The document discusses recent trends in anaerobic digestion (AD) within publicly owned treatment works (POTWs) and highlights the increasing viability and challenges surrounding biogas production. Key trends include favorable regulatory changes, the need for improved waste treatment options, and growth in CNG vehicle usage, while challenges consist of gas cleanup requirements and complex commercial arrangements. Opportunities for biogas valorization are on the rise, aided by advancements in gas treatment technologies and the strategic location of AD systems near urban CNG fleets and natural gas infrastructure.

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Recent Trends
There are over 1200 Publicly Owned
Treatment Works (POTW) that have
anaerobic digestion (AD) as part of
their wastewater treatment system.
Several trends and legislative
changes are converging to increase
interest in the production and
valorization of biogas:
ƒƒ Favorable regulatory rules
changes. In 2014, the Final Rule
for RFS II enabled biogas derived
from approved pathways to qualify
for D3 RINs. These are RINs for
cellulosic biofuels, which attract
the highest value. The qualifying
uses for the biogas are CNG
vehicles, pipeline injection, and
electricity derived from biogas.
The latter qualifies since it can be
used to power electric cars.
ƒƒ Increasingly stringent
requirements for the treatment and
disposal of primary and secondary
sludges from POTWs.
ƒƒ Increasingly stringent constraints
on the disposal of wet agricultural
wastes, primarily manure and
dairy wastes. These are high in
organic matter and nutrients.
ƒƒ Increasing use of CNG powered
vehicle fleets by municipalities
and the private sector (e.g. waste
management).
Biogas Recent Trends,
Challenges and Opportunities:
Broadly speaking, large-scale wastewater treatment sites (e.g. POTWs,
industrial sites) have tended to adopt packaged systems from a considerable
number of AD vendors. Dairy and livestock farmers, who need to dispose of
their wastes, have more often opted for less highly engineered (i.e. cheaper)
AD systems, some of which can be as simple as a lined, covered pond with a
mixing pump.
The majority of institutional and farm-owned AD systems burn the biogas
on-site to provide process and/or facility heating. Some also use the biogas to
raise steam or to power genset engines.
Challenges
The technology for AD is relatively mature, with a number of vendors offering
packaged systems. There are several design variations on the market, each
with their sweet spot in terms of applicability. The choice of AD type is typically
driven by
ƒƒ Waste throughput/scale
ƒƒ Waste composition and variability
While the AD technology is mature and has been widely adopted, valorization
of the biogas produced has proven more challenging. As stated previously,
the majority of AD systems burn the biogas on-site, for process and/or facility
heating. The heating needs at most locations are seasonal, so there is often an
excess of biogas, particularly in the summer. Excess biogas is typically flared,
to avoid methane emission. Locations that have a continuous steam use have
an advantage in that they can typically burn all the biogas to offset natural
gas (or oil) in the boiler. Some locations using AD have a genset engine (e.g.
Jenbacher, Wartsila, etc.) to generate electricity from biogas.
The maximum value of the biogas is attained by gaining D3 RIN credits. In
order to achieve this, the biogas must be used as a fuel. This can be by use in
CHG vehicles, injection into pipelines, or generating electricity.
The fact that there a relatively small number of sites that use AD biogas
to generate D3 RINs indicates the difficulties in accomplishing this. These
challenges span both technical and commercial issues.
ƒƒ Gas cleanup – biogas from AD contains methane, CO2, H2S, moisture, and
siloxanes. The biogas typically has a fuel value of 500-650 BTU/scf. The fuel
value is dependent on the feed composition. The fuel value of natural gas
is around 1000 BTU/scf. In order to be used for internal combustion engine
fuel, or injected into a natural gas pipeline, the biogas must be processed
to remove the CO2, H2S, moisture and siloxanes. In the case of pipeline
injection, the gas must meet very stringent quality requirements. The gas

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utilities typically mandate that the following equipment, designed or certified by themselves, is installed prior to
injection into their pipeline
yy Gas chromatograph
yy Custody transfer flowmeter
yy Regulator
yy Remote terminal unit (RTU)
yy Emergency shut-off valve
yy Gas odorizer
This equipment costs in the neighborhood of $1 million depending on flowrates. The biogas quality requirements for
injection into the Xcel Energy distribution pipeline is shown in the table below.
Constituents/Properties Limit Units
Higher Heating Value (HHV) 965-1,100 BTU/scf
Wobbe (based on HHV) 1,185-1,285
Carbon Dioxide (mol %) 3.0 mol%
Oxygen 2.0 mol%
Total Inerts 14.3 mol%
H2
S) 0.25 (4) gr/Cscf (ppmv)
Total Sulfur 5.0 (85) gr/Cscf (ppmv)
Hydrocarbon Dew Point Cricondentherm 15 degrees F
Water Vapor Content 3 Ib/MMscf
Dust, Dirt, Scum, and Other Solids Free of
Water and Hydrocarbons in Liquid Form Free of
Temperature 32-110 degrees F
ƒƒ Scale and location – Natural gas is a high volume business. The existing natural gas infrastructure is based on
extraction, processing, compression, transmission, and distribution of large volumes of gas. In 2016, the United States
consumed about 27.49 trillion cubic feet (Tcf) of natural gas (EIA). The quantity of biogas produced is a fraction of
1% of the total quantity of natural gas consumed. In addition, anaerobic digesters are located where the waste is
produced. This results in most of the gas being stranded, and only suitable for local use. The scale of AD systems
is a hindrance to generation of electricity using biogas. The extent of gas cleanup for electricity generation is less.
Typically, only the removal of H2S (for permitting reasons) and siloxanes (to prevent engine fouling) is required.
However, the electrical power generation and conditioning equipment to enable connection to the grid is prohibitively
expensive for small-scale systems. For the most part, electricity generated from biogas is used locally to the AD
system, and not via connection to the grid.
ƒƒ Commercial Issues – the commercial/contractual terms for a biogas cleanup and use program have proven difficult to
resolve. Wastewater treatment plants, in many cases, do not have much interest in operating a fuel plant. They will
lease the land required for the gas clean-up systems to the operator. Likewise, the gas utilities or fleet operators who
would be the purchasers of the gas do not typically have any interest in operating the plant. They primarily want the

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gas and the RINs. Therefore, it falls to a project developer to raise the capital and assume the risk of the project. A
typical straight payback for such a project is 4-6 years, assuming a D3 RIN value of $2.00. A D3 RIN is assigned to
each 77,000 BTU of natural gas. Thus, each MMBTU of natural gas (about 1000 scf) has around $26 of RIN value.
This compares to a wholesale industrial price for natural gas of $4 per MMBTU. This makes biogas to transportation
fuel projects attractive at first glance. However, the devil is in the detail. The division of this value between the POTW,
the project developer/operator, and the gas utility is challenging to reconcile in a manner that results in a project that
is attractive to a developer. The currently high value of the D3 RINs is driven by the scarcity of qualifying fuels. If
the gap between the RFS volumes and commercially available D3 RIN fuel quantities decreases, the RIN value will
diminish and erode the financial basis for projects.
Opportunity
Despite the hurdles outlined in the preceding section, there is increasing interest in biogas valorization projects. The
challenge of developing cost-effective gas treating systems at scales suitable for anaerobic digesters has been solved.
Several vendors offer packaged systems with process performance wraps. These include Unison, Generon, and
ESC Energy Systems. These employ mature process technologies, using physical processes. Additionally, there are
other treatment processes being developed, which may reduce CAPEX and OPEX for treatment. An example of this is
biological treatment for H2S removal.
Likewise, the issue of location is surmountable. While it may not make sense to use the biogas for transportation fuel
and qualify for D3 RINs at many AD system locations, with over 1200 AD systems in operation at wastewater treatment
plants, there are a significant number that will be operating close to either CNG fleet operators, or natural gas distribution
infrastructure. These are most commonly in urban areas.
If a company were to develop a standardized technical and contractual approach, and be willing to own and operate the
gas treatment system, then commercial terms could likely be suitable to the host wastewater treatment plants.