# Analysis of CO

2 

# Emissions,

Reductions, and Captu r e for Large-Scale Hyd r ogen

P r oduction Plants

October 2 0 1 0 Vist ww w .p r a x ai r .com 

# A White Paper

A uthor

Dante Bonaquist, Corporate Fellow and Chief ScientistO ctober 20 10

www.praxair.com Page 1 of 9 

# Analysis of CO 2 

# Emissions, Reductions, and Capture for Large

- Scale Hydrogen Production Plants

A White Paper

Author
Dante Bonaquist

, Corporate Fellow and Chief Scientist



### Abstract

Hydrogen (H 2 ) production

, when used for making ultra

- low sulfur diesel (ULS D)

, 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

H 2 avoids the emission of 2.75 tons of sulfur dioxide (SO 2 ) and 144 tons of equivalent carbon

dioxide (CO 2 ) 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 CO 2 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, large

scale hydrogen plants can potentially bring CO 2 emissions down to within 9 percent of t he theoretical minimum. Improvements to hydrogen pipeline networks have also led to
additional CO 2 reductions.

The SMR process emits CO 2 as a byproduct, thereby raising the question of whether electrolysis could be used to produce hydrogen

and avoid this emission. This paper shows that

electro l ysis, when powered by fossil

- fuel sources of electricity, has an indirect energy use that is over three times greater than the direct
CO 2 emissions from SMR. 

### Hydrogen Plant Process Description

Modern

, large

- scale hy drogen 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
S MR

- 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 sp l it

, 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 lea ving 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

ref ormer furnace . See Figure 2.Analysis of CO 2 Emissions, Reductions, and

Capture for Large

- Scale Hydrogen Production

Plants

O ctober 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

.

T ypical Operating Temperature 650 ° F to 750 ° F

Processing Steps 1. Hydrotreating r eactor : Converts sulfur compounds to H 2 S and saturates any
olefins

.

a. Catalyst: Co

- Mo or Ni

- Mo

b. Typical c atalyst life: 7 years

2. Sulfur r emoval r eactor : Removes H 2 S

.

a. Catalyst: ZnO

b. Reaction: H 2 S + ZnO  ZnS + H 2 O

c. Typical c at alyst 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: CH 4 + H 2 O + Heat  3H 2 + CO

a. Highly e ndothermic r eaction

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

2. Water g as s hift: CO + H 2 O  CO 2 + H 2 + Heat

a. Mildly e xothermic r eaction

. 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 CO 2 Emissions, Reductions, and

Capture for Large

- Scale Hydrogen Production

Plants

O ctober 20 10 www.praxair.com 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. r ings, Ni

- based

. 2. Reformer tubes: 4

- in. to 5

- in. diameter by 40 ft to 45 ft long.

3. Reformer t ube life: 10 years

. 4. Furnace type: Round ( c an) or box.

Hig h Temperature Shift

Function Convert carbon monoxide to hydrogen

.

Reaction Water g as s hift: CO + H 2 O  CO 2 + H 2 + Heat

1. Mildly e xothermic r eaction

. 2. Reaction favored by mild temperature and excess steam

. 3. Converts about 70 to 75 percent of carbon m onoxide.

Catalyst Iron/ c hrome

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, act ivated carbon, alumina, and silica gel.

Typical Operating

Conditions 1. Feed pressure: 200 to 900 psig

. 2. Feed H 2 composition: 50 to 95 percent

. 3. Tail gas pressure: 5 to 70 psig

. 4. H 2 recovery: 65 to 90 percent

. Typical Operating Equipment 1. Adsorbe r vessels: 4 to 12

. 2. Surge t ank: 1 to 2 (12 to 13 ft d iameter)

. 3. Valve s kid and c ontrols

.



### CO 2 

### Production and Emissions in Hydrogen Manufacture

Natural gas is the source of all carbon that is ultimately emitted in the reformer flue gas as

CO 2 . The C O 2 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 CO 2 emissions can be determined by measuring the flow and composition of the

natur al gas entering the reformer as feed and

fuel with conversion to CO 2 according to the following hypothetical reaction:

C X H Y + (X+Y/4)O 2  (X)CO 2 + (Y/2)H 2 OAnalysis of CO 2 Emissions, Reductions, and

Capture for Large

- Scale Hydrogen Production

Plants

O ctober 2010 www.praxair.com Page 4 of 9

Figure 2: Steam Methane Reformer

– Minimum Steam Case

For a typical natural gas composition

app roximated as 90 percent methan e and 10 percent ethane, X equals 1.10 and Y equals 4.2.



### Hydrogen Plant CO 2 

### Emissions:

Modern v ersu s Historical

In this paper, a modern hydrogen plant consists of an SMR followed by high temperature shift with PSA purificatio n. A historical hydrogen plant consists of an SMR followed by high temperature and low temperature shifts, and an monoethanolamine ( MEA ) unit for CO 2 removal followed by methanation (chemical reaction to form methane) to remove residual CO and CO 2

. Pract ically 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 CO 2 generation and emission from modern and historical hydrogen plants respectively for the sam e 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 CO 2 intensity, short tons per day of CO 2 per 1 MMscfd of hydrogen

, is 12 percent less than its

hist orical counterpart (25 versus 28.5). This does not tell the complete story since the

moder n plant is exporting 150,000 lb /hour of steam that is efficiently use d by the refinery

. Crediting the modern hydrogen plant for steam production, the CO 2 intensity drops to 22.1 short tons per day of CO 2 per 1 MMscfd of hydrogen

, or 22 percent l e ss that the historical plant. Table

2 summarizes the comparison between the modern and historical hydrogen plant CO 2 emissions. Note that the modern plant is at 113

percen t of minimum theoretical CO 2 em issions.



### Further Reductions in Hydrogen

Plant CO 2 

### Emissions: 2009 to 2014

Not withstanding the close approach of modern large

- scale hydrogen plants to the theoretical
minimum CO 2 emission rate, improvements scheduled for impl ementation by Praxair over

the next five years will lead to further reductions. The primary motivation for these improvements is cost saving s from reduced natural gas consumption , which lead s to higher profitability.

The a ctual natural gas consumption ra te is dependent on several parameters

, including export steam flow, hydrogen product pressure

, and ambient conditions, but a value of 370

b tu/scf of H 2 is typical. Refer to Table 3.

Assuming successful development and commercialization, the natural gas co nsumption rate of new hydrogen plants and existing modern plants retrofit with the above improvements could be reduced to 340 b tu/scf

of H 2 . This would yield a CO 2 intensity of 23Analysis of CO 2 Emissions, Reductions, and

Capture for Large

- Scale Hydrogen Production

Plants

O ctober 2010 www.praxair.com Page 5 of 9 Figure 3: Modern Hydrogen Plant

Figure 4: Historical Hydrogen PlantAnalysis of CO 2 Emissions, Reductions, and

Capture for Large

- Scale Hydrogen Production

Plants

O ctober 20 10 www.praxair.com Page 6 of 9 Table 2 Modern vs. Historical Hydrogen Plants

Source CO 2 Formed/Emitted (tons per day)

Modern Hydrogen Plant Historical Hydrogen Plant

Complete conversion of feed to H 2 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 CO 2

/ 1 MM scf of H 2 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 CO 2 per 100 MMscfd of product H 2 or 104 percent of the theoretical CO 2 emissio ns

.

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 

### CO 2 

### 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 deve lopment of such networks,

lower

- efficiency historical hydrogen plants have been acquire d 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 o f the U

. S

. refining industry . (This demand was driven by clean fuel specifications, product mix, and

demand for motor fuels. ) The difference in CO 2 intensity between the old and new facility is 3.5 tons per day of CO 2 per 1 MMscfd of H 2

.Analysis of CO 2 Emissions, Reductions, and

Capture for Large

- Scale Hydrogen Production

Plants

O ctober 20 10 www.praxair.com 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 CO 2 reduction of 82,000 tons of

CO 2 per year.

Additional CO 2 reductions ( not yet quantified ) accrue from the development of effic ient 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 b scf) 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

u s ed to the greates t extent.



### CO 2 

### Capture from Hydrogen Plants

Several options are available for capture of 50 to

90 percent of the CO 2 normally emitted (see Figure 7) . The option selected depend s on the

nature of future regulations

, including allowance pricing. An allowanc e price or credit of $40 to $50/ton of CO 2 (2005 cost b asis including compression to 2 000 psig and pipeline transportation of 10 miles) should be adequate to trigger investmen t for capture at the 50 percent level

. 

### Disposition of CO 2 

### Captured from Hydrogen Plants

CO 2 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 ( S O x ) , a nd oxygen can be

controlled to meet current and future specifications. Given the volume of CO 2 captured from SMR

- based hydrogen plants, it will be necessary to aggregate with otherAnalysis of CO 2 Emissions, Reductions, and

Capture for Large

- Scale Hydrogen Production

Plants

O ctober 2010 www.praxair.com Page 8 of 9 Figure 7: Hydrogen Plant CO 2 Capture Options

Figure 8: CO 2 Pipel ine Costs ( 3 )

sources to cost effectively transport the CO 2 to a sink. For example, the maximum CO 2 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. 

### CO 2 

### Inte nsity of SMR

- Based Hydrogen Plants vs. Water Electrolysis

Electrolysis of water is used on a small scale to supply hydrog en for applications where lower

cost sources are not available. From a CO 2 perspective, electrolysis has no direct emissions; however, the indirect emissions are large.

Table 4 provides information on the indirect CO 2 emissions from water

- electrolysis

- based hydrogen production

.

Table 4 demonstrates that water electroly sis is
not a viable means to lower CO 2 emissions attributable to hydrogen production. The
theoretical minimum CO 2 intensity for electrolysis is greater than the actual for SMR

based hydrogen plants by a factor of 2. Even if
a CO 2 - 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 CO 2 - emitting coal

- and gas

- fired power plants before considering hydrogen generation for large consumers currently served by natural

- gas

- ba sed hydrogen plants.Analysis of CO 2 Emissions, Reductions, and

Capture for Large

- Scale Hydrogen Production

Plants

O ctober 2010 www.praxair.com Page 9 of 9 Table 4 Analysis of CO 2 Emissions for Water Electrolysis Production o f Hydrogen

kWh/kg of H 2 kWh/1 MMscfd of H 2

Electrolyzer power use Theoretical minimum 33 83,970

Large unit actual 50 127,000

Average U.S. power grid CO 2 inte nsity 1.3 lb of CO 2 /kWh ( 4 )

Tons of CO 2

/1 MMscfd of H 2

CO 2 intensity for electrolyzer Theoretical minimum 54.6

Large unit actual 82.6

CO 2 intensity for SMR

- based H 2 plant Theoretical minimum 22.1

Actual 25

Notes:

1. 1 kg = 393 scf of H 2



### Conclu sions

Process and equipment improvements made over the past 25 years have reduced the CO 2 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 CO 2 reductions have been achieved as industrial gas firms have developed sophisticated hydrogen pipeline networks in

are as of concentrated demand

, such as the

Texas

- Louisiana Gulf Coast. From 50 to 90 percent of the CO 2 emitted from hydrogen plants can be captured using technology currently available. Allowance prices of $50 per ton of

CO 2 are needed to trigger investment ( 5 )

. The captured CO 2 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 CO 2 from electrolysis of water would be significantly higher tha n direct

emissions from natural

- gas

- based hydrogen plants; therefore

, electrolysis for hydrogen production is not an option for lowering CO 2 emissions. 

### References

1. Bonaquist, Dante, and Riva Kru t. The Role of Hydrogen in Minimizing Black Carbo n Emissions from Diesel Engines. Praxair

w hite p aper

, May 2010

, www.praxair.com

.

2. htt p://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 Sequestratio n from a Hydrogen Production Facility in an Oil Refinery . Prepared for U.S. Department of Energy National Energy Technology

Labora tory Funding Opportunity Number

DE

- FOA

- 0000015

, CFDA Number: 81.089, Praxair, Inc ., August 7, 2009.