Biogas Production Opens New Energy Frontiers (2008)

Return to Environment

Converting manure and other farm organic waste into renewable energy

When assessing the prospects for large-scale biogas production in Alberta, there’s one powerful fact Mahendran Navaratnasamy keeps coming back to. “It’s greener than any other gas technology,” says Navaratnasamy, a Research Engineer with Alberta Agriculture and Food and the province’s ‘go-to’ technical advisor on biogas.

Whether this ‘green advantage’ can propel biogas production into a feasible option is far from certain, he acknowledges. There are many challenges, ranging from high investment costs paired with long-term paybacks, to a handful of important technological and logistical difficulties to overcome. But against the current backdrop of rising energy costs and growing environmental concerns, biogas production is an emerging option that is rapidly generating interest – particularly for its potential benefits to the agricultural industry.

Biogas production using anaerobic digesters can take large volumes of agricultural byproducts, such as manure, feed spills, meat and food processing wastes, and crop residues, and convert these into a form of energy similar to natural gas. “If we can make large-scale biogas production a viable option, it could go a long way to helping the agricultural industry address the issue of managing manure and other farm organic waste,” says Navaratnasamy. “It could also help reduce onfarm energy costs and potentially provide a new source of farm income. These and other related environmental benefits make biogas production a strong candidate to play an important role in the future of Alberta’s agricultural industry.”

Biogas basics

Biogas is produced through the process of ‘anaerobic digestion,’ or digestion in the absence of air. Organic material is placed inside a large tank, called an anaerobic digester or biodigester, where it is broken down by microorganisms.

The process releases both methane and carbon dioxide, which form the mixture known as biogas. The remaining solid organic material, known as digestate, retains the nutrients of the original material but is easier to handle, contains little or no odour, and is potentially a lower risk nutrient source. These benefits make it ideal for cropland application, which can help replace commercial fertilizer needs.

The biogas produced can be converted into electrical energy by internal combustion engines or power turbines. A co-generator can also be used to capture heat energy during this conversion, resulting in up to 90 percent efficiency compared to the 20 to 30 percent efficiency in conventional electricity generators.

“Biogas is similar to natural gas in that it can be used as a fuel in power generators, engines, boilers and burners,” says Navaratnasamy. “Agricultural producers can use biogas directly on their farms, to help meet their farm’s energy demand. Potentially, they could also sell any excess electricity to neighbouring communities or to the power pool.”

Biogas can be added to natural gas lines if carbon dioxide and hydrogen sulphide are removed, and vehicles can be modified to run on either purified or blended forms of biogas.

Key challenges

The main current hurdle for biogas production is economic feasibility. The capital costs of large-scale anaerobic digester plants are very high and may range from a few hundred thousand to a few million dollars, depending on the size of the plant. Several North American studies concluded the payback period can range from five to 16 years, depending on best and worse case scenarios.

Other key challenges are a lack of infrastructure and technological limitations related to efficient large-scale production and use of biogas.

“One of the most attractive opportunities is to purify biogas to natural gas quality and supply it into the natural gas distribution system – but to do that at a major scale would require meeting existing standards to ensure the efficiency and consistency of the process, as well as large investments in new infrastructure.”

Developing a large centralized digester would also require major infrastructure and logistical frameworks to bring manure to one place, handle digestate and manage numerous other requirements.

Growing support

Despite these hurdles, the prospects for biogas production are steadily improving as the technology advances and as government and industry get on side with supporting biogas as an alternative energy option.

While there are few large-scale biodigesters in North American, they are becoming more common in Europe and other parts of the world. A number of small biodigesters are being used by agricultural operations in Alberta, including several hog operations and a beef feedlot, and interest is picking up, says Navaratnasamy

“At least five anaerobic digesters are in use for processing agricultural wastes in Alberta,” he says. “A few more digesters are in use for processing municipal and industrial wastes.”

Most of the anaerobic digesters currently used in the agricultural industry process a single type of waste, known as a substrate, which in most cases is manure.

One of the best opportunities to increase the efficiency of biogas production is to include additional organic materials, known as co-substrates, to be digested along with the manure. However, this requires more sophisticated co-digestion systems – an area of technology in relatively early development.

“Technology advances in this area can make a big improvement to the prospects for biogas,” says Navaratnasamy. “Co-digestion systems would provide flexibility and increase the potential for farmers to grow and use energy crops to make additional revenue. This process may also enrich or balance the nutrients in the digestate.”

While viable co-digestion has faced several technical hurdles related to the gas mixtures derived from variable material, the good news is there’s substantial opportunity for progress, he says. “Co-digestion processes have to advance and I believe this will happen down the road. There are clear improvements that can be made with simply more time and activity.”

Recently, the Alberta Energy and Utilities Board (EUB) announced the approval of plans for the development of a 3.2- megawatt biogas-fuelled power plant on the eastern edge of Lethbridge. “This may be one of the first co-digestion plants in the province – a sign that the technology is improving and viable.”

Integrated ethanol opportunity

Researchers are also exploring the opportunities for integrating biogas production with the production of other alternative fuels such as ethanol and biodiesel. At least two integrated production plants are under development in North America – one in Nebraska and one in Ontario.

“It’s no secret that because of the climate change issue and concerns around energy supply, governments are in support of biofuels,” says Navaratnasamy.

Ethanol production in particular has received huge attention and backing, he notes. But one of the issues with ethanol is that its production requires substantial fossil fuel consumption. Some estimates have indicated 1 unit of fossil fuel is required to produce just 1.3 units of ethanol.

“One of the opportunities being investigated is to use biogas to meet the energy needs of ethanol production,” says Navaratnasamy. “This would make ethanol production more meaningful from an environmental perspective.”

While there is potential for this type of integrated facility in Alberta, the scale currently required for economic feasibility remains largely prohibitive. “Looking at the new plants being developed, it appears that a production capacity of at least 25 million litres of fuel will be required, so currently there is not a lot of opportunity for that type of facility.”

Large integrated plants also require substantial and consistent huge volumes of manure within a reasonable distance of a centralized facility, he notes.

Steady progress

For Alberta, Navaratnasamy sees the most immediate opportunities as the continued gradual adoption of small-scale anaerobic digesters on livestock operations.

“Over the long run, I think we’ll see these digesters become a lot more common,” he says. “Managing environmental issues will continue to be a major challenge and that’s an important area where these digesters can play a role.

“I see biodigesters as one of the ways we can tackle those issues, while creating opportunities for producers to generate additional income by producing renewable energy.”

The pork industry in particular has shown great recent interest in biodigesters, as a possible means of creating a more stable future beyond its current period of financial pressures. A few individual livestock operations have also implemented digesters as manure management solutions.

The Alberta government is also showing increasing signs of support – most recently announcing funding to support feasibility studies, infrastructure and development of bioenergy alternatives and a bioenergy producer credit program.

“Right now biogas production is a technology that has not matured yet, but there’s no doubt it’s an important technology,” says Navaratnasamy. “As momentum builds with both the technology and the support for the technology, I believe we’ll see more money, more motivation and ultimately more opportunities for agricultural operations.”

More information on biogas production, including commercial technologysuppliers, is available on the Alberta Agriculture and Food website,

Article from: Farming for Tomorrow. Website:

Return to Environment

Biogas Technology Not the Right Fit for B.C. - for now (2008)

Return to Environment

European “Tour de manure” examines feasibility of anaerobic digestion system.

By David Schmidt, Country Life in BC – June 2008

Around the world, anaerobic digestion is being touted as a way to turn animal and green waste into biogas, a combination of natural gas (methane) and carbon dioxide, which can then be used for heating and/or power generation. The technology is already popular in Europe and was identified as an action item in the new B.C. Agriculture Plan.

A farm biogas system would put manure and other wastes through an anaerobic digester (AD). About 15 percent of the mass would be turned into gas which would feed a cogeneration unit and the remaining “digestate” directed into a manure pit and eventually spread as fertilizer, composted or used as bedding.

Last fall, 22 B.C. government and industry representatives took a European “tour de manure,” visiting about 20 AD’s in Switzerland, Austria and Germany, to determine whether the technology is applicable in B.C.

“The European biogas industry has boomed in the past five years,” B.C. Milk Producers Association director of producer relations Paris Thomas reported at the Pacific Agriculture Show in Abbotsford earlier this year.

Switzerland hopes to get five percent of its power, four percent of its heat and eight percent of its fuel from AD’s by 2020. To do that, they have removed tariffs on biogas fuels and upped electricity feed-in tariffs “to enable people in the industry to be profitable,” Thomas said. Since Switzerland has no landfills, AD’s also receive tipping fees for delivered waste.

While they are generating electricity, the Swiss are not using the heat effectively, thereby losing valuable energy.

Swiss AD’s are located both on and off-farm. He showed one farm which had built a bay to receive off-farm waste for the digester, reporting that the farmer considered the AD the best thing he’d ever done on his farm. He showed another AD which resembled a large industrial building, noting the facility had seven loading bays including three dedicated to deadstock. Heat from the AD was being used to pasteurize the deadstock.

Austria has passed a “green electricity act” which gives the industry 71 million euro per year in assistance, provides feed-in tariffs, guaranteed electricity grid access, 10 to 60 Euro per tonne tipping fees and tax exemptions through 2020. By the end of this year, Austria will get four percent of its power from “green electricity.” It is converting its government fleet to biogas power and expects to have 200 biomethane service stations by 2010. Like Switzerland, heat utilization remains an issue.

As a result of the incentives, Austrian AD’s have gone from producing just 2 MW of electricity in 2001 to 86 MW in 2007. The installations include a community sewage facility which processes 22,000 tonnes of waste per year.

Germany charges its consumers about 10 Euro per year to subsidize green energy. AD’s receive 20 year power contracts with guaranteed grid access and price premiums depending on the size of the facility. AD’s also receive a bonus for using agricultural crops and for using the heat. As a result, there are now about 4,000 AD’s in Germany. “This is a model we want to stay away from,” Thomas stated, pointing out the incentives mean German farmers are growing “perfectly healthy silage just to feed the digesters.”

The B.C. group hired Eric Camirand of Electrigaz Technologies to study the feasibility of AD’s in the Fraser Valley. Dairy producers like the idea of being able to do something with their manure while greenhouse growers hope to offset the increasing cost of natural gas.

However, Camirand’s report was not very positive. He noted manure is probably the least efficient source of methane, generating only 30 to 50 cubic meters of methane per tonne. In contrast, corn silage generates about 200 cubic metres and bread almost 600 cubic metres of methane per tonne. Even if they use all potential feed sources in the Lower Mainland, AD’s would still generate only about 50 MW of electricity per year.

Camirand said B.C.’s low electricity rates don’t generate enough return to justify the high capital investment. Even with their high incentives, European AD’s generate returns of only about $50,000 per year.

“The capital investment is about $1 million per megawatt,” he said. With B.C. Hydro paying only five cents per kwh for power, an AD project “doesn’t make sense.”

While B.C. Hydro is now offering eight cents per kwh for new clean energy projects, that’s still at least two cents per kwh less than what Camirand thinks is necessary. Other experts suggest AD’s need at least 15 cents per kwh to generate any return on investment.

Camirand doesn’t expect B.C. rates to get that high any time soon.

“We have the cheapest energy in North America and it’s already green.”

If there is an opportunity for AD’s, it will be in gas and biofuels.

Since methane is “renewable natural gas,” Camirand says Terasen is interested in offering operators long-term contracts at a premium price. Biogas is almost three times as efficient as ethanol giving it tremendous potential if it is recognized as a biofuel. AD’s can also reduce odour and greenhouse gas and improve air quality.

While Camirand believes the technology has potential, “current energy market conditions do not favour its development.

“AD’s future is in the hands of policy makers.”

Country Life in BC
Associate Editor
David Schmidt

tel 604/858-9193
fax 604/858-7043

Return to Environment

The Economics of Biogas Systems in Ontario (2007)

Return to Environment

Presentation at the Ontario Dairy Symposium; March 7, 2007 at London Ontario.

Donald Hilborn, P.Eng.
Engineer- Byproducts and Manure
Environmental Policy and Programs Branch
Ministry of Agriculture, Food and Rural Affairs
401 Lakeview Drive
Woodstock, Ontario N4T 1W2
tel:519 537 7928 cell: 519 535 0511 fax: 519 539 5351

There is interest in Ontario to install farm based biogas systems. Dairy and beef farms have an advantage because their manure produced is an ideal input. This paper uses information from an existing Ontario based farm using a biogas system to develop economic information.

Description of Existing Operation

This farm has 140 milking cows plus replacements. The farmstead consists of livestock barns, feed storages, equipment storages and two households. This operation has an electrical usage of an average of 700 kWh per day.

To replace external energy usage (except tractor diesel fuel), the farm installed an anaerobic digester in 2002. The digester produces biogas from the manure from the 140 cows (plus some of the replacements). The biogas is utilized in an internal combustion diesel engine that powers a 50 kW generator. Approximately 750 kWh per day is generated. Ten per cent of the power from the diesel engine is sourced from diesel fuel. Ninety per cent of the output is 675 kWh which is almost equal to the farmstead usage.

In addition to the electrical energy produced, an equal amount of heat (750 kWh per day) is obtained from heat exchangers on the generator motor. Approximately 30% of the heat is used to maintain the digester at 40 degrees C. The remaining heat is conducted via a hot water based system to heat the two homes. An insulated 5000 gallon tank is used to store energy via hot water to address the uneven heat requirements. The farmstead’s homes have been fully heated from this source during the past two winter seasons.

This facility is estimated to cost approximately $250,000.

Value of the Power Produced

In Ontario there are three distinct ways to manage on farm generated power.

1. Independent System

Possible to have a system run completely independent to the grid. There will be challenges such as the need to generate continuously (or store power) and the inability for certain generator systems to respond quickly to different load requirements. The full cost of this system has not been explored.

2. Net Metering Program

Net metering gives a renewable energy producer the ability to put electrical power onto the grid and remove it for power supply on the farm when required. Current rules in Ontario allow up to 500 kW of generation via this process (if grid capacity allows). The farm settles on a one year basis. If more power is put on the grid over this one year basis then is removed, the value of this extra power is lost.

Example Farm using the Net Metering Program

Avoided electrical costs @ $0.12 per kWh =$30500 per yr (12% of investment)

The example farm currently is using this program. In addition to the above benefit, the electrical demand charge has been eliminated on the farm because power is generated at the same time peak power requirements occur. Since more energy is produced then is used (appr. 50 kWh per day) the farm can’t receive value for this surplus under the net metering program.

For net metering to be economically effective, the farmstead should use all the generated power. Operations that are heavy power users fit this best. Net metering gives protection from inflation since you are replacing power that is subject to inflation.

3. Standard Offer Program (SOP)

The standard offer program gives a renewable energy producer the ability to put renewable power on to the grid and be paid a fixed price for a long term period. This program is available in Ontario as of Dec 2006. It pays 11 cents per kwh for the power plus a 3.52 cent bonus for power generated during peak requirement times (bioenergy systems only). The 11 cent value inflates at 20% of the consumer price index.

Example Farm using the Standard Offer Program

Electricity sold @ 0.125 per kWh =$34000 per yr (14% of investment)

No avoided electrical costs

An advantage of this program is that all the power produced is paid for. Operations that are not heavy power users fit this. One main disadvantage is that the sold power value inflates very slowly whereas the farmstead has to buy power of the grid for its own use that is subject to full inflation. This will have a very large impact over a 20 year period.

Standard Offer Program using clause 6.4

There is a section in this program that deals with an embedded renewable generation system (ie. introduces power into the farmstead system prior to the main electrical meter). For this case, the current understanding is that the farm will get paid the SOP price for any power produced less the Hourly Ontario Energy Price (HOEP) for any power used in the farmstead within the same hour.

Example Farm under the Standard Offer Program with clause 6.4 Avoided electrical costs = $30500 per year. Estimated Payment for renewable electricity = $18000 per year (selling at SOP prices, buying at est. HOEP, no transportation costs). Net Value to farm =$48500 per year (=0.18 per kWh) (19%)

Note. At the time of writing I am uncertain about settlement procedure, uncertain about demand charges, I assumed average wholesale prices in previous calculation and I did not take into account losses (1%)

This program (if available according to the current understanding) allows a farmer to sell all power produced and it gives inflation protection for power used. It is most effective when the farmstead uses significant quantities of power.

Value needed to be an Economically Viable Option for Ontario Farms

OMAFRA has completed calculations indicating that between 13.3 to 22 cents per kwh is required for a biogas system to be economically viable. This is assuming a mature industry, reasonable costs of line connections and no access to any other capital funding programs. The lower value (13.3 cents) requires a very efficient system likely with commingling of off farm source energy materials. The higher value would allow energy crops such as corn silage to be utilized.

The current Standard Offer Program seems to only be viable if the ability to trade power as outlined in clause 6.4 is available. This value is best if the farmstead uses almost as much power as is produced.

Other benefits such as …

  • high grade bedding production,
  • possible separation of sand bedding
  • effective use of surplus he
  • manure pathogen, odour reduction
  • greenhouse gas benefits and
  • effective treatment of off farm source organics

are not considered in this assessment. Any one of these benefits alone may improve the economics sufficiently to make the system viable. The challenge is to give an economic value to these benefits.

Return to Environment