Biogas from sewage plants helping to meet California’s environmental mandates

The potential for the on-site generation of heat and power from bio-wastes at water treatment plants in California is substantial, and can be increased further if additional wastes from other industries are brought to the site. Pramod Kulkarni discusses the technology and economic options.

The use of biogas from waste water (sewage) treatment plants for cogeneration is a logical step to meet California’s ambitious energy and environmental goals. California has long supported inclusion of clean and efficient generation in its portfolio of energy resources. It has actively promoted use of renewable energy generation through tax incentives and rebates, and has a mandated that, by the year 2020, 33% of retail electricity sold in the state come from renewable energy sources.

California has also actively supported and promoted efficient electricity generation from relatively clean fossil fuels such as natural gas. This has led to an existing cogeneration capacity of 9000 MW that provides combined heat and power (CHP) for on-site use or sale to utilities. Most of this cogeneration capacity is at plants larger than 20 MW. In spite of a recent legislative and policy initiatives support for CHP, small and distributed cogeneration has not seen much growth in California in the recent years.

Concern for reducing greenhouse gas emissions (GHG) has also given impetus to CHP support in California. The California Air Resources Board (ARB) has proposed 4000 MW of CHP capacity by the year 2020 to reduce 6.6 million tonnes of carbon dioxide equivalent per year. Using methane from waste water treatment plants (WWTPs) for CHP development helps meet both the policy goals of renewable electricity generation and GHG reduction.

Regardless of the mandates, it is in a community’s financial interest to explore WWTP-based cogeneration as a means to manage the cost of this essential municipal service. WWTPs are an integral part of all urban and many rural communities that process residential, commercial, and industrial wastes.

The process is energy intensive and the cost of electricity has been rising. Disposal of the solids, called sludge, left after treating the sewage is an added cost that is increasing.

Plants in rural or semi-urban areas can spread the sludge on adjoining fields, or send them to landfills. In densely urban metropolises like Los Angeles the sludge has to be hauled away to far away counties or even another state; adding transportation cost and increasing diesel emissions.

There are sufficient economic reasons for a WWTP to build an anaerobic digester and use the gas for on-site energy use.


At all the WWTPs the process begins with a primary level of treatment, but many also conduct secondary and tertiary treatments of the waste stream. The residual waste stream (effluent) left after processing waste to the requisite level of cleanliness must be disposed of in compliance with local, state and federal regulations. The effluent is dried using mechanical means and the resulting sludge can biodegrade and produces methane gas and other materials.

The sludge could be spread in drying beds, used in the fields, or transported to composting sites or landfills. An alternative method is to collect waste materials in a digester and subject it to controlled biodegradation followed by combustion of the resulting methane (biogas).

The sludge left over after separation of water from waste must be processed prior to disposal, and this task accounts for as much as 30% of a wastewater treatment facility’s costs. According to the US Environmental Protection Agency, the sewage sludge contains 10 times the energy needed to treat it, and it is technically feasible to recover energy from sludge. Anaerobic digestion helps recover energy and reduce the volume of sludge that needs to be disposed off. The renewable electricity and heat recovered through anaerobic digestion of sludge and combusting the biogas can be directly used in the wastewater treatment process.

Digester-generated biogas (methane) has the same chemical composition as natural gas. The difference is that digester gas has about 40-60% of the caloric value of pipeline quality natural gas. Nonetheless, digester methane can be used in boilers, turbines, and fuel cells. However, digester methane must be treated further to reduce moisture, hydrogen sulfide and other harmful materials before it can be used for turbines or fuel cells.

Of the 268 WWTPs with more than one million gallons per day (MGD) capacity in California, only 117 have digesters. Generally it is not cost-effective to install CHP systems at plants with less than three or four MGD of capacity. The generation capacity at these plants ranges from 30 KW to 3 MW. As of 2005 only 23 WWTPs were producing power using CHP. Currently the total biogas-based electricity generation capacity at of these plants is approximately 35 MW, and is a substantially lower than of its potential.

Due to the multiple reasons cited earlier, many WWTPs are actively assessing the option of adding digesters or recovering power from existing digesters. Many are revisiting a CHP option due to the altered dynamics of the resource quality and quantity, energy and operating costs, and the cost of complying or not complying with the environmental regulations. Other factors such as the renewable energy credits and potential carbon credits are being considered as well.


The 268 WWTPs in California have an average dry weather flow of at least 1 million gallons per day or more and the average combined daily wastewater flow of these WWTPs is 3000 MGD. These WWTPs range in size from 1 MGD to 400 MGD, and digesters can collectively produce approximately 17 billion standard cubic feet (scf) of gas per day. Using the commonly used internal combustion engines at such sites, and assuming a heat rate of 9750 btu/KWh , this gas has the potential to generate approximately 125 MW of base-load power in California.

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Figure 1. Cumulative market potential for WWTP CHP through sludge co-digestion of multiple bio-waste streams in Californiaà‚ Source: Co-digestion of Dairy Manure/Food Processing Waste and BioSolids/Food Processing Wastes to Energy, California Energy Commission Report 500-2007-015. March 2008

The waste heat, as a byproduct of cogeneration, can be used on-site to keep the digesters at the optimum temperature for biogas production. Based on the economics of producing gas and installing CHP, the prevailing electric and gas rates, and using current cost of capital and tax benefits California could add additional 90 MW of CHP capacity beyond the existing 35 MW of WWTP based CHP.

In California the WWTPs need not be limited by the availability of the on-site influx of sewage. By adding bio-wastes available in a logistically and economically viable proximity, they can increase their gas production. A study by the California Energy Commission’s Public Interest Energy Research (PIER) programme concluded that, by co-digesting dairy waste, food processing waste, and restaurant grease and oil with the sludge can increase biogas production. Disposing of these waste streams is a serious challenge for both the dairy and food processing industry. If left untended, both waste streams generate 3 million tons of carbon dioxide emissions annually. When added to the WWTP digesters, these liabilities can be turned into assets, substantially boosting gas and electricity production.

Finally, food, oil and grease (FOG) wastes from restaurants and institutional facilities can also be added to digesters at WWTPs to increase generation. FOG, not as abundant as dairy manure in California, is still quite potent in its ability to increase gas production and improving the economics of CHP installation. The technology for mixing FOG to digesters has been demonstrated at several locations. These demonstrations show that, by co-digesting FOG, biogas production at a WWTP can increase by 10-40%.

Out of approximately 1700 dairies in California many could possibly digest their manure at the dairy for electricity generation, but they often lack sufficient on-site electrical demand to economically justify installation of a CHP system. Thus there are currently less than 10 dairy-based digesters operating in California, and the prospect of adding more at this time is discouraging.

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Two DFC3000 power plants, again from FuelCell Energy, supply energy to the regional wastewater treatment facility at the Dublin San Ramon Service District in Pleasanton, California.

This is in spite of a growing pressure to cap the methane generated by cow manure. Water discharge and air emissions restrictions preclude building additional digesters. Consequently enough dairy manure is available that could be processed at WWTPs if the economics of transportation were favorable. Obtaining additional permits for dairy manure treatment and sludge disposal should not be as formidable a task for a WTTP, as it is for the dairies, since the WWTPs already have the requisite permits.

After a successful demonstration at a WWTP digester in eastern Los Angeles County, a PIER study estimated that the long-term technical potential for co-digesting dairy manure with food waste in California could technically yield 334 MW of electricity generation capacity. After applying the financial models used to evaluate capital investment decisions, the PIER report found the long-term market potential to be 250 MW.

Agriculture, food, and milk processing industry plants are major parts of California’s economy. A by-product of these operations is a waste stream that needs to be disposed properly. The solid waste is generally land filled and the liquids are neutralized and discharged according to strict regulations. Both these operations add to the food processor’s operating expenses. There are over 4600 food and beverage manufacturers and 121 milk processors in the state, which collectively produce a resource that has a potential to be co-digested with sludge.

The PIER study cited above assessed the technical and market potential for added CHP capacity at WWTP locations if the food processing. The study concluded that co-digestion of the food processing waste stream, in the long run could increase the technical and market potential for CHP capacity by 129 MW and 97 MW, respectively.

Fats, oils and grease (FOG) from food establishments mentioned previously, when not stopped at the source, create expensive disruptions in the sewage pipelines. When collected through grease traps and other means, they become a valuable biowaste for digesters. Approximately 28 million Californians live in metropolitan areas and annually generate 275,000 tonnes of restaurant waste oils/grease are produced per year. This FOG has a potential to yield 1.2 billion scf of gas, enough to supply about 10 MW of base load generation capacity. Tipping fees and the additional available gas could be sufficient to improve the economics for small WWTPs which otherwise may not consider developing CHP projects.

The WWTP plant in Millbrae, CA project demonstrated that adding grease/oil digestion to an otherwise uneconomical small project can result in a cost-effective CHP system.


Besides the resource availability, realizing the full potential by digesting various bio-wastes at WWTPs for electricity generation depends on the interplay of three major factors: technology, economics and regulations.


A CHP system consists of an electric generator and a prime mover (except in the case of a fuel cell), waste heat recovery systems, a digester to generate gas, equipment to clean the gas, mixers, waste heat recovery equipment, pollution control equipment and instruments to monitoring and measure pollution. The system components are generally selected based on the quantity of gas available, the regulatory regime in effect and cost considerations.

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The technology choice for electricity generation and waste heat recovery influences a CHP project’s economic viability. Major factors in selecting technologies are the ability to efficiently convert biogas into electricity, and cost-effectively recover heat for on-site use. The cost of emission control and monitoring are also critical factors in selecting one technology over another.

There are many CHP technologies; each has different benefits and drawbacks. Selection of a specific technology for the CHP system is done by optimizing the efficiency, emissions and cost of the technology. Its deployment is determined by site-specific conditions. The four main technology options are:

  • internal combustion (IC)
  • engines
  • microturbines
  • gas turbines
  • fuel cells.

The size of the CHP system is also determined by the amount of gas that is available at each digester site. The current installations in California range from a 30 kW to 3 MW of different configurations of microturbines, fuel cell modules, small turbines or IC engines. Any of these technologies could be deployed as one large unit or multiple units of a smaller size, depending on the certainty and timing of biogas availability. IC engines are the most common equipment used for CHP systems at WWTPs. Microturbines and small turbines are also common but are installed less frequently. Fuel cells are the least common but are gaining fast acceptance due to generous tax credits and non-existent emissions.

All these technologies require that the digester biogas be separated from hydrogen sulfide, moisture, siloxane, and other trace elements that impact the performance of the generating technologies. Microturbines and fuel cells are more susceptible to these contaminants than IC engines. Early installations of microturbines were seriously hampered by failure of the gas scrubbing equipment. Not removing the contaminants result in expensive maintenance, interruptions, and under-performance. Often the cost of gas scrubbing equipment renders smaller projects economically less attractive.

Although anaerobic digesters are quite common and have been used for decades, the ease of operation and maintenance of one type of digester over the other can be quite different. While discussing digester technologies, a few researchers and operators of digester systems shared the view that some European digesters have relatively better output of biogas and lower maintenance costs. While there is a lot of interest in these improved technologies, they need to be tested under California conditions.

The biggest uncertainty until now has been the impact on the digester chemistry of mixing diverse bio-waste in WWTP digesters. The PIER study cited earlier explored the feasibility of co-digesting different bio-waste in WWTP and has shown the technical viability of co-digesting varied biowaste. However, this is still on-going work and the mixing of different types of food wastes in different volumes to digesters still requires additional study.

In California monitoring, measuring, and controlling emissions is critical for obtaining permits, and operating within the state’s requirements. As regulations controlling criteria pollutants change and become more stringent, it becomes imperative that technologies for monitoring, measuring and validating (MMV) emission reductions be accurate and inexpensive. The need for inexpensive and well-calibrated MMV technologies becomes more critical as requirements for GHG reduction are implemented and marketable carbon credits are created. Measurement according to acceptable and established protocols becomes critical to participate in the carbon market.


Ultimately, the decision to develop a CHP system hinges on the WWTPs operating economics. The primary business of a WWTP is to quickly and cost-effectively dispose off the incoming waste stream in accordance with the regulations. In this context, the use of digesters and the development of CHP systems to reduce methane is based on assessing energy savings, and the relative costs of compliance and non-compliance (penalties) with water and air emission regulations. Sometimes the decision depends on the potential to export the electricity to a local utility. The transaction cost of entering into a contract to sell power figures in the economic calculation. Many of the factors considered in developing a business case for installing a CHP system are listed in Table 1.

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California’s City of Tulare wastewater treatment plant incorporates a 900 kW CHP plant based on three 300 kW fuel cell units from FuelCell Energy, which burn anaerobic digester gas produced on-site. The on-site energy system also includes an engine generator and a solar PV installation above car parking facilities.

A potential of digesters to reduce the volume of sludge needing disposal by 40-50% figures prominently in the decision to install a digester. Large plants that want to reduce shipments of sludge to distant locations normally have digesters on site although some may choose flare the gas into the atmosphere rather than generate electricity on site. Until the recent past, due to the low cost of petrol or diesel and limited concern about the GHG and other pollutants, transporting to the far off location made economic sense. The rising cost of energy and increasing resentment by localities to accept waste from other cities or counties is changing the economics in favor of expanding digester capacities or building new ones.

The use of pumps, motors, and aeration equipment require electricity and approximately 35% of the operating costs of WWTPs are energy costs. In California the electricity prices range from the low of 8 cents per kWh during off peak periods to a high of 30 cents during the summer peak. In 2008 and 2009, the average electricity rates in California’s major urban centers have ranged from 13.5 cents per kWh and 16.5 cents per kWh respectively.

The on-site energy use is also increasing as many WWTPs resort to using more energy intensive technologies to meet increasingly stringent water discharge rules. Often there are high demand charges for increased electrical loads. The rising cost of electricity, especially during peak hours, has led WWTP operators to explore energy efficiency and self generation options. Some of the plants also buy natural gas from the local utility to heat the digesters.

Although a few large WWTPs in California supply electricity to local utilities and get paid for them, they are now a rarity. Electricity production from a CHP system at a WWTP varies with the gas production, and the fluctuating power does not command a high price from the utilities. Therefore the future development of CHP for WWTPs is likely to be driven mostly by the site-specific economic factors described above.

Lastly, the development of more CHP is very much affected by availability of financing, subsidies, tax credits, favorable tax treatments, and renewable energy credits. Till recent past, CHP systems were also eligible for self-generation incentives (rebates), but since their abrogation, very few WWTPs have developed CHP systems.


In California, environmental regulations figure prominently in evaluating the viability of a CHP project at a WWTP. The regulations, both prevailing and proposed, are stipulated by the local air quality management districts (AQMDs) and from the Global Warming Solutions Act of 2006, commonly referred to as Assembly Bill 32 or simply AB32. Ironically, sometimes complying with one regulation often results in violating the intent of another.

As an electricity generator, CHP facilities are generally subject to a relatively stricter set of pollution control rules than those applied to a WTTP that flares its methane without electric generation. Many WWTP sites have an existing permit that allows them to burn biogas from digesters through flaring. If they decide to install a CHP system, they are reclassified as an electricity generator. Changed classification subjects them to a different set of emission compliance rules, which adds to the cost of emission containment. Although the net impact on the emission of controlled pollutants from the site may change only slightly, the rules applicable to electricity generation are more restrictive and require investment in new and expensive emission abatement equipment.

This investment may adversely affect the decision by WWTP to install CHP in some jurisdictions. This reclassification has become a major barrier that needs to be addressed through policy initiatives

Under the AB32 a site generating more than 1 MW of power and producing more than 2500 tonnes of CO2 equivalent is subject to reporting requirements. The added reporting requirements may not be onerous, but uncertainty about the required reporting may discourage CHP installation. Under the proposed rules, a WWTP that flares the combusted biogas is treated as ‘industrial’ and is subject to reporting requirements only if it exceeds 25,000 tonnes per year.

Moreover, the impact of possible carbon trading rules in California and the US is still uncertain, so the economic benefits of reducing carbon emissions are not presently known. Although carbon dioxide from WWTP digesters is deemed biogenic and, therefore, exempt to some extent, this is not the case for nitrous oxide (N2O) and methane from WWTP digesters. The eligibility of N2O and methane reduction for carbon reduction credits, and their validation and tradability are also unknown and create further uncertainty for WWTP owners who are trying to understand what developing CHP will mean to them in the future.

California AQMDs have stringent rules and regulations on emitting oxides of nitrogen (NOx) and particulate matters (PM). Currently the biggest hurdles for a CHP installation are the paucity and cost of Emission Reduction Credits (ERC) for NOx and PM emissions. In some AQMDs ERCs are either not available or are prohibitively expensive thus adversely affecting the project economics. The need for mitigation devices, such as selective catalytic reduction (SCR), may also seriously affect economic feasibility.

To comply with these regulations or to escape them altogether, fuel cells or microturbines often become the technology of choice, provided the subsidies are available to compensate for higher fuel cell costs or the cost of scrubbing and pressurizing the gas for microturbines. If these technology options are not economic, IC engines are usually chosen for CHP operations, in which case most of the air quality challenges are related to NOx control.


The cumulative potential for WWTP-based CHP of approximately 450 MW is much larger than previously assumed. The increase in potential is due to addition of other biodegradable materials which until recently were not digested at WWTPs. The primary function of these facilities is to provide cost-effective treatment of sewage, but the opportunity to reduce GHG emissions from other wastes and create additional CHP capacity need not compromise that responsibility. In fact, when properly structured and executed, these new opportunities will compliment the primary functions of WWTPs and generate additional revenue through tipping fees. This expanded role increases the market potential of WWTP-based CHP more than four-fold, raising it from 100 MW to 450 MW.

Barriers to investment in and installation of a CHP system severely limit development of electrical capacity using sewage waste and other bio-wastes. The complexities associated with technology choices, economic factors and regulatory issues further complicate decisions by WWTP operators to develop CHP at their facilities. Progress has been slow in resolving regulatory issues that keep facility owners from investing in clean and efficient CHP. Their resolution is necessary if CHP is to play a significant role to support the state’s environmental and efficiency policies.

In addition to reducing reliance on fossil fuels, reducing GHG emissions, and efficient use of waste heat, WWTPs with CHP can help reduce the impact of food processing, dairy and restaurant grease and oil waste on California landfills and water supplies.

Besides supporting technology advancement, California’s energy agencies are contemplating and have already promulgated some policies that support the development of clean and efficient CHP at WWTPs. Most policy initiatives focus on streamlining or modifying existing programmes, procedures, protocols, or permitting issues to support the development of WWTP market potential. Some of these recommendations involve a single state agency, while others will require the active engagement of multiple agencies and industry stakeholders for implementation. Restoring some of the rebates and development of feed-in-tariffs will go a long way in realizing the sewage based CHP potential.

California has a track record for being in the vanguard of renewable energy development. Hopefully the biogas from sewage plants can contribute to its fullest potential.

Pramod Kulkarni is with the Electricity Analysis Office, Electricity and Demand Analysis Division, California Energy Commission, Sacramento, California, US. Email:


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