The biogas “universe” transcends municipal departments and has expanded beyond just the generation of heat and electricity. In the past, the answer to the question “how to best use biogas?” was either to produce hot water or to produce electricity. Today, the answer is much more complex because the demand for, and production of, biogas has increased.
Biogas is produced by the anaerobic bacterial degradation of organic material, such as sewage sludges, source-separated organics, food wastes, farm materials or industrial byproducts (e.g., glycerine). Biogas is produced at wastewater treatment plants, farms, solid waste facilities, landfills and industrial sites.
The carbon dioxide produced when burning natural gas is a greenhouse gas (GHG), while that when burning biogas is not. Biogas carbon is produced as part of the natural cycle, which includes the digestion of biologically based materials. This said, because methane is a greenhouse gas, a biogas end user will produce a GHG emission if unutilized methane is emitted to atmosphere.
The potential to produce biogas has not been fully realized in Canada. It is estimated that Ontario alone could produce 752 Mm3/year of renewable natural gas (i.e., upgraded biogas) from anaerobic digestion. This is less than 3% of Ontario’s year 2015 (fossil fuel) natural gas consumption. With gasification, this number increases to 17% of Ontario’s year 2015 natural gas consumption. Action 6.1 of Ontario’s Five Year Climate Action Plan is to lower the carbon content of natural gas in Ontario by sourcing gas from renewable sources. At the right price, biogas producers would be able to supply sufficient biogas to support a 2% mandatory renewable requirement.
The cost to produce and utilize biogas depends partly on the cost to prepare material for digestion, the cost to clean the biogas (i.e., condition), the cost to manage undigested material, and the cost to utilize the biogas.
The economic return of a biogas project is based on the savings accrued by using biogas rather than another form of energy, or based on the market value of the biogas product itself. Biogas can be used to produce thermal, electrical and motive energy. There may be enough savings realized by altering how a facility uses biogas to pay for the capital investment to make the change. Grants from governments are designed to bias this evaluation towards achieving a policy outcome (e.g., reduction in grid peak demand or reduction of GHG emissions).
However, a business case is most attractive when the sale of the biogas product generates a revenue stream that pays for the project. The viability of most biogas projects depends on savings obtained, incentives awarded, and profits realized.
Raw biogas is “wet”, 60% – 70% methane and “dirty”. Conditioned biogas is “clean” and “dry”. The end use of the biogas determines the degree of conditioning required. For example, a gas turbine requires cleaner biogas than a boiler. Contaminants in raw biogas that impact most end users are siloxanes, hydrogen sulfide, ammonia, oxygen, nitrogen and moisture.
Clean (conditioned) biogas can be used to direct drive blowers or pumps, exported as a fuel, or sold as a raw material (e.g., to produce bioplastics). On one recent project, a community housing entity offered to purchase all the conditioned biogas produced by a proposed wastewater treatment plant to reduce its GHG emissions.
A more common situation is to use biogas to produce heat. This is conveyed either directly as steam or hot water (e.g., steam injection into a reactor) or indirectly through heat exchangers (e.g., hot water circuit). The biogas can also be compressed and conveyed to provide heat directly (e.g., incinerator burners) or indirectly (e.g., heating of thermal oil. The value of this biogas is equal to the value of natural gas not purchased and greenhouse gas emissions not emitted.
Biogas is also used as fuel to generate electricity (and heat). This electricity can be exported to the grid or can be used “behind the meter” at the facility where it is generated. The common end users are internal combustion engines, combustion gas turbines, steam turbines and microturbines. The value of the electricity produced depends on incentives, electricity pricing, and the cost to supply the energy to an end user.
The cost to export electricity, or to export any form of energy, depends on the distance to the tie in point and the requirements to match the exported power to the power characteristics at the connection point. For electricity, the characteristic may be voltage; for renewable natural gas, pressure; and for hot water or steam, temperature.
The willingness to provide an incentive depends partly on the grid electricity GHG emission factor. The Canadian National Inventory Report estimates that the 2014 electricity emission factor for Manitoba is 3.9 g CO2e/kWh, Ontario is 50 g CO2e/kWh, and Saskatchewan is 820 g CO2e/kWh. An internal combustion cogeneration (cogen) unit produces electricity with an emission factor of about 95 g CO2e/kWh (assuming a 1% methane slip). The justification to pay a premium for biogas-generated electricity in Saskatchewan is stronger than it would be in Manitoba.
It may also be beneficial to supply a mix of natural gas and biogas to an engine where the emission factor of natural gas generated electricity is also cleaner than that from the grid. However, blending the two gasses requires sophisticated control because of their very different Wobbe indices. The Wobbe Index (WI) is a measure of the heating value of fuel gas arriving from the gas line to the orifice where a burner is located. Two gasses with similar Wobbe indices are interchangeable.
The economics improve if the facility already has biogas that can be used to produce electricity. It is not uncommon for an owner to generate their own electricity as a means to protect them from the volatility of the electricity market. The economics of producing electricity further improves if the heat generated is used year round by a heat sink (e.g., chiller, boiler). Dumping heat is a waste of resources.
On paper, some projects can be funded partly by peak shaving. For example, a Class A consumer in Ontario may save more money shaving peaks over 16 hours during the year than providing a steady supply throughout the year. Savings are realized because the consumer is assessed less for the non-consumption part of their bill (i.e., global adjustment).However, it is a risky proposition to base economics decisions over a 10 to 20-year window on something that can be changed by the stroke of a pen.
The biogas universe expanded dramatically when the value of upgraded biogas became divorced from the price of natural gas. A biogas upgrader strips carbon dioxide from biogas along with other remaining contaminants, leaving primarily only methane. Upgraded biogas, referred to as biomethane, is in many circumstances interchangeable with natural gas. Propane can be added to biomethane if the match with natural gas is not close enough for an end user’s application. The carbon dioxide can be stripped from biogas using a number of technologies, including pressure swing adsorption, selective membranes, water scrubbing, chemical scrubbing, physical absorption, and cryogenic separation.
There are now biogas upgrading facilities in Quebec, Ontario and British Columbia.
Biomethane, when injected into the gas grid, is referred to as renewable natural gas (RNG). The commericial value of RNG is no different than that of natural gas, unless the market places a value on RNG’s environmental attributes. The producer must establish a relationship with the gas distributor to convey the gas to a buyer. The producer would obtain a renewable identification number or equivalent for the RNG, inject the RNG into the grid while still retaining (or sharing) ownership, and then sell the RNG to another consumer.
In jurisdictions where there is a mandated renewable component for natural gas, the producer of the RNG could obtain a long-term supply contract similar to the electricity feed-in-tariff contracts. Low carbon economy initiatives such as cap and trade, carbon taxation or emission caps will continue to drive up the revenue from these types of contracts. The savings are more dramatic if the RNG offsets the purchase of diesel or gasoline than if it offsets the purchase of natural gas.
There are a number of standards for RNG, including the Quebec BNQ 3672-100 and Southern California Gas Company Rule Number 30. The tolerance for RNG quality variability decreases as the RNG accounts for a larger portion of the natural gas flowing past the grid injection point. The natural gas grid operates lines at different pressures, much in the same way as the electrical grid does with voltages.
An RNG project can become uneconomical if the injection point is far from the site or the pressure required to inject into the grid at the injection point is high. In cases where the injection point is on a portion of the grid that is dendritic, the consumers downstream of the injection point must consume sufficient natural gas year round to support year round injection.
In the past, biogas was flared, and natural gas was purchased for plant heating. Some plants used the biogas to generate electricity or to drive blowers or pumps. With a preferential rate for renewable electricity or a subsidy for behind the meter generation, many facilities installed combined heat and power engines. A step change occurred because the environmental characteristics of biogas have, in many jurisdictions, divorced the price of RNG from that of fossil fuel natural gas.
In the future, the end users who require a raw material derived from a renewable carbon source may transform biogas from fuel to a sought after raw material, increasing the biogas producer’s revenue even higher.
Patrick Coleman, P.Eng., is with Black & Veatch. This article appears in ES&E Magazine’s June 2017 issue.