TECH Briefs www.burnsmcd.com A Burns & McDonnell Publication 2010 No. 2 By Benjamin G. Munz, EIT and James P. Hays, PE, LEED ® AP As interest grows in the use of renewable energy, it’s crucial to examine the costs involved in making nontraditional fuels available to consumers. In a study focusing on a wastewater treatment plant in Southern California, Burns & McDonnell evaluated the feasibility of converting biogas into pipeline-grade gas using a pressure-swing adsorption process. The study also examined the possibility of generating electrical power with the unused discharge gas from the process. Background Biogas, a renewable resource, is the product of the decomposition of organic matter in an oxygen-free environment, typically an anaerobic digester. This gas can originate from numerous sources, such as wastewater treatment plants, cattle manure, food waste and landfills. In most applications, this gas is simply diverted to a flare or conditioned for combustion in a reciprocating engine or microturbine for electrical power generation. Another, more economically beneficial use of this gas is to upgrade it to pipeline quality and merge it with the natural gas in the pipeline. To do this, the biogas must first be cleaned and separated. Most gas companies require roughly 98% methane and a minimum heating value of 990 British thermal units per standard cubic foot (Btu/SCF). It is also necessary to remove trace constituents such as the hydrogen sulfide (H 2 S) and various siloxanes that can be harmful to equipment, and to meet the gas specification of the pipeline company. Pressure-Swing Adsorption: The Process Pressure swing adsorption (PSA) is a technology used to separate certain gas species from a mixture of gases under pressure according to the species’ molecular characteristics and affinity for an adsorbent material. Special adsorptive materials are used as a molecular sieve, preferentially adsorbing the target gas species at high pressure. Typical adsorbents are activated carbon, silica gel, alumina and other zeolites. The process then swings to low pressure to desorb the gases from the adsorbent material. Gas species that are not adsorbed exit the pressure vessel first. As the pressure drops further, gases desorb from the adsorption media. This allows the gas to be separated into two fractions: a product gas and a tail gas. PSA processes rely on the fact that, under pressure, gases tend to be attracted to solid surfaces, or be “adsorbed.” The higher the pressure, the more gas is adsorbed; when the pressure is reduced, the gas is released, or desorbed. PSA processes can be used to separate gases in a mixture because different gases tend to be attracted to different solid surfaces more or less strongly. The process produces an enriched product gas and a waste gas called tail gas. The product gas will have a higher heating value (HHV) close to a therm of pipeline quality natural gas at 1,000 Btu/SCF, while the tail gas will have a low HHV around 125 Btu/SCF. Thus, PSA system- produced gas is likely to meet the gas quality standards for distribution lines and the tail gas will have enough energy content to combust in a flare. The wastewater treatment plant in Southern California was evaluated for possible installation of a PSA system. This site is relatively small, producing only 175 standard cubic feet per minute (SCFM) of digester gas, which is the feed stream to the PSA system. Secondary Gas Conditioning One option for utilizing the remaining tail gas after the PSA process is to generate electrical power by passing it through a microturbine or other generator. Aside from the need to boost Biogas to Pipeline-Quality Gas Using Pressure-Swing Adsorption Process, Cost and Return on Investment For more information, please e-mail: [email protected] or [email protected]. Benjamin G. Munz, EIT, is an assistant mechanical engineer in the Burns & McDonnell San Diego office. He specializes in machine and mechanical system design, heat transfer and HVAC design. He received his bachelor’s degree in mechanical engineering from North Carolina State University. James P. Hays, PE, LEED ® AP, is manager of engineering in the Burns & McDonnell San Diego office. He has more than 25 years of experience in project and program management, design and design leadership, and engineering execution. He is a registered professional engineer in 12 states.
Transcript
TECHBriefs www.burnsmcd.com A Burns & McDonnell Publication 2010 No. 2
By Benjamin G. Munz, EIT andJames P. Hays, PE, LEED® APAs interest grows in the use of renewable energy, it’s crucial to examine the costs involved in making nontraditional fuels available to consumers. In a study focusing on a wastewater treatment plant in Southern California,Burns & McDonnell evaluated the feasibility of converting biogas into pipeline-grade gas using a pressure-swing adsorption process. The study also examined the possibility of generating electrical power with the unused discharge gas from the process.
BackgroundBiogas, a renewable resource, is the product of the decomposition of organic matter in an oxygen-free environment, typically an anaerobic digester. This gas can originate from numerous sources, such as wastewater treatment plants, cattle manure, food waste and landfills.
In most applications, this gas is simply diverted to a flare or conditioned for combustion in a reciprocating engine or microturbine for electrical power generation. Another, more economically beneficial use of this gas is to upgrade it to pipeline quality and merge it with the natural gas in the pipeline. To do this, the biogas must first be cleaned and separated. Most gas companies require roughly 98% methane and a minimum heating value of 990 British thermal units per standard cubic foot (Btu/SCF). It is also necessary to remove trace constituents such as the hydrogen sulfide (H2S)and various siloxanes that can be harmful to equipment, and to meet the gas specification of the pipeline company.
Pressure-Swing Adsorption: The ProcessPressure swing adsorption (PSA) is a technology used to separate certain gas species from a mixture of gases under pressure according to the species’ molecular characteristics and affinity for an adsorbent material. Special
adsorptive materials are used as a molecular sieve, preferentially adsorbing the target gas species at high pressure. Typical adsorbents are activated carbon, silica gel, alumina and other zeolites. The process then swings to low pressure to desorb the gases from the adsorbent material. Gas species that are not adsorbed exit the pressure vessel first. As the pressure drops further, gases desorb from the adsorption media. This allows the gas to be separated into two fractions: a product gas and a tail gas.
PSA processes rely on the fact that, under pressure, gases tend to be attracted to solid surfaces, or be “adsorbed.” The higher the pressure, the more gas is adsorbed; when the pressure is reduced, the gas is released, or desorbed. PSA processes can be used to separate gases in a mixture because different gases tend to be attracted to different solid surfaces more or less strongly.
The process produces an enriched product gas and a waste gas called tail gas. The product gas will have a higher heating value (HHV) close to a therm of pipeline quality natural gas at 1,000 Btu/SCF, while the tail gas will have a low HHV around 125 Btu/SCF. Thus, PSA system-produced gas is likely to meet the gas quality standards for distribution lines and the tail gas will have enough energy content to combust in a flare.
The wastewater treatment plant in Southern California was evaluated for possible installation of a PSA system. This site is relatively small, producing only 175 standard cubic feet per minute (SCFM) of digester gas, which is the feed stream to the PSA system.
Secondary Gas ConditioningOne option for utilizing the remaining tail gas after the PSA process is to generate electrical power by passing it through a microturbine or other generator. Aside from the need to boost
BiogastoPipeline-QualityGasUsingPressure-SwingAdsorptionProcess, Cost and Return on Investment
Benjamin G. Munz, EIT, is an assistant mechanical engineer in the Burns & McDonnell San Diego office. He specializes in machine and mechanical system design, heat transfer and HVAC design. He received his bachelor’s degree in mechanical engineering from North Carolina State University.
James P. Hays, PE, LEED® AP, is manager of engineering in the Burns & McDonnell San Diego office. He has more than 25 years of experience in project and program management, design and design leadership, and engineering execution. He is a registered professional engineer in 12 states.
TECHBriefs 2010 No. 2 2 Burns & McDonnell
the heating value of the gas for combustion within a microturbine, there is the problem of constituents harmful to the equipment. The H2S, sulfur dioxide (SO2) and siloxanes that remain in the tail gas of the PSA system can damage mechanical systems. A secondary gas conditioning system must be employed either in front of or behind the PSA. Removing moisture, H2S, SO2, halogens, siloxanes and other contaminants is essential to purifying digester gas and biogas for use as an efficient energy source, as well as for use in an engine or turbine.
Option 1: PSA and FlareIn this option, the gas will enter the PSA system, producing pipeline-quality product gas for introduction into the pipeline and tail gas containing the impurities separated from the raw digester gas. The low Btu value of the tail gas is sent to the flare. (See Figure 1.) Additional gas cleaning is not required for burning in a flare. Use of an existing flare may be possible. The manufacturer of the flare should be consulted about performance with low Btu gas.
A bypass line for the raw gas will be included to bypass the PSA unit in the event of a malfunction, or as required to perform routine maintenance. The raw gas will then be directed to the flare, which is most likely the current means of digester gas disposal.
Table 1 shows the predicted mass balance for the system. The flow stream numbers correspond to numbers shown on the process flow diagram in Figure 1. PSA Vendors supply actual mass balances based on feed composition. Methane recovery rates varyfrom 60% to 90%.
The balance confirms the product composition and heating value, and provides the flow of pipeline-quality product for benefit calculations.
Option 2: PSA with Power GenerationIn this option, the gas will also enter the PSA system to produce pipeline-quality product gas for introduction into the pipeline and produce a tail gas containing the impurities separated from the raw digester gas. In order to meet the requirements for gas quality for the microturbine, the gas must be conditioned. The tail gas will be conditioned using a secondary gas conditioning system.
Depending on the efficiency of the PSA unit in removal of the impurities, it is possible to place the gas cleaning system in the tail gas stream, which will have a smaller volume of gas to treat and thus a potential lower capital cost. However, upon investigation, it was discovered that cost savings were minimal. Therefore, it is recommended to place the gas conditioning system prior to the PSA system, protecting the more expensive PSA unit in addition to conditioning the tail gas.
Table 1: Raw gas composition for option 1 is from direct sampling from a Southern California Wastewater Treatment Plant. The mass balance illustrates the flow of pipeline-quality gas.
DIGESTER PSA
BYPASSTO FLARE
PIPELINE
FLARE
1 2
3
Figure 1: Process flow diagram for PSA-to-flare option.
Stream 1 2 3
RawGas
PSAProduct Gas
PSATail Gas
Flow rate (SCFM) 175 104 71
Flow rate (ACFM) 183 16 70
Pressure (psig) 0 90 3
Temperature (F) 73 120 150
Moisture (pounds/minute) 0.3492 0.0007 0.002
Gas (pounds/minute) 12.6 4.81 7.79
Given/required HHV (Btu/scf) 599 990 132
Methane (% dry volume) 64.6% 98% 15.9%
Carbon dioxide (% dry volume) 33.9% 2% 80.5%
Oxygen (% dry volume) 0.2% 0% 0.4%
Carbon monoxide (% dry volume) - - -
Nitrogen (% dry volume) 1.3% 0% 3.2%
Moisture (% dry volume) 2.1% 0% 2%
Free hydrogen (spot %) - - -
Hydrogen sulfide (spot %) 2.6 ppm 0 ppm 6.4 ppm
Siloxanes (ppm) 33 ppm 0 ppm 81.2 ppm
Ammonia (spot %) - - -
Halocarbons (spot ppm) - - -
Dust and gum - - -
Volatile organics (ppm) 532 ppm 0 ppm 1309 ppm
Mass Balance for Option 1, PSA to Flare
Com
posi
tion
ppm= parts per million
Burns & McDonnell 3 TECHBriefs 2010 No. 2
DIGESTER PSA
BYPASS TO FLARE
PIPELINE
FLARE
1 2 3
Table 2: Raw gas composition for option 2 is from direct sampling from a Southern California Wastewater Treatment Plant. The mass balance shows pipeline-quality gas diverted to enrich tail gas.
Mass Balance for Option 2, Gas Conditioning-to-PSA-to-Microturbine
GASCONDITIONING
BYPRODUCTSBYPASS TO FLAREOR MICROTURBINE
POWER MICROTURBINE
ATMOSPHERE
problems with the PSA system, or as required to perform routine maintenance. The raw gas will be directed to the gas conditioning system, then to the microturbines, or bypass both the gas conditioning system and the PSA unit and go directly to the flare. Under this scenario, the gas conditioning would need to be ahead of the PSA unit to clean all of the raw gas.
The balance confirms the composition and heating value of the product gas and shows how much of the pipeline quality product gas will be needed to boost the heating value of the tail gas for use within a microturbine. These data indicate that the quantity of the pipeline-quality product gas must be reduced by approximately 23% to accommodate for sweetening the low-Btu tail gas.
Cost EvaluationThe California study examined costs in terms of the capital investment required, the operating cost of the system, and the internal rate of return (IRR). In the example given, estimates for demolition and removal of existing equipment are included in the capital cost because the equipment occupies the only available space for the new system.
The product gas line estimate is based on connecting to the plant pipe system. If the site does not consume as much gas as is being generated by the gas treatment system, additional pipe will be required to connect to the gas main (cost not included).
Capital CostPSA to Flare Total installed cost: $1,113,766 • Flare unit (if new required): $140,000PSA to Existing Microturbines Total installed cost: $1,719,441
An average cost of 16 cents/kWh was used for development of the power costs used for the parasitic load of the system as well as for the production from the existing microturbines. An escalation of 2% per year was applied. Municipalities are most likely on a special rate system and a negotiated agreement for power would need to be developed. Costs from the
Com
posi
tion
Figure 2: Process flow diagram for microturbine (option 2).
Due to the low Btu value of the tail gas, some of the product gas must be blended with the tail gas to meet the Btu requirements of the microturbine. (See Figure 2.) Microturbines require a fuel with a minimum heating value of 350 Btu/SCF.
A bypass line for the raw gas will be included to bypass the PSA unit in the event of any
TECHBriefs 2010 No. 2 4 Burns & McDonnell
feasibility-level study are in 2008 dollars, with no allowance for contingencies based on differing site conditions and fuel compositions.
The IRR was calculated for four scenarios over a 20-year lifespan. (See Table 3.) This calculation also included a salvage cost during year 20 for the removal and cleanup of old equipment, assumed to be equal to the future worth of the installation price. The design conditions in Table 3 are for the Southern California facility. The scenarios identified as maximum require running the PSA units at maximum capacity.
It is apparent that for the design flow rate for the Southern California site, it is not beneficial to use existing microturbines. The IRR for other sites with similar flow would actually be negative due to the increase in capital cost for the purchase of the microturbines. This means that the system would not pay off within the lifetime of the equipment.
The economies of scale play an important part on the return on investment. Large facilities are more cost-beneficial. Since the units are skid-mounted, the installation cost should not increase significantly over the cost of the smaller unit. Figure 3 depicts the cumulative cost benefits over a 20-year period for the Southern California facility for both design and full-capacity use of the PSA unit under flare and microturbine options.
With the flare option being the most effective option for future sites that do not already possess microturbines, the effects of a higher flow for larger facilities was investigated further. The cumulative cash flow was also plotted
using the PSA information for various size units under the same conditions as described above for the 20-year basis shown in Figure 4. The IRR is in Table 4. The 175 scfm scenario is specifically for the Southern California site and is the same unit as for the 300 scfm, operating at less than maximum capacity.
Based on the information available, facilities with larger capacities are more attractive.
ConclusionsPSA with FlareThe PSA system coupled with a flare to burn the residual tail gas has the lowest capital investment and provides the quickest return on the investment. It should be noted that for the particular installation at the Southern California plant, only half of the capability of the PSA unit is utilized, therefore that PSA system would be more attractive for a larger capacity facility. The minimum size capacity for the PSA unit from one supplier is 300 scfm. The capital investment would remain unchanged as well as the operating cost with twice the amount of product gas.
PSA with Power GenerationThe Southern California wastewater treatment plant for this scenario has existing generation equipment from a previous attempt to convert digester gas into electric power. The existing microturbines are reported as being in operable condition. The use of the existing microturbines was evaluated as a means of recovering someof the lost energy required to produce the product gas.
Under this scenario, gas conditioning is required, which adds to the capital investment.
Figure 3: Cumulative cash flow for Southern California site under flare and microturbine options, at design and full-capacity use.
Scenario IRR
Design – To Flare 7.3%
Design – To Microturbine 5%
Maximum – To Flare 27.1%
Maximum – To Microturbine 25%
Internal Rate of Return Comparison
Table 3: Operation at higher capacity increases IRR.
$250,000,000
$200,000,000
$150,000,000
$100,000,000
$50,000,000
$0
-$50,000,000
0 2 4 6 8 10 12 14 16 18 20Year
Scenario Cumulative Cash Flow
Design – To Flare Design – To Microturbine
Max – To Flare Max – To Microturbine
$7,000,000
$6,000,000
$5,000,000
$4,000,000
$3,000,000
$2,000,000
$1,000,000
0
-$1,000,000
-$2,000,000
Burns & McDonnell 5 TECHBriefs 2010 No. 2
Additionally, the microturbines require a higher BTU value for the gas then what is provided in the tail gas stream. Therefore some of the product gas would be required to be blended with the tail gas to elevate its heating value. The tail gas combination also has to be pressurized for blending and feed to the microturbines, which adds to the overall power consumption of the system. Even with the benefit of having existing microturbines to reduce the capital expenditure, the combination of the additional capital cost, the lower net production of product gas, and the higher operating cost, does not achieve cash flow breakeven until the 14th year, which does not make this scenario very attractive. However, if you consider the
Figure 4: Cumulative cash flow for various sizes of PSA-to-flare systems shows economy-of-scale benefits.
Size IRR
175 scfm 7%
300 scfm 27%
1,150 scfm 66%
1,800 scfm 84%
2,400 scfm 93%
4,800 scfm 112%
9,600 scfm 133%
Internal Rate of Return for Various Sizes of PSA-to-Flare Option
Table 4: Larger PSA systems yield a higher IRR.
$250,000,000
$200,000,000
$150,000,000
$100,000,000
$50,000,000
$0
-$50,000,000
Cumulative Cash Flow For Various PSA Sizing Options
0 10 20 5 15
300 scfm
1150 scfm
4800 scfm
9600 scfm
1800 scfm
2400 scfm
economy of scale and increase the amount of product gas and tail gas to the full potential of the PSA unit, the payback is reduced totwo years.
Based on information gathered and developed for this report, the PSA alternative is a viable solution to generating pipeline quality gas from biogas. The paramount goal is to produce pipeline-quality gas. The maximum amount of product gas is produced by the use of the PSA system with the tail gas going directly to the flare. Additionally, this arrangement also has the lowest capital cost and is recommended for the demonstration facility at the Southern California wastewater treatment plant.
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