Jacobson-taking Your Digester Gas - Final

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Preprint, Residuals and Biosolids 2012, March 25-28, 2012, Raleigh, NC Page 1 of 25

Taking Your Digester Gas on the Road:

The Case to Upgrade Digester Gas for Vehicle Fuel

Eron Jacobson, Brown and CaldwellJim Schettler, Brown and CaldwellChristopher Muller, Brown and Caldwell

Jing Luo, Pima CountyR

egional Wastewater Reclamation DepartmentBrown and Caldwell701 Pike Street, Suite 1200Seattle, Washington 98101(206) 749-2883

KEY WORDS

Digester gas, biogas, biomethane, natural gas, gas separation, CNG, vehicle fuel

ABSTRACT

Often digester gas generated by anaerobic digestion at WWTPs is used to produce heat andelectricity through cogeneration, but under the right market conditions digester gas may providebetter economic and environmental value as a vehicle fuel. Electricity is relatively inexpensive insome parts of the country and the payback for the installation of cogeneration is noteconomically attractive. While the use of digester gas for anaerobic digester process and spaceheating in a boiler is still often inexpensive, not all of the digester gas is used throughout theyearespecially during the spring and summer months. This leaves some or all of the digestergas available for an alternative end use.

Two case studiesthe City of Tacoma, Washington, and Pima County (Tucson), Arizonaarepresented where digester gas end-use alternatives were evaluated and resulted in vehicle fuelproduction being identified as the most cost-effective alternative, over other more traditional enduses. Both of these locations have relatively low electricity costs (less than about $0.06 perkilowatt-hour). A quantity of digester gas sufficient to make 100 kilowatt-hours of electricity candisplace roughly 23 to 26 liters of diesel fuel or 26 to 30 liters of gasoline for vehicle fuel. Thispaper discusses the technologies, life-cycle costs, and carbon emissions reductions thatdemonstrate that for these utilities, converting their digester gas to vehicle fuel was the besteconomical and a good environmental use of their resource.

As the role of wastewater utilities expands from treatment to resource recovery, understandingthe best use of those recovered resources will serve only to improve the long-term sustainabilityof operations, fiscal and environmental. This paper discusses the technical aspects of vehicle fuelproduction and the likely impacts to long-term operating costs and capital budgets, along withthe benefits to plant operators, design engineers, and utility managers.

INTRODUCTIONDigester gas from anaerobic digestion of municipal sewage sludge in its raw form is limited in itsend uses because it has only medium heating or British thermal unit (Btu) value and because it


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includes undesirable constituents such as hydrogen sulfide (H2S), siloxanes, and water. Manywastewater treatment plants (WWTPs) utilize a portion of the digester gas in its raw form inboilers for process and space heating and rarely use all of the gas on an annual basis. Boilers area relatively inexpensive technology for digester gas utilization. Cogeneration or combined heatand power applications are also common but are more expensive and often require removal of

the majority of these impurities prior to combustion. When coupled with operating costs andwhere electricity rates are low, the economic payback period for a cogeneration system with gastreatment can be quite long.

Digester gas end uses can often be broadened by removing the undesirable constituents andseparating out the carbon dioxide (CO2) from the methane (CH4) to produce a high-Btu pipeline-quality gas (i.e., renewable natural gas or biomethane). Gas separation processes have been usedfor decades in landfill gas recovery facilities and longer in the natural gas industry. Biomethane,like natural gas, can also be compressed and used as a fuel for buses, light trucks, refuse haulers,and other vehicles, which are all common fleet vehicles for many municipalities. Usingcompressed biomethane as a vehicle fuel in many locations can provide a positive economic

payback by offsetting the cost of diesel fuel or gasoline, which continue to escalate and haveshown significant volatility, making budgeting and cost control difficult for many utilities.

Digester gas is a biogenic and renewable energy source, and the use of digester gas-derivedbiomethane as a vehicle fuel can reduce the greenhouse gas (GHG) emissions and criteriapollutants such as carbon monoxide (CO) and nitrogen oxides (NOx) that would otherwise begenerated from combustion of gasoline or diesel fuel. The economic and environmentaladvantages of upgrading biogas to biomethane are further supported if grid electricity isinexpensive and is generated by renewable sources (e.g., hydropower), such as the majority ofthat supplied to the Pacific Northwest. Thus the importance of site location is critical. TheWWTP should be in close proximity to vehicles that may use the fuel and to a natural gaspipeline. This paper discusses the different technologies for upgrading digester gas to vehiclefuel quality and compressed vehicle fueling technologies. It also presents two case studies inwhich utilities have found this to the best end use for their WWTP digester gas.

Biogas Upgrading to Biomethane

Conversion of biogas to compressed high-Btu pipeline-quality natural gas (biomethane) forpipeline or fuel vehicle use is not an entirely new concept. More than 30 plants in the UnitedStates are currently upgrading landfill gas to high-Btu compressed biomethane (LMOP 2009).Sweden has more than 40 biogas upgrading plants and Germany has about 25 operating onlandfill gas or digester biogas (De Arespacochaga 2010). Digester gas is similar to landfill gas,but in many ways is easier to process because of much lower concentrations of nitrogen (N2),oxygen (O2), and volatile organic compounds (VOCs). A handful of WWTPs upgrade biogas tobiomethane, and the number of plants is growing. Current plants include:

King County South Plant, in Renton, Washington, operates two 33,650 cubic meter perday (m3/day) gas upgrading systems (Figure 1) that have been injecting biomethane intothe Puget Sound Energy (PSE) natural gas pipeline for more than 20 years.


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Similarly, to create pipeline-quality biomethane, a number of undesirable constituents must beremoved from biogas. The unwanted constituents of biogas can include hydrogen sulfide, water,siloxanes, VOCs, ammonia, carbon dioxide, nitrogen, oxygen, and particulate. The qualityrequirements for biomethane and the processes for upgrading biogas are very similar for vehiclefuel and for direct injection into the natural gas pipeline. The Society of Automotive Engineers

(SAE) published a recommended practice or fuel quality specification for compressed natural gas(CNG) vehicle fuel SAE J1616. The contractual specifications for injecting compressedbiomethane into a natural gas pipeline vary to a small degree among pipeline owners (GTN2005). The SAE recommendation and typical pipeline requirements for heating value and WobbeIndex (a measure of fuel energy flow through a fixed orifice) generally dictate 97 percentmethane or higher in the biomethane. The biogas upgrading system needs to consistently meetthe methane content and other gas requirements set forth by the vehicle engine specificationand/or negotiated by the natural gas utility. A comparison of typical natural gas qualityrequirements for natural gas pipelines, vehicle fuel, and biomethane is provided in Table 1.

Table 1. Compressed Biomethane Gas Constituents Comparison of Natural Gas with

Compressed Natural Gas and Biomethane Composition

ConstituentCommercialnatural gasvariability f

Typical naturalgas pipeline

requirements e

CNG vehiclefuel (SAE

J1616)

Examplebiomethanerequirements

Methane, CH4, % by volume 70100 No limit given No limitgiven

> 9798

Ethane, C2H6,% by volume 016 Variesd Varies d 0

Propane, C3H8 , % by volume 010 Variesd Varies d 0

Butane, C4H10, % by volume 04 Variesd Varies d 0

Heavier hydrocarbons, C5 +,

% by volume

< 1 Varies d Varies d 0

Carbon dioxide, CO2, % byvolume

02 < 23 < 3 < 23

Nitrogen, N2, % by volume 014 < 34g No limit

given< 3 g

Oxygen, O2, % by volume < 1 < 0.20.4 -a < 0.20.4

Hydrogen, H2 % by volume < 1 No limit given No limitgiven

< 0.2

Water, H2O, mg/m3 Per

specification< 65110 - b 35.437.1 No limitgiven

> 35.436.7

Wobbe Index, MJ/m3 (perHHV)

Varies 47.752.9 48.552.9 c 47.751.6

Other common objectionablesubstances (e.g., siloxanes,dust)

0 0 0 0


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a Oxygen must be kept below the flammability limit per SAE J1616, National Fire Protection Association(NFPA) 87, and other codes.

b Dew point of 5.6C below the monthly lowest dry-bulb temperature at maximum container pressure.c An acceptable Wobbe Index range may be 44.7 to 46.6 MJ/m3 at high altitude per SAE J1616.dHydrocarbon dew point temperature may restrict content and dew point may vary with the deliverypressure.

e ref. GTN 2006, NWP 2010.fref. Baukal and Schwartz 2001.g Including O2 and CO2.

The major difference between biomethane for vehicle fuel and pipeline injection is the requiredfinal gas pressure. Vehicle fuel requires a final pressure of 210 to 250 bar. Natural gas pipelinepressures are typically much lower, usually 10 to 40 bar. The high pressure requirement forvehicle fuel is due to lower volumetric energy density of natural gas compared to gasoline ordiesel fuel.

Biogas CO2 Separation Technologies

The biogas treatment process for pipeline injection or for vehicle use depends largely on thetechnology chosen for removal of CO2, or CO2 separation and the needs of the buyer or user. Thefollowing three major categories of gas separation technologies are commonly used to removeCO2 for biogas:

physical and chemical solvents pressure swing adsorption (PSA) membranes

Often these technologies are used in concert in sequential unit operations. The choice of CO2removal technologies during detailed design should take many factors into account, including

CH4 recovery efficiency, reliability, power and heat requirements, maintainability, final pressure,gas quality, size, and cost. A brief description of the technologies follows.

Solvents (Absorption)

Solvent systems for CO2 removal work by selectively absorbing CO2 from the biogas whileallowing methane to pass. Absorption is the transfer process of a gas constituent into a liquid inwhich it is soluble. The removal process of CO2 from biogas usually occurs at pressures greaterthan 7 bar to increase methane recovery rates. The compressed biogas flows upward through apacked tower while the solvent flows downward in a counter-current fashion. The compressedbiogas leaves the tower with CO2 levels reduced to the required end-product quality. Theselective absorption of CO2 over methane allows the methane to pass through while removing

CO2. Regeneration of the solvent is required for the closed-loop system and is accomplished byreducing the pressure of the solvent and/or by heating. This process releases the CO2, H2S, andother residual gases, which are then burned in a flare, or scrubbed and vented. Solvents that areused for biogas scrubbing include water, amines, and glycols.

Water

The absorption of CO2 into water is a physical process. Physical absorption has the advantageover chemical absorption in that regeneration of the solvent does not require heating, only


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pressure reduction. The use of water has the advantage that the solvent makeup for a closed-loopsystem is readily available and requires no chemical handling. The King County South Plant hasbeen using water absorption technology for more than 25 years to produce biomethane for thenatural gas pipeline.

Flotech is a New Zealand-based company that has manufactured packaged water solvent systemsfor 25 years. Flotech makes water absorption systems called Greenlane (Figure 2) for gas flowsfrom 2,040 m3/day to more than 73,400 m3/day. This technology has been installed in at least 29facilities in Canada, Europe, Japan, New Zealand, and other countries.

Figure 2. Greenlane Flotech Manuka system for 2,040 m3/day flow rate

Amines

Amines are a chemical solvent used in absorption processes to remove CO2 and H2S from biogasand natural gas. The chemical absorption process is reversible and the solvents are typically veryselective for acid gas removal (i.e., CO2 and H2S). The acid gas constituents chemically reactwith components of the liquid to form a loosely bound reaction product. The chemical reaction isreversible by reducing the pressure of the solvent and heating. The heating process adds a degreeof complexity compared to physical solvents, but the heat can be recoverable. The heat requiredto regenerate the solvent and the general complexity of the system can be drawbacks to thistechnology for WWTP applications of small size. Chemical solvents are used quite often atlarger scales for natural gas processing and in some medium-scale biogas projects in Europe andlandfills in the United States. Lckeby Water of Sweden reportedly has installed at least 10 PuracCApure systems utilizing amine solutions at WWTPs, landfills, and farm digesters in Sweden,Norway, and Germany. The system capacities range from 5,000 m3/day to 82,800 m3/day.

Glycols (e.g., Selexol) and Other Physical SolventsGlycols are physical solvents that dissolve or absorb CO2 and H2S in a manner similar to thewater absorption process. Because the process is physical, heating is not often required toregenerate the solvent. Only a reduction in pressure is typically required for regeneration (unlessH2S concentrations are very high [Kidnay and Parish 2006]). Physical solvents such as glycolsand methanol are far more selective of CO2 and H2S than is water, thus reducing the gas


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separation column size and flow rate of solvent circulation. While this is advantageous from anequipment capital cost perspective, the use of glycols or other physical solvents makes them lessattractive from an operations perspective because of the chemical handling. The maintenancecost for the solvent makeup can be expensive, especially if pretreatment to remove H2S is notdone first. Several glycol plants in the United States are used for landfill gas treatment, but these

are designed for much larger gas flow rates than the biogas flow rates typical to WWTPs.

Pressure Swing Adsorption

Most PSA systems take advantage of the difference in equilibrium capacities of adsorbents forCO2 at high and low pressures. Adsorbents are porous materials that naturally or throughmanufacturing have high surface areas per volume and are chosen for their selectivity for CO2.The adsorption of CO2 onto the surface of the adsorbent is a weak physical attraction by van derWaals forces. The capacity of an adsorbent for CO2 is the amount of CO2 that can be adsorbed atan equilibrium condition. The capacities at high pressure are greater than those at low pressure.PSA systems are systems of multiple packed beds, which operate continuously by having onevessel online and the other(s) in a state of regeneration. In this process, the biogas typically is

compressed to7 to 14 bar and flows through the packed bed where the CO2 is removed by theadsorbent. When the online bed reaches its capacity it is isolated from the process, and the biogasflows through a newly regenerated bed. The spent bed is regenerated by depressurizing thevessel and may use a dry regeneration gas free of CO2 to further decrease the partial pressure ofCO2 (the driving force). Adsorbents used for CO2 PSA systems include molecular sieves(zeolites) and carbon molecular sieves.

At least two North American companies currently offer standardized PSA system designs forbiogas purification: Xebec and Guild Associates. Both companies have more than 10 biogas andlandfill gas plants currently in operation. Guild Associates has at least two operating systems atWWTPs in Ohio and Texas. Both offer packaged systems with compression at sizes of 2,850m3/day up to many tens of thousands of m3/day. The Xebec systems (Figure 3) require H

2S

removal upstream of the system to maintain the capacity of the adsorbent for CO2.


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Figure 3. Small Xebec PSA system

Membranes

Membranes are thin semi-permeable barriers that selectively separate CO2 (also H2S and watervapor) from biogas. The driving force for the process is the differential partial pressures with ahigh pressure on the process side and low pressure on the waste side. The CO2 dissolves anddiffuses through the thin non-porous membranes faster than methane does. In this process, thebiogas is compressed to pressures of 14 bar or greater and sent into the membrane separationchamber, where CO2 is selectively removed. The selectivity for CO2, or the ability to remove justCO2 and not also CH4, is not as high as that of adsorbents or solvents and usually a two-stageprocess is required to have acceptable methane recovery efficiency. The waste gas from the firststage is often re-compressed, sent through another membrane separation chamber, and then re-injected into the first-stage membrane separation chamber.

The largest supplier of membranes for biogas separation is Air Liquides MEDAL (MEmbraneSystems DuPont Air Liquide), which was originally a joint venture of DuPont and Air Liquide.The technology uses polymeric fibers for the membranes, which can remove CO2, H2S, water,and about half of the oxygen if present. At least 13 landfill gas plants reported using membraneseparation to remove CO2. A picture of a membrane separation system is shown in Figure 4.


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Figure 4. Air Liquide MEDAL membrane system

Biogas Pre-Separation and Post-Separation Treatment and MonitoringTreatment prior to and/or after CO2 separation from the biogas is often required. The removal ofH2S may be necessary to protect the integrity of the adsorbent used in the PSA system and the

membranes. H2S will typically need to be removed to a low concentration as pre-separationtreatment, but may be removed as post-separation treatment on the waste gas or may becombusted with the waste gas. An activated carbon bed as post-separation treatment may berequired as a guard bed, depending on the types and quantities of impurities in the biogas. Someof the technologies also require a post-separation water removal step.

Each of the separation technologies will have a waste or off-gas stream consisting largely of theCO2 removed from the biogas, but also some CH4 and other constituents. The waste gas (or tailgas) typically has CH4 content from less than 0.1 percent up to 30 percent, depending on theseparation technology. The tail gas may be vented if methane and other VOC concentrations arevery low or combusted in a gas-assisted flare or thermal oxidizer depending on the methane

content. The lower limit for CH4 content for adequate combustion in a typical enclosed flare isabout 2230 percent. When the waste gas has a low CH4 content, a slip stream of biogas orsupport gas (e.g., natural gas or biomethane) is required to sustain combustion in a flare orthermal oxidizer. Thermal oxidizers can reduce the amount of gas required compared to anenclosed flare.

The biomethane must be odorized and the quality monitored prior to entering the natural gaspipeline or vehicle fueling station. Odorization is required for safety so that it can be detected if aleak develops downstream of the system. This involves small amounts of mercaptan beinginjected into the gas. Gas quality is typically assured through the continuous monitoring ofmethane, carbon dioxide, water, and hydrogen sulfide. This is typically accomplished with gas

chromatography-mass spectrometry and/or with individual gas analyzers. Periodic sampling forother constituents such as siloxanes and other VOCs may also be required.

Operations and Maintenance Considerations

Biogas upgrading systems generally have a more complex process than the typical cogenerationtechnologies, but not necessarily higher operations and maintenance (O&M) costs. While theprocesses may be more complex, many of the components in a biogas upgrading system arecommon to a WWTP such as gas compressors, pumps, media beds, instruments, and automated


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valves. Maintenance on these items is typical to that of the equipment. Many of the biogasupgrading system vendors offer various types of O&M service plans from remote monitoringand scheduled maintenance to operational responsibility. For most biogas upgradingtechnologies, the majority of the operating costs are in the form of electricity for compressionand for the hydrogen sulfide removal media. Thus low electricity costs help to keep overall

operational costs in check. For the most part, the CO2 separation processes do not require muchin the way of consumables. As a comparison, most cogeneration technologies require pressureboosting and removal of hydrogen sulfide, siloxanes, and water. Many of the same operatingcosts are incurred with cogeneration applications in addition to the cogeneration equipmentmaintenance itself.

Compressed Natural Gas Vehicles

Conversion of vehicles to run on CNG is relatively common, and many dedicated engines andvehicles are readily available direct from manufacturers (NGVA 2011, CARB 2007, US EPA2010). Fleet vehicles such as buses, taxis, or refuse haulers in close proximity to a WWTP offer agreat opportunity for conversion to CNG or expansion with CNG-ready vehicles. The diesel fuel

or gasoline that would otherwise be consumed by the fleet vehicles can be displaced bycompressed biomethane at a very competitive and stable price. A CNG vehicle fleet in closeproximity to the plant or fueling station is especially advantageous because the vehicles couldutilize the biomethane without significant increases in mileage traveled for re-fueling.

Operation of vehicles on natural gas or biomethane has advantages and disadvantages over dieselfuel or gasoline. According to the United States Environmental Protection Agency (US EPA)(US EPA 2002), natural gas vehicle emissions when compared to gasoline emissions release:

90 to 97 percent less carbon monoxide 25 percent less carbon dioxide

35 to 60 percent less nitrogen oxides 50 to 75 percent less non-methane hydrocarbons little to no particulate matter

Some experience has shown that CNG vehicles have less maintenance and longer engine lifebecause natural gas burns cleaner than diesel fuel or gasoline (Puget Sound Clean Cities 2010,US EPA 2002, Chandler et al. 2006). However, the replacement costs for spark plugs and otherfuel delivery system-related issues have been known to cause the CNG vehicles to havemarginally higher maintenance costs (Chandler et al. 2002, Chandler et al. 2006, Bell 2011). Theefficiency of CNG vehicles can also be lower than diesels because of the lower compressionratios of spark-ignition when compared to compression ignition engines. Additional

disadvantages include requirements for specialized maintenance training for CNG vehicles,limited vehicle range because CNG has 20 to 25 percent of the energy density of gasoline anddiesel fuel, and slower fuel filling times for CNG vehicles.

A number of traits make natural gas or biomethane a relatively safe vehicle fuel even though it isflammable (US EPA 2002). With a specific gravity of about 0.55, methane gas is lighter than airand has a tendency to rise and disperse rather than pooling on the ground. It also has a relativelynarrow flammability range of about 5 to 15 percent in air and a higher ignition temperature than


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gasoline. Proper safety precautions must be taken as flammable mixtures can occur in closedspaces.

Biomethane Compression, Drying, Storage, and Fueling StationsThe use of biomethane as a vehicle fuel requires additional equipment for compression, storage,

and fueling. CNG vehicles require pressures of about 250 bar. Because pressures leaving thebiogas upgrading system are typically between 7 and 14 bar, an additional compression stage isrequired. High-pressure compression skids are common to the CNG market. Most conventionalCNG fueling facilities compress natural gas from pipeline pressures to greater than 250 bar.CNG compression skids with and without acoustical enclosures are shown in Figure 5.Additional gas dryers are likely to be required to prevent liquid water in the vehicle fuel. As gaspressure is increased to vehicle fuel pressures, the ability of the gas to retain water vapordecreases.

Figure 5. Gardner Denver packaged CNG compression skid and GreenField compressor

with acoustical enclosure

CNG fueling stations are required to fill the CNG vehicles and can be one of two types. Time-fillstations slowly fill a number of vehicles over an extended period of time. The vehicles areconnected to a filling hose and left unattended to fill for typically 8 to 12 hours. The fillingautomatically starts when a vehicle storage tank is connected and empty, and stops when it isfull. This type of fueling station is often appropriate for fleet vehicles such as buses, trucks, orrefuses haulers, which are parked at their fueling station overnight. A fast-fill station acts tocompress the gas as required to fill a vehicle in a short time, often as little as 10 to 30 minutesdepending on the storage vessel size and compressor capacities. A picture of a time-fill fuelingstation is shown in Figure 6 and a fast-fill fuel station in Figure 7.


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Figure 6. Time-fill fueling posts from Gas Equipment Systems Inc. (GESI)

Figure 7. Fast-fill fueling station from GreenField


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Regardless of its end use, digester gas is produced continuously, and some form of productionequalization or storage system is often required. Vehicle fueling demand is not constant, butdigester gas production isalbeit at an uneven rate. To utilize all of the digester gas produced ata WWTP not required for plant heating needs, storage vessels can be sized to store thebiomethane during the day when the fleet vehicles are in use and on the weekends. However,

system costs to provide multi-day storage can be cost-prohibitive.

An alternative to storage is to inject excess biomethane to the natural gas pipeline system forstorage or transport. Biomethane can be injected into the pipeline when CNG fleet vehicles arenot filling, and biomethane with supplemental natural gas could fill vehicles at a later time. Inthis way, the natural gas pipeline acts as a de facto storage system for the biomethaneproduction. The natural gas pipeline system may also be used as a transport mechanism to movebiomethane from a WWTP to a vehicle fueling station at a different location. This type offlexibility requires the cooperation of the local natural gas provider and existing compatibleinfrastructure of the natural gas critical components. If all of the biomethane is not used, a long-term favorable contract price for the remaining biomethane is beneficial. Figure 8 shows one

possible configuration for a complete CNG fast-fill fueling station.

Figure 8. Complete fueling system with fast-fill station from GreenField

CNG Vehicle PurchaseCNG vehicles are available directly from original equipment manufacturers from passengervehicles to heavy duty vehicles. The Honda Civic GX, Chevy Express, Ford Transit, and GMC

Savana are original equipment manufacturer offerings for dedicated CNG light and medium dutyvehicles. A number of industrial vehicle manufacturers sell refuse haulers, tractor-trailers, buses,and other heavy duty vehicles that can be built around CNG engines. The U.S. Department ofEnergys Alternative Fuels and Advanced Data Center maintains a list of CNG vehiclemanufacturers and models.


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An example of a light duty vehicle for pricing comparison of the CNG version versus thegasoline version is the Honda Civic. The list cost for the Honda Civic CNG is about $25,500.This can be compared to the gasoline version at $15,600$24,400.

Conversations with Peterbilt indicate that a new refuse hauler complete with CNG storage and

fuel delivery system would be about $250,000 compared to about $220,000 for a diesel version.The total cost is approximate and depends on the configuration selected, but the difference wouldremain at about $30,000 (Bell 2011).

Vehicle Conversion

The conversion of diesel-engine vehicles to operate on CNG or biomethane involvesmodifications to the vehicle. The storage of CNG on the vehicle requires high-pressure storagevessels, which typically take up more space than diesel fuel tanks. The ignition of biomethane inthe engine requires the addition of spark plugs, ignition systems, and associated wiring. A newfuel delivery system to the engine cylinders is required for the gaseous fuel instead of a liquidfuel. Finally, the engine timing and fuel-air mixture control need to be adjusted to efficiently

burn the biomethane. All of these conversions are commonly done. Conversion for a vehicle torun on compressed biomethane is the same as for CNG.

Diesel and gasoline vehicles converted to operate on natural gas must be certified to meet therequirements of the Clean Air Act. Specifically, the vehicles must comply with Mobile SourceEnforcement Memorandum 1A, including addendum and addendum revision. Certificates ofconformance for conversion of a vehicle or engine are issued by the US EPA. More than 30small-volume manufacturers can perform this service on more than 100 models of light, medium,and heavy duty vehicles (DOE 2011). Table 2 shows the conversion costs for a range of cars,vans, and trucks.

Table 2. Compressed Natural Gas Fuel Conversion Cost for Different Vehicles

VehicleReported conversion cost

in 2009 a

Ford Crown Victoria, Lincoln Town Car, Mercury Marquis $13,500

Ford E350 cargo passenger van $15,500

Ford F150, F250, F350 pickup truck $16,500$18,500

Ford E450 cutaway shuttle van $18,500$22,500

GMC Sierra 1500HD/2500HD, Chevrolet Silverado1500HD/2500HD pickup truck

$12,500$15,200

GMC Savana G1500/2500, Chevrolet Express G1500/2500

cargo/passenger van $12,500$16,000aref NGVA, 2009.

The conversion of vehicles that are close to the end of their lives is not advisable. Generally, theuseful life of a vehicle is considered to be 10 years or 193,000 kilometers (NGVA 2009).


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Grants and Funding

A number of potential tax credits, grants, and loan guarantees are available from the federalgovernment for CNG vehicles and fueling equipment. In addition to the following programs,state and local programs may also provide incentives:

Diesel Emissions Reduction Act (DERA) program: This program was created underthe Energy Policy Act of 2005. It is a grant and loan authority run through the US EPA asa competitive process. Although the original act was for fiscal years 2007 through 2011,it was recently extended for 5 more years. (http://epa.gov/cleandiesel/grantfund.htm)

Clean Cities: Clean Cities is a government-industry partnership sponsored by theDepartment of Energy. (http://www1.eere.energy.gov/cleancities/projects.html)

State Energy Program (SEP) Special Projects program: This is a program through theUS EPA that may provide a federal grant for natural gas stations.(http://www1.eere.energy.gov/wip/sep.html)

Clean Fuels Grant Program: This program provides grant funding for designated areasof ozone and carbon monoxide air quality nonattainment including low-emission buses,

alternative fuel stations, and some associated facilities.(http://fta.dot.gov/grants/13094_3560.html)

Case Study: City of Tacoma

The City of Tacoma has been investigating means of increasing sustainable operations City-widefor several years. As part of these efforts, the Wastewater Division investigated the installation ofcogeneration at the Central Treatment Plant (CTP) to reduce the electrical demand from the gridand utilize excess biogas, which is currently either used for heating or flared. As part of this prioranalysis, the project cost for installation of two 633-kilowatt (kW) internal combustion (IC)engine-generator cogeneration units in an existing facility at CTP with gas treatment was

estimated at approximately $9.2 million. The electricity rates at CTP are quite low at $0.033 perkilowatt-hour (kWh). This low electricity rate made the economic payback for the cogenerationproject unattractive, even when high-strength liquid wastes were co-digested to increase gasproduction.

In a study commissioned by the City, Brown and Caldwell (BC) looked at adding a14,225 metrictons per year of food waste to the Citys digestion system to increase biogas production toimprove the economic viability of cogeneration and to make beneficial use of a product that itcurrently hauls to landfills. The City is in a relatively unique situation; it owns and operates thewastewater, solid waste, and power utilities. The addition of pulped food waste to the digestionprocess would add 5,100 m3/day of excess digester gas not being used by the boilers for process

and space heating. It would also provide a tipping fee for disposing of the organic material, anadded revenue to offset capital and operating costs.

Several digester gas utilization alternatives were investigated to determine the highest and bestuse for the generated gas. These alternatives included the following:

A1,266 kW cogeneration system with gas treatment (earlier design)
http://epa.gov/cleandiesel/grantfund.htmhttp://epa.gov/cleandiesel/grantfund.htmhttp://epa.gov/cleandiesel/grantfund.htmhttp://www1.eere.energy.gov/cleancities/projects.htmlhttp://www1.eere.energy.gov/cleancities/projects.htmlhttp://www1.eere.energy.gov/cleancities/projects.htmlhttp://www1.eere.energy.gov/wip/sep.htmlhttp://www1.eere.energy.gov/wip/sep.htmlhttp://www1.eere.energy.gov/wip/sep.htmlhttp://fta.dot.gov/grants/13094_3560.htmlhttp://fta.dot.gov/grants/13094_3560.htmlhttp://fta.dot.gov/grants/13094_3560.htmlhttp://fta.dot.gov/grants/13094_3560.htmlhttp://www1.eere.energy.gov/wip/sep.htmlhttp://www1.eere.energy.gov/cleancities/projects.htmlhttp://epa.gov/cleandiesel/grantfund.htm


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An expanded cogeneration system with an additional 633 kW engine-generator for a1,900 kW total capacity

An 8,150 m3/day biogas upgrading system for injection to the natural gas grid with plantheat provided by digester gas to the boilers

An 8,150 m3/day biogas upgrading system with a vehicle fueling station with plant heatprovided by digester gas to the boilers

BC developed system layouts and net present values (NPVs) (capital and O&M costs) for thefood waste receiving and process facility and digester gas utilization alternatives. A number ofconditions were favorable to the biogas upgrading and vehicle fuel alternative for the City:

The Citys Solid Waste Division operates a large fleet of refuse haulers for garbage andrecycling collection, and would likely add additional haulers for collecting food wasteseparately.

The natural gas utility that serves Tacoma, PSE, already contracts with two entities topurchase biomethane. PSE has purchased biomethane from the King County Renton

South Treatment Plant since 1987. Bioenergy Washington has been upgrading landfillgas at the King County Cedar Hills Landfill to pipeline quality for sale to PSE since2008.

The Tacoma CTP has sludge heat recovery for its dual-phased digestion process, whichreduces some of the heat load at the plant and makes more digester gas available forupgrading. However, a significant portion of the digester gas would still need to be sentto CTPs existing boilers to provide plant heating.

Tacoma is located in Pierce County in the Puget Sound region. Pierce County alreadyoperates a fleet of CNG transit buses and has a CNG filling station. Many other CNGvehicle fleets and filling stations exist around the Puget Sound, making it a familiartechnology.

To utilize the compressed biomethane, the study looked at alternatives to phase in 15 new CNGrefuse haulers over 2 years and 50 new CNG refuse haulers over 5 years. The 50 CNG refusehaulers would be able to utilize all of the biomethane produced with the food waste addition tothe digesters. The cost to convert existing refuse haulers or the cost difference to buy new refusehaulers as CNG-capable were estimated at $30,000 per vehicle. There is adequate space acrossthe street from CTP for a food waste receiving station and CNG fleet slow and fast-fill fuelingstation.

The study assumed that PSE would be amenable to allowing injection of biomethane into itsnatural gas grid for use in a different location or at a different time. PSE may charge a fee for the

service of wheeling or effectively storing the gas.

Based on the 20-year NPV conducted for each of the alternatives, matching co-digestion withcompressed vehicle fuel would be the most cost-effective approach for the City. The range ofelectricity rates that cogeneration would offset included the average rate at the plant, $0.033 perkWh, and an assumed higher rate of $0.06 per kWh that might be possible to negotiate withimplementation of Washington states renewable portfolio legislation. The biomethane sale rateswere assumed to be $3.40 to $6.80 per gigajoule (GJ), which represents 50 and 100 percent of


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the natural gas rate paid by City at the time of the study, respectively. The cost of diesel fuel wasassumed to be $0.89 per liter. Table 3 summarizes the capital cost and NPV developed for eachalternative. The majority portion of the capital cost is for the food waste receiving and processingsystem, which was estimated at about $10.2 million and which is included in the capital costreported in the table. While none of the options for food waste co-digestion with biogas

utilization provide a net economic benefit, the vehicle fuel alternatives come closest to breakingeven. Grants, subsidies, and further design refinements and efficiencies may provide a positiveNPV for these alternatives.

Table 3. Summary of Capital Costs, Net Present Value Biogas Utilization Alternatives at

Tacoma CTP

Alternative comparison Capital cost 20 year NPV e

Food waste co-digestion with cogeneration a $19,400,000 ($17,900,000) to($13,300,000)

Food waste co-digestion with expanded

cogeneration

b

$21,500,000 ($18,800,000) to

($12,600,000)Food waste co-digestion with biomethaneproduction for natural gas pipeline injection(boiler heating with digester gas) c, f

$15,000,000 ($13,300,000) to($11,100,000)

Food waste co-digestion with biomethaneproduction for CNG vehicle use including time-fill station for 15 vehicles (boiler heating withdigester gas) d, f

$17,000,000 ($11,600,000) to($9,900,000)

Food waste co-digestion with biomethaneproduction for CNG vehicle use including bothtime-fill and fast-fill stations for 50 vehicles(boiler heating with digester gas) d, f

$18,900,000 ($5,700,000)

a

1.266 MW cogeneration system (two 633 kW engine-generators), power avoided at$0.033/kWh to $0.060/kWh.1.9 MW cogeneration system (three 633 kW engine-generators), power avoided at$0.033/kWh to $0.060/kWh.

c 8,150 m3/day water solvent type biogas upgrading system, natural gas sale price of$3.40/GJ to $6.80/GJ (HHV).8,150 m3/day water solvent type biogas upgrading system, natural gas sale price of$3.40/GJ to $6.80/GJ (HHV), diesel fuel cost of $0.89/liter.

eNPV assumes a net discount rate of 2.6%.

fElectricity rate at $0.033/kWh.

The compressed biomethane vehicle fuel alternatives would also provide the highest total grossGHG reductions. The primary energy sources offset are electrical power from Tacoma PowerUtility (TPU), natural gas, and diesel fuel as part of a new CNG fleet. Figure 9 shows thedifferent gross fuel/energy GHG offsets for each alternative. What is apparent is that the directfuel offsets generate up to 10 times the emissions reductions that cogeneration will producebecause of the high proportion of hydropower of TPUs electricity production. In addition, theCTP emissions of criteria pollutants (including NOx, CO, non-methane hydrocarbons, andparticulate) would be significantly lower for the biogas upgrading alternatives compared to the


18/25


onsite combustion of biogas through cogeneration. As air regulations grow stricter, permitting ofstationary combustion sources for cogeneration such as IC engine-generators also become moredifficult and is a consideration for any project.

Figure 9. Comparative gross greenhouse gas reductions from energy offset

scenarios at Tacoma Central Treatment Plant

The City of Tacoma is currently investigating the alternative of biogas upgrading for fleetvehicle use further.

Case Study: Pima County

As part of a County-wide comprehensive biosolids and biogas master plan, Pima County hasbeen investigating a number of beneficial use options for biogas utilization including use forvehicle fuel. Pima County is consolidating solids treatment from the existing Roger Road plantinto an expanded anaerobic digestion facility at the Ina Road Water Reclamation Facility (WRF).Solids loading rate to digestion at the Ina Road plant is estimated to increase to 73 metric tonsper day (dry) in 2014 and to 108 metric tons per day in 2030. The quantity of digester gasproduced at the plant will also increase significantly from about 28,300 m3/day in 2014 to 42,500m3/day in 2030. Pima County currently has very old IC engine-generators at the Ina Road WRFutilizing the biogas for cogeneration, but these units are past their useful lives. As part of thebiogas master plan, consideration was given to the Countys goals and objectives. One of theCounty goals included a requirement to beneficially utilize 100 percent of biogas produced (i.e.,

no flaring), dictating more utilization system redundancy than may be otherwise.

BC initially identified 17 candidate technologies for biogas utilization, including severalcogeneration technologies, biosolids drying, and biogas upgrading technologies to producepipeline-quality biomethane for natural gas pipeline injection and vehicle fueling. After an initialscreening of alternatives, BC developed system layouts, capital costs, and NPVs (capital andO&M costs) for the remaining utilization alternatives. These alternatives included:

0

500

1000

1500

2000

2500

3000

3500

Cogeneration

1.27 MW

Cogeneration

1.9 MW

Natural Gas

Production

Compressed

Biomethane

Diesel-15 trucks

Compressed

Biomethane

Diesel-All Use

GrossCarbonEmissionsReductions

(tonne-CO2e/year)


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A 4.4-megawatt (MW) capacity cogeneration alternative with lean-burn engine-generators and gas conditioning with an average output of about 3 MW.

Two alternatives with a 55,200 m3/day biogas upgrading system with digester gas-firedboilers providing plant heat demands, one alternative with a 11,300 m3/day compressedbiomethane fast-fill type vehicle fueling station and the other with biomethane injection

into the natural gas grid. Two alternatives with a 55,200 m3/day biogas upgrading system with effluent source

electric-driven heat pumps providing plant heat demands, one alternative with 11,300m3/day compressed biomethane fast-fill type vehicle fueling station. The heat pumpalternatives ultimately proved not to provide an economic advantage and are notpresented here.

A few key factors made the biogas upgrading alternatives attractive for the Ina Road WRF:

The composite electricity rates at the Ina Road WRF including the demand charge areunder $0.06/kWh and the potential to receive renewable energy credits from the local

electrical utility, Tucson Electric Power, is uncertain and the benefits are complicated byother contractual factors.

Pima County is located in Southern Arizona, where heating demands for the anaerobicdigestion process and space heating are relatively low most of the year. Boiler fuelrequirements would use only 3 to 35 percent of the digester gas produced. Therefore, asignificant majority of the digester gas would be available year-round for upgrading. Inaddition, much of the heat available from cogeneration would not be utilized much of theyear.

A large-diameter, high-pressure (24 bar) natural gas pipeline that is connected to the ElPaso Gas Company pipeline network runs less than a mile from the plant. The El PasoGas Company pipeline network is one of the principal deliverers of natural gas to

Southern California, improving the potential to wheel biomethane to a potentially morelucrative market.

The local natural gas utility, Southwest Gas, indicated that it is actively looking for ademonstration project of this type and would consider purchasing and/or wheeling thebiomethane for sale or vehicle fuel as long as its conditions are met, including a gasquality monitoring system.

The City of Mesa already has some CNG fleet vehicles, making the technology familiarto a local municipality.

The 17-year NPV comparison for the final five alternatives indicates that the alternative toupgrade the biogas and use some of the biomethane as vehicle fuel would provide the best

economic payback to the County. The cogeneration alternative would benefit from an avoidedelectricity cost of only $0.059/kWh (with no renewable energy credits). The displacement ofdiesel fuel at a representative diesel price of $1.03/liter equates to a natural gas price of about$26.50/GJ on an energy-equivalent basis. The NPV analysis did not include the cost to convertor purchase new CNG vehicles because exactly what type of vehicles would be used was not yetdecided; however, the diesel fuel savings are quite substantial and could support conversion orpurchase of new CNG vehicles. The analysis assumed that 25 percent of the biomethane


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produced would be used to displace diesel fuel consumption by County vehicles, equaling about1.1 million liters of diesel per year.

The alternative to add biomethane into the natural gas grid compared favorably to cogenerationat a biomethane sale price of about $5.20 to $5.70/GJ (higher heating value [HHV]) or higher. A

range of biomethane sale prices were used because sale price is uncertain until a contract is inplace. Natural gas wholesale costs are currently at about $4.30/GJ (HHV) at natural gas hubsclosest to Pima County. While the biomethane injection alternative is not favorable at a sale priceof $4.30/GJ, the County could phase in new CNG vehicles by purchasing small numbers ofvehicles each year and still provide a better economic return than the cogeneration alternative.The results of the NPV analysis are shown in Table 4.

Table 4. Summary of Capital Costs, Net Present Value Biogas Utilization Alternative at

Ina Road WRF

Alternative comparison Capital cost2011$

b, c 17-year NPV2011$

a, d, e, f, g

IC engine cogeneration with all digester gasi ($12,630,000) ($1,280,000)

Use digester gas in boilers for heat, separate and sell

remaining gas as natural gash, j

($11,810,000) ($6,320,000) to $2,860,000

Use digester gas in boilers for heat, separateremaining gas, use 1/4 for vehicle fuel, sell rest as

natural gash, j

($12,810,000) $4,570,000 to $11,450,000

aNPV assumes a discount rate of 3.25%.b Capital cost for vehicle fuel alternatives do not include the costs of vehicles.

c Includes additional capital cost for one additional unit in 2024.dBased on average overall electricity cost of $0.059/kWh per Tucson Electric.e Based on pipeline-quality biomethane at 36.9 MJ/Nm3 higher heating value (minimum 98% methane)

and net sale price of $4.20 to $7.90/GJ (i.e., net after service fees for gas transport).fBased on diesel prices of $1.03 per liter and 38.5 MJ/liter lower heating value.g Assumes no economic vehicle fuel rebates or grants, or renewable energy credits.h About 10% of digester gas used in boiler to meet average heating needs for mesophilic operation.i Assumes biogas lower heating value of 20.8 MJ/Nm3, an electrical efficiency of 42% and that on

average all heat is supplied by engines.j Assumes a methane recovery rate of 98.5%, which is typical to Greenlane water solvent system and

60% methane in inlet gas.

BC conducted a sensitivity analysis for a number of variables in the analysis including theamount of biomethane used for vehicle fuel. This sensitivity analysis verified that the morebiomethane is used as vehicle fuel, the better the NPV. Even with only about 5 percent of thebiomethane used as vehicle fuel, this alternative is better than cogeneration if the remainder ofthe biomethane can be sold for $5.20/ GJ or higher. Figure 10 shows the results of the sensitivityanalysis.


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Figure 10. Vehicle fuel percentage use effect on net present value

A high-level analysis of GHG impacts was conducted for the five biogas utilization alternatives.This analysis included the GHG emissions reductions associated with the energy that wouldotherwise be used in the absence of the biogas utilization alternative. Figure 11 shows the resultsof the analysis. The cogeneration alternative would provide the largest GHG reduction by about30 to 40 percent over the next-best alternative. Arizonas GHG emission rate associated withelectricity production is fairly high, making renewable electricity valuable for reducing GHGemissions. However, the cogeneration alternative would produce the highest levels of carbon

monoxide, nitrogen oxides, and VOCx at the plant.

-$10

-$5

$0

$5

$10

$15

$20

5% 10% 15% 20% 25% 30% 35%

17-YearNPV,million

Percent of Biomethane as Vehicle Fuel, %

Vehicle Fuel Percentage Use Effect on NPV

IC engine cogeneration

with all digester gas

Use digester gas in boilers

for heat, part as vehicle

fuel, sell rest as NG - HIGHBIOMETHANE SALE PRICE

Use digester gas in boilers

for heat, part as vehicle

fuel, sell rest as NG - LOWBIOMETHANE SALE PRICE

Area where NPV for biogas upgrading with

vehicle fuel use is better than cogeneration


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Figure 11. Comparative gross greenhouse gas reductions from energy offset

scenarios at Ina Road WWTPa. Includes GHG emissions for energy inputs or offsets only, including electricity, natural gas, and

diesel fuel.b. Based on 2009 electricity emission for Arizona from (US EPA 2009).c. Based on natural gas and diesel fuel emissions rates (Greenhouse Gas Protocol, 2006).

The Pima County biosolids master plan is still in draft form. BC continues to work with theCounty to help it select the alternative that will provide the most benefit for the Countyspriorities.

CONCLUSIONS

Upgrading biogas produced from anaerobic digestion to pipeline quality for vehicle fuel use canprovide the best economic alternative for a WWTP with mature technologies while providingGHG reductions. Traditional use of digester gas in boilers for heating usually does not makebeneficial use of all the gas available and cogeneration may not provide a positive payback overthe life of the equipment. Upgrading digester gas to pipeline quality broadens the potential useand sale of the biogas resource. Biogas upgrading technologies have been operating successfullyfor many decades and it are being adopted by an increasing number of WWTPs. Several biogasupgrading technologies are suitable for a large range of digester gas flows and there are several

experienced system manufacturers. CNG fleet vehicles are available direct from severalmanufacturers and conversion of diesel or gasoline vehicles is commonplace.

Two recent WWTP case studies identified biogas upgrading with some or all of the biomethaneused as vehicle fuel as providing the best NPV for biogas utilization. The conditions that madebiogas upgrading for vehicle fuel an economically favorable and logistically viable optionincluded:

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

Cogeneration Pipeline Gas, Boilers for Heat Pipeline Gas, 25% Vehicle Fuel,

Boilers for Heat

GrossCarbonEmissionsRed

uctions

(tonne-CO2e/year)


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Low electricity prices Potential to sell biomethane not used by vehicles at favorable prices to a natural gas

utility

A municipality that is willing to convert a diesel or gasoline vehicle fleet, or expand anexisting CNG vehicle fleet

Low plant heating demands resulting in a relatively large amount of excess digester gas Possibility of consuming nearly all of the digester gas produced throughout the year

The alternative to upgrade digester gas at the Tacoma CTP and use all of the biomethane asvehicle fuel for its refuse hauler fleet provided the best economic alternative for the City. A largepercentage of the Citys refuse hauler fleet would be phased in as CNG vehicles or converted forCNG operation.

At Pima Countys Ina Road WRF, upgrading digester gas and using some of the biomethane forvehicle fuel and selling the remainder of the biomethane offered the best economic scenario forbiogas utilization. Even a small fraction of the biomethane used as vehicle fuel offers a large

payback and the remainder could be sold to the local utility or more lucrative markets through anearby distribution pipeline.

The offset of diesel fuel with biomethane offered a better opportunity to reduce GHG emissionsfor the City of Tacoma because of the large percentage of hydropower in the electricity sourcecomposition in the Pacific Northwest. Where the electrical grid has a larger fossil fuelcomponent in Arizona, the use of digester gas for cogeneration had a larger GHG reduction fromelectricity offset. Under both scenarios, biogas upgrading would produce fewer criteria pollutantssuch as NOx and CO than would cogeneration with internal combustion engines.

REFERENCES

Baukal, Charles E., Schwartz, Robert E., The John Zink Combustion Handbook, CRC PressLLC, Boca Raton, Fla., 2001.

Bell, John, Peterbilt Representative, personal communication with Eron Jacobson regardingcompressed natural gas refuse haulers, 1/2/2011.

California Air Resources Board (CARB), Alternative Fuel Retrofit Systems Certified by the AirResources Board, updated 2/9/2007, accessed 1/10/2012,http://www.arb.ca.gov/msprog/aftermkt/altfuel/altfuelsys94_020907.pdf.

Chandler, K., Ebert, E. and Melendez, M., Washington Metropolitan Area Transit Authority:Compressed Natural Gas Transit Bus Evaluation, NREL/TP-540-37626, April 2006.

Chandler, K., Ebert, E. and Melendez, M., Washington Metropolitan Area Transit Authority:

Compressed Natural Gas Transit Bus Evaluation, NREL/TP-540-37626, April 2006.Chandler, Kevin, Walkowicz, Kevin, and Clark, Nigel, United Parcel Service (UPS) CNG TruckFleet: Final Results, U.S. Department of Energy/National Renewable Energy Lab TruckEvaluation Project, August 2002.

Chicago Climate Exchange Document: World Resources Institute GHG Calculation Tools forStationary Emission Sources,http://www.ghgprotocol.org/templates/GHG5/layout.asp?type=p&MenuId=OTAx,accessed 10/1/2006.
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De Arespacochaga, Nicolas, Evaluation of Biogas Treatment Efficiency for the Elimination ofSiloxanes: State-of-the art on biogas utilisation as a vehicle fuel, July 2010.OWSO10C10-SL1001

U.S. Energy Information Administration, State Electricity Profiles, 2009 Edition,http://www.eia.doe.gov/cneaf/electricity/st_profiles/e_profiles_sum.html, accessed

6/25/2011.United States Environmental Protection Agency (US EPA), Updated Certification Guidance forFuel Converters, 10/28/2010,http://iaspub.epa.gov/otaqpub/display_file.jsp?docid=23319&flag=1, accessed1/10/2012.

Gas Transmission Northwest (GTN), Pipeline Specifications, 2005,http://www.gastransmissionnw.com/info_post/04100PipeSpecs_GTN_LR.pdf, accessed2/21/2011.

Gas Transmission Northwest (GTN), Pipeline Specifications, TransCanada and other pipelinegas quality tariff specifications, May 2005,http://www.gastransmissionnw.com/info_post/04100PipeSpecs_GTN_LR.pdf, accessed

2/16/2011.GreenField Compression, Introduction and Component Cost of CNG ,http://www.zeitenergy.com/presos/Hightower.pdf, accessed 2/16/2011.

Kidnay, Arthur and Parrish, William, Fundamentals of Natural Gas Processing, CRC Press, BocaRaton, Fla., 2006.

Lindeburg, Michael R., Mechanical Engineering Reference Manual, Professional Publications,Inc, Belmont, Calif., 12th Edition, 2006.

NGV America (NGVA), Frequently Asked Questions About Converting Vehicles to Operate onNatural Gas,http://www.ngvc.org/pdfs/FAQs_Converting_to_NGVs.pdf, accessed6/26/2009.

NGV America (NGVA), Guide to Available Natural Gas Vehicles and Engines, updated5/14/2011,http://www.ngvamerica.org/pdfs/marketplace/MP.Analyses.NGVs-a.pdf,accessed 1/10/2012.

Northwest Pipeline (NWP) GP, FERC Gas Tariff, General Terms and Conditions, 5th Revision,6/8/2010.

Puget Sound Clean Cities, Compressed Natural Gas Fueling Stations in the Puget Sound,http://www.pugetsoundcleancities.org/FuelingNaturalGas2.htm, accessed 12/12/2010.

SAE J1616 Recommended Practice for Compressed Natural Gas Vehicle Fuel, RecommendedPractice, 2/1/1994.

Turns, Stephen R., An Introduction to Combustion, The McGraw-Hill Company, 2nd Edition,2000.

U.S. Energy Information Administration (U.S. Environmental Protection Agency [US EPA]),Clean Alternative Fuels: Compressed Natural Gas, Fact Sheet, EPA 420-F-00-33, March2002.

U.S. EPA Landfill Methane Outreach Program (LMOP), Operational LFG Energy ProjectsDatabase, 2009,http://www.epa.gov/landfill/proj/index.htm. Accessed on 10/20/2009.

United States Department of Energy Alternative Fuels & Advanced Vehicles Data Center,Vehicle Conversions,http://www.afdc.energy.gov/afdc/vehicles/conversions.html,accessed, 2/16/2011.
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Wise, Darin, Plant Superintendent, City of Newark WWTP, Newark, Ohio, personalcommunications with Eron Jacobson regarding Guild Associates biogas upgradingsystem, 1/7/2011.

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