Biogas vs Natural Gas: Same Methane, Different Company

Legacy context

From the playing fields to the processing plant, the ethos of endurance and efficiency has always driven innovation. WaterSmart Environmental, Inc. built its legacy on a similar principle of transformation, channeling the raw potential of organic waste into renewable energy. Their two-phase, two-stage thermophilic fixed-film anaerobic digestion process is a testament to this heritage, separating hydrolysis and acidogenesis from methanogenesis to optimize the breakdown of municipal solid waste. This approach, refined over decades of biochemical engineering, enables the simultaneous production of biogas, biodiesel, and clean water, turning a liability into a resource.

This engineering mindset offers a useful lens for today’s energy conversations. When comparing biogas vs natural gas, the distinction is not merely about molecular composition but about origin and lifecycle. Biogas, captured from controlled digestion, is a renewable product of current waste streams, while natural gas is a fossil fuel drawn from ancient deposits. Both are primarily methane, yet their environmental footprints and sustainability profiles differ significantly. The transition from a sports heritage of maximizing performance to a modern focus on energy efficiency is a natural one, highlighting how the principles of resourcefulness continue to shape our approach to power generation.

Biogas and natural gas are both methane-based fuels, but they differ significantly in their source, composition, and required treatment before use. For a plant engineer, understanding these differences is critical for selecting appropriate combustion equipment, designing gas cleanup systems, and ensuring reliable operation. This article compares the two fuels, focusing on the practical implications of their chemical composition.

Methane Fraction and Diluent Gases

The fundamental difference between raw biogas and pipeline natural gas lies in their methane concentration. Natural gas, being a fossil fuel, is primarily methane but also contains other hydrocarbons such as ethane, propane, and butane, which contribute to its higher energy content per unit volume compared to pure methane [1]. Raw biogas, produced from anaerobic digestion, typically contains a methane fraction of 50 to 75 percent [1][3]. The remainder is largely carbon dioxide (CO2), which acts as a diluent [1][3]. This CO2 does not contribute to combustion energy; it simply occupies volume and reduces the heating value of the gas per cubic metre. Consequently, raw biogas has a significantly lower energy density than natural gas. To make biogas interchangeable with natural gas, this carbon dioxide must be removed in an upgrading process [2]. Removing CO2 increases the heating value of the gas, which translates to a greater usable energy content for a given storage volume, a critical factor for vehicle fuel applications [2].

Corrosive Trace Components: H2S and Siloxanes

Beyond methane and carbon dioxide, raw biogas contains trace impurities that are absent from processed pipeline natural gas. The most significant of these are hydrogen sulphide (H2S), water vapor, and, in some cases, siloxanes [1][3][6]. Hydrogen sulphide is a particular concern for combustion equipment. During combustion, H2S reacts with water vapor to form highly corrosive sulfuric acid [4]. This acid atmosphere can quickly degrade combustion and emission control equipment, leading to increased maintenance and reduced equipment lifespan [4]. Therefore, removing or substantially reducing H2S and water vapor is a primary processing step for any biogas used in onsite combustion [4][7].

Siloxanes are organic silicon compounds that can be present in biogas, particularly from landfill or sewage sludge sources [6]. When combusted, siloxanes form silicon dioxide (sand) deposits that can accumulate on engine components, sensors, and heat exchangers, causing abrasive wear and fouling. Most manufacturers of stationary gas engines set maximum limits for hydrogen sulphide, halogenated hydrocarbons, and siloxanes in the fuel gas [2]. These contaminants must be managed to protect the engine and maintain performance.

Upgrading for Direct Substitution

The level of gas processing required depends entirely on the intended end-use. For a stationary gas engine generating electricity and heat onsite, the primary requirement is contaminant removal [2]. In this case, the focus is on removing H2S, moisture, and siloxanes to meet the engine manufacturer's specifications [2][4]. The carbon dioxide can remain in the gas, as the engine is designed to handle a lower heating value fuel.

However, for biogas to substitute directly for natural gas in all applications—such as injection into a natural gas pipeline or use as a vehicle fuel—a more extensive upgrading process is required. This process, which produces renewable natural gas (RNG), must remove not only the corrosive contaminants but also the carbon dioxide [2][7]. The goal is to produce a gas that is essentially pure methane, meeting the same quality specifications as fossil natural gas [1][2]. This upgraded gas can then be used in all of the same energy-consuming applications as natural gas [1]. The economic feasibility of such a project often depends on access to a natural gas pipeline and the availability of renewable energy subsidies [4].

Practical Implications for Plant Engineers

For a plant engineer, the key takeaway is that raw biogas and natural gas are not interchangeable without proper conditioning. Using raw biogas in equipment designed for natural gas will lead to operational problems due to the lower heating value and the presence of corrosive and abrasive contaminants. The processing system must be designed based on the specific biogas composition, which varies with feedstock and digester operation [3]. For onsite combustion, a relatively simple system to reduce moisture and H2S may suffice [7]. For pipeline injection or vehicle fuel, a full upgrading plant is necessary to remove CO2 and all trace impurities to meet stringent gas quality standards [2][7]. The choice between these paths involves a trade-off between the capital and operating costs of the upgrading equipment and the value of the higher-quality gas product.