Analysis of CO2

 Emissions, 

Reductions, and Capture 

for Large-Scale Hydrogen 

Production Plants 

October 2010 Vist www.praxair.com

A White Paper

Author

Dante Bonaquist, 

Corporate Fellow and Chief Scientist
October 2010

www.praxair.com

Page 1 of 9

Analysis of CO2 Emissions, Reductions, and Capture for 

Large-Scale Hydrogen Production Plants

A White Paper

Author

Dante Bonaquist, Corporate Fellow and Chief Scientist

Abstract

Hydrogen (H2) production, when used for 

making ultra-low sulfur diesel (ULSD), results in 

cleaner air. Over 95 percent of global hydrogen

production is through steam methane reforming

(SMR) (1). When used to make ULSD, a ton of 

H2 avoids the emission of 2.75 tons of sulfur 

dioxide (SO2) and 144 tons of equivalent carbon 

dioxide (CO2) from the truck tailpipe when 

particulate filters are used (2).

SMR plants are safe, reliable and efficient. 

Process and equipment improvements made 

over the past 25 years have reduced the CO2

intensity of hydrogen plants by more than 20

percent, to the point where emissions are within 

13 percent of the theoretical minimum. Over the 

next five years, process, equipment, and 

operational improvements to modern, largescale hydrogen plants can potentially bring CO2

emissions down to within 9 percent of the 

theoretical minimum. Improvements to 

hydrogen pipeline networks have also led to 

additional CO2 reductions.

The SMR process emits CO2 as a byproduct, 

thereby raising the question of whether 

electrolysis could be used to produce hydrogen 

and avoid this emission. This paper shows that 

electrolysis, when powered by fossil-fuel 

sources of electricity, has an indirect energy use 

that is over three times greater than the direct 

CO2 emissions from SMR.

Hydrogen Plant Process Description

Modern, large-scale hydrogen plants that use

natural gas as a feedstock are the primary 

means of meeting the growing demand for 

hydrogen from the refining sector. A modern 

SMR-based hydrogen plant consists of four

primary subsystems (see Figure 1).

Natural gas is used as both feed and fuel. The 

natural gas stream is split, and the majority is 

used as process feed, which is compressed and 

desulfurized before entering the reformer reactor 

tubes. The natural gas used as fuel is mixed 

with pressure swing adsorption (PSA) tail gas

and combusted within the reformer furnace to 

provide the energy required to drive the 

reforming reactions. Gas leaving the reformer 

enters a high-temperature shift reactor, where

carbon monoxide (CO) is reacted with steam to 

produce additional hydrogen. After cooling, 

hydrogen-rich gas from the shift reactor is 

processed by a PSA unit for purification to 

product hydrogen specifications. The PSA tail 

gas, consisting of unreacted methane, CO, 

nitrogen, and unrecovered hydrogen, is recycled 

for mixing with natural gas and used as fuel in 

the reformer furnace. Additional information for 

each subsystem is provided in Table 1.

To efficiently manage energy flows within the 

hydrogen plant, a complex heat exchanger 

network is integrated within and around the 

reformer furnace. See Figure 2.
Analysis of CO2 Emissions, Reductions, and 

Capture for Large-Scale Hydrogen Production 

Plants

October 2010

www.praxair.com

Page 2 of 9

Figure 1: Hydrogen Plant Block Flow Diagram

Table 1

Hydrogen Plant Subsystems

Desulfurization

Function Remove all sulfur compounds to less than 0.1 ppmw.

Typical Operating 

Temperature

650°F to 750°F

Processing Steps 1. Hydrotreating reactor: Converts sulfur compounds to H2S and saturates any 

olefins.

a. Catalyst: Co-Mo or Ni-Mo

b. Typical catalyst life: 7 years

2. Sulfur removal reactor: Removes H2S.

a. Catalyst: ZnO 

b. Reaction: H2S + ZnO  ZnS + H2O

c. Typical catalyst life: 1 to 2 years (depends on natural gas sulfur content).

Reforming

Function Converts methane and light hydrocarbons to hydrogen and carbon monoxide.

Reactions 1. Reforming: CH4 + H2O + Heat  3H2 + CO

a. Highly endothermic reaction.

b. Reaction favored by high temperature, low pressure, and excess steam.

2. Water gas shift: CO + H2O  CO2 + H2 + Heat

a. Mildly exothermic reaction.

b. Reaction favored by mild temperature and excess steam.

Characteristics 1. Ni-based catalyst poisoned by sulfur and chloride compounds.

2. Excess steam suppresses carbon formation.

3. 90 to 95 percent of the hydrocarbons are reacted.

4. Catalyst life: 5 years.
Analysis of CO2 Emissions, Reductions, and 

Capture for Large-Scale Hydrogen Production 

Plants

October 2010

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Page 3 of 9

Table 1

Hydrogen Plant Subsystems

Typical Operating 

Conditions

1. Process gas outlet temperature: 1400°F to 1700°F.

2. Pressure: 200 psig to 450 psig.

Equipment 1. Catalyst size: 5/8-in. x 5/8-in. rings, Ni-based.

2. Reformer tubes: 4-in. to 5-in. diameter by 40 ft to 45 ft long.

3. Reformer tube life: 10 years.

4. Furnace type: Round (can) or box.

High Temperature Shift

Function Convert carbon monoxide to hydrogen.

Reaction Water gas shift: CO + H2O  CO2 + H2 + Heat

1. Mildly exothermic reaction.

2. Reaction favored by mild temperature and excess steam.

3. Converts about 70 to 75 percent of carbon monoxide.

Catalyst Iron/chrome

Catalyst Life 5 to 7 years

Typical Operating 

Temperature

650°F to 700°F

Typical 

Temperature Rise

125°F

H2 PSA

Function Purifies hydrogen-rich gas (purity hydrogen product >99.99 percent).

Adsorbents Molecular sieve, activated carbon, alumina, and silica gel.

Typical Operating 

Conditions

1. Feed pressure: 200 to 900 psig.

2. Feed H2 composition: 50 to 95 percent.

3. Tail gas pressure: 5 to 70 psig.

4. H2 recovery: 65 to 90 percent.

Typical Operating 

Equipment

1. Adsorber vessels: 4 to 12.

2. Surge tank: 1 to 2 (12 to 13 ft diameter).

3. Valve skid and controls.

CO2 Production and Emissions in 

Hydrogen Manufacture

Natural gas is the source of all carbon that is 

ultimately emitted in the reformer flue gas as 

CO2. The CO2 is formed by reaction of CO with 

steam in the reforming and shift processes and 

during combustion of natural gas, CO, and 

unreacted methane in the reformer furnace. 

Total CO2 emissions can be determined by

measuring the flow and composition of the

natural gas entering the reformer as feed and 

fuel with conversion to CO2 according to the 

following hypothetical reaction:

CXHY+ (X+Y/4)O2  (X)CO2 + (Y/2)H2O
Analysis of CO2 Emissions, Reductions, and 

Capture for Large-Scale Hydrogen Production 

Plants

October 2010

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Page 4 of 9

Figure 2: Steam Methane Reformer – Minimum Steam Case

For a typical natural gas composition 

approximated as 90 percent methane and 10 

percent ethane, X equals 1.10 and Y equals 4.2.

Hydrogen Plant CO2 Emissions: 

Modern versus Historical

In this paper, a modern hydrogen plant consists 

of an SMR followed by high temperature shift 

with PSA purification. A historical hydrogen 

plant consists of an SMR followed by high 

temperature and low temperature shifts, and an 

monoethanolamine (MEA) unit for CO2 removal 

followed by methanation (chemical reaction to 

form methane) to remove residual CO and CO2. 

Practically all large hydrogen plants operated by 

industrial gas firms and refineries built since the 

mid-1980s are the modern type. Figures 3 and 

4 show CO2 generation and emission from 

modern and historical hydrogen plants 

respectively for the same quantity of hydrogen 

product: 100 million standard cubic feet per day

(100 MMscfd) of hydrogen contained in the 

product stream.

Note that the modern hydrogen plant’s CO2

intensity, short tons per day of CO2 per 1 

MMscfd of hydrogen, is 12 percent less than its

historical counterpart (25 versus 28.5). This 

does not tell the complete story since the 

modern plant is exporting 150,000 lb/hour of 

steam that is efficiently used by the refinery. 

Crediting the modern hydrogen plant for steam 

production, the CO2 intensity drops to 22.1 short 

tons per day of CO2 per 1 MMscfd of hydrogen,

or 22 percent less that the historical plant. Table 

2 summarizes the comparison between the 

modern and historical hydrogen plant CO2

emissions. Note that the modern plant is at 113

percent of minimum theoretical CO2 emissions.

Further Reductions in Hydrogen 

Plant CO2 Emissions: 2009 to 2014

Not withstanding the close approach of modern 

large-scale hydrogen plants to the theoretical 

minimum CO2 emission rate, improvements 

scheduled for implementation by Praxair over 

the next five years will lead to further reductions. 

The primary motivation for these improvements 

is cost savings from reduced natural gas 

consumption, which leads to higher profitability. 

The actual natural gas consumption rate is 

dependent on several parameters, including 

export steam flow, hydrogen product pressure,

and ambient conditions, but a value of 370 

btu/scf of H2 is typical. Refer to Table 3.

Assuming successful development and 

commercialization, the natural gas consumption 

rate of new hydrogen plants and existing 

modern plants retrofit with the above 

improvements could be reduced to 340 btu/scf 

of H2. This would yield a CO2 intensity of 23
Analysis of CO2 Emissions, Reductions, and 

Capture for Large-Scale Hydrogen Production 

Plants

October 2010

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Page 5 of 9

SMR

Shift &

Heat 

Recovery

PSA

Total CO2 Emissions 

2,500 TPD

CO2

665 TPD

CO2

1,470 TPD

CO2 1,470 TPD

Natural

Gas

Flue Gas

Air

Tail Gas

Syngas H2

100 MM scfd

99.9%

150,000 lbs/hr

Export Steam Heat 

Recovery

Figure 3. Modern Hydrogen Plant

Figure 3: Modern Hydrogen Plant

SMR

2 Stage 

Shift &

Heat 

Recovery

MEA

CO2 1,370 TPD

CO2 830

TPD

CO2 1,500 

TPD

Air

Syngas

Contained H2

100 MM SCFD

97%

Methanation

CO2 1,480

TPD

MEA unit uses steam

for regeneration

Minimal air pre-heat

High Temperature Flue Gas

Portion of H2 product

reacted to reduce

CO & CO2to methane

Total CO2 Emissions 2,850 TPD

Natural

Gas

Heat 

Recovery

Figure 4. Historical Hydrogen Plant

Figure 4: Historical Hydrogen Plant
Analysis of CO2 Emissions, Reductions, and 

Capture for Large-Scale Hydrogen Production 

Plants

October 2010

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Page 6 of 9

Table 2

Modern vs. Historical Hydrogen Plants

Source CO2 Formed/Emitted (tons per day)

Modern Hydrogen Plant Historical Hydrogen Plant

Complete conversion of feed to H2 1485 1485

Combustion of fuel to provide reforming 

energy

420 420

Combustion of fuel to provide export steam 290 NA

Power for separation and compression 10 10

Total emissions (theoretical minimum) 2205 1915

Actual emissions 2500 2850

Tons of CO2/1 MMscf of H2 Product

Intensity 25 28.5

Actual/Theoretical x 100 113% 149%

Notes:

1. For 100 MMscfd of hydrogen contained in the product stream.

2. Feed composition: 90 percent methane, 10 percent ethane.

3. Power at 50 percent thermal efficiency.

tons of CO2 per 100 MMscfd of product H2 or 

104 percent of the theoretical CO2 emissions.

Table 3

Hydrogen Plant Efficiency Improvements

Improvement Btu/scf 

reduction

Stack loss reduction 4 to 7

Fixed heat loss reduction 1 to 5

S:C ration reduction 2 to 3

Reformer temperature 

increase

2 to 4

Shift reactor optimization 1

PSA tail gas preheating 5 to 10

Compressor ISC unloaders 1

Total 16 to 31

CO2 Reductions by Hydrogen 

Supply Management

Industrial gas firms such as Praxair have 

developed efficient networks of hydrogen plants 

interconnected by pipelines to reliably and 

economically supply hydrogen to refineries and 

other users. A map of Praxair’s U.S. Gulf Coast 

hydrogen production and distribution system is 

shown in Figure 5.

As part of the development of such networks, 

lower-efficiency historical hydrogen plants have 

been acquired from refineries and replaced with 

modern plants. For example, Praxair acquired 

an 80 MMscfd historical hydrogen plant from a 

large Texas refinery, replacing it with a 100 

MMscfd plant as part of a capacity expansion to 

meet the growing hydrogen demand of the U.S.

refining industry. (This demand was driven by 

clean fuel specifications, product mix, and 

demand for motor fuels.) The difference in CO2

intensity between the old and new facility is 3.5 

tons per day of CO2 per 1 MMscfd of H2.
Analysis of CO2 Emissions, Reductions, and 

Capture for Large-Scale Hydrogen Production 

Plants

October 2010

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Page 7 of 9

Figure 5: U.S. Gulf Coast Hydrogen Production and Distribution System

Assuming an operating rate of 80 percent, this 

resulted in a net CO2 reduction of 82,000 tons of 

CO2 per year.

Additional CO2 reductions (not yet quantified)

accrue from the development of efficient 

hydrogen supply systems shared among many 

customers. For example, Praxair has built a salt 

dome cavern for underground storage of 

hydrogen in eastern Texas (see Figure 6).

Figure 6: Hydrogen Storage Cavern

This facility has a working volume of 1.5 billion 

standard cubic feet (1.5 bscf) of hydrogen,

allowing Praxair’s hydrogen supply network to 

meet fluctuating customer demand without 

rapidly modulating the capacity of hydrogen 

plants. As a result, the most efficient plants are 

used to the greatest extent.

CO2 Capture from Hydrogen Plants

Several options are available for capture of 50 to 

90 percent of the CO2 normally emitted (see 

Figure 7). The option selected depends on the 

nature of future regulations, including allowance 

pricing. An allowance price or credit of $40 to 

$50/ton of CO2 (2005 cost basis including 

compression to 2000 psig and pipeline 

transportation of 10 miles) should be adequate 

to trigger investment for capture at the 50 

percent level.

Disposition of CO2 Captured from 

Hydrogen Plants

CO2 captured from a hydrogen plant is suitable 

for enhanced oil recovery (EOR) and 

underground storage in saline aquifers or 

depleted gas reservoirs. It is expected that 

levels of impurities such as water, nitrous oxide 

(NOx), sulfur oxide (SOx), and oxygen can be 

controlled to meet current and future 

specifications. Given the volume of CO2

captured from SMR-based hydrogen plants, it 

will be necessary to aggregate with other 
Analysis of CO2 Emissions, Reductions, and 

Capture for Large-Scale Hydrogen Production 

Plants

October 2010

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Page 8 of 9

Figure 7: Hydrogen Plant CO2 Capture Options

Figure 8: CO2 Pipeline Costs (3)

sources to cost effectively transport the CO2 to a

sink. For example, the maximum CO2 available 

from a 100 MMscfd hydrogen plant with a 95

percent operating rate is 780,000 short tons per 

year. Figure 8 shows that this quantity is far 

below the minimum economic threshold for 

pipeline transportation.

CO2 Intensity of SMR-Based 

Hydrogen Plants vs. Water 

Electrolysis

Electrolysis of water is used on a small scale to 

supply hydrogen for applications where lowercost sources are not available. From a CO2

perspective, electrolysis has no direct 

emissions; however, the indirect emissions are 

large.

Table 4 provides information on the indirect CO2

emissions from water-electrolysis-based 

hydrogen production.

Table 4 demonstrates that water electrolysis is 

not a viable means to lower CO2 emissions 

attributable to hydrogen production. The 

theoretical minimum CO2 intensity for 

electrolysis is greater than the actual for SMRbased hydrogen plants by a factor of 2. Even if 

a CO2-free source of electric power, such as 

wind generation, is available, a better policy 

would be to use that power to reduce power 

produced at CO2-emitting coal- and gas-fired 

power plants before considering hydrogen 

generation for large consumers currently served 

by natural-gas-based hydrogen plants.
Analysis of CO2 Emissions, Reductions, and 

Capture for Large-Scale Hydrogen Production 

Plants

October 2010

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Page 9 of 9

Table 4

Analysis of CO2 Emissions for Water Electrolysis Production of Hydrogen 

kWh/kg of H2 kWh/1 MMscfd of H2

Electrolyzer power use Theoretical minimum 33 83,970

Large unit actual 50 127,000

Average U.S. power grid CO2 intensity 1.3 lb of CO2/kWh (4)

Tons of CO2/1 MMscfd of H2

CO2 intensity for electrolyzer Theoretical minimum 54.6

Large unit actual 82.6

CO2 intensity for SMR-based H2 plant Theoretical minimum 22.1

Actual 25

Notes:

1. 1 kg = 393 scf of H2

Conclusions

Process and equipment improvements made 

over the past 25 years have reduced the CO2

intensity of hydrogen plants by more than 20 

percent, to the point where emissions are within 

13 percent of the theoretical minimum. Over the 

next 5 years, process, equipment, and 

operational improvements can potentially bring 

emissions down to within 9 percent of the 

theoretical minimum.

Additional CO2 reductions have been achieved 

as industrial gas firms have developed 

sophisticated hydrogen pipeline networks in 

areas of concentrated demand, such as the 

Texas-Louisiana Gulf Coast. From 50 to 90

percent of the CO2 emitted from hydrogen plants

can be captured using technology currently 

available. Allowance prices of $50 per ton of 

CO2 are needed to trigger investment (5). The

captured CO2 will be suitable for EOR or 

geologic sequestration; however, the emissions 

from hydrogen plants must be aggregated with 

other sources to gain economies of scale for 

cost-effective pipeline transportation. Indirect 

emissions of CO2 from electrolysis of water 

would be significantly higher than direct 

emissions from natural-gas-based hydrogen 

plants; therefore, electrolysis for hydrogen 

production is not an option for lowering CO2

emissions.

References

1. Bonaquist, Dante, and Riva Krut. The Role 

of Hydrogen in Minimizing Black Carbon 

Emissions from Diesel Engines. Praxair 

white paper, May 2010, www.praxair.com.

2. http://www.hydrogenassociation.org/general/ 

faqs.asp#howproduced.

3. IPCC Special Report on Carbon Dioxide 

Capture and Storage. Prepared by Working 

Group III of the Intergovernmental Panel on 

Climate Change [Metz, B., O. Davidson, H. 

C. de Coninck, M. Loos, and L. A. Meyer 

(eds.)]. Cambridge University Press, 

Cambridge, United Kingdom and New York, 

NY, USA. IPCC, 2005.

4. DOE/EPA. Carbon Dioxide Emissions from 

the Generation of Electric Power in the 

United States, July 2000.

5. Carbon Capture and Sequestration from a 

Hydrogen Production Facility in an Oil 

Refinery. Prepared for U.S. Department of 

Energy National Energy Technology 

Laboratory Funding Opportunity Number

DE-FOA-0000015, CFDA Number: 81.089, 

Praxair, Inc., August 7, 2009.