Biogas Upgrading: Getting From Raw Gas to Biomethane

Legacy context

WaterSmart Environmental built its reputation on a simple observation: anaerobic digestion, for all its centuries of use, was treated as a natural curiosity rather than a precision engineering process. The firm’s heritage lies in pushing that biochemistry into a controlled, two-phase system—separating hydrolysis and acidogenesis from methanogenesis to stabilize what nature leaves to chance. That legacy of treating waste streams as a feedstock for predictable outputs—methane, biodiesel, and recovered water—mirrors the modern push toward cleaner, more efficient gas treatment.

Today, the conversation has shifted upstream. As digestion systems become more sophisticated, the raw biogas they produce is no longer the end product; it is an intermediate. The question is no longer simply how to generate methane, but how to refine it into a pipeline-grade resource. Biogas upgrading has emerged as the logical next step for operators who already understand the value of phase separation and controlled biology. The same mindset that drove WaterSmart’s fixed-film thermophilic design—maximizing yield through deliberate process control—now applies to scrubbing CO₂, removing trace contaminants, and conditioning gas for injection or vehicle fuel. The heritage of engineering discipline carries directly into this modern challenge.

Biogas Upgrading: Process Routes to Pipeline-Grade Biomethane

Raw biogas from an anaerobic digester is not directly suitable for pipeline injection or vehicle fuel use. Typical biogas contains 50–75 percent methane, with the balance being primarily carbon dioxide, trace quantities of corrosive hydrogen sulphide (0 to 15,000 ppm), and water vapour [4]. Upgrading removes these impurities to produce biomethane with a methane concentration high enough to meet pipeline specifications. The four principal commercial routes are water scrubbing, pressure swing adsorption (PSA), membrane separation, and amine chemical absorption. Each route removes carbon dioxide and hydrogen sulphide differently, and each has a characteristic methane slip—the loss of methane in the off-gas—that is the key economic loss term.

Common Pretreatment Requirements

Before any upgrading step, raw biogas must be conditioned. Water is typically removed by condensation to a specified dew point, for example below -35 °C at 260 bar in one documented PSA installation [1]. Hydrogen sulphide is often reduced upstream of the main upgrading unit. The simplest method is biological desulphurisation, where oxygen or air is added directly into the digester chamber. With this method, hydrogen sulphide levels can be reduced by up to 95 percent to levels lower than 50 ppm [3]. Oxygen should be added in stoichiometric amounts, and the level needed depends on the hydrogen sulphide concentration; usual levels are 2–6 percent air in biogas [3]. Safety is critical: methane is explosive in the range of 5–15 percent in air, so overdosing of air must be avoided, particularly in the event of a pump failure [3]. Biological desulphurisation can also take place in a separate bio-filter filled with plastic bodies on which desulphurising micro-organisms are attached; in this unit, 5–10 percent air is added before the biogas enters [3]. For routes that are sensitive to sulphur poisoning, such as amine systems, a polishing step may be required after biological desulphurisation, but the evidence does not specify a universal limit for this.

Water Scrubbing

Water scrubbing uses the higher solubility of carbon dioxide and hydrogen sulphide in water compared to methane. Raw biogas is compressed and fed to the bottom of a packed column, where it contacts water flowing counter-currently. Carbon dioxide and hydrogen sulphide dissolve into the water, while methane passes through the top. The water is then regenerated by depressurisation or stripping with air, releasing the acid gases. Water scrubbing is a physical process, so it does not require chemical regeneration agents. It handles hydrogen sulphide reasonably well, but the dissolved hydrogen sulphide can create odour and corrosion issues in the water loop. Methane slip is moderate; the evidence does not provide a specific percentage for water scrubbing, so a plant engineer should obtain vendor data for the specific design. Pretreatment for water scrubbing typically requires water removal and hydrogen sulphide reduction to protect the packing and prevent fouling.

Pressure Swing Adsorption (PSA)

PSA is a cyclic process that exploits the different adsorption affinities of gases on a solid adsorbent, typically activated carbon or a molecular sieve. In a documented PSA installation, the plant has four separate synchronised adsorption columns that work in a cyclic mode, changing between adsorption and regeneration [1]. Raw biogas is compressed to about 5 bar pressure, and hydrogen sulphide is separated in a pre-filter before the gas enters the PSA columns [1]. Carbon dioxide is removed in the PSA process, and the cleaned gas is then compressed further for delivery [1]. PSA can achieve high methane purity, but methane slip occurs during the regeneration phase, when the adsorbent is depressurised and the off-gas contains methane that was not fully retained. The evidence does not give a specific methane slip value for PSA, so this must be obtained from the equipment supplier. PSA requires dry gas, hence the dew point specification mentioned above, and it requires hydrogen sulphide removal upstream to prevent poisoning of the adsorbent [1].

Membrane Separation

Membrane separation relies on the different permeation rates of gases through a polymer membrane. Carbon dioxide and hydrogen sulphide permeate faster than methane, so when raw biogas is compressed and passed across the membrane surface, the acid gases pass through the membrane wall and are removed on the permeate side, while methane is retained on the feed side. Membranes are compact, have no moving parts in the separation stage, and are relatively simple to operate. However, methane slip can be significant, particularly if the membrane selectivity is not high, because some methane inevitably permeates with the carbon dioxide. The evidence does not provide a specific methane slip value for membrane systems. Pretreatment for membranes is critical: water vapour must be removed to prevent condensation on the membrane surface, and hydrogen sulphide must be reduced because it can degrade some membrane materials. The evidence does not specify a maximum hydrogen sulphide concentration for membrane feed, so the plant engineer should consult the membrane manufacturer.

Amine Chemical Absorption

Amine chemical absorption uses a liquid solvent, typically an alkanolamine, that chemically reacts with carbon dioxide and hydrogen sulphide. The raw biogas is contacted with the amine solution in an absorber column; the acid gases react with the amine and are absorbed, while methane passes through. The amine solution is then heated in a regenerator column to reverse the reaction, releasing a concentrated carbon dioxide stream and regenerating the solvent for reuse. Amine systems achieve very low methane slip because the absorption is chemical and highly selective for acid gases over methane. However, they are energy-intensive due to the heat required for regeneration. Amine systems are sensitive to impurities: hydrogen sulphide can form heat-stable salts that degrade the solvent, and oxygen can cause oxidative degradation. Therefore, pretreatment must include thorough hydrogen sulphide removal and, in some cases, oxygen removal. The evidence does not provide specific limits for these contaminants in amine feed gas, so the plant engineer should obtain them from the solvent supplier.

Methane Slip as the Key Loss Term

Methane slip is the fraction of methane in the raw biogas that is lost in the off-gas or permeate stream rather than recovered in the biomethane product. It is the key loss term because methane is both the valuable product and a potent greenhouse gas. PSA and membrane systems generally have higher methane slip than water scrubbing and amine systems, but the evidence does not provide quantitative values for any of the routes. The plant engineer should therefore request guaranteed methane slip figures from equipment vendors and compare them on a life-cycle basis, accounting for the value of the lost methane and any requirement to oxidise the off-gas to control emissions.

Route Selection Considerations

The choice of upgrading route depends on the biogas flow rate, the required methane purity, the acceptable methane slip, the availability of utilities such as heat and water, and the level of pretreatment already installed. Water scrubbing is robust and well proven but requires a large water flow and produces a dilute carbon dioxide stream. PSA is modular and can be scaled, but it requires careful control of the cyclic operation and has a higher methane slip. Membranes are compact and simple but may require multiple stages to achieve high purity, increasing both capital cost and methane slip. Amine systems achieve the lowest methane slip but have the highest energy demand and the most demanding pretreatment requirements. The evidence does not provide a direct cost comparison, so the plant engineer should evaluate capital and operating costs qualitatively: amine systems tend to have higher operating costs due to heat, while membrane systems tend to have lower operating costs but higher methane loss.