NREL is a national laboratory of the U.S. Department of Energy, Office of Energy 

Efficiency & Renewable Energy, operated by the Alliance for Sustainable Energy, LLC.

Contract No. DE-AC36-08GO28308

H2A Biomethane Model 

Documentation and a 

Case Study for Biogas From 

Dairy Farms

Genevieve Saur and Ali Jalalzadeh-Azar

Technical Report

NREL/TP-5600-49009

December 2010
NREL is a national laboratory of the U.S. Department of Energy, Office of Energy 

Efficiency & Renewable Energy, operated by the Alliance for Sustainable Energy, LLC.

National Renewable Energy Laboratory

1617 Cole Boulevard

Golden, Colorado 80401

303-275-3000 • www.nrel.gov

Contract No. DE-AC36-08GO28308

H2A Biomethane Model 

Documentation and a 

Case Study for Biogas From 

Dairy Farms

Genevieve Saur and Ali Jalalzadeh-Azar

Prepared under Task No. H2782330

Technical Report

NREL/TP-5600-49009

December 2010
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Contents 

Introduction..................................................................................................................................... 1
 

New Model Features....................................................................................................................... 2
 

New Worksheet – Biogas Upgrade ............................................................................................. 2
 

New Worksheet – Biomethane Pipeline ..................................................................................... 4
 

New Worksheet – Biomethane Compressor ............................................................................... 6
 

Worksheet Modification – ‘Results’........................................................................................... 7
 

Case Study – Biomethane From Dairy Waste .............................................................................. 10
 

Description and Process Flow................................................................................................... 10
 

Biogas Feedstock – Cost........................................................................................................... 10
 

Biogas Feedstock – Upstream Energy Use and Emissions ....................................................... 10
 

Total Energy Use .................................................................................................................. 10
 

Greenhouse Gas Emissions ................................................................................................... 13
 

Biogas Feedstock – Production Process Emissions .................................................................. 13
 

Biomethane Pipeline System .................................................................................................... 13
 

External Compression Plant ...................................................................................................... 14
 

Case Study Parameters for Biogas Upgrading Process............................................................. 14
 

Case Study – Results................................................................................................................. 15
 

Case Study – Sensitivity ........................................................................................................... 15
 

Summary ....................................................................................................................................... 18
 

References..................................................................................................................................... 19
 

iv 
Figures 

Figure 1. Gas composition inputs in ‘Biogas Upgrade’ .................................................................. 3
 

Figure 2. Energy content and usage in ‘Biogas Upgrade’ .............................................................. 3
 

Figure 3. Biogas capital costs in ‘Biogas Upgrade’ ........................................................................ 3
 

Figure 4. ‘Biomethane Pipeline’ summary of cost results layout ................................................... 5
 

Figure 5. ‘Biomethane Pipeline’ excerpt of results in $/mi metric ................................................. 5
 

Figure 6. Compressor layout for external compression .................................................................. 6
 

Figure 7. Example of cost results excerpted from ‘Results’ tab ..................................................... 7
 

Figure 8. Example Energy Data table excerpted from ‘Results’ tab .............................................. 8
 

Figure 9. Example Upstream Energy Usage table excerpted from ‘Results’ tab ........................... 8
 

Figure 10. Example of detailed Production Process GHG Emissions excerpted from ‘Results’ ... 9
 

Figure 11. Example of detailed Upstream GHG Emissions excerpted from ‘Results’ .................. 9
 

Figure 12. Excerpt from ‘Process Flow’ tab ................................................................................. 11
 

Figure 13. Table C1 in ‘HyARC Physical Property Data’ tab ...................................................... 12
 

Figure 14. Excerpt Table A in the ‘HyARC Physical Property Data’ tab .................................... 13
 

Figure 15. Breakdown baseline scenario cost for biomethane from dairy biogas ........................ 16
 

Figure 16. Emissions Summary from ‘Results’ tab of baseline scenario for biomethane from
 

dairy biogas................................................................................................................................... 16
 

Figure 17. Sensitivity of several parameters on the cost of biomethane ...................................... 17
 

Tables 

Table 1. Default Scaling Ranges for Uninstalled Costs .................................................................. 4
 

Table 2. Baseline Parameters for Upgrading Biogas From Dairy Farms ..................................... 15
 

Table 3. Sensitivity Parameters With Percent Change From Baseline in Parenthesis.................. 15
 

Table 4. Sensitivity Results for High and Low Biomethane Cost ................................................ 17
 

v 
Introduction 

The new H2A Biomethane model was developed to estimate the levelized cost of biomethane by 

using the framework of the vetted original H2A models for hydrogen production and delivery. 

For biomethane production, biogas from sources such as dairy farms and landfills is upgraded by 

a cleanup process. The model also estimates the cost to compress and transport the product gas 

via the pipeline to export it to the natural gas grid or any other potential end-use site. Inputs 

include feed biogas composition and cost, required biomethane quality, cleanup equipment 

capital and operations and maintenance (O&M) costs, process electricity usage and costs, and 

pipeline delivery specifications. (All costs are presented in 2005 dollars unless otherwise noted.) 

The original H2A model capabilities can be found in the user guides [1, 2]. These should be used 

with this document for a complete description of the current model. 

1 
New Model Features 

New Worksheet – Biogas Upgrade 

A new worksheet, ‘Biogas Upgrade’, was developed to help users provide the required inputs for 

characterizing the upgrade process with respect to biomethane yield, energy consumptions, 

emissions, and costs. This can be used to upgrade biogas from any source (e.g., dairy farms or 

landfills) to natural gas pipeline quality. Figure 1 to Figure 3 show the required inputs in orange. 

These input data are also required for other calculations. 

Potential projects will vary with respect to the input biogas and the required output biomethane 

quality. For instance, pipeline quality natural gas varies slightly from one state to another and 

from one utility to another. This model can capture some basic elements, but does not design a 

cleanup and purification system, which are highly dependent on feedstock composition, quality, 

and variation. This model calculates the volume and energy content of the input biogas and 

output biomethane based on the methane (CH4), carbon dioxide (CO2), and nitrogen (N2) 

contents in an average annual flow. This approximation does not account for seasonal or other 

variations. Additionally, delivery components of the model may be sized for peak flow or an 

annual average, depending on the level of detail desired. This model provides a broad technoeconomic analysis to help users identify worthwhile projects for more in-depth consideration. 

The CH4, CO2, and N2 components of the biogas and biomethane are used to calculate energy 

contents of the input and output streams and the energy usage, (see Figure 2). Other impurities 

are listed for completeness and to provide space for an extended analysis. The energy content 

values are used in several places to determine energy usage values and resulting emissions. Cells 

in green are for informational purposes. Further units and constant conversion information are in 

the ‘Constants and Conversions’ tab. All calculations can be seen by clicking in blue cells. 

The values for electricity and biogas usage reflected in this worksheet (cells 'Biogas 

Upgrade'!B24 and 'Biogas Upgrade'!B25, respectively) should then be added as utility and 

feedstock, respectively in the ‘Input_Sheet_Template’ Variable Operating Costs: Energy 

Feedstocks, Utilities, and Byproducts section. This is done in the same way as in the standard 

H2A Production model [1]. 

Figure 3 shows the capital costs section in the ‘Biogas Upgrade’ tab. The total installed costs 

here are used in the levelized cost of biomethane as seen in cell ‘Input_Sheet_Template’!C53. 

The user can either enumerate costs here or unlink to this worksheet and specify the costs in cell 

C53 of the ‘Input_Sheet_Template’ tab. 

2 
Input Biogas Composition Notes Output Biomethane Requirement Notes 

Rate (Nm3/h) 2000 Enter in 'Input_Sheet_Template' Rate (Nm3/hr) 1225 905 kg/hr 

Methane (CH4) (%) 60% by volume CH4 Recovery Factor 99% 

How muc

CO2 (%) 38% by volume Methane (CH4) (%) 97% 851 kg/hr 

Nitrogen (%) 2% by volume CO2 (%) 1% 24 kg/hr 

Nitrogen (%) 2% 31 kg/hr 

H2S (ppm) 600-800 H2S (ppm) <4 

Siloxane (mg/m3) 60-80 Siloxane (ppb) <30 Biogas Density 1.201 kg/Nm3 Biomethane Density 0.739 kg/Nm3 

Figure 1. Gas composition inputs in ‘Biogas Upgrade’ 

Energy Content Biogas Cleanup Plant Utility Usage Methane (CH4) LHV 0.052 GJ/kg methane Electricity Consumption 0.230 kWh/nm3 biogas LHV Biogas 0.0223 GJ/Nm3 biogas LHV Biomethane 0.0361 GJ/Nm3 biomethane Energy Usage Units Notes 

Total Electricity Usage 0.610 kWh/kg biomethane 

Compression 0.102 kWh/kg biomethane For information only, change values on 'Biomethane Compressor' sheet. 

Process 0.508 kWh/kg biomethane IMPORTANT: IF Process Electricity Usage values change, the Utility in Variable Operating Costs must be deleted/re-add

Biogas Usage 2.209 Nm3 biogas/kg biomethane IMPORTANT: IF Biogas Usage values change, the Feedstock in Variable Operating Costs must be deleted/re-added on 

Figure 2. Energy content and usage in ‘Biogas Upgrade’ 

The following can be used for calculating costs to be put in 'Capital Costs' tab Use Default Scaling yes List of equipment required for biogas conditioning 

Reference Unit 

Size (nm3/hr) Scaling Factor 

Reference Unit 

Uninstalled Costs 

($(2005)) Size Required (nm3/hr) Baseline Uninstalled Costs ($(2005)) Installation Factor 

Baseline Installed 

Costs ($(2005)) 

Purification/upgrading system (Default Scaling) 5000 0.65 4,656,101 2000 2,566,619 1.29 3,310,939 

User Defined 1 2000 0 1.29 0 

User Defined 2 2000 0 1.10 0 

User Defined 3 2000 0 1.10 0 

User Defined 4 2000 0 1.10 0 

User Defined 5 2000 0 1.10 0 

User Defined 6 2000 0 1.10 0 

User Defined 7 2000 0 1.10 0 

User Defined 8 2000 0 1.10 0 

User Defined 9 2000 0 1.10 0 

Total Cost $2,566,619 $3,310,939 

Figure 3. Biogas capital costs in ‘Biogas Upgrade’ 

3 
 

The biogas capital costs section in ‘Biogas Upgrade’ can be used in one of two ways: 

•	 Select “yes” next to “Use Default Scaling” (cell B28). 

•	 Select “no” next to “Use Default Scaling” (cell B28) (include uninstalled costs and an 

installation cost factor in the designated space). 

Default values are included in the first line of the cost table (Figure 3) to indicate appropriate 

uninstalled costs. The default scaling is based on vendor quotes for cleanup of biogas from dairy 

farms. The capital costs of a biogas cleanup plant depend on the composition and impurity level 

of feed biogas and the required quality of the output gas; therefore, these values are not 

applicable for all cases. 

ݍ Scaling uses the standard equation, ܥ ൌ ܥ ௙௘௥ቀ ݍ ௙௘௥ൗ ቁ

ௌி

 for the capital costs. From vendor data 

two capacity ranges are modeled for representative biogas from a single or group of dairy farms. 

The variable definitions and the reference values are shown in Table 1. 

Table 1. Default Scaling Ranges for Uninstalled Costs 

Biogas Flow Rate Range (Nm3/h) Reference Rate (qref) Reference Cost (Cref) Scaling Factor (SF) 

150 ≤ q < 700 400 $1.16 M 0.250 

700 ≤ q ≤ 10,000 5,000 $4.66 M 0.65 

New Worksheet – Biomethane Pipeline 

The biomethane pipeline cost is adapted from the H2A Delivery Components model [3]. Three 

types of pipelines can be modeled: 

•	 A high-pressure transmission line 

•	 Medium-pressure trunk lines 

•	 Low-pressure distribution lines. 

Cost results for the trunk and distribution lines are combined; transmission line costs are shown 

separately on the ‘Biomethane Pipeline’ tab (see Figure 4). Figure 5 provides the results in a 

$/mi metric The ‘Results’ tab shows the total cost breakdown for the pipeline system. 

For most case studies involving biomethane, a new transmission line will probably be 

unnecessary because the system will use natural gas transmission lines. In general the expansion 

of the natural gas pipeline network to accommodate new biomethane sources might only include 

a distribution or trunk line from the biogas conditioning plant to the network. However, a feature 

of the ‘Biomethane Pipeline’ worksheet is to model the costs and dimensions of more complex 

systems if required. 

4 
 

 

Calculation Outputs (Be sure ALL data is entered before checking) 

Pipeline Type 

Result Transmission Trunk / Distribution Total 

Pipeline Portion of Real Levelized Delivered Biomethane 

Cost ($(2005)/kg) $0.00 $0.11 $0.11 

Capital Cost Contribution to the Pipeline Share of Real 

Levelized Delivered Biomethane Cost ($(2005)/kg) $0.00 $0.07 $0.07 

Energy/Fuel Cost Contribution to the Pipeline Share of 

Real Levelized Delivered Biomethane Cost ($(2005)/kg) $0.00 $0.00 $0.00 

Other Cost Contribution to the Pipeline Share of Real 

Levelized Delivered Biomethane Cost ($(2005)/kg) $0.00 $0.04 $0.04 

Figure 4. ‘Biomethane Pipeline’ summary of cost results layout 

Calculation Outputs per Mile (For information use only) 

Pipeline Type 

Result Transmission Trunk Distribution 

Total Length of Pipelines (mi) 0 0 10 

Total Pipeline Real Cost ($/mi-yr) $0.00 $0.00 $86,304.82 

Est. Total Pipeline Cost ($/mi) $0.00 $0.00 $416,633.65 

Pipeline Capital ($/mi) $0.00 $0.00 $347,087.60 

Pipeline Land RoW ($/mi) $0.00 $0.00 $41,390.58 

Pipeline Labor Costs ($/mi) $0.00 $0.00 $8,548.86 

Pipeline Fixed O&M ($/mi) $0.00 $0.00 $19,606.61 

Figure 5. ‘Biomethane Pipeline’ excerpt of results in $/mi metric 

The spreadsheet inputs can be categorized as design inputs, scenario inputs, economic 

assumptions, capital investment, and O&M costs. The main difference between the current 

module and the H2A Delivery Components model is that revised values are used for 

compressibility factor (Z), density conversions, and costs for biomethane delivery rather than 

hydrogen. The compressibility factor (Z) is used to determine pipeline diameter by Equations (1) 

and (2) [2]. Calculating the pipeline diameter is necessary for economic evaluation of the 

delivery pipeline [2]. In formulating the compressibility factor (Z), the critical temperature and 

pressure obtained from the NIST Web book on CH4, the main component in biomethane, are 

used where Tc equals 190.6 K and Pc equals 46.1 bar [2, 4]. The density of biomethane was used 

in several conversion equations in place of hydrogen. Finally, the costs were adjusted to remove 

a 10% surcharge on hydrogen pipelines over natural gas pipelines, which is consistent with the 

original source material [2, 5]. Further details can be found in the H2A Delivery Components 

Model version 1.1 Users Guide for the H2 Pipeline [2].

૛ࡼ൫૙૛ .૚

૛ࡼି૚

૚૞.૙ ૚૟.ૢ૝ࢊ൯૛

ࢉ࢙ࢗ ൌ ૠ૜ૠ ቀ

ࡼ

ࢉ࢙ࢀ

࢓ࢆ࢓ࢀࡸ૚૟.ૢ૙ࢽ ൬ ቁࢉ࢙

൰ ࡱ Equation 1 

5 
6 

ࢋൌࢊ

૙.૛૙૚૟ቆ

ሻࢉ࢙ࢗሺܖ ܔ

૙.૞૚ ା࢔࢒ቆ

૚૟.ૢ૙ࢽ࢓ࢆ࢓ࢀࡸ

૚ࡼ૛ࡼష૛

૛ ቇି૚ૢ.ૢ૚૟ቇ

 Equation 2 

where 

qsc = gas flow rate at standard conditions (scf/day) 

Tsc = temperature at standard conditions (°R) (= 530°R in Equation 2) 

Psc = pressure at standard conditions (psia) (= 14.7 psia in Equation 2) 

P1 = inlet pressure (psia) 

P2 = outlet pressure (psia) 

d = inside pipeline diameter (in) 

γ = mean gas relative density (air = 1) 

L = pipeline length (mi) 

Tm = mean temperature of pipeline (°R) 

Zm = mean compressibility factor 

E = pipeline efficiency (= 0.92 in Equation 2) 

New Worksheet – Biomethane Compressor 

The biomethane compressor model is adopted from the H2A Delivery Components model [3]. It 

can be used for further external compression of biomethane to a pipeline or other end-use 

pressure. Multiple reciprocal compressors can be installed in parallel to handle large throughput 

(see Figure 6), including the use of spare compressors. Each compressor can consist of up to 

three compression stages. 

Figure 6. Compressor layout for external compression 

(from DOE, H2A Delivery Components Model Version 1.1: Users Guide, April 7, 2006) 

The spreadsheet inputs (‘Biomethane Compressor’ tab) can be categorized as design inputs, 

economic assumptions, capital investments, and O&M costs. Input cells are colored in orange, an 

H2A model standard, down column B in the ‘Biomethane Compressor’ tab. 

Biomethane in 

(Pinlet) Biomethane out 

(Poutlet) 
 

The main changes made to the tab from the H2A Components Delivery model are the 

compressibility (Z) factor, specific heat ratio (cp/cv), and default costs. The compressibility factor 

Z is used in the theoretical power and electricity usage calculations (see H2A Components 

Delivery Model 1.1 User Guide for a detailed explanation) [2]. The formulation of the 

compressibility factor (Z) is based on the approach used for pipelines. The specific heat ratio was 

changed to 1.32 because the working fluid was changed from hydrogen to natural gas or CH4. 

The default costs for a biomethane compressor were adjusted for natural gas compressors, which 

put the total costs in line with the original cost report [6]. Furthermore, in several conversion 

calculations, biomethane density was substituted for hydrogen density. Further details can be 

found in the H2A Components Delivery Model 1.1 User Guide in the H2 Compressor section 

[2]. 

The ‘Biomethane Compressor’ tab models a single pressure differential. If multiple compression 

stations are required, the results from several input scenarios need to be combined. For instance, 

a three-stage external compression station can compress biomethane from 90 psia (distribution 

pipeline) to 600 psia (trunk pipeline). If a second station is required for 600 psia (trunk pipeline) 

to 1000 psia (transmission line), the input scenario would need to be run separately and manually 

combined with previous results. 

Worksheet Modification – ‘Results’ 

The ‘Results’ tab includes three sections: Costs, Energy, and Emissions. The latter two provide 

the results for the cleanup process modeled and the upstream processes. 

The Costs Results table is shown in Figure 7 and includes cost results in $/kg and $/GJ. 

Conversion to MMBtu is also possible, but not implemented in the current version. The 

conversion between GJ and MMBtu is 1.055 GJ/MMBtu, based on the lower heating value 

(LHV) of both. The cost breakdown is separated by production process (biogas cleanup plant), 

pipeline costs, and external compressor costs. 

Specific Item Cost 

Calculation 

Total Cost of 

Delivered Biomethane $0.64/kg $13.11/GJ 

Cost Component Biomethane Production 

Cost Contribution ($/kg) Pipeline Costs ($/kg) Compressor Costs ($/kg) 

Biomethane 

Production Cost 

Contribution ($/GJ) 

Pipeline Costs 

($/GJ) 

Compressor 

Costs ($/GJ) 

Capital Costs $0.08 $0.07 $0.03 $1.63 $1.50 $0.63 

Decommissioning Costs $0.00 $0.02 

Fixed O&M $0.03 $0.04 $0.01 $0.67 $0.73 $0.29 

Feedstock Costs $0.34 $0.00 $0.01 $6.95 $0.00 $0.10 

Other Raw Material Costs $0.00 $0.00 

Byproduct Credits $0.00 $0.00 

Other Variable Costs (including 

utilities) $0.03 $0.58 

Sub Total $0.48 $0.11 $0.05 $9.86 $2.23 $1.02 

Figure 7. Example of cost results excerpted from ‘Results’ tab 

The Energy section includes the Energy Data table (Figure 8), which summarizes energy inputs 

for feedstocks and utilities for the production process and external compression. It also 

summarizes the energy outputs or other by-products that were included. The biogas feedstock 

energy usage is based on the energy content and quantity of biogas input versus biomethane 

output. The Upstream Energy Usage table (Figure 9) calculates total, fossil fuel, and petroleum 

energy consumed by the energy inputs shown in the Energy Data table (Figure 8) in accordance 

with the Greenhouse Gases, Regulated Emissions, and Energy Use in Transportation (GREET) 

model [7]. 

7 
 

 

Energy Data 

Feedstock Energy Input (GJ/kg 

biomethane) 

Energy Input (kWh/kg 

biomethane) 

LHV (GJ or 

mmBtu/usage unit) 

Usage (/kg 

biomethane) Unit 

Unit System 

Conversion 

Factor 

Biogas_metric 0.049 13.708 0.022 2.209 Nm3 @ 0°C 1 

Utility 

Industrial Electricity_metric 0.002 0.508 0.004 0.508 kWh 1 

External Compression 

Industrial Electricity_metric 0.000 

Energy Output (GJ/kg 

biomethane) 

0.102 

Energy Output (kWh/kg 

biomethane) 

0.004 

LHV (GJ or 

mmBtu/usage unit) 

0.102 

Production (/kg 

biomethane) 

kWh 

Unit 

1 

Unit System 

Conversion 

Factor 

Biomethane (1 kg) 0.049 13.572 0.049 1.000 kg 1 

Byproducts 

Figure 8. Example Energy Data table excerpted from ‘Results’ tab 

Upstream Energy Usage (GJ/kg Biomethane) 

Feedstock Total Energy Fossil Fuels Petroleum 

Biogas_metric -4.08E-02 -3.53E-02 -1.93E-03 

Utility 

Industrial Electricity_metric 2.97E-03 2.57E-03 1.41E-04 

External Compression 

Industrial Electricity_metric 5.99E-04 5.18E-04 2.83E-05 

Figure 9. Example Upstream Energy Usage table excerpted from ‘Results’ tab 

The Emissions section calculates the greenhouse gas (GHG) emissions based on direct energy 

inputs to the production process and the upstream energy use. There are summary and detail 

tables for both Production Process GHG Emissions and Upstream GHG Emissions (see Figure 

10 and Figure 11). By default, in the production process calculation, all emissions are counted as 

CO2. Emissions are calculated in accordance with the GREET model [7]. 

Production process emissions from the biogas feedstock are included in Table A, ‘HyARC 

Physical Property’ tab. This includes CO2 and CH4 that are lost or vented during the biogas 

cleanup process. The process emissions are calculated from the specified biogas cleanup process 

in the ‘Biogas Upgrade.’ 

8 
Production Process GHG Emissions (/kg biomethane) 

Feedstock CO2 CH4 N2O Total GHG (CO2 eq) 

Biogas_metric 1.622 9.49E-03 0.00E+00 1.840 

Utility 

Industrial Electricity_metric 0.000 0.00E+00 0.00E+00 0.000 

External Compression 

Industrial Electricity_metric 0.000 0.00E+00 0.00E+00 0.000 

Figure 10. Example of detailed Production Process GHG Emissions excerpted from ‘Results’ 

Upstream GHG Emissions (kg/kg biomethane) 

Feedstock CO2 CH4 N2O Total GHG (CO2 eq) 

Biogas_metric -2.271 1.86E-03 2.04E-05 -2.222 

Utility 

Industrial Electricity_metric 0.382 5.01E-04 5.22E-06 0.395 

External Compression 

Industrial Electricity_metric 0.077 1.01E-04 1.05E-06 0.080 

TOTAL -1.812 2.46E-03 2.67E-05 -1.748 

Figure 11. Example of detailed Upstream GHG Emissions excerpted from ‘Results’ 

9 
Case Study – Biomethane From Dairy Waste 

The revised model was used to perform the following hypothetical case study for production of 

biomethane from stranded biogas in a dairy farm. The average annual rate of biogas was 

2000 Nm3

/h. The case study system was designed based on this flow rate to show basic design 

functionality with an implicit assumption that peak hourly flow rate could be controlled to not 

exceed the annual average for sizing of system components. After purification and cleanup, the 

biomethane product is transported by a pipeline for further compression and injection into the 

natural gas pipeline. The case study models a breakdown in costs and associated emissions for 

three distinct subsystems: (1) biogas purification/cleanup; (2) low-pressure pipeline transport; 

and (3) additional compression for injection into a natural gas trunk line. 

Description and Process Flow 

Figure 12 describes the purpose and process flow of the system being modeled, illustrating the 

‘Process Flow’ tab of the model. 

Biogas Feedstock – Cost 

A biogas feedstock was added to the AEO 2005 High A case prices, ‘Energy Feed & Utility 

Prices’ tab, as a user-defined feedstock. A constant cost of $7.6/GJ in 2010$ [8] was used for the 

lifetime of the plant and converted to 2005 dollars by using the GDP Implicit Deflator Price 

Index, Table 9A, in the Short Term Energy Outlook September 2009 [9]. The actual cost used is 

based on the energy content as calculated in the ‘Biogas Upgrade.’ In the case study, the energy 

content of the feed biogas was 0.0223 GJ/Nm3 based on the CH4 content and total biogas 

volume. 

Biogas Feedstock – Upstream Energy Use and Emissions 

Upstream energy and emissions data for the biogas feedstock are calculated using a newly 

released report by the California Air Resources Board (CARB) [10]. This can be seen in Figure 

13, an excerpt of Table C1 in the ‘HyARC Physical Property Data’ tab. The CARB report is 

based on a modified version of the GREET model [7, 11] to calculate the associated energy and 

emissions for upgrading biogas from dairy farms to natural gas quality. A breakdown of numbers 

matching those from the CARB report can be seen in the associated cells. 

Total Energy Usage 

Total Energy for biogas (Figure 13) was determined from the CARB report [10]. This includes 

the total energy for biogas recovery, biogas processing to natural gas quality, and transport by 

pipeline to a compressed natural gas (CNG) fueling station or other end-use application. The 

length of the pipeline is adjusted relative to the 50 miles assumed in the CARB report. Fossil 

fuels and petroleum usage portions of the “Total Energy” circled in red (Figure 13) were 

calculated using the same respective ratios for industrial electricity (circled in green in Figure 13 

because the main energy input for upgrading the biogas will be electricity, so that is the main 

source of upstream emissions. The fossils fuel and petroleum energy usage is related to the 

electricity usage for the biogas recovery, processing, and transportation. All calculations can be 

accessed within individual cells for details. More details are available in the CARB report. 

10 
 

 

Cleanup 

 

If additional compression is used in the model (cell ‘Biogas Upgrade’!B23 is not zero), the total 

energy is calculated from energy usage values in the ‘Biomethane Compressor’ tab using 

GREET values for U.S. average mix industrial electricity. 

Process Flow Diagram 

Shaded areas represent the boundaries of this model. 

Waste Water 

Treatment Plant 

Landfills 

Dairy Waste 

Anaerobic Digester 

Clean-Up System Injection in NG 

Pipelines 

Source Distribution & 

Utilization Power Grid 

Vehicle Fueling Station 

Hydrogen 

Electricity 

Heat Stationary 

End-Use 

Biomethane 

Biogas 

Production & 

Reformation / Fuel 

Cell Systems 

Stream Summaries 

Upgrading biogas for biomethane involves the following key processes: 

1. Compression of feed gas to about 100 psig (6.8 bar) 

2. Hydrogen sulfide removal 

3. Siloxane and VOC removal 

4. Carbon dioxide removal 

5. Compression of biomethane to high pressure (e.g. pipeline pressure), if required. 

6. Thermal oxidizer / flaring of purge (tail) gas, if included in the analysis 

The product gas upstream of the compression process is about 90 psig (6.2 bar). The methane content of the purge (tail) gas can be modulated to 

faciliate flaring/oxidizing. 

PSA technology is used for the removal of impurities (H2S, CO2, etc.). In addition to the PSA units, the system consists of gas analyzer, 

flowmeters, cooling devices, and controls. Note that other technologies such as chemical absorption and cryogenic separation can be used instead 

of PSA if desired. 

The product gas has the natural gas pipeline quality: 

CH4: 96% - 98% by volume 

CO2: Less than 2% 

H2S: Less than 4 ppm 

Siloxane: Less than 30 ppb. 

The inlet biogas quality (chemical composition) varies depending on the source of biogas--landfills, dairy farms, waste water treatment plant, etc. 

(The inlet gas composition is recorded at the "Biogas Upgrade" tab) 

Figure 12. Excerpt from ‘Process Flow’ tab 

(from NREL/PO-560-46899) 

11 
Table C1 2005 Upstream Energy and Emissions for H2 Feedstocks: for each MJ (LHV, or as noted) of feedstock available at H2 production 

09/5/2008 for year 2005 technologies 

Energy: J/MJ Greenhouse Gas Emissions: gram

Feedstock/Fuel Description Total Energy Fossil Fuels Petroleum CO2 CH4 

Commercial Natural Gas_metric North American sources -- at plant 65,830 65,387 4,195 4.759 0.130 

Industrial Natural Gas_metric North American sources -- at plant 65,830 65,387 4,195 4.759 0.130 Electric Utility Natural Gas_metric North American sources -- at plant 65,830 65,387 4,195 4.759 0.130 Commercial Electricity_metric U.S. Average - at Wall Outlet 1,626,707 1,407,727 77,032 208.947 0.274 

Industrial Electricity_metric U.S. Average - at Wall Outlet 1,626,707 1,407,727 77,032 208.947 0.274 

Electric Utility Steam Coal_metric at Plant Gate 19,878 19,241 13,877 1.548 0.113 

Retail Diesel_metric at Forecourt 149,143 146,120 65,864 11.466 0.095 

E85 Ethanol_metric 74 wt% ethanol from corn and 26 w 1,254,723 608,478 91,705 -8.078 0.105 

Retail Gasoline_metric at Forecourt 206,668 202,867 94,357 15.515 0.099 

Woody Biomass_metric Poplar at Plant Gate 30,911 30,497 24,723 -101.108 0.003 

Steam_metric Assume steam generation from na 76,814 76,297 4,895 5.553 0.152 

Commercial Natural Gas North American sources -- at plant 65,830 65,387 4,195 4.759 0.130 

Industrial Natural Gas North American sources -- at plant 65,830 65,387 4,195 4.759 0.130 Electric Utility Natural Gas North American sources -- at plant 65,830 65,387 4,195 4.759 0.130 Electric Utility Steam Coal at Plant Gate 19,878 19,241 13,877 1.548 0.113 

Retail Diesel at Forecourt 149,143 146,120 65,864 11.466 0.095 

E85 Ethanol 74 wt% ethanol from corn and 26 w 1,254,723 608,478 91,705 -8.078 0.105 

Retail Gasoline at Forecourt 206,668 202,867 94,357 15.515 0.099 

Woody Biomass Poplar at Plant Gate 30,911 30,497 24,723 -101.108 0.003 

Steam Assume steam generation from na 76,814 76,297 4,895 5.553 0.152 

User Defined Feed 1 User Defined Feed 2 User Defined Feed 3 User Defined Feed 4 Biogas_metric Detailed California-Modified GREE -826,347 -715,108 -39,131 -46.02524238 0.037722536 

Landfill Gas_metric Detailed California-Modified GREE -839,556 -726,539 -39,757 -46.58590588 0.053465664 

Electricity - NGCC - at Wall Outlet NGCC - at Wall Outlet 1,326,688 1,326,077 5,246 133.381 0.370 

Figure 13. Table C1 in ‘HyARC Physical Property Data’ tab 

12 
 

 

 

Greenhouse Gas Emissions 

Greenhouse gas emissions include CO2 (including volatile organic compounds and carbon 

monoxide), CH4, and nitrous oxide (N2O) in grams/MJ, and total GHGs in CO2eq. These values 

were determined using calculations from the CARB report on biogas [10]. This includes the 

direct and upstream GHGs for biogas recovery, biogas processing to natural gas quality, and 

transport by pipeline to a CNG fueling station or other end-use application. It includes an 

adjustment for the specified length of pipeline modeled relative to the 50 miles assumed in the 

CARB report. Full details can be found in the CARB report and by clicking in individual cells of 

this model (Figure 13). 

If additional compression is used in the model (‘Biogas Upgrade’!B23 is not zero), the 

greenhouse gases (GHGs) are calculated from emissions values in the ‘Biomethane Compressor’ 

tab using GREET values for U.S. average mix industrial electricity. 

Biogas Feedstock – Production Process Emissions 

The production process GHG emissions are based on the purification and losses associated with 

processing the biogas to biomethane quality. In the upgrading process, the losses include a trace 

of CH4 (as reflected in the CH4 recovery factor in the ‘Biogas Upgrade’) and the separated CO2. 

In the current version, both gases are assumed to be vented or lost to the atmosphere during the 

purification process. Figure 14 shows an excerpt of Table A in the ‘HyARC Physical Property 

Data’ tab where the boxes outlined in red are the emissions related to the production process. 

(Figure 14 has been split for readability. The blue arrows show the divided ends.) These are 

calculated based on the composition of the input and output feed stream in the ‘Biogas Upgrade.’ 

TABLE A - Energy Feedstock and Utility Properties Table Done 

Feedstock Type Source Source Year 

(for original 

price data) 

H2a 

Reference 

Year 

Feedstock 

Units for 

Price Table 

HHV/LHV Source HHV/LHV 

Biogas_metric 

C

Fa

produced/GJ or 

$(2005)/GJ LHV 

C

Factor (kg CH4 

GJ biogas/Nm3 biogas 

H2A Usage 

Input Unit/ 

kg H2 

H2A LHV (GJ 

or mmBtu/ 

H2A usage 

input unit) 

List O2 Emissions 

ctor (kg CO2 

Unit System 

p

m

H4 Emissions N2O Emissions 

Factor (kg N2O 

produced/GJ or 

mmBtu feed) 

Nm3 @ 0°C 0.0223 Feed Utility 32.87 

mmBtu feed) 

Metric 0.19 

roduced/GJ or 

mBtu feed) 

Figure 14. Excerpt Table A in the ‘HyARC Physical Property Data’ tab 

Biomethane Pipeline System 

For this case study a single distribution line of 10 miles was modeled. Using the maximum 

design feed biogas capacity, a pipeline diameter of 5 in. was determined by the delivery 

component of the model. The outlet pressure of the biogas conditioning plant is assumed to be 

around 100 psia, which becomes the inlet pressure to the pipeline. The pressure at the outlet of 

the connecting pipeline is assumed to be 90 psia. 

The total capital investment was $3,884,782 and total O&M was $281,555/yr. This investment 

worked out to be approximately $0.11/kg ($2.23/GJ) biomethane. 

13 
External Compression Plant 

By default, the ‘Biomethane Compressor’ tab models three parallel compressors with up to three 

stages per compressor. Two are used in normal operation; the third is a backup unit for 

contingency. The biomethane is compressed from the output pressure of a low-pressure pipeline 

(e.g., 90 psia), which connects the biogas cleanup plant to the external compression plant, to the 

pressure of natural gas transmission/distribution line (e.g., 600 psia) at the point of injection. 

For the default input data, the total capital investment of the compressor was $1,631,963 and the 

total O&M was $151,336/yr, resulting in an investment of $0.05/kg ($1.02/GJ) biomethane. 

Case Study Parameters for Biogas Upgrading Process 

Cost data from vendors were collected to determine the cost of biomethane from biogas. The 

costs are commensurate with the upgrading process and are converted to the base currency of the 

model using the EIA GDP Implicit Deflator Price Index [9]. 

The biogas composition is assumed to be 60% CH4, 38% CO2, 2% N2, hydrogen sulfide (H2S) of 

600–800 ppm, and siloxane of 60–80 mg/m3. The volume and energy content of the biogas are 

based on the CH4, CO2, and N2 content; the other impurities are noted for detail of pipeline 

quality requirements. The other values have little effect on energy or volume; however, siloxane, 

H2S, and other impurities are important for the biogas cleanup design in a real system. In line 

with the quality of pipeline natural gas, the product-gas composition is 96%–98% CH4 (97% 

used), < 1% CO2 (1% used), < 4 ppm H2S, < 30 ppb siloxane. All percentages are by volume. 

The expected average flow was 2000 Nm3/h (~875 scfm) assuming that peak flow could be 

moderated to not exceed that average. The system has an annual operating capacity factor of 

90%, resulting in an annual operation of 7,884 h. 

The variable operating costs consist of utility electricity and biogas feedstock. The electricity 

usage for the upgrading process was determined to be 0.23 kWh/Nm3 of feed gas based on the 

vendors’ data. A constant cost of 0.055/kWh for industrial rate electricity was used so 

sensitivities could be run on the price of electricity. Estimated dairy biogas feedstock costs 

ranged from 2.9/GJ (2010 dollars) for a covered-lagoon digester to 7.6/GJ (2010 dollars) for a 

plug-flow digester and to 11/GJ (2010 dollars) for a well-mixed anaerobic digester system [8]. A 

baseline cost of 7.6/GJ (2010 dollars) was assumed as the default value in this case study. The 

biogas usage was calculated to be 2.209 Nm3

/kg biomethane using an energy content of 0.0223 

GJ/Nm3

 as calculated in the ‘Biogas Upgrade’ from the biogas composition. 

The uninstalled capital cost is estimated to be $2.57 M with an installation factor of 1.29. This 

multiplier was estimated based on vendor input and covers the full installation costs; therefore, 

no additional costs are included in the indirect depreciable capital costs section of the 

‘Input_Sheet_Template’. The annual O&M cost is determined to be 6% of the uninstalled capital 

cost. The system life is 20 years with a salvage value of 10% at end of life. An H2A standard 

10% internal rate of return is used. 

Table 2 shows the summary of parameters used for the case study. 

14 
Table 2. Baseline Parameters for Upgrading Biogas From Dairy Farms 

Parameter Baseline Value 

Feedstock biogas composition 60% CH4, 38% CO2, 2% N2, H2S in 600–800 ppm, 

siloxane 60–80 mg/m3 

Product biomethane composition 97% CH4, 1% CO2, < 4 ppm H2S, < 30 ppb siloxane 

Feed biogas flow rate 2,000 Nm3

/h 

Capacity factor 90% (7,884 h/yr) 

Electricity usage 0.23 kWh/Nm3

 biogas 

Biogas price $(2010) 7.6/GJ 

Uninstalled capital cost $(2005) 2.57 M 

Installation factor 1.29 

Annual O&M 6% uninstalled capital cost 

System life 20 years 

Salvage value 10% 

IRR 10% 

Case Study – Results 

The format of the results can be seen in the following figures, which are in line with the current 

H2A presentation. The breakdown of costs can be seen in Figure 15, excerpted from the 

‘Results’ tab in the spreadsheet model. 

The emissions summary can be seen in Figure 16. Production of the biogas results in a net 

reduction of CO2, but the purification results in some loss of that initial benefit. CO2 cleaned 

from the biogas is assumed to be vented to the atmosphere as well as a small loss of CH4 during 

the cleanup process. Overall there is a net reduction in total CO2 from well to end-use 

application, but the total GHG is a net increase because some CH4 and N2O are lost. 

Case Study – Sensitivity 

A sensitivity analysis was run on several key parameters/variables (see Table 3). Their respective 

low and high limits were used to determine the range of effects their variations might have on 

biomethane cost. 

Table 3. Sensitivity Parameters With Percent Change From Baseline in Parenthesis 

Parameter Baseline Value Low Value High Value 

Biogas price 6.8 ($(2005)/GJ) 2.6 9.85 

Total direct capital cost $(2005)3,310,939 $2,979,845 (–10%) $3,642,033 (+10%) 

Biogas usage 2.209 (nm3

/kg biomethane) 2.099 (–5%) 2.319 (+5%) 

Operating factor 90% 95% 85% 

Electricity price 0.055 ($/kWh) 0.050 (–10%) 0.061 (+10%) 

Electricity usage 0.508 (kWh/kg biomethane) 0.483 (–5%) 0.533 (+5%) 

Pipeline length 10 (mi) 8 (–20%) 12 (+20%) 

External compression 

outlet pressure 

600 (psia) 540 (–10%) 660 (+10%) 

15 
Specific Item Cost 

Calculation 

Total Cost of Delivered Biomethane $0.64/kg $13.11/GJ 

Cost Component Biomethane Production Cost Contribution ($/kg) Pipeline Costs ($/kg) Compressor Costs ($/kg) Biomethane Production Cost Contribution ($/GJ) Pipeline 

($/GJ

Capital Costs $0.08 $0.07 $0.03 $1.63 $1.5

Decommissioning Costs $0.00 $0.02 

Fixed O&M $0.03 $0.04 $0.01 $0.67 $0.7

Feedstock Costs $0.34 $0.00 $0.01 $6.95 $0.0

Other Raw Material Costs $0.00 $0.00 

Byproduct Credits $0.00 $0.00 

Other Variable Costs (including 

utilities) $0.03 $0.58 

Sub Total $0.48 $0.11 $0.05 $9.86 $2.2

Figure 15. Breakdown baseline scenario cost for biomethane from dairy biogas 

Emissions Summary CO2 CH4 N2O 

Total upstream emissions (kg/kg biomethane) -1.81 2.46E-03 2.67E-05 

Total process emissions (kg/kg biomethane) 1.62 0.01 0.00 

Total well to pump emissions (kg/kg biomethane) -0.19 1.20E-02 2.67E-05 

Figure 16. Emissions Summary from ‘Results’ tab of baseline scenario for biomethane from dairy 

16 
 

 

 

 

The tornado chart in Figure 17 and Table 4 show the results. Biogas price has the largest effect 

by far with a low biogas price producing biomethane at $9.01/GJ and at a high price $17.50/GJ. 

All other variables had a net effect of only ± $0.36/GJ. The electricity and biogas usage varied 

by ± 5% of their baseline value, because efficiency was expected to vary in a smaller range, 

whereas capital cost and electricity price varied ± 10%. The outlet pressure of the compression 

plant varied by ± 10% and the distribution pipeline length by ± 20%. The pipeline length had a 

significant effect, even within a few miles. Biogas price was given a high and low value based on 

the USDA paper [8]. 

$6.00 $8.00 $10.00 $12.00 $14.00 $16.00 $18.00 $20.00 

Electricity Usage (-/+ 5%) 

Compression Plant Outlet Pressure (-/+ 10%) 

Electricity Price (-/+ 10%) 

Operating Capacity Factor (95%,90%,85%) 

Total Biogas Conditioning Plant Direct Capital Cost (-/+ 10%) 

Biogas Usage (-/+ 5%) 

Distribution Pipe Length (-/+ 20%) 

Biogas Price ($2.6/GJ,$6.8/GJ,$9.9/GJ) 

Biomethane Cost ($/GJ) 

Biomethane Cost Sensitivity 

Figure 17. Sensitivity of several parameters on the cost of biomethane
 

Table 4. Sensitivity Results for High and Low Biomethane Cost 

Parameter Low Cost ($/GJ 

Biomethane) 

High Cost ($/GJ 

Biomethane) 

Electricity usage (± 5%) $13.08 $13.14 

Compression plant outlet pressure (± 10%) $13.07 $13.14 

Electricity price (± 10%) $13.04 $13.18 

Operating capacity factor (95%, 90%, 85%) $12.99 $13.23 

Total biogas conditioning plant direct capital cost (± 10%) $12.94 $13.27 

Biogas usage (± 5%) $12.75 $13.46 

Distribution pipe length (± 20%) $12.75 $13.47 

Biogas price ($2.6/GJ,$6.8/gj,$9.9/GJ) $9.01 $17.50 

17 
Summary 

A biomethane cost-analysis model based on the H2A Production and H2A Delivery Components 

models was developed to calculate the costs associated with biogas purification, transport, and 

compression. Biogas resource potential is geographically widespread and might easily be 

integrated into natural gas networks [11]. Biomethane production and use offer environmental 

benefits and can help meet the requirements of the evolving renewable portfolio standards. The 

original H2A models were used with necessary modifications to determine the levelized cost of 

biomethane at the production plant and point of delivery to the natural gas grid or any other enduse site. The H2A Biomethane model includes additional worksheet tabs. 

A new worksheet, ‘Biogas Upgrade,’ was designed to help users characterize the biogas cleanup 

plant by providing data such as the chemical compositions of the biogas and biomethane streams, 

biogas feed flow rate, and process energy usage. As an option, the worksheet also allows the 

users to input itemized capital costs and implement a scaling factor. These data help determine 

the properties of the inlet and outlet streams and project the total costs, energy consumption, and 

emissions. Another new worksheet, ‘Biomethane Pipeline,’ analyzes a network of pipelines that 

might be used for either collection of biogas from several sources to a central purification plant 

or export of biomethane to the natural gas grid or to other application sites. A ‘Biomethane 

Compressor’ worksheet was also added to account for the costs of any pressure-boosting 

compressors that may be required depending on the end-use application (e.g., injection into the 

natural gas pipeline). 

A case study was developed for a hypothetical scenario where biomethane is produced from 

biogas and is exported to the natural gas grid. In this scenario, biogas is purchased from a dairy 

farm at a cost of $6.80/GJ. The assumptions for the cost analysis include: 10% rate of return, 20­

year life time, and 1.9% inflation rate. The biogas upgrading plant processes 2000 Nm3

 biogas/h 

for an approximate output of 9.6 M Nm3/yr (360 M scf/yr; 7.1 M kg/yr) of pipeline quality 

biomethane recognizing that some volume is lost in the cleanup process, which removes CO2, 

N2, and other impurities. The projected levelized cost of biomethane delivered to the natural gas 

pipeline is about $13.11/GJ LHV, which includes the costs of purification, pipeline transport, 

and compression. 

18 
References 

1. Steward, D., T. Ramsden, and J. Zuboy, H2A Production Model, Version 2 User Guide. 

2008. p. Medium: ED; Size: 69 pp. 

2. H2A Delivery Components Model Version 1.1: Users Guide. 2007; Available from: 

http://www.hydrogen.energy.gov/h2a_delivery.html. 

3. H2A Delivery Components Model Version 1.1. 2007; Available from: 

http://www.hydrogen.energy.gov/h2a_delivery.html. 

4. National Institute of Standards and Technology (NIST) Webbook: Methane. 2008 [cited 

2010 June 17]; Available from: http://webbook.nist.gov/cgi/cbook.cgi?ID=74-82-8. 

5. Parker, N.C., Using Natural Gas Transmission Pipeline Costs to Estimate Hydrogen 

Pipeline Costs, in UCD-ITS-RR-04-35. 2005, Institute of Transportation Studies, 

University of California Davis: Davis, CA. 

6. True, W.R., More Construction, Higher Costs in Store for US Pipelines. The Oil and Gas 

Journal, 2000. 98. 

7. The Greenhouse Gases, Regulated Emissions, and Energy Use in Transportation 

(GREET) Model. 2009 June, 3, 2010]; Available from: 

http://www.transportation.anl.gov/modeling_simulation/GREET/. 

8. An Analysis of Energy Production Costs from Anaerobic Digestion Systems on U.S. 

Livestock Production Facilities, National Resources Conservation Service, Editor. 2007, 

USDA. 

9. Short‐Term Energy Outlook. September 2009, Energy Information Administration, U.S. 

Department of Energy. 

10. California Air Resources Board, Detailed California-Modified GREET Pathway for 

Compressed Natural Gas (CNG) from Dairy Digester Biogas Version 1.0. 2009, 

California Environmental Protection Agency. 

11. California Air Resources Board: Low Carbon Fuel Standards Program. [cited 2010 June 

30]; Available from: http://www.arb.ca.gov/fuels/lcfs/lcfs.htm. 

19 
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H2A Biomethane Model Documentation and a Case Study for 

Biogas From Dairy Farms

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DE-AC36-08GO28308

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6. AUTHOR(S)

Genevieve Saur and Ali Jalalzedeh-Azar

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NREL/TP-5600-49009

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H2782330

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14. ABSTRACT (Maximum 200 Words)

The new H2A Biomethane model was developed to estimate the levelized cost of biomethane by using the 

framework of the vetted original H2A models for hydrogen production and delivery. For biomethane production, 

biogas from sources such as dairy farms and landfills is upgraded by a cleanup process. The model also estimates 

the cost to compress and transport the product gas via the pipeline to export it to the natural gas grid or any other 

potential end-use site. Inputs include feed biogas composition and cost, required biomethane quality, cleanup 

equipment capital and operations and maintenance costs, process electricity usage and costs, and pipeline delivery 

specifications.

15. SUBJECT TERMS

h2a, biomethane, hydrogen, dairy farm, landfill

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