Life Cycle Assessment of

Hydrogen Production via

Natural Gas Steam Reforming

Revised February 2001 ï NREL/TP-570-27637

Pamela L. Spath

Margaret K. Mann

National Renewable Energy Laboratory

1617 Cole Boulevard

Golden, Colorado 80401-3393

NREL is a U.S. Department of Energy Laboratory

Operated by Midwest Research Institute • Battelle • Bechtel

Contract No. DE-AC36-99-GO10337
National Renewable Energy Laboratory

1617 Cole Boulevard

Golden, Colorado 80401-3393

NREL is a U.S. Department of Energy Laboratory

Operated by Midwest Research Institute • Battelle • Bechtel

Contract No. DE-AC36-99-GO10337

Revised February 2001 ï NREL/TP-570-27637

Life Cycle Assessment of

Hydrogen Production via

Natural Gas Steam Reforming

Pamela L. Spath

Margaret K. Mann

Prepared under Task No. HY004041
NOTICE

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February 2001 Revision Notes

Notes regarding changes from the November 2000 published version of this report

Pages 7, 10, and 15 contain updated information.

November 2000 Revision Notes

Notes regarding changes from the August 2000 published version of this report

A reduction was made in the amount of natural gas losses. This changed several of the numbers

and percentages given throughout the report. However, most of the values varied by a small

amount and the conclusions remain the same.

The Executive Summary, pages 8ñ21 and pages 23ñ24 contain updated information.
0

5

10

15

20

25

30

35

40

45

50

55

60

65

CH4 NMHCs NOx SOx CO particulates benzene

Air emissions, excluding CO2 (g/kg of H2)

EXECUTIVE SUMMARY

A life cycle assessment (LCA) of hydrogen production via natural gas steam reforming was performed to examine

the net emissions of greenhouse gases, as well as other major environmental consequences. LCA is a systematic

analytical method that helps identify and evaluate the environmental impacts of a specific process or competing

processes. In order to quantify the emissions, resource consumption, and energy use (i.e., environmental stressors),

material and energy balances are performed in a cradle-to-grave manner on the operations required to transform

raw materials into useful products. Natural gas lost to the atmosphere during production and distribution is also

taken into account. Ultimately, this LCA will be compared to other hydrogen production technologies to examine

the environmental benefits and drawbacks of the competing systems.

The size of the hydrogen plant was set at 1.5 million Nm3

/day (57 million scfd). The natural gas is reformed in

a conventional steam reformer, and the resulting synthesis gas is shifted in both high and low temperature shift

reactors; purification is performed using a pressure swing adsorption (PSA) unit. Although the plant requires some

steam for the reforming and shift reactions, the highly exothermic reactions result in an excess amount of steam

produced by the plant. For the base case, this steam is assumed to be used by some other source. Therefore, the

stressors that would have resulted from producing and transporting natural gas and combusting it in a boiler are

avoided because the other process/facility is not required to produce this steam (see section 3.0 for details).

 

In terms of total air emissions, CO2 is emitted in the greatest quantity, accounting for 99% (by weight) of the total

air emissions. The CO2 accounts for 89.3% of the systemís global warming potential (GWP), defined as a

combination of CO2, CH4, and N2O emissions expressed as CO2-equivalence for a 100 year time frame. Methane

accounts for 10.6% of the GWP. The overall GWP of the system is 11,888 g CO2-equivalent/kg of hydrogen

produced; the following table contains a breakdown of the sources showing that the hydrogen plant itself accounts

for 74.8% of the greenhouse gas emissions.

Sources of System Global Warming Potential

total

(g/kg of H2)

% from

construction &

decommissioning (a)

% from

natural gas

production

& transport

% from

electricity

generation

% from H2

plant

operation

% from

avoided

operations (b)

Greenhouse gas

emissions (CO2-eq)

11,888 0.4% 25.0% 2.3% 74.8% -2.5%

(a) Construction and decommissioning include plant construction and decommissioning as well as construction of the

natural gas pipeline.

(b) Avoided operations are those that do not occur because excess steam is exported to another facility. See section 3.0

for more information about this.

Other than CO2, methane is emitted in the next greatest quantity followed by non-methane hydrocarbons

(NMHCs), NOx , SOx , CO,

particulates, and benzene. Most of

these air emissions are a result of

natural gas production and

distribution. In terms of resource

consumption, as anticipated, natural

gas is used at the highest rate,

followed by coal, iron (ore plus

scrap), limestone and oil. There is

also a considerable amount of water

consumed primarily at the hydrogen

plant. This is due to the steam

requirements for reforming and shift

conversion. The majority of the

system waste (72.3%) is generated

during natural gas production and

distribution. The remaining waste

comes from electricity production

(31.0%), and construction and

Rev 11/00
decommissioning (3.8%). There is also a small amount of waste that is credited to the system due to the avoided

operations (-7.1%). Water emissions are small compared to the other emissions.

In examining the energy balance of the system, most of the energy consumed is that contained in the natural gas

feedstock. The hydrogen plant energy efficiency is 89.3%, on a higher heating value (HHV) basis (defined as the

energy out of the system divided by the energy into the system). Two additional energy efficiencies and two

energy ratios, as defined in the following table, were used to examine the energy budget of the system.

Energy Efficiency and Ratio Definitions (LHV basis)

Life cycle efficiency (%)(a) External energy

efficiency (%) (b)

Net energy ratio (c) External energy ratio (d)

where:

Eh2 = energy in the hydrogen

Eu = energy consumed by all upstream processes required to operate the hydrogen plant

Ef = energy contained in the natural gas fed to the hydrogen plant

Eff = fossil fuel energy consumed within the system (e)

(a) Includes the energy consumed by all of the processes.

(b) Excludes the heating value of the natural gas feedstock from the life cycle efficiency formula.

(c) Illustrates how much energy is produced for each unit of fossil fuel energy consumed.

(d) Excludes the energy of the natural gas to the hydrogen plant.

(e) Includes the natural gas fed to the hydrogen plant since it is consumed within the boundaries of the system.

Energy Balance Results (LHV basis)

System Life cycle

efficiency

External energy

efficiency

Net energy

ratio

External

energy ratio

H2 production via natural

gas steam reforming

-39.6% 60.4% 0.66 5.1

On a life cycle basis, for one MJ of fossil fuel consumed by the system, 0.66 MJ of hydrogen is produced (LHV

basis). This reflects the fact that because natural gas is a non-renewable resource, more energy is consumed by

the system than is produced. This number also accounts for the upstream energy used in producing and

distributing the natural gas and in producing the electricity required to operate the hydrogen plant.

Finally, a sensitivity analysis was performed on the following variables: materials of construction, natural gas

losses, operating capacity factor, recycling versus landfilling of materials, natural gas boiler efficiency, hydrogen

plant energy efficiency, and hydrogen plant steam balance (no credit for excess steam). Most of the variables

examined had no noticeable effect on the LCA. Reducing the hydrogen plant energy efficiency from 89.3% to

80% has the largest effect, with most stressors, including the system GWP, increasing by about 16%. Changes

in natural gas losses significantly affect the GWP. The assumed loss in the base case analysis was 1.4% of the total

amount removed from the ground. A 0.5% loss reduces the GWP by 5%, while a 4% loss results in a 16% increase

from the base case result. NMHC emissions and total system energy consumption are also affected by changes

in the natural gas loss. One other variable had a significant effect on the energy balance of the system is the

hydrogen plant steam balance. The base case assumes that the excess steam produced at the hydrogen plant is used

by another source. If this were not the case, then the system could not be credited for the stressors due to the

avoided natural gas production and distribution, and combustion in a boiler. The upstream energy that is avoided

in producing and distributing natural gas which would have been combusted in a boiler can no longer be credited

to the system. This causes the net energy ratio to decrease from 0.66 to 0.59, and the life cycle efficiency to

decrease from -39.6% to -52.8%.

Rev 11/00
Table of Contents

Units of Measure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

Abbreviations and Terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

1.0 Introduction ..................................................................... 3

2.0 Hydrogen Plant Description and Assumptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

3.0 System Boundaries and Major Assumptions ............................................ 5

4.0 Construction Material Requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

5.0 Natural Gas Composition and Losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

6.0 Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

6.1 Air Emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9

6.2 Greenhouse Gases and Global Warming Potential . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

6.3 Energy Consumption and System Energy Balance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

6.4 Resource Consumption . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

6.5 Water Emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

6.6 Solid Waste . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

7.0 Sensitivity Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

8.0 Impact Assessment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

9.0 Improvement Opportunities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

10.0 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

11.0 References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
List of Tables

Table 1: Steam Methane Reforming Hydrogen Plant Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

Table 2: Hydrogen Plant Material Requirements (Base Case) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

Table 3: Natural Gas Compositions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

Table 4: Average Air Emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

Table 5: Greenhouse Gases Emissions and Global Warming Potential . . . . . . . . . . . . . . . . . . . . . . . . . 11

Table 6: Average Energy Requirements (LHV basis) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

Table 7: Energy Efficiency and Ratio Definitions (LHV basis) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

Table 8: Energy Balance Results (LHV basis) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

Table 9: Average Resource Consumption . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Table 10: Water Consumption . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Table 11: Breakdown of Hydrogen Plant Water Consumption . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

Table 12: Solid Waste Generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

Table 13: Variables Changed in Sensitivity Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

Table 14: Sensitivity Analysis Results - Percent change from base case . . . . . . . . . . . . . . . . . . . . . . . . 18

Table 15: Impacts Associated with Stressor Categories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

List of Figures

Figure 1: Hydrogen Plant Block Flow Diagram . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

Figure 2: System Boundaries for Hydrogen Production via Natural Gas Steam Reforming .......... 6

Figure 3: Life Cycle GWP (CO2 equivalents) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

Figure 4: Sensitivity Results for GWP . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

Figure 5: Sensitivity Results for Life Cycle Efficiency . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

Figure 6: Sensitivity Results for External Energy Efficiency . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

Figure 7: Sensitivity Results for Net Energy Ratio . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

Figure 8: Sensitivity Results for External Energy Ratio . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
1

Units of Measure

Metric units of measure are used in this report. Therefore, material consumption is reported in units based

on the gram (e.g., kilogram or megagram), energy consumption based on the joule (e.g., kilojoule or

megajoule), and distance based on the meter (e.g., kilometer). When it can contribute to the understanding

of the analysis, the English system equivalent is stated in parenthesis. The metric units used for each

parameter are given below, with the corresponding conversion to English units.

Mass: kilogram (kg) = 2.205 pounds

megagram (Mg) = metric tonne (T) = 1 x 106

 g = 1.102 ton (t)

Distance: kilometer (km) = 0.62 mile = 3,281 feet

Area: hectare (ha) = 10,000 m2

 = 2.47 acres

Volume: cubic meter (m3

) = 264.17 gallons

normal cubic meters (Nm3

) = 0.02628 standard cubic feet (scf) at a standard temperature &

pressure of 15.6°C (60°F) and 101.4 kPa (14.7 psi), respectively

Pressure: kilopascals (kPa) = 0.145 pounds per square inch

Energy: kilojoule (kJ) = 1,000 Joules (J) = 0.9488 Btu

gigajoule (GJ) = 0.9488 MMBtu (million Btu)

kilowatt-hour (kWh) = 3,414.7 Btu

gigawatt-hour (GWh) = 3.4 x 109

 Btu

Power: megawatt (MW) = 1 x 106

 J/s

Temperature: °C = (°F - 32)/1.8

Hydrogen Equivalents:

1 kg H2 = 423.3 scf gas = 11.126 Nm3

 gas

= 142 MJ (HHV basis) = 120 MJ (LHV basis)
2

Abbreviations and Terms

Btu - British thermal units

CO2-equivalence- Expression of the GWP in terms of CO2 for the following three components CO2, CH4,

N2O, based on IPCC weighting factors

DEAM - Data for Environmental Analysis and Management (also referred to as the TEAMÆ

database)

EIA - Energy Information Administration

GWP - global warming potential

HHV - higher heating value

HTS - high temperature shift

IPCC- Intergovernmental Panel on Climate Change

kWh - kilowatt-hour (denotes energy)

LCA - life cycle assessment

LHV - lower heating value

LTS - low temperature shift

MMSFCD - million standard cubic feet per day

MW - megawatt (denotes power)

N2O - nitrous oxide

Nm3

 - normal cubic meters

NMHCs - non-methane hydrocarbons

NOx - nitrogen oxides, excluding nitrous oxide (N2O)

NREL - National Renewable Energy Laboratory

PSA - pressure swing adsorption

SMR - steam methane reforming

SOx - sulfur oxides, including the most common form of airborne sulfur, SO2

Stressor - A term that collectively defines emissions, resource consumption, and energy use; a

substance or activity that results in a change to the natural environment

Stressor category - A group of stressors that defines possible impacts

TEAMÆ - Tools for Environmental Analysis and Management (software by Ecobalance, Inc.)

U.S. DOE - United States Department of Energy

U.S. EPA - Unite States Environmental Protection Agency

wt% - percentage by weight
3

1.0 Introduction

Hydrogen is used in a number of industrial applications, with todayís largest consumers being ammonia

production facilities (40.3%), oil refineries (37.3%), and methanol production plants (10.0%). In 1996, three

trillion cubic feet of hydrogen were consumed in the United States (SRI, 1998). International consumption

of hydrogen follows a similar trend, with ammonia production accounting for 62.4% of the worldís hydrogen,

and refining and methanol production consuming 24.3% and 8.7%, respectively. Because such large

quantities of hydrogen are required in these instances, the hydrogen is generally produced by the consumer,

and the most common method is steam reforming of natural gas. 

A life cycle assessment (LCA) of hydrogen production via steam reforming of natural gas was completed

by the National Renewable Energy Laboratory (NREL). Although, this study in itself is complete, this is the

first in a series of assessments for comparing the environmental benefits and drawbacks of hydrogen

production via other routes such as biomass, wind, and photovoltaics. Additionally, other long-term

technologies (e.g., photobiological hydrogen production, plasma reforming/oxidation, and carbon nanotube

hydrogen storage) can be examined using this analysis tool to explore the possibility of improved

environmental consequences. 

The primary goal of this LCA is to quantify and analyze the total environmental aspects of producing

hydrogen via natural gas steam reforming. In recognition of the fact that upstream processes required for

the operation of the steam methane reforming (SMR) plant also produce pollutants and consume energy and

natural resources, this LCA was performed in a cradle-to-grave manner. For this reason, natural gas

production and distribution, as well as electricity generation, were included in the system boundaries. The

size of the hydrogen plant is 1.5 million Nm3

/day (57 million scfd) which is typical of the size that would

be found at todayís major oil refineries. All resources, emissions, and energy flows were inventoried within

the boundaries of the system so that the total environmental picture of the system could be depicted.

2.0 Hydrogen Plant Description and Assumptions

The system studied in this LCA is hydrogen production via catalytic steam reforming of natural gas, which

is a mature technology and is the route by which most hydrogen is made today. The methodology is the same

as that used and described in detail in earlier LCAs performed by NREL (Mann and Spath, 1997 and Spath

and Mann, 1999). The material and energy balance data for the hydrogen plant were taken from SRI, 1994.

This report presents an accurate picture of todayís typical SMR plant with one exception; the design does

not include a low temperature shift (LTS) reactor. Past analysis (Mann, 1995) and standard practice in the

hydrogen production business have shown the addition of an LTS reactor to be economical due to the small

amount of additional hydrogen produced. Therefore, for this LCA, the SRI design was modified to include

an LTS conversion step. For comparison, a sensitivity analysis was performed to examine the difference in

the overall emissions if an LTS reactor were not included in the hydrogen plant design (see section 7.0). 

Figure 1 is a block flow diagram of the natural gas steam reforming plant studied in this analysis. Prior to

steam reforming, the natural gas is pretreated in a hydrogenation vessel in order to convert any sulfur

compounds to H2S. A small amount of hydrogen, which is recycled from the product stream, is used in this

step. The H2S is then removed in a ZnO bed. After pretreatment, the natural gas and 2.6 MPa (380 psi)

steam are fed to the steam reformer. The resulting synthesis gas is then fed to high temperature shift (HTS)

and LTS reactors where the water gas shift reaction converts 92% of the CO into H2. The hydrogen is

purified using a pressure swing adsorption (PSA) unit. The reformer is fueled primarily by the PSA off-gas,

but a small amount of natural gas (4.4 wt% of the total reformer fuel requirement) is used to supply the

balance of the reformer duty. The PSA off-gas is comprised of CO2 (55 mol%), H2 (27 mol%), CH4 (14

mol%), CO (3 mol%), N2 (0.4 mol%), and some water vapor. The steam reforming process produces 4.8

MPa (700 psi) steam, which is assumed to be exported for use by some other process or facility. Electricity

is purchased from the grid to operate the pumps and compressors. Table 1 gives the major performance and

design data for the hydrogen plant.
High

temperatureshift

Lowtemperatureshift

Hydrogenation ZnO Bed 

natural gasfeedstock

offgas

H product slipstream 2

Catalyticsteamreforming

naturalgas fuel

steam

Figure 1: Hydrogen Plant Block Flow Diagram

4
5

Table 1: Steam Methane Reforming Hydrogen Plant Data

Design Parameter Data

Plant size (hydrogen production capacity) 1.5 million Nm3

/day

(57 million scfd)

Hydrogen purity Industrial grade (>99.95 mol% H2)

Average operating capacity factor 90%

Natural gas consumed @ 100% operating capacity 392 Mg/day (feed)

43 Mg/day (fuel)

Steam requirement (2.6 MPa or 380 psi) @ 100% operating capacity 1,293 Mg/day

Steam production (4.8 MPa or 700 psi) @ 100% operating capacity 1,858 Mg/day

Electricity requirement @ 100% operating capacity 153,311 MJ/day

Hydrogen plant energy efficiency (higher heating value (HHV) basis) 89%

(defined in text below)

Note: The hydrogen plant efficiency changes if the excess steam can not be utilized by a nearby source. However, this

does not change the amount of hydrogen produced by the plant.

The hydrogen plant energy efficiency is defined as the total energy produced by the hydrogen plant divided

by the total energy into the plant, determined by the following formula:

 energy in product hydrogen + 4.8 MPa steam energy (exported) 

natural gas energy + electricity + 2.6 MPa steam energy (required)

If the steam were not included in the above equation, the conversion efficiency would decrease to 79.2% (i.e.,

the 2.6 MPa steam is produced internally and the 4.8 MPa steam could not be used by another source).

Additionally, if a user could not be found for the 4.8 MPa steam but the 2.6 MPa steam were still included

as an energy input, then the hydrogen plant energy efficiency drops to 69.1%. While this would be the

preferred operation for a hydrogen plant integrated with petroleum refining, a stand-alone dedicated

hydrogen production facility would generate the 2.6 MPa steam internally rather than buy it if a customer

for the 4.8 MPa steam could not be found. Additionally, if a customer could not be found for the 4.8 MPa

steam, the operator might consider using it to generate electricity for use internally or for sale to the grid.

However, it should be noted that given equal opportunity to find customers, a steam byproduct credit is worth

more than an electricity byproduct credit because of efficiency losses in converting steam to electricity.

In addition to adding an LTS reactor to the plant design, the reformer flue gas composition was corrected to

include NOx, CO, and particulate emissions. Since the reformer furnace is equipped with a low NOX burner

which reduces the emissions to 20 ppm (SRI, 1994), this amount was assumed to be emitted from the

hydrogen plant. CO and particulate emissions were obtained from the U.S. Environmental Protection

Agencyís (EPA) data on natural gas combustion furnaces (U.S. EPA, 1995). The amount of the pollutant

is given per the quantity of natural gas fired based on an average natural gas HHV of 8,270 kcal/m3

 (1,000

Btu/scf). The data were ratioed to account for the difference in the heating value of the reformer fuel versus

that of natural gas. The resulting CO and particulate emissions from the reformer are 0.084 g/kg H2 and

0.023 g/kg H2, respectively. 

3.0 System Boundaries and Major Assumptions

The software package used to track the material and energy flows between the process blocks in the system

was Tools for Environmental Analysis and Management (TEAMÆ), by Ecobalance, Inc. Figure 2 shows the

boundaries for the system. The solid lines in the figure represent actual material and energy flows; the dotted

lines indicate logical connections between process blocks. The dashed lines with Xs through them denote

the flows that do not occur because the steam is produced by the hydrogen plant instead of a natural gas

boiler. These are the avoided emissions, and thus are taken as credits in the total inventory of the system.
Figure 2: System Boundaries for Hydrogen Production

via Natural Gas Steam Reforming

6

RM = raw materials

M = materials

E = energy

Em = emissions

Construction

of equipment

RM

E

Em

Hydrogen

production

plant

M

E

Em

RM

E

Recycling

Em

E

Production

& distribution

of natural gas

Em

E

RM

Em

Raw material

extraction

E RM

Production

& distribution

of electricity

Em

RM

RM

E

Landfilling

Em

Avoided operations

-E -RM

Natural gas

boiler

-Em

-RM

-E

Production

& distribution

of natural gas

-Em
7

The stressors associated with natural gas production and distribution, as well as those for electricity

generation, were taken from the TEAMÆ database, known as Data for Environmental Analysis and

Management (DEAM). The steps associated with obtaining the natural gas feedstock are drilling/extraction,

processing, and pipeline transport. Processing includes glycol dehydration and gas sweetening using the

amine process in which sulfur is recovered as elemental sulfur. The emissions associated with each process

step in the natural gas production block were obtained through a joint study by Ecobalance, Inc. and the Gas

Research Institute (GRI). Electricity production was assumed to be the generation mix of the mid-continental

United States, which according to the National Electric Reliability Council, uses 64.7% coal, 5.1% lignite,

18.4% nuclear, 10.3% hydro, 1.4% natural gas, and 0.1% oil; power distribution losses are taken at 7.03%.

The stressors associated with this mix were also determined in a cradle-to-grave manner in DEAM, and thus

taken into account in this LCA. Some details about the DEAM database modules can be found in the

appendix of Mann and Spath (1997).

Because hydrogen production by steam reforming of natural gas is a highly exothermic process more steam

is produced by the hydrogen plant than is consumed. The excess steam generated by the plant is assumed

to be used by another source. Because this other source does not have to generate steam itself, a credit is

taken for the stressors that would have resulted from producing and transporting natural gas and combusting

it in a boiler assuming a boiler efficiency of 75%. The emissions for natural gas production are the same as

those discussed in the previous paragraph. The natural gas boiler emissions were based on emissions from

EPA for natural gas combustion in industrial boilers (U.S. EPA, 1995). A sensitivity analysis was performed

to examine the changes in the LCA results for the case where no user for the steam could be found, and

therefore credits could not be taken for the excess steam (see section 7.0).

For this study, the plant life was set at 20 years with 2 years of construction. In year one, the hydrogen plant

begins to operate; plant construction takes place in the two years prior to this (years negative two and

negative one). In year one the hydrogen plant is assumed to operate only 45% (50% of 90%) of the time due

to start-up activities. In years one through 19, normal plant operation occurs, with a 90% capacity factor.

During the last quarter of year 20 the hydrogen plant is decommissioned. Therefore, the hydrogen plant will

be in operation 67.5% (75% of 90%) of the last year.

4.0 Construction Material Requirements

Methods for determining plant construction and decommissioning are the same as those used in NRELís past

LCAs (see Mann and Spath, 1997 and Spath and Mann, 1999). Table 2 lists the material requirements used

for the plant in this study. A sensitivity analysis was performed to determine how changing these numbers

would affect the results (see section 7.0).

Table 2: Hydrogen Plant Material Requirements (Base Case)

Material Amount required

(Mg)

Concrete 10,242

Steel 3,272

Aluminum 27

Iron 40

Because of the large amount of natural gas being consumed, an assumption was made that additional

pipelines would be required to move the natural gas from the oil or gas wells to the hydrogen plant.

Ullmann's Encyclopedia of Industrial Chemistry (1986) states that typical pipe diameters in the natural gas

industry are 60-110 centimeters (23.6-43.3 inches) and Kirk-Othmerís Encyclopedia of Chemical Technology

(1993) lists a range of 36-142 centimeters (14.2-55.9 inches). For this analysis, the total length of pipeline

transport is assumed to be 4,000 km (2,486 mi), based on information from Ecobalance, Inc. The main

pipeline diameter was set at 61 centimeters (24 inches) and is assumed to extend 80% of the total distance

Rev 2/01
8

or 3,200 km (1,988 mi). Because the main pipeline is shared by many users, only a portion of the material

requirement was allocated for the natural gas combined-cycle plant. To determine this percentage, the

natural gas required by the hydrogen plant was divided by the total flow through the 61 cm diameter pipe at

a pressure drop of 0.05 psi/100 feet (0.001 MPa/100 meters), resulting in a value of 0.9%. The remaining

length of the total pipeline, 800 km (498 mi), was also sized so that the pressure drop through the pipe would

not exceed 0.05 psi/100 feet (0.001 MPa/100 meters). This resulted in a pipe diameter of 15 centimeters (6

inches). Thus, the total pipeline steel requirement for the hydrogen plant was 12,539 Mg (13,822 tons)

assuming a standard wall thickness. The process steps associated with producing the steel (e.g., iron

production, electricity generation, steel manufacture, etc.) were included in the analysis, and a sensitivity

case was performed using different pipe diameters to determine the effect of material requirements on the

results (see section 7.0). Due to a lack of data, the emissions that would result from installing the pipeline

were not included in the analysis. 

5.0 Natural Gas Composition and Losses

While natural gas is generally thought of as methane, about 5 - 25% of the volume is comprised of ethane,

propane, butane, hydrogen sulfide, and inerts (nitrogen, CO2, and helium). The relative amounts of these

components can vary greatly depending on the location of the wellhead. Table 3 gives the composition of

the natural gas feedstock used in this analysis, as well as typical pipeline and wellhead compositions. The

composition used in this study (first column) assumes that the natural gas is sweetened to remove H2S to a

level of 4 ppmv prior to pipeline transport. Before feeding the natural gas to the reformer, any residual sulfur

is removed using a zinc oxide bed.

Table 3: Natural Gas Compositions

Component Natural gas feedstock

used in analysis (a)

Typical pipeline

composition (b)

Typical range of wellhead

components (mol%) (c)

Mol % (dry) Mol % (dry) Low value High value

Methane (CH4) 94.5 94.4 75 99

Ethane (C2H6) 2.7 3.1 1 15

Propane (C3H8) 1.5 0.5 1 10

Nitrogen (N2) 0.8 1.1 0 15

Carbon dioxide (CO2) 0.5 0.5 0 10

Iso-butane (C4H10) 0 0.1 0 1

N-butane (C4H10) 0 0.1 0 2

Pentanes + (C5

+

) 0 0.2 0 1

Hydrogen sulfide (H2S) 0 0.0004 0 30

Helium (He) 0 0.0 0 5

Heat of combustion, HHV 53,680 J/g

(23,079 Btu/lb)

53,463 J/g

(22,985 Btu/lb)

____ ___

(a) Taken from SRI, 1994.

(b) Taken from Chemical Economics Handbook (Lacson, 1999) and adjusted to included H2S.

(c) Taken from Ullmann's Encyclopedia of Industrial Chemistry, 1986.

In extracting, processing, transmitting, storing, and distributing natural gas, some is lost to the atmosphere.

Over the past two decades, the natural gas industry and others have tried to better quantify the losses. There

is a general consensus that fugitive emissions are the largest source, accounting for about 38% of the total,

and that nearly 90% of the fugitive emissions are a result of leaking compressor components (Resch, 1995

and Harrison et al, 1997). The second largest source of methane emissions comes from pneumatic control

Rev 11/00
9

devices, accounting for approximately 20% of the total losses (Resch, 1995). The majority of the pneumatic

losses happen during the extraction step. Engine exhaust is the third largest source of methane emissions

due to incomplete combustion in reciprocating engines and turbines used in moving the natural gas through

the pipeline. These three sources make up nearly 75% of the overall estimated methane emissions (Resch,

1995 and Harrison et al, 1997). The remaining 25% comes from sources such as dehydrators, purging of

transmission/storage equipment, and meter and pressure regulating stations in distribution lines. 

According to the EPA, transmission and storage account for the largest portion of the total methane emissions

at 37% followed by extraction at 27%, distribution at 24%, and processing contributing the least at 12%

(Harrison et al, 1997). In the late 1980s EPA, GRI, and the American Gas Association (AGA) initiated a

study which estimated the methane emitted to the atmosphere from U.S. natural gas operations to be 1.4%

+/- 0.5% of the gross natural gas produced (Harrison et al, 1997). Another publication (Kirchgessner et al,

1997) which includes several authors of the EPA/GRI/AGA study, states that numerous estimates of methane

emissions are available and that the most commonly cited leakage rates range from 1-4%. Following the

EPA/GRI/AGA study, the Natural Gas STAR Program was launched in 1993. It is a voluntary program with

the natural gas industry designed to reduce methane emissions through cost-effective measures. The program

currently has over 80 partners. Because of this program, the overall amount of methane lost to the

atmosphere is actually expected to decrease as the natural gas industry grows. The base case of this LCA

assumed that 1.4% of the natural gas that is produced is lost to the atmosphere due to fugitive emissions.

To determine the effect that natural gas losses have on the results, and specifically on the systems global

warming potential (GWP), a sensitivity analysis was performed on this variable (see section 7.0). The

natural gas production module in DEAM was altered so that it could accommodate different natural gas loss

rates.

6.0 Results

The results of this LCA, including air emissions, energy requirements, resource consumption, water

emissions, and solid wastes, are presented here. The functional unit, also known as the production amount

that represents the basis for the analysis, was chosen to be the net amount of hydrogen produced. Most

values are given per kg of hydrogen, averaged over the life of the system so that the relative contribution of

stressors from the various operations could be examined. Because the resource consumption, emissions, and

energy use are functions of the size of the plant and the technology, care should be taken in scaling results

to larger or smaller facilities, or applying them to other hydrogen production systems. 

6.1 Air Emissions

In terms of total air emissions, CO2 is emitted in the greatest quantity, accounting for 99 wt% of the total air

emissions. The vast majority of the CO2 (84%) is released at the hydrogen plant. Table 4 is a list of the

major air emissions as well as a breakdown of the percentage of each emission from the following

subsystems: construction and decommissioning, natural gas production and transport, electricity generation,

hydrogen plant operation, and avoided operations. After CO2, methane is emitted in the next greatest

quantity followed by non-methane hydrocarbons (NMHCs), NOx, SOx, CO, particulates, benzene, and N2O.

Overall, other than CO2, most of the air emissions are a result of natural gas production and distribution.

Very few emissions, other than CO2, come from the hydrogen plant operation itself. The CH4 is primarily

a result of natural gas fugitive emissions which are 1.4% of the gross natural gas production for the base case.

Although not shown in Table 4, the CH4 emitted during production and distribution of natural gas is 76%

of the total system methane emissions.

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10

Table 4: Average Air Emissions

Air Emission System total

(g/kg of H2)

% of

total in

this table

% of total

excluding

CO2

% of total from

construction &

decommissioning

% of total from

natural gas

production &

transport

% of total

from

electricity

generation

% of t

from H2 

opera

Benzene (C6H6) 1.4 < 0.0% 1.3% 0.0% 110.9% 0.0% 

Carbon Dioxide (CO2) 10,620.6 99.0% 0.4% 14.8% 2.5% 

Carbon monoxide (CO) 5.7 0.1% 5.3% 2.0% 106.3% 0.7% Methane (CH4) 59.8 0.6% 55.7% < 0.0% 110.8% < 0.0% 

Nitrogen oxides (NOX as NO2) 12.3 0.1% 11.0% 1.8% 90.3% 9.5% 

Nitrous oxide (N2O) 0.04 < 0.0% < 0.0% 7.3% 37.6% 58.7% 

Non-methane hydrocarbons(NMHCs)

16.8 0.2% 15.6% 1.7% 89.8% 14.5% 

Particulates 2.0 < 0.0% 1.8% 64.5% 25.2% 11.6% Sulfur oxides (SOX as SO2) 9.5 0.1% 8.8% 13.5% 68.3% 24.9% 

Note: Construction and decommissioning include plant construction and decommissioning as well as construcpipeline.

Rev 2/01
11

6.2 Greenhouse Gases and Global Warming Potential

Although CO2 is the most important greenhouse gas and is the largest emission from this system, quantifying

the total amount of greenhouse gases produced is the key to examining the GWP of the system. The GWP

of the system is a combination of CO2, CH4, and N2O emissions. The capacity of CH4 and N2O to contribute

to the warming of the atmosphere is 21 and 310 times higher than CO2, respectively, for a 100 year time

frame according to the Intergovernmental Panel on Climate Change (IPCC) (Houghton, et al, 1996). Thus,

the GWP of a system can be normalized to CO2-equivalence to describe its overall contribution to global

climate change. The GWP, as well as the net amount of greenhouse gases, are shown in Table 5. It is

evident from this table that CO2 is the main contributor, accounting for 89.3% of the GWP for this specific

system. However, it is important to note that the natural gas lost to the atmosphere during production and

distribution causes CH4 to affect the systemís GWP. Although the amount of CH4 emissions is considerably

less than the CO2 emissions on a weight basis (10,621 g of CO2/kg of H2 versus 60 g of CH4/kg of H2),

because the GWP of CH4 is 21 times that of CO2, CH4 accounts for 10.6% of the total GWP.

Table 5: Greenhouse Gases Emissions and Global Warming Potential

Emission

amount

(g/kg of H2)

Percent of

greenhouse gases

in this table (%)

GWP relative to

CO2 (100 year IPCC

values)

GWP value

(g CO2-equivalent/kg of H2)

Percent

contribution

to GWP (%)

CO2 10,621 99.4 1 10,621 89.3

CH4 60 0.6 21 1,256 10.6

N2O 0.04 0.0003 310 11 0.1

GWP N/A N/A N/A 11,888 N/A

Note: Additional figures after the decimal than those that are significant are presented so that the emissions

would not appear as being zero. 

Figure 3 shows how the CO2-equivalent emissions are divided among natural gas production and distribution,

electricity generation, plant construction and decommissioning and pipeline construction, hydrogen plant

operation, and avoided operations. The majority comes primarily from the hydrogen plant, which accounts

for 74.8% of the overall GWP of the system. This is followed by natural gas production and distribution

which contributes 25.0% to the GWP. Again, this is due to the amount of the natural gas lost to the

atmosphere. Changing the amount of natural gas lost will have a significant affect on the systemís GWP and

this can be seen in the sensitivity analysis in section 7.0.

6.3 Energy Consumption and System Energy Balance

Energy consumption is an important part of LCA. The energy consumed within the system boundaries

results in resource consumption, air and water emissions, and solid wastes. Table 6 shows the energy balance

for the system and because of its magnitude, the natural gas energy is listed separately. Most of the energy

consumed, about 87%, is that contained in the natural gas fed to the steam reformer. As discussed in section

3.0, because of the excess steam produced at the hydrogen plant, a credit is taken for the stressors associated

with producing and transporting natural gas and then combusting it in a boiler. Therefore, the non-feedstock

energy from the avoided operations steps is negative.

Rev 11/00
Figure 3: Life Cycle GWP (CO -equivalent) 2

41

(0.4%)

293

(-2.5%)

2,972

(25.0%)

273

(2.3%)

Construction &

Decommissioning

Avoided

Operations

Avoided Operations = steam production from a natural gas boiler and

natural gas production & distribution required to obtain the natural gas

Electricity

Generation

8,895

(74.8%)

Hydrogen

Plant

Operation

Net greenhouse gas emissions

11,888 g CO equivalent/kg of net hydrogen produced 2

Natural Gas

Production &

Distribution

12

Rev 11/00
13

Table 6: Average Energy Requirements (LHV basis)

System

total energy

consumption

(MJ/kg H2)

% of

total in

this

table

% of total from

construction &

decommissioning

% of total

from natural

gas

production

&

distribution

% of total

from 

electricity

generation

% of total

from avoided

operations

Energy in the

natural gas to

hydrogen plant

159.6 87.1% N/A 100.0% N/A N/A

Non-feedstock

energy consumed

by system (*)

23.6 12.9% 2.4% 169.8% 17.0% -89.3%

Total energy

consumed by

system

183.2 N/A N/A N/A N/A N/A

* Excludes the energy in the natural gas feedstock energy but includes the energy in the natural gas lost

to the atmosphere during natural gas production.

The hydrogen plant energy efficiency is 89.3%, on an HHV basis (defined in section 2.0). Table 7 contains

four additional terms for evaluating the energy balance of the system. The results are in Table 8.

Table 7: Energy Efficiency and Ratio Definitions (LHV basis)

Life cycle efficiency (%)(a) External energy

efficiency (%) (b)

Net energy ratio (c) External energy ratio (d)

where:

Eh2 = energy in the hydrogen

Eu = energy consumed by all upstream processes required to operate the hydrogen plant

Ef = energy contained in the natural gas fed to the hydrogen plant

Eff = fossil fuel energy consumed within the system (e)

(a) Includes the energy consumed by all of the processes.

(b) Excludes the heating value of the natural gas feedstock from the life cycle efficiency formula.

(c) Illustrates how much energy is produced for each unit of fossil fuel energy consumed.

(d) Excludes the energy of the natural gas to the hydrogen plant.

(e) Includes the natural gas fed to the hydrogen plant since it is consumed within the boundaries of the

system.

Rev 11/00
14

Table 8: Energy Balance Results (LHV basis)

Base case result

Life cycle efficiency -39.6%

External energy efficiency 60.4%

Net energy ratio 0.66

External energy ratio 5.1

The energy in the natural gas is greater than the energy content of the hydrogen produced. Therefore, the

life cycle efficiency is negative. This reflects the fact that because natural gas is a non-renewable resource,

more energy is consumed by the system than is produced. In calculating the external energy efficiency, the

energy content of the natural gas is not included, making the result of this measure positive. The difference

between the hydrogen plant efficiency and the external energy efficiency quantifies how much energy is used

in upstream processes. The results also show that for every MJ of fossil fuel consumed by the system, 0.66

MJ of hydrogen are produced (LHV basis). Although the life cycle efficiency and net energy ratio are more

correct measures of the net energy balance of the system, the external measures are useful because they

expose the rate of energy consumption by the upstream process steps. Disregarding the energy in the natural

gas feedstock, the majority of the total energy consumption comes from natural gas production and

distribution (see Table 6), which can be further broken up into sub-processes: natural gas extraction,

processing, transmission, storage, and distribution. Analyzing each of these steps, it was found that the large

amount of energy consumed in natural gas production is specifically from the natural gas extraction and

transport steps. Conversely, the energy credit from the avoided operations is also a result of natural gas

production and distribution. Note that in general, higher efficiencies and energy ratios are desired for any

process, not only in terms of economics, but in terms of reduced resources, emissions, wastes, and energy

consumption.

6.4 Resource Consumption

Fossil fuels, metals, and minerals are used in converting natural gas to hydrogen. Excluding water, Table

9 shows the major resource consumption requirements for the system. As expected, natural gas is used at

the highest rate, accounting for 94.5% of the total resources on a weight basis, followed by coal at 4.1%, iron

(ore plus scrap) at 0.6%, limestone at 0.4%, and oil at 0.4%. The iron and limestone is used in the

construction of the power plant and pipeline. The majority of the oil consumption (60.9%) comes from

natural gas production and distribution while most of the coal is consumed to produce the electricity needed

by the hydrogen plant.

Rev 11/00
15

Table 9: Average Resource Consumption

Resource total

(g/kg H2)

% of

Total in

this

table

% of total from

construction &

decommissioning

% of total

from natural

gas production

& transport

% of total

from

electricity

generation

% of total

from

avoided

operations

Coal (in ground) 159.2 4.1% 7.1% 17.4% 77.2% -1.7%

Iron (Fe, ore) 10.3 0.3% 100.0% 0.0% 0.0% 0.0%

Iron scrap 11.2 0.3% 100.0% 0.0% 0.0% 0.0%

Limestone (CaCO3,

 in ground)

16.0 0.4% 100.0% 0.0% 0.0% 0.0%

Natural gas (in ground) 3,642.3 94.5% < 0.0% 110.8% 0.1% -10.9%

Oil (in ground) 16.4 0.4% 30.0% 60.8% 15.1% -6.0%

Table 10 is a breakdown of the water consumption for the system. The majority of the water is consumed

at the hydrogen plant. Table 11 divides the hydrogen plant usage into that required for reforming and shift

and that used to produce additional steam. The smaller percentage (24.0%) is the amount that is consumed

during the conversion of natural gas to hydrogen while the higher percentage (71.2%) is a result of the excess

steam production.

Table 10: Water Consumption

total

(liters/kg

H2)

% of total from

construction &

decommissioning

% of total

from natural

gas production

& transport

% of total

from

electricity

generation

% of total

from H2

plant

operation

% of total

from avoided

operations

Water consumed 19.8 3.6% 1.3% < 0.0% 95.2% -0.1%

Table 11: Breakdown of Hydrogen Plant Water Consumption

Amount consumed

(liters/kg H2)

% of total water

consumption

Water consumed in reforming & shift reactions 4.8 24.0%

Water consumed in 4.8 MPa steam production 14.1 71.2%

Total water consumption from hydrogen plant 18.8 95.2%

6.5 Water Emissions

Similar to the findings of previously performed LCAs (Mann and Spath, 1997; and Spath and Mann, 1999),

the total amount of water pollutants was found to be small compared to other emissions. Therefore, a list

of the individual components and their quantities is not reported in this document. The total amount of water

pollutants for this study equals 0.19 g/kg of H2 with the primary pollutant being oils (60%) followed by

dissolved matter (29%). It is interesting to note that the water pollutants come primarily from the material

manufacturing steps required for pipeline and plant construction.

Rev 2/01
16

6.6 Solid Waste

The waste produced from the system is miscellaneous non-hazardous waste, totaling 201.6 g/kg of hydrogen

produced. Table 12 contains a breakdown of the percentage of waste from each of the subsystems. The

majority (72.3%) comes from natural gas production and distribution. Breaking this down further, pipeline

transport is responsible for 50% of the total system waste and natural gas extraction is the second largest

waste source, accounting for 22% of the total. Although the majority of the pipeline compressors are driven

by reciprocating engines and turbines which are fueled by the natural gas, there are some electrical machines

and electrical requirements at the compressor stations. The waste due to pipeline transport is a result of this

electricity requirement. The remaining system waste comes from the grid electricity (31.0%) required to

operate the hydrogen plant and from construction and decommissioning (3.8%) (the electricity generation

mix is described in section 3.0.). Since there are two process steps using a considerable amount of electricity

(natural gas pipeline transport and the hydrogen production plant), almost 80% of the system waste is a result

of power generation. Because most of the electricity in the U.S. is generated from coal-fired power plants

(51.7%, U.S. DOE, July 1998), the majority of the waste will be in the form of coal ash and flue gas clean-up

waste. There is also a small credit for the waste avoided during natural gas production, distribution, and

combustion (-7.1%). Although this study did not account for any solid wastes from the hydrogen plant itself,

it should be noted that the only waste stream from the plant will be a small amount of spent catalyst

generated from the reformer and shift reactors about every 5 years. 

Table 12: Solid Waste Generation

total

(g/kg H2)

% of total from

construction &

decommissioning

% of total

from natural

gas production

& transport

% of total

from

electricity

generation

% of total

from avoided

operations 

Waste generated 201.6 3.8% 72.3% 31.0% -7.1%

7.0 Sensitivity Analysis

A sensitivity analysis was conducted to examine the effects of varying the base case assumptions for several

parameters. These parameters and their changes are shown in Table13. Each parameter was changed

independently of all others so that the magnitude of its effect on the base case could be assessed. Therefore,

no single sensitivity case represents the best or worst situation under which these systems might operate. 

Table 13: Variables Changed in Sensitivity Analysis

Variable Base case value Sensitivity analysis cases

Amount of materials required for plant

construction

see section 4.0 for details decrease by

50%

increase by

50%

Amount of materials required for pipeline

construction

see section 4.0 for details decrease by

20%

increase by

20%

Natural gas losses (% of gross production) 1.4% 0.5% 4%

Operating capacity factor 0.90 0.80 0.95

Materials recycled versus materials landfilled 75/25 50/50

Shift reactors HTS and LTS no LTS (HTS only)

Natural gas boiler efficiency 75% 64%

Hydrogen plant energy efficiency (HHV basis) 89.3% 80%

Steam balance (credit/debit) credit for excess steam (4.8

MPa); debit for 2.6 MPa steam

(see section 2.0 & 3.0)

no credit for excess steam

(4.8 MPa); assumed 2.6 MPa

steam made internally

Rev 11/00
17

Individual energy and material balances could not be obtained for the natural gas production and distribution

steps (extraction, glycol dehydration, amine gas sweetening, and pipeline transport), therefore a sensitivity

analysis which varied the wellhead gas composition could not performed. However, from the DEAM

database a breakdown of the stressors show that the majority come from extraction and pipeline transport

and only a small fraction are the result of separation, dehydration, and sweetening.

Table 14 shows the percent change from the base case in the major resources, emissions, waste, and energy

consumption. Reducing the hydrogen plant energy efficiency 9.3 percentage points has the largest effect on

the results, with the stressors increasing by about 16%. Changing the natural gas losses affects not only the

methane emitted from the system, but also the amount of NMHC emissions because 4.2% of the natural gas

lost to the atmosphere is ethane and propane. The loss assumed in the base case was 1.4% of the amount

removed from the ground. For a 0.5% natural gas loss the CH4 emissions decrease from the base case result

by about 49% and the NMHCs decrease by about 19%. For a 4% loss the CH4 emissions increase by 147%

and the NMHCs increase by about 57% (see Figure 4 as well as a discussion in the next paragraph for the

effect that the CH4 has on the systemís GWP). Additionally, because there is a large amount of energy

consumed in extracting the natural gas, the energy consumption for the 0.5% loss case decreases by 7% and

increases by 22% for the 4% loss case.

It is also important to note that if the excess steam produced at the hydrogen plant can not be used by another

source, then the credit for the stressors due to the avoided natural gas production, distribution, and

combustion can not be applied to the overall system emissions. This would cause the natural gas

consumption to go up along with several of the system air emissions. Benzene, CO, and CH4 all increase by

about 11% each. Additionally, the non-feedstock energy consumption would also increase significantly

(89%). Although this increase is large, it is important to note that the majority of the energy consumption

is still due to the natural gas feedstock. However, the change in energy consumption will affect the energy

efficiency and energy ratio numbers as discussed in the following paragraph (also see Figures 5 - 8).

Figures 4 through 8 display the resulting GWP, life cycle efficiency, external energy efficiency, net energy

ratio, and external energy ratio, respectively, for the sensitivity analysis. For comparison, the base case

results are shown on these figures. Reducing the plant energy efficiency from 89.3% to 80% increases the

GWP of the system by 16%. This variable also has a large effect on the energy balance of the system causing

the life cycle efficiency to drop about 25% and the net energy ratio to decrease from 0.66 to 0.57. The only

other variable that has a significant effect on the systemís GWP is a change in the natural gas losses.

Reducing the natural gas losses to 0.5% reduces the GWP by about 4% and increasing the natural gas losses

to 4% increases the GWP by 16% (again, refer to Figure 4). This variable also slightly affects the system

energy balance. For the 4% natural gas loss case, the net energy ratio decreases 3% (0.66 to 0.64) and the

life cycle efficiency decreases 8% (-39.6% to -42.9%). Additionally, two other variables have a noticeable

effect on the energy balance of the system: the case where no steam credit or debit is taken and the case

where the boiler efficiency is reduced to 64%. For the steam case, it is assumed that the hydrogen plant

produces the amount of steam required for the process but does not have a source nearby which can utilize

the excess steam. The upstream energy that is avoided in producing and distributing natural gas which would

have been combusted in a boiler can no longer be credited to the system. This causes the net energy ratio

to decrease by 10% (0.66 to 0.59) and the life cycle efficiency to decrease from -39.6% to -52.8%. Changing

the boiler efficiency has only a slight effect on the energy balance with the net energy ratio increasing 2%

(0.66 to 0.67) and the life cycle efficiency increasing 6% (-39.6% to -37.3%).

Rev 11/00
18

Table 14: Sensitivity Analysis Results - Percent change from base case

Stressor -50%

const.

materials

+50%

const.

materials

-20%

pipeline

materials

+20%

pipeline

materials

0.5%

nat. gas

loss

4% nat.

gas loss

0.8 op

capacity

0.95 op

capacity

50/50

recycle/

landfill

No

LTS

Coal -0.91% 0.91% -1.06% 1.06% -0.14% 0.43% 0.89% -0.37% 0.15% -0.68% 

Iron ore -4.30% 4.30% -18.28% 18.28% 0.00% 0.00% 12.50% -5.26% 5.41% 0.00% 

Iron scrap -4.22% 4.22% -18.31% 18.31% 0.00% 0.00% 12.50% -5.26% 5.25% 0.00% 

Limestone -47.04% 47.04% -1.18% 1.18% 0.00% 0.00% 12.50% -5.26% 0.35% 0.00% 

Natural gas 0.00% 0.00% 0.00% 0.00% -0.90% 2.71% 0.00% 0.00% 0.00% 0.90% 

Oil -12.73% 12.73% -0.92% 0.92% -0.50% 1.49% 3.76% -1.58% 0.04% 0.33% 

Water consumed -0.17% 0.17% -0.66% 0.66% -0.01% 0.03% 0.45% -0.19% 0.19% 0.01% 

Benzene (C6H6) 0.00% 0.00% 0.00% 0.00% -0.90% 2.71% 0.00% 0.00% 0.00% 0.90% 

Carbon Dioxide (CO2) -0.08% 0.08% -0.0% 0.04% -0.13% 0.38% 0.05% -0.02% 0.01% 0.81% 

Carbon Monoxide (CO) -0.81% 0.81% -0.07% 0.07% -0.87% 2.60% 0.24% -0.10% 0.00% 0.91% 

Non-methane Hydrocarbons -0.24% 0.24% -0.24% 0.24% -19.14% 57.30% 0.21% -0.09% 0.04% 0.57% 

Methane (CH4) -0.01% 0.01% 0.00% 0.00% -49.05% 146.87% 0.00% 0.00% 0.00% 0.90% 

Nitrogen Oxides (NOX as NO2) -0.73% 0.73% -0.08% 0.08% -0.74% 2.20% 0.23% -0.10% 0.00% 0.57% 

Nitrous Oxide (N2O) -1.12% 1.12% -1.02% 1.02% -0.31% 0.92% 0.92% -0.39% 0.11% -0.32% 

Particulates (unspecified) -28.32% 28.32% -1.58% 1.58% -0.21% 0.62% 8.07% -3.40% 0.44% 0.12% 

Sulfur Oxides (SOX as SO2) -6.18% 6.18% -0.22% 0.22% -0.56% 1.67% 1.68% -0.71% 0.01% 0.29% 

Non-hazardous miscellaneous waste -0.54% 0.54% -0.55% 0.55% -0.59% 1.77% 0.48% -0.20% 0.59% 0.26% 

Non-feedstock energy consumed by system 

(includes energy in natural gas loss energy)

-0.58% 0.58% -0.25% 0.25% -7.38% 22.09% 0.30% -0.13% 0.03% 1.19% 

Energy in natural gas to hydrogen plant 0.00% 0.00% -0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.81% 

Total energy consumed by system -0.08% 0.08% -0.03% 0.03% -0.95% 2.85% 0.04% -0.02% 0.00% 0.86% 

Rev 11/00
Figure 4: Sensitvity Results for GWP

G

WP -gof C

O -equivanent/kg of H 2 2

Figure 5: Sensitivity Results for Life Cycle Efficiency

Life Cycle Efficiency (%)

base

case

base

case

-50%

materials

-50%

materials

-20%

pipeline

-20%

pipeline

+20%

pipeline

+20%

pipeline

1%

loss

1%

loss

5%

loss

5%

loss

0.8

op cap

0.8

op cap

0.95

op cap

0.95

op cap

50/50

recycle

50/50

recycle

no

LTS

no

LTS

no

stm

no

stm

0.8

energy eff

0.8

energy eff

64%

boiler eff

64%

boiler eff

+50%

materials

+50%

materials

19

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

-55%

-50%

-45%

-40%

-35%

-30%

-25%

-20%

-15%

-10%

-5%

0%

Rev 11/00
Figure 6: Sensitivity Results for External Energy Efficiency

External Energy Efficiency (%)

20

base

case

-50%

materials

-20%

pipeline

+20%

pipeline

1%

loss

5%

loss

0.8

op cap

0.95

op cap

50/50

recycle

no

LTS

no

stm

0.8

energy eff

64%

boiler eff

+50%

materials

Figure 7: Sensitivity Results for Net Energy Ratio

Net Energy Ratio

base

case

-50%

materials

-20%

pipeline

+20%

pipeline

1%

loss

5%

loss

0.8

op cap

0.95

op cap

50/50

recycle

no

LTS

no

stm

0.8

energy eff

64%

boiler eff

+50%

materials

0.50

0.52

0.54

0.56

0.58

0.60

0.62

0.64

0.66

0.68

0%

10%

20%

30%

40%

50%

60%

70%

Rev 11/00
Figure 8: Sensitivity Results for External Energy Ratio

External Energy Ratio

21

base

case

-50%

materials

-20%

pipeline

+20%

pipeline

1%

loss

5%

loss

0.8

op cap

0.95

op cap

50/50

recycle

no

LTS

no

stm

0.8

energy eff

64%

boiler eff

+50%

materials

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

Rev 11/00
22

8.0 Impact Assessment

Life cycle impact assessment is a means of examining and interpreting the inventory data from an

environmental perspective. There are several options for analyzing the systemís impact on the environment

and human health. To meet the needs of this study, categorization and less-is-better approaches have been

taken. See SETAC (1997, 1998) for additional details about the different methods available for conducting

impact assessments. Table 15 summarizes the stressor categories and main stressors from the natural gas

steam reforming, hydrogen production system. A discussion of these stressor categories as well as

information about the known effects of these stressors can be found in Spath and Mann (1999).

Table 15: Impacts Associated with Stressor Categories

Stressor categories Stressors Major impact

category

H = human health

E = ecological

health

Area impacted

L= local (county)

R = regional (state)

Major Minor G = global

Ozone depletion

compounds

NO H, E R, G

Climate change Greenhouse gases CO2, CH4, N2O, CO

and NOx (indirectly),

water vapor

H, E R, G

Particulates H, E L, R

Contributors to smog Photochemical NOx, VOCs H, E L, R

Acidification

precursors

SO2, NOx, CO2 H, E L, R

Contributors to

corrosion

SO2, H2S, H2OE L

Other stressors with

toxic effects

NMHCs, benzene H, E L

Resource depletion Fossil fuels, water,

minerals, and ores

E R, G

Solid waste Catalysts,

coal ash (indirectly),

flue gas clean up

waste (indirectly)

H, E L, R

9.0 Improvement Opportunities

The component of life cycle assessment known as improvement, is used to identify opportunities for reducing

the environmental impact of a system. From the sensitivity analysis, it is evident that the hydrogen plant

energy efficiency has the largest effect on the system stressors (resources, emissions, waste, and energy use)

and thus this variable has the largest environmental impact. Because SMR and shift conversion are

conventional technologies where improvements have been made in the past, significant increases in yields

through changes in furnace/reactor designs or catalyst types are not expected. However, it is important to

note that the hydrogen production plant should be operated as efficiently as possible to minimize the

environmental burden of the system.
23

Reducing the natural gas losses is an opportunity for improvement and this would improve the GWP of the

system. The base case analysis shows that 11% of the GWP is a result of methane emissions and 76 wt%

of the total system methane comes from natural gas lost during production and distribution. If the losses

were reduced from 1.4% to 0.5%, methane would account for 6% of the GWP instead of 11%. Reducing

the natural gas losses would also improve the energy balance of the system. Depending on the composition

of the natural gas, approximately 48,400 J of energy are lost per gram of natural gas that leaks to the

atmosphere (LHV basis). For the base case, 2.7 MJ are lost per kg of H2 produced and this would be reduced

to 0.5 MJ/kg of H2 if the natural gas losses were only 0.5%. As discussed in section 5.0, the Natural Gas

STAR Program is an industry consortium working to reduce methane emissions from natural gas production

and distribution.

10.0 Conclusions

Although hydrogen is generally considered to be a clean fuel, it is important to recognize that its production

may result in environmental consequences. Examining the resource consumption, energy requirements, and

emissions from a life cycle point of view gives a complete picture of the environmental burdens associated

with hydrogen production via steam methane reforming. The operation of the hydrogen plant itself produces

very few emissions with the exception of CO2. On a system basis, CO2 is emitted in the largest quantity,

accounting for 99 wt% of the total air emissions and 89% of the system GWP. Another air emission that

effects the GWP of the system is CH4, which primarily comes from the natural gas lost to the atmosphere

during production and distribution. The energy balance of the system shows that for every 0.66 MJ of

hydrogen produced, 1 MJ of fossil energy must be consumed (LHV basis). From both an environmental and

economic standpoint, it is import to increase the energy efficiencies and ratios of any process. This in turn

will lead to reduced resources, emissions, wastes, and energy consumption. Future work will involve

comparing this study with hydrogen production via other routes such as biomass, wind, and photovoltaics.

Rev 11/00
24

11.0 References

Harrison, M.R.; Shires, T.M.; Wessels, J.K.; Cowgill, R.M. (1997). ìMethane Emissions from the Natural

Gas Industry.î Project Summary. United States Environmental Protection Agency. Report #

600/SR-96/080. National Risk Management Research Laboratory. Research Triangle Park, NC.

Houghton, J.T.; Meira Filho, L.G.; Callander, B.A.; Harris, N.; Kattenberg, A.; Maskell, K., eds. (1996).

Climate Change 1995. The Science of Climate Change. Published for the Intergovernmental Panel

on Climate Change. New York: Cambridge University Press.

Kirchgessner, D.A.; Lott, R.A.; Cowgill, R.M.; Harrison, M.R.; Shires, T.M. (1997) ìEstimate of Methane

Emissions from the U.S. Natural Gas Industry.î Chemosphere. Vol. 35, No. 6; pp. 1365-1390.

Kirk-Othmer's Encyclopedia of Chemical Technology. (1993). 4th Edition, Vol. 12, pp. 324-335.

Lacson, J.G. (1999). CEH Product Review: Natural Gas. Chemical Economics Handbook. SRI

International. Menlo Park, CA. Volume 4. Section 229.2000. 

Mann, M.K.; Spath, P.L. (1997). Life Cycle Assessment of a Biomass Gasification Combined-Cycle Power

System. National Renewable Energy Laboratory, Golden, CO, TP-430-23076.

Mann, M.K. (1995). Technical and Economic Assessment of Producing Hydrogen by Reforming Syngas

from the Battelle Indirectly Heated Biomass Gasifier. National Renewable Energy Laboratory,

Golden, CO, TP-431-8143.

Resch, R.A. (1995). ìEPAís Natural Gas Star Program.î Society of Petroleum Engineers Conference.

Paper No. SPE 29731. Houston, TX, March 27-29.

SETAC. (1997, 1998). Life-Cycle Impact Assessment: The State-of-the-Art. Society of Environmental

Toxicology and Chemistry. Pensacola, FL.

Spath, P.L; Mann, M.K. (1999). Life Cycle Assessment of Coal-fired Power Production. National

Renewable Energy Laboratory, Golden, CO, TP-570-25119.

SRI International. (1998). Chemical Economics Handbook Product Review. Hydrogen. Industrial Gases

743.5000 A - 743.5006 E. Menlo Park, CA.

SRI International. (1994). Options for Refinery Hydrogen. Report No. 212. Menlo Park, CA.

Ullmann's Encyclopedia of Industrial Chemistry. (1986). 4th Edition, Vol. A17, pp. 74-101, Weinheim

(Federal Replublic of Germany): VCH.

U.S. Department of Energy. (July 1998). Annual Energy Review 1997. Energy Information Administration,

Office of Energy Markets and End Use. DOE/EIA-0384(97). Washington, D.C.

U.S. Environmental Protection Agency. (1995). Compilation of Air Pollutant Emission Factors. United

States Environmental Protection Agency. AP-42. Vol. 1, parts 1, 2, and 3; Stationary Point and

Area Sources. Ann Arbor, MI.

Rev 11/00
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Life Cycle Assessment of Hydrogen Production via Natural Gas Steam Reforming

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13. ABSTRACT (Maximum 200 words) A life cycle assessment of hydrogen production via natural gas steam reforming was performed to examine the net emissions

of greenhouse gases as well as other major environmental consequences. LCA is a systematic analytical method that helps identify and evaluate the environmental

impacts of a specific process or competing processes.

February 2001 Revision Notes: Notes regarding changes from the August 2000 published version of this report.

Pages 7, 10, and 15 contain updated information.

November 2000 Revision Notes: Notes regarding changes from the August 2000 published version of this report.

A reduction was made in the amount of natural gas losses. This changed several of the numbers and percentages given throughout the report. However, most of the

values varied by a small amount and the conclusions remain the same. The Executive Summary, pages 8ñ21 and pages 23ñ24 contain updated information.

14. SUBJECT TERMS

life cycle assessment; hydrogen; natural gas;v steam reforming

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