Biomethane Plants: Upgrading Biogas Into a Grid Quality Gas

Burning biogas on site to make power and heat is the established path, and for a lot of sites it is the right one.

There is a second option that changes the economics entirely: rather than converting the gas to electricity, clean it up until it is indistinguishable from natural gas, and sell it as gas.

A biomethane plant does that. It is a fundamentally different business model to cogeneration, and whether it suits depends far more on your commercial position than on your engineering.

Biogas and biomethane are not the same thing

Worth being precise, because the terms get used interchangeably and they are not.

Biogas is what comes out of a digester or a landfill. Methane diluted with carbon dioxide, plus water vapour, hydrogen sulphide and various trace contaminants. Combustible, but nowhere near the specification of pipeline gas.

Biomethane, sometimes called renewable natural gas, is biogas that has been upgraded: the carbon dioxide removed, the contaminants stripped, the moisture taken out, until the methane content and calorific value meet the specification for natural gas.

At that point it is functionally natural gas, and it can be injected into a gas network, compressed for vehicle fuel, or supplied to a customer who currently buys fossil gas.

The distinction that matters commercially: biogas is a fuel you use. Biomethane is a product you sell.

Why a site would choose upgrading over cogeneration

No use for the heat. This is the strongest single reason. Cogeneration economics depend heavily on the recovered heat having a home. A site with abundant gas and no meaningful heat demand is running a generator and dumping half the output. Upgrading sidesteps that entirely, because there is no waste heat to place.

Gas is worth more than electricity to you. Depends on your tariffs, your grid connection position and what the gas is worth to a buyer. Sites facing expensive or constrained grid connection sometimes find gas the easier product to move.

Grid connection is the obstacle. Exporting electricity requires network approval, and depending on the location and the network that can be slow, expensive or capacity limited. Gas injection has its own approval path, which on some sites is the easier one.

Vehicle fuel. Compressed biomethane can fuel a fleet. For an operation running its own heavy vehicles, producing your own fuel from your own waste stream is a genuinely attractive proposition.

Corporate and customer decarbonisation demand. There is real and growing demand for renewable gas from businesses with emissions commitments who cannot electrify their process heat. That demand supports a price.

Why a site would stay with cogeneration

You have a genuine heat demand. If the heat has an obvious home, particularly the digester itself, cogeneration captures value that upgrading cannot. Total fuel utilisation is high and the case is simple. See CHP plants.

Lower complexity. Cogeneration is a well trodden path with a straightforward approval route on most sites.

You want to offset expensive imported electricity. If you are paying a high commercial tariff, generating behind the meter is often the highest value use of the gas.

Smaller scale. Upgrading the plant carries fixed costs and complexity that need a certain gas volume to justify. Below that, cogeneration is generally the more sensible answer.

No route to market for the gas. No nearby network connection point, no buyer, no fleet. Without an offtake, upgrading produces a product you cannot sell.

What the upgrading process involves

Several technologies exist and they achieve the same end by different means. The choice depends on gas volume, required output specification, available utilities and site constraints.

Pre-treatment comes first regardless of technology. Removing hydrogen sulphide, siloxanes, moisture and particulates. This is the same requirement as for an engine, and it is not optional.

Carbon dioxide removal is the core step, taking the gas from its raw methane content up to pipeline specification. The main approaches are membrane separation, pressure swing adsorption, water or chemical scrubbing, and cryogenic separation. Each has different capital cost, energy consumption, methane slip and complexity.

Conditioning to final specification: pressure, moisture, odorisation where required for network injection, and any calorific value adjustment.

Measurement and quality assurance. Continuous monitoring, because a network operator will require demonstrated compliance with specification before and during injection.

Two things worth asking about any proposed technology:

Methane slip. How much methane escapes with the removed carbon dioxide. It is a direct loss of product and, since methane is a potent greenhouse gas, a genuine emissions issue that undermines the environmental case if it is high.

Parasitic energy load. Upgrading consumes energy. How much, and what does that do to the net product yield?

The commercial questions that decide it

Engineering is rarely what kills a biomethane project. Commercial position is.

Where does the gas go? A network injection point, a compression facility for vehicle fuel, or a direct pipeline to a customer. Without an answer, there is no project.

How far away is it? Pipeline construction to reach a connection point is a substantial cost, and distance frequently decides feasibility.

What will the network operator require? Specification, metering, odorisation, continuous quality monitoring and a connection agreement. These are non trivial and they take time.

What is the offtake arrangement? A contract, at what price, for how long. Project finance depends on this rather than on the plant.

What certification applies? Renewable gas certification schemes affect the price the product commands.

Is the gas supply reliable enough to contract against? If you have committed to supply and your digester has a bad month, that is a commercial problem rather than an engineering one.

Or do both

Not either or on every site.

Some operations upgrade the bulk of the gas for injection and run a smaller cogeneration unit on a slipstream to serve on site electricity and, crucially, digester heating. That is often the most efficient overall configuration, because the digester needs heat regardless and upgrading does not produce any.

It adds complexity. On sites with sufficient volume it can be the best answer.

Frequently asked questions

Is biomethane the same as natural gas?

Once upgraded to specification, functionally yes. Same principal constituent, same calorific value range, interchangeable in the same equipment and networks.

How much gas do I need for upgrading to be viable?

More than for cogeneration, because upgrading plants carries fixed cost and complexity. The threshold depends on the technology, your offtake price and distance to a connection point.

Can I inject into the gas network in Australia?

Network injection of biomethane is established in several jurisdictions and the framework continues to develop. Requirements vary by network and state. Early engagement with the network operator is essential.

What happens to the carbon dioxide removed?

Usually vented. On some sites it can be captured and used, for example in food grade applications, which adds a revenue stream. See CO2.

Which upgrading technology is best?

Depends on volume, required specification, available utilities and site constraints. Compare capital cost, energy consumption, methane slip and operational complexity.

Can I switch from cogeneration to upgrading later?

Possible, and easier if anticipated at the outset, since gas treatment, space and utilities can be planned for.

How long does a project take?

Longer than cogeneration, largely because of network connection and offtake contracting rather than construction.

Start with the offtake, not the plant

A biomethane project stands or falls on where the gas goes and what it is worth.

See biobiomethane plantsmethane plants, biogas power generation, project management, or get in touch.