates revenue, the CI benefit can easily outweigh the OPEX penalty — a 1% slip reduction ≈ 3–5 gCO₂e/MJ pathway CI improvement ≈ $200–500k/yr extra LCFS revenue at typical credit price.

2. PSA (Pressure Swing Adsorption)

PSA exploits the differential affinity of CO₂ vs CH₄ for adsorbents — CO₂ adsorbs strongly at high pressure (6–10 bar), then desorbs when pressure is dropped. A typical PSA cycle:

1. ADSORPTION (4 min) — feed at 100 psig through bed; CO₂ adsorbs, CH₄ passes through (product) 2. PRESSURE EQUALIZATION — connect to depressurizing bed to recover product-side CH₄ 3. BLOWDOWN — depressurize to ~1 bar; CO₂ + some slip CH₄ released to off-gas 4. PURGE — flow product gas backwards through bed at low P to remove residual CO₂ 5. PRESSURE EQUALIZATION — accept product from another bed to start re-pressurization 6. RE-PRESSURIZATION — bring bed back to 100 psig with product gas Total cycle = N_beds × t_ads_step. Synchronous: one bed always in adsorption.

Adsorbent options

Adsorbent	Working cap (kg CO₂/kg)	Bulk density (kg/m³)	Notes
CMS (carbon molecular sieve)	0.10	650	Biogas industry standard; fast kinetics
13X zeolite (NaX)	0.15	720	Higher capacity but moisture-sensitive (per Cavenati 2004)
4A zeolite	0.08	750	Smaller pore; niche use
Activated carbon	0.12	500	Lower selectivity, less common for biogas

Bed-count configuration drives CH₄ recovery

Configuration	CH₄ recovery	Notes
2-bed (legacy)	75–85%	Single pressure equalization; high slip
4-bed + 1 PE	90–95%	Mid-tier; legacy mid-2000s installations
6-bed + 2 PE	95–98%	Modern RNG industry default
8-bed + 3 PE	98–99.5%	Premium; vehicle-grade or LCFS-critical projects

PSA sizing

M_bed = (CO₂_load_per_min × t_ads_step) / Working_capacity CO₂_load = Q × x_CO₂ × ρ_CO₂ (ρ_CO₂ = 1.964 kg/Nm³ at 0°C/1 bar) V_bed = M_bed / ρ_bulk L/D ≈ 3 (taller than scavenger beds for cycle dynamics) Methane slip: CH₄_slip = (1 − η_recovery) × CH₄_feed CO₂e_slip = CH₄_slip_kg × (1 − CE_offgas) × GWP_CH4 where CE_offgas: flare 0.95, RTO 0.995, RNG engine 0.985, vent 0.0

3. Membrane (Polymer Hollow-Fiber)

Polymer membrane systems use selective hollow-fiber membranes that pass CO₂ faster than CH₄. Continuous operation (no cycling) and modular design. Two major industry vendors: Evonik (SEPURAN / SEPURAN G5X) and Air Liquide (MEDAL).

Permeance / selectivity by polymer type

Polymer	CO₂ permeance (GPU)	α (CO₂/CH₄)	Notes
Polyimide (Evonik SEPURAN / Air Liquide MEDAL)	100	30	Industry workhorse
Advanced polyimide (SEPURAN G5X premium)	130	50	Higher selectivity → lower slip
Cellulose acetate (Cynara/UOP legacy)	60	30	Older technology; CO₂/CH₄ separation
Polysulfone (Permea/Prism legacy)	8	20	Low capacity; mostly historical

The unit GPU = 1 × 10⁻⁶ cm³(STP)/(cm²·s·cmHg) = 3.348 × 10⁻¹⁰ mol/(m²·s·Pa). At 100 GPU CO₂ permeance with 6 bar partial-pressure differential, flux ≈ 13 Nm³ CO₂/(m²·day) — but real systems achieve ~30–60% of this due to negative driving force at the retentate end.

Multi-stage configuration

Configuration	CH₄ recovery	Specific area (m²/(Nm³/h biogas))
Single-stage	88–92%	30
Two-stage + permeate recycle	95–98%	55
Three-stage + recycle (premium)	99–99.5% (Evonik G5X 99.8%)	90

Why multi-stage is mandatory above ~95% purity

Single-stage membrane has negative CO₂ driving force at the retentate end of high-purity operation — i.e., the CO₂ partial pressure on the feed side becomes lower than on the permeate side, so CO₂ would back-permeate from permeate to retentate. This makes pure single-stage operation impossible above ~92% CH₄ product purity. The fix is multi-stage with permeate recycle: stage 1 makes a coarse separation, stage 2 polishes the retentate to pipeline spec, and the stage-2 permeate (CH₄-rich) gets recycled back to the feed compressor.

Sizing — empirical specific area

A = A_base × stage_factor × (100/perm_GPU) × (30/α)^0.5 × (9 bar/P_feed) A_base for polyimide 100 GPU / α=30 / 9 bar feed: Single-stage: 30 m²/(Nm³/h biogas) Two-stage: 55 Three-stage: 90 Corrections scale linearly (permeance, pressure) or sqrt (selectivity).

This is screening-grade empirical sizing — for FID, vendor performs module-by-module integration using Aspen HYSYS or vendor-proprietary tools (ChemCAD, gPROMS).

4. Amine Absorption (MEA, MDEA, K₂CO₃)

Amine absorption is the dominant CO₂ removal technology for large gas-processing plants (≥10 MMscfd) and is gaining share in larger biogas/RNG projects. CO₂ is chemically absorbed into a circulating aqueous amine solution, then stripped via reboiler at lower pressure.

Amine solvent options

Solvent	CO₂ loading (mol CO₂/mol amine)	Reboiler duty (GJ/t CO₂)	Notes
MEA (monoethanolamine, 15–30%)	0.4	3.5–4.0	High capacity, high regen energy, degradation issues
MDEA (methyldiethanolamine, 40–50%)	0.3	2.5–3.0	Lower regen energy; H₂S co-selective in some formulations
aMDEA (activated MDEA)	0.5	2.5–3.0	BASF; CO₂ selective vs H₂S — common for biogas
Hot K₂CO₃ (Benfield)	0.3	4.0–4.5	Mature technology; lower amine degradation

Amine plant flow

Raw biogas → Absorber (40°C, 6–8 bar) → Rich amine → Cross HX → Stripper (110–125°C, 1.5 bar) → Lean amine → Cross HX → Absorber Absorber: CO₂ + amine → carbamate (chemical reaction; high selectivity) Stripper: reverse reaction with heat input (regen) → CO₂ off-gas + regenerated amine

Advantages and disadvantages for biogas service

Pros	Cons
Highest CH₄ recovery (99.5–99.9%) — best for LCFS	High capex ($8–15M per MMscfd for small biogas plants)
Lowest methane slip (0.1–0.5%)	Reboiler steam/gas duty significant OPEX
Robust to feed-rate swings	Amine degradation requires reclamation (annual)
Handles H₂S residuals well (aMDEA selective)	Stripper off-gas is wet CO₂ at low pressure
Mature, well-understood technology	Larger plant footprint than PSA / membrane

Amine economics break-even relative to PSA/membrane somewhere above ~5 MMscfd biogas feed. Below that scale, PSA dominates on opex/capex; above ~20 MMscfd, amine becomes competitive on recovery alone.

5. Water Scrubbing (Physical Absorption)

Water scrubbing is the simplest CO₂ removal technology — pump biogas up a packed tower while water flows down. CO₂ dissolves in water much more readily than CH₄ (Henry's Law constants ~25× different), so the bottoms-out water carries most of the CO₂ away while CH₄ leaves the top.

Henry's Law basis

H_CO₂ at 10°C, 1 atm: ~1500 mg/L (high solubility) H_CH₄ at 10°C, 1 atm: ~30 mg/L (low solubility) Selectivity: H_CO₂ / H_CH₄ ≈ 50 Absorber typically at 6–10 bar, 5–15°C Stripper / flash regen at 1 bar (gas dissolved out by depressurization)

Pros and cons

Pros	Cons
Simplest technology; non-toxic solvent	Lower CH₄ recovery than amine (96–99%)
No chemical degradation; reclamation simple	Higher water circulation rate (significant pump power)
Co-removes H₂S — eliminates dedicated scavenger	Off-gas (regen) wet and at low pressure
Mature in European biogas market	Less established in US (PSA / membrane dominate)
Insensitive to feed composition swings	Sensitive to feed temperature

Water scrubbing is the dominant European biogas-upgrading technology (especially Sweden, Germany, Netherlands) but a minority US technology. It tends to suit landfill or food-waste projects with high H₂S where the co-removal of H₂S in the water cycle eliminates a dedicated scavenger train.

6. Comparison Summary & Decision Guide

Performance comparison (200 scfm dairy, 60% CH₄ baseline)

Metric	PSA (6-bed CMS)	Membrane (2-stage PI)	Amine (aMDEA)	Water scrub
CH₄ recovery	96.5%	97%	99.7%	97%
CH₄ slip (kg/d)	123	105	11	105
CO₂e from slip (t/yr at flare)	67	57	6	57
Compression power (kWh/Nm³)	0.19	0.22	0.30 (incl reboiler)	0.25
OPEX ($/MMBtu)	$0.76	$7.66 (membrane replacement)	$4–6	$2–3
CAPEX intensity (relative)	1.0×	1.5×	2.5×	1.3×
Best fit feedstock	WWTP, mid-LFG	Dairy / LCFS-critical	Large LFG (≥10 MMscfd)	European biogas mkt

Decision guide

Project profile	Recommended upgrading technology
Dairy RNG, CARB LCFS-eligible	3-stage membrane (lowest slip) OR amine
Landfill RNG, <5 MMscfd	6-bed PSA (best $/MMBtu)
Landfill RNG, >10 MMscfd	Amine (highest recovery at scale)
WWTP digester RNG	PSA (well-matched to flow scale)
Food waste RNG with high H₂S	Water scrubbing (co-removes H₂S) OR membrane with upstream scavenger
Vehicle-grade CNG (97%+ purity)	8-bed PSA OR amine

Methane slip CO₂e impact (the LCFS lever)

For a 200 scfm dairy with 60% CH₄, the CO₂e slip varies dramatically by configuration:

GWP convention: CO₂e column uses IPCC AR6 GWP_CH₄ = 29.8 (engineering accounting). The LCFS-CI impact column converts to CARB AR4 GWP_CH₄ = 25 per §95488 (multiply CO₂e column by 25/29.8 = 0.84 if recomputing LCFS pathway CI from this table).

Configuration	CH₄ to atmosphere	CO₂e/yr (AR6 GWP=29.8)	LCFS-CI impact (AR4 GWP=25)
2-bed PSA 80% recovery + vent	256 t/yr	~7,630 t	−15 gCO₂e/MJ pathway penalty
6-bed PSA 96.5% + flare (CE 95%)	2.2 t/yr	67 t	−2 gCO₂e/MJ
3-stage membrane 99.5% + RTO (CE 99.5%)	0.06 t/yr	2 t	−0.05 gCO₂e/MJ
Amine 99.7% + flare	0.6 t/yr	17 t	−0.4 gCO₂e/MJ

The 4,000× spread between best and worst configurations explains why modern dairy RNG projects converge on premium configurations (3-stage membrane + RTO, or amine + flare with continuous CE monitoring) despite the OPEX premium.

7. Standards & References

Yang R.T. "Adsorbents: Fundamentals and Applications" (Wiley 2003, ISBN 978-0471297413)
Ruthven, Farooq, Knaebel "Pressure Swing Adsorption" (VCH 1994, ISBN 978-0471188186)
Baker R.W. "Membrane Technology and Applications" 3e (Wiley 2012, ISBN 978-0470743720)
GPSA Engineering Data Book 14e (2017) §17 (Adsorption) + §21 (Sulfur Recovery)
Cavenati, Grande & Rodrigues (2004) — "Adsorption equilibrium of methane, CO₂ and N₂ on zeolite 13X" J. Chem. Eng. Data 49:1095–1101
Santos, Grande & Rodrigues (2011) — 4A vs 13X for landfill biogas Energy 36:314–319
Augelletti et al. (2017) — biogas PSA parametric sensitivity J. Cleaner Prod. 140:1390
Scholz et al. (2013) — biogas membrane process design RSC Adv. 3:13443
Robeson (2008) — α/permeance upper-bound tradeoff J. Membr. Sci. 320:390
Evonik SEPURAN Green / SEPURAN G5X product literature
Air Liquide Advanced Separations / MEDAL technical literature
40 CFR 80.1426 (RFS2 D3 RIN pathway feedstock criteria)
40 CFR 98 Subpart W §98.236 (GHGRP equipment leak measurement)
CARB LCFS Regulation 17 CCR §95488 — methane-slip pathway CI accounting
SoCalGas Rule 30 / SDG&E / PG&E biomethane gas-quality tariffs
IPCC AR6 — CH₄ GWP100 = 29.8 (CARB LCFS uses AR4 = 25)

CO₂ Removal Upgrading: PSA vs Membrane vs Amine vs Water Scrubbing