Criteria Air Pollutants and Greenhouse Gas Emissions from Hydrogen

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Energy and the Environment

Criteria Air Pollutants and Greenhouse Gas Emissions from Hydrogen Production in U.S. Steam Methane Reforming Facilities Pingping Sun, Ben Young, Amgad Elgowainy, Zifeng Lu, Michael Q. Wang, Ben Morelli, and Troy Robert Hawkins Environ. Sci. Technol., Just Accepted Manuscript • DOI: 10.1021/acs.est.8b06197 • Publication Date (Web): 30 Apr 2019 Downloaded from http://pubs.acs.org on May 1, 2019

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Environmental Science & Technology

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Criteria Air Pollutants and Greenhouse Gas

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Emissions from Hydrogen Production in

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U.S. Steam Methane Reforming Facilities

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Pingping Suna, Ben Youngb, Amgad Elgowainy*,a, Zifeng Lua, Michael Wanga, Ben Morellib,

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Troy Hawkinsa

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a Energy

Systems Division, Argonne National Laboratory, 9700 S. Cass Ave., Lemont, IL 60439

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b Eastern

Research Group, Inc. (ERG), 110 Hartwell Ave. #1, Lexington, MA 02421

8 9 10 11 12 13 14 15 16 17 18 19 20 21

* Email: [email protected]

ACS Paragon Plus Environment


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Abstract

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The global and U.S. domestic effort to develop a clean energy economy and curb environmental

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pollution incentivizes the use of hydrogen as a transportation fuel, owing to its zero tailpipe

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pollutant emissions and high fuel efficiency in fuel cell electric vehicles (FCEVs). However, the

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hydrogen production process is not emissions free. Conventional hydrogen production via steam

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methane reforming (SMR) is energy intensive, co-produces carbon dioxide, and emits air

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pollutants. Thus, it is necessary to quantify the environmental impacts of SMR hydrogen

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production alongside the use-phase of FCEVs. This study fills the information gap, analyzing the

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greenhouse gas (GHG) and criteria air pollutant (CAP) emissions associated with hydrogen

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production in U.S. SMR facilities by compiling and matching the facility-reported GHG and CAP

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emissions data with facilities’ hydrogen production data. The actual amounts of hydrogen

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produced at U.S. SMR facilities are often confidential. Thus, we have developed four approaches

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to estimate the hydrogen production amounts. The resultant GHG and CAP emissions per MJ of

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hydrogen produced in individual facilities were aggregated to develop emission values for both a

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national median and a California state median. This study also investigates the breakdown of

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facility emissions into combustion emissions and non-combustion emissions.


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Abstract Art

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Introduction

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Hydrogen is used widely in modern society, with applications across many fields. For

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example, vast amounts of hydrogen are currently used in the petroleum refining industry for

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hydrotreating processes and conversion processes, and in the agricultural fertilizer industry for

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ammonia production. Other applications are in the petrochemical industry (e.g., for the production

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of methanol, acetic acid), food industry (hydrogenating oils), metallurgy and electronics industries

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(as a reducing agent), and aerospace industry (as a propulsion fuel).[1, 2]

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In recent years in the United States, hydrogen has been introduced as a clean transportation

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fuel for vehicles (e.g., fuel cell electric vehicles, or FCEVs) to reduce transportation emissions.

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Currently, the transportation sector is a major air emissions contributor, responsible for more than

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50% of nitrogen oxides (NOx), more than 30% of volatile organic compounds (VOCs), and more

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than 20% of particulate matter (PM) emissions of the total emissions inventory in the

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United States.[3] Thus, it is of interest to evaluate the potential benefits of reducing air emissions



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in the transportation sector by adopting hydrogen FCEVs to displace the present reliance on on-

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road internal combustion engine (ICE) vehicles. In California, as well as the northeastern

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United States, light-duty hydrogen FCEVs are available with access to hydrogen fueling stations.[2]

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However, evaluation of the potential air emissions benefit of FCEV adoption needs to be

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considered from a full life cycle perspective, requiring investigation of the air emissions of the

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hydrogen production process.

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At present, 95% of the hydrogen is produced via the steam‒methane reforming (SMR)

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process using fossil natural gas (mainly methane [CH4]) as a feedstock.[4] This process is energy

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intensive, requiring high temperature for the reforming process, and it co‒produces a significant

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amount of carbon dioxide (CO2).[4] Both CH4 and CO2 are greenhouse gases (GHGs), which must

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be tracked for performing environmental evaluation of the hydrogen life cycle. In addition to the

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tracking of GHG emissions, the tracking of criteria air pollutant (CAP) emissions from SMR

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facilities is also of interest. Under the Clean Air Act, the U.S. Environmental Protection Agency

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(EPA) regulates criteria pollutants, nitrogen dioxide (NO2), ozone (O3), sulfur dioxide (SO2), PM,

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carbon monoxide (CO), and lead (Pb) to protect public health and welfare.[5] In addition to these

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pollutants, VOCs are also regulated to reduce ozone.

71 72

Despite the importance of evaluating the environmental impacts of hydrogen production,

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such information is scarce, especially for CAP emissions (only Zapata et al.[6] reported some CAP

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emissions for the top three SMR facilities in California, to the best of our knowledge). Most SMR

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emissions studies have focused on the evaluation of GHG emissions, such as Rutkowski’s H2A

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modeling work,[7] Spath and Mann’s life cycle analysis (LCA) work for the SMR process,[8] Wulf


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and Kaltschmitt’s LCA work for the hydrogen supply chain,[9] Bhandari et al.’s review work for

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hydrogen production LCA,[10] SMR design and emission evaluation by industrial gas supplier

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Praxair,[11] Ruether et al.’s LCA work for hydrogen production from liquefied natural gas

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(LNG),[12] SMR design work by TopsØe, [13] LCA evaluation by Argonne National Laboratory,[14]

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and hydrogen production process analysis work by Idaho National Laboratory.[15] The present

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study aims to fill this information gap, providing the CAP emissions along with the GHG

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emissions associated with hydrogen production in SMR facilities in the United States. The CAP

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emissions include emissions of VOCs, CO, NOx, SO2, particulate matter less than 10 μm (PM10),

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and particulate matter less than 2.5 μm (PM2.5), whereas the GHG emissions include emissions of

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CO2, CH4, and nitrous oxide (N2O). The SMR emission is evaluated by compiling and matching

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facility-reported GHG and CAP emissions (reported by the EPA) with facility hydrogen

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production. A key element of the present study is estimating individual SMR facility hydrogen

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production amounts, as this information is often absent in public sources and is considered

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confidential business information (CBI).

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The resultant GHG and CAP emissions per MJ of hydrogen produced in individual

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facilities were aggregated to develop national median emission values, as well as California

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median emission values, given California’s leading position in the United States to promote

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hydrogen FCEVs and the required infrastructure (hydrogen refueling stations). As of

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January 2018, the United States had 39 publicly accessible hydrogen refueling stations for FCEVs,

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35 of which were in California.[16] Given the importance of California in hydrogen use for fuel cell

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vehicles, it is of great interest to investigate the hydrogen production burdens within California.

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Methodology

99



100

The study focuses on stand-alone SMR facilities, whereas captive hydrogen production within

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refineries is excluded because SMR facilities within refineries often do not have clear boundaries

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in terms of material and energy flows, thus complicating the emissions allocation between refinery

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products and hydrogen. In addition, the captive hydrogen is often produced for internal use as an

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intermediate product, not as a final product for vehicle use.

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Emissions Data Sources

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National Emissions Inventory Data

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CAP emissions information for U.S. SMR facilities is collected from the National

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Emissions Inventory (NEI) database.[17] The NEI provides emissions data for CAPs, CAP

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precursors, and hazardous air pollutants from U.S. point, nonpoint, on-road, off-road, and event

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sources every 3 years. For industrial point sources, such as SMR facilities, NEI emissions records

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are reported using unit-level designations that correspond to Source Classification Codes

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(SCCs).[18] Thus, the NEI source is used to provide both unit-level process and facility-level CAP

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emissions quantities. Facilities use a mix of methods to calculate process emissions, including

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continuous emissions monitoring systems (CEMS), EPA-sourced process emission factors, and

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stack testing. As the NEI database is updated every 3 years, the 2014 datasets were used, as they

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were the most recent available datasets when this study was carried out. The list of SMR facilities

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included in the 2014 NEI datasets is in Table S1 in the Supporting Information (SI) section, and

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the facility-level CAP and GHG emissions are listed in the SI in Table S2.

119 120

Greenhouse Gas Reporting Program Data

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The Greenhouse Gas Reporting Program (GHGRP) requires businesses operating in certain

122

sectors to report annual emissions of CO2, CH4, N2O, and certain fluorinated greenhouse gases


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from specific equipment and processes at their plants.[19] Different sectors are regulated and

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reported under different subparts of the GHGRP rule. Hydrogen plants are regulated under

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Subpart P, and combustion emissions from any facility are regulated under Subpart C. Any

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facilities with CO2 capture, collection, or sales are subject to reporting under Subpart PP. Although

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information provided in Subpart PP regarding CO2 amounts is often reported confidentially,

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amounts are included within the total releases reported in other subparts (Subpart P in this study).

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The present study compiles data from both Subparts P and C. GHG emissions are reported at the

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process level. Facilities can report emissions using CEMS or through specific emissions

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calculation methods approved by the EPA, which vary by industry and process. The GHGRP

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datasets do not include SCCs or generate consistent field names across all records. Therefore, a

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combination of text processing and subpart-specific details is used to match emissions to

134

subprocesses. The SMR facilities included in the 2014 GHGRP datasets are also listed in Table S1

135

in the SI, and the facility CAP and GHG emissions are listed in Table S2 in the SI.

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Estimation of Hydrogen Production Volume

137

Individual facilities’ annual hydrogen production volumes are often CBI. In the present

138

study, the hydrogen production volume information was estimated by applying four approaches

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that use different databases, including the following:

140 141

1. The hydrogen data from the EPA’s Chemical Data Reporting (CDR) database.[20] The CDR

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was required “under the Toxic Substances Control Act (TSCA), which requires manufacturers

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(including importers) to provide EPA with information on the production and use of chemicals

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in commerce in large quantities.”[20] The database is updated once every four years; thus, the

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most recent reports were CDR 2012 and CDR 2016 for the operation years of 2011 and 2015,



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respectively. The CDR 2012 data (for 2011 operation), directly reporting annual hydrogen

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production data, were used in the present study.

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2. The Merchant Hydrogen Plant Capacities data reported by Pacific Northwest National

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Laboratory (PNNL).[21] The PNNL report compiled hydrogen production capacities at

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merchant hydrogen plants from various sources, including company statements and related

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reports.[21] With the capacity of the hydrogen plants, the production in a specific year was

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estimated by assuming a utilization rate of 80%, which will be discussed in more detail below.

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3. The 2014 GHGRP database to derive hydrogen production from reported CO2.

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For the SMR process, CO2 is emitted via two sources: chemical co-production and fuels

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combustion. Following is the reaction of steam methane reforming:

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CH4 + H2O  CO + 2H2

(1)

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CO + H2O  CO2 +H2

(2)

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The stoichiometric CO2/H2 production is 4 (mole/mole) or 5.5 (kg/kg). Accounting for the CO2

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produced from fuel combustion for the energy supply, the general industrial practice shows

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that the total CO2/H2 ratio is in the range of 7.50–10.00 (kg/kg), with a median value of 9.04

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and an average value of 9.01, as shown in Table 1. Thus, the present study used the ratio of

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9.0 (kg CO2/kg H2) to estimate hydrogen production amount using facility CO2 emissions,

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corresponding to a ratio of 75.0 g CO2/MJ H2. For the PNNL dataset, by assuming a utilization

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rate of 80% for all facilities, the facility with a median hydrogen production emission

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(g CO2/MJ H2) shows a CO2/H2 mass ratio of about 9.0, which is consistent with the

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assumption used for GHGRP.

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Table 1. Literature Review of Total CO2/H2 Ratios in SMR Facilities in the United States CO2/H2

CO2/H2a

Combustion

(kg/kg)

(g/MJ)

CO2/Total

Source

Note

U.S. Department of Energy

H2A model version 3, based

CO2 1

2

9.28

8.89

77.3

74.1

Not reported

Not reported

(DOE)/National Energy

on the Aspen plus model,

Technology Laboratory, M.D.

with an efficiency level of

Rutkowski[7]

72% without steam export

Spath and Mann (2001), National Renewable Energy Laboratory (NREL) report[8]

Import 380 psi steam of 1293 Mg/day Export 700 psi steam 1858 Mg/day Energy efficiency 89% Steam export of 12.8 lb/lb H2

3

9.67

80.6

Not reported

Wulf and Kaltschmitt (2012), Bhandari et al. (2014)[9,10]

4

8.89

74.1

28.4%

Bonaquist (Praxair) (2010)[11]

Export steam 18.4 MJ steam/kg H2 Current practice, including carbon from feed, combustion for reformer, steam export, separation, compression, heat loss, and others With steam export, 6.4 lb/lb H2

10.00

83.3

14.7%


Historical practice No steam export



5

7.87

65.6

Not reported


7.50

62.5

Not reported

Ruether et al. (2006)[12],

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Ideal condition

DOE/NRELreport 6

8.10

67.5

32.4%

Rostrup-Nielsen and Rostrup-

For a high-efficiency, natural

Nielsen (undated), Haldor

gas-based plant (low heating

TopsØe Technologies[13]

value [LHV] efficiency of 94%a) Including till gas or fuel gas, steam exported

7

9.26

77.2

17.0%

The Greenhouse Gases,

Based on the H2A[7]

Regulated Emissions, and

modeling results, no steam

Energy Use in

export. Including all on-site

Transportation Model,

CO2 emissions, from

(GREET) 2017[14]

combustion, noncombustion, and other sources.

8

9.04

75.4

28.5%

Idaho National Laboratory

Modeled with Aspen Plus,

(2010) [15]

conventional case, with steam export of 0.8 lb/lb H2

Median

9.04

75.4

28.4%

Average

9.01

75.4

24.9%

Present

9.13

76.1

PNNL capacity report [21]

Study

PNNL data for hydrogen capacity, assuming 80% utilization rate, derived by applying CO2/H2 = 9.0 (kg/kg) assumption for the


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facility with median CO2 emissions per MJ hydrogen

169

a The

170

2017[14].

hydrogen production is converted from kg to MJ by using LHVs of 120 MJ/kg, according to GREET model

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The hydrogen production cases shown in Table 1 cover a wide range of operation practices

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and energy efficiency levels. For example, some hydrogen production facilities produce additional

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steam for export while others do not. Some production processes have energy efficiency level

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percentages in the low 70s, while others have efficiency levels of about 94%[13] (the system

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input/output information and calculation formulas were not revealed). It is worth noting that the

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facilities with steam export have higher shares of combustion CO2 (than the cases without steam

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export); however, they do not necessarily have higher CO2/H2 ratios. This result occurs because

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the facilities vary in process design, system boundary (material and energy input and output),

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process energy use optimization, and some other factors. For example, the Spath and Mann (2001)

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study imported low pressure steam and exported high pressure steam,[8] resulting in a high

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efficiency rate of 89% but also reporting a moderate CO2/H2 ratio of 8.89. Bonaquist[11] showed

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that the historical SMR facility emits 10.0 kg CO2/Kg H2 without steam export, whereas a modern

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SMR facility emits a lower 8.89 kg CO2/kg H2 with 6.4 lb of steam export per lb of H2 production.

184 185

Note that making the CO2/H2 = 9.0 (kg/kg) assumption yields valuable information for

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estimating hydrogen production volumes in SMR facilities, which enables the estimation of CAP

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emissions per MJ of hydrogen: evidently, this assumptions leads to a constant CO2 emission per

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MJ of hydrogen production (75.0 kg CO2/MJ H2) across all facilities in the GHGRP dataset.

189



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4. Provision of a few industrial facilities’ hydrogen production and CAP emissions information

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(the facility names were kept confidential upon request). These data reflect the facility’s

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production and CAP emissions in 2016 (GHG emission information was not provided).

193 194

Given the inclusion of various data pools and methods to estimate hydrogen production, Figure 1 is provided to summarize the usage and matching of various data pools.

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Figure 1. Summary of Various Emissions Database Pools (in the Numerator) and

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Methodology Used to Estimate Hydrogen Production

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The rigorous data matching between the NEI[17] dataset and PNNL report[21] results in

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29 sets of hydrogen emissions data (from 29 SMR facilities covered in both datasets). Similarly,

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32 sets of hydrogen production emissions data can be estimated based on the facility overlap

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between the NEI dataset[17] and the GHGRP dataset[19] (that is used to estimate the hydrogen

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production volume). Several facilities were excluded as they co-produce carbon monoxide and/or

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other chemicals based on cross-checking with the CDR database and notes in the PNNL report,

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shown in Table S1 in the SI. The hydrogen co-produced with other chemicals would have different

205

emissions per MJ hydrogen as the facility emissions burdens need to be allocated to all products.

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Industry sources provided three datasets of the actual facility hydrogen production and monitored

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CAP emissions.


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With the GHG and CAP emissions information and hydrogen production information, the

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emissions per MJ of hydrogen for stand-alone SMR facilities are estimated by dividing the SMR

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facility emissions by the hydrogen production amounts. Some facilities might co-produce

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additional steam for sale/export or collect some CO2 for sale; however, the lack of detailed product

212

information makes allocation infeasible. Thus, to estimate SMR emissions, all the facility

213

emissions burdens are attributed to the hydrogen product.

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Results and Discussions

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Estimated Hydrogen Production for Each SMR Facility

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SMR facility hydrogen production estimates from the CDR database, PNNL report, and

217

GHGRP datasets for each facility are shown in Figure S1 in the SI. Although the industry sources

218

are kept confidential, the disclosed annual hydrogen production amounts from the three industrial

219

sources are 6,515, 18,615, and 93,075 MT/year, respectively. The emissions per MJ of hydrogen

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production is then individually derived for each data pool (CDR, PNNL, and GHGRP). The source

221

and year of each dataset used to derive normalized hydrogen production emissions (g/MJ for CO2

222

emissions and mg/MJ for CAP, CH4, and NO2 emissions) are summarized in Table 2.

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Table 2. Year and Source of Each Dataset for Deriving CAP and GHG Emissions per MJ

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of Hydrogen Produced in U.S. SMR Facilities Dataset

Hydrogen Production

CAP Emissions

GHG Emissions

CDR

Source

Year

Source

Year

Source

Year

CDR

2011

NEI

2011

GHGRP

2011



PNNL

PNNL

2016 report, assuming 80% utilization rate,

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NEI

2014

GHGRP

2014

NEI

2014

GHGRP

2014

Facility

2016

NAa

NA

corresponding to CO2/H2=9.0 (kg/kg) GHGRP

GHGRP

2014 CO2 emission, assuming CO2/H2=9.0 (kg/kg)

Industrial

Facility

2016

Report

225

a NA

Report

= Not available.


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SMR CAP Emissions per MJ H2 Production from Various Data Pools

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The SMR facility CAP emissions and GHG emissions per MJ H2 production are derived

228

by dividing the total facility emissions (from the NEI database or industrial partners) by the

229

hydrogen production amount (MT/year). The mathematical expressions are shown in the SI. The

230

masses of hydrogen production were converted to energy values based on hydrogen low heating

231

values of 290 btu/scf and gas density of 2.55 g/scf from GREET 2017,[14] leading to a result of

232

119.98 MJ/kg. The results for CAP emissions are shown in Figure 2, and the values for the GHG

233

emissions are shown in Figure 3. Note that some data points are truncated in the figures with values

234

far beyond the range for majority points. But the maximum values are listed in the SI in Tables S3

235

and S4.

236

For all of the pollutants, the PNNL- and GHGRP-derived emissions data (per MJ hydrogen

237

production) are consistent with the results derived from the CDR data and industrial data (that have

238

actual hydrogen production data), validating the assumptions used for the PNNL dataset (the 80%

239

utilization rate) and the GHGRP dataset (CO2/H2=9 [kg/kg]) to estimate hydrogen production.

240



241 242

Figure 2. CAP Emissions of U.S. SMR Facilities per MJ of H2 Product


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For VOC, CO, and NOx pollutant emissions, the emissions per MJ of hydrogen appear to

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decrease with an increasing hydrogen production amount. This finding can be related to several

245

factors. First, larger facilities are more likely to be equipped with more efficient emissions control

246

technologies. Second, large facilties are prone to have higher energy efficiency levels and thus are

247

both combusting less fuel for each MJ of hydrogen production and emitting fewer pollutants.

248

Third, operations at the large facilities might run more steadily, whereas small facilities are more

249

likely to have intermittent operations (on and off) that, on average, result in more emissions per

250

MJ hydrogen production. However, the PM10, PM2.5, and SO2 emissions per MJ hydrogen

251

production do not appear to correlate to hydrogen production volume, indicating that the second

252

and third reasons are likely not the causes; otherwise they would have consistent impacts across

253

all pollutants. Therefore, the decreasing VOC, CO, and NOx pollutant emission intensities

254

(g pollutant/MJ H2) with increasing hydrogen production scale are likely caused by the differences

255

in emission control techonologies, which differ for various pollutants.

256

There are few CH4 and N2O emissions data from the GHGRP database, and the data are

257

rather scattered. The range of CO2 emissions per MJ hydrogen derived from the PNNL report and

258

CDR database vary widely, including emissions from both chemical co-production and that from

259

fuel combustion.



260 261

FIGURE 3. GHG Emissions of U.S. SMR Facilities per MJ of H2 Product

262


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The analysis for the individual data pool was also conducted, and the national results are

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shown in the SI in Table S3 (for national CAP emissions) and Table S4 (for GHG emissions); the

265

CAP and GHG results for California are shown in the SI in Table S5. The median and capacity

266

weighted average (W Avg) values for SMR CAP emissions are calculated for for the combined

267

data pools (CDR, PNNL, GHGRP, and industrial sources), as shown in the SI in Table S6 for

268

national results and in Table S7 for California results. The narrow range of emissions values

269

derived from the PNNL and GHGRP data pools implies that reasonable assumptions have been

270

used for each dataset (e.g., the 80% utilization rate for the former and the assumption of

271

CO2/H2=9.0 [kg/kg] used for the latter).

272

The emissions per MJ of hydrogen production vary significantly across facilities, and the

273

median values were used to present national values for each species. It is worth mentioning that

274

although many facilities report both combustion emissions and non-combustion emissions, some

275

facilities report emissions as one single source only, under either combustion emissions or non-

276

combustion emissions. Therefore, for these facilities, the combustion emissions or non-

277

combustion values can be zero.

278

The CAP emissions dataset includes 32 facilities from the 2014 NEI database; the number

279

of facilities considered was constrained by the availability of stand-alone facility capacity or

280

production data, which are often business confidential. The first and third quartiles of the emissions

281

factors from various SMR facilities indicate a large variation of emissions among these facilities.

282

The CAP and GHG emissions per MJ hydrogen production in California SMR facilities

283

were also estimated. The California Air Resources Board (CARB) also reports individual

284

California SMR facility CAP and GHG emissions.[22] The 2014 facility total emissions data from

285

CARB are close to that reported in the NEI for 2014. The CARB database does not have hydrogen



286

production data; thus, the hydrogen production amount had to be estimated as well by using the

287

PNNL report (assuming the 80% utilization rate) and CARB GHG emissions (by assuming

288

CO2/H2 = 9 [kg/kg]). The Californial CAP and GHG emissions (per MJ of hydrogen) derived from

289

the NEI dataset are shown in Table S7 and that from the CARB dataset are shown in Table S8 of

290

the SI.

291

The California SMR CAP and GHG emissions per MJ hydrogen production are compared

292

to that of national SMR facilities in Figure 4. The capacity of California stand-alone SMR facilities

293

spans a wide range (on the order of 1,000 MT to 100,000 MT annual hydrogen production), and

294

is consistent with that of national facilities (see Figures 2 and 3). The results from the present study

295

are also compared to the previous study by Zapata et al. (2018),[6] as shown in Figure 4. Note that

296

the CARB database[22] does not include CO emissions information, and the reference (Zapata et al.

297

2018[6]) does not include GHG emissions information.

298


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299 300

Figure 4. The Median and Average Values of National and California (CA) SMR Total CAP and GHG Emissions per MJ

301

Hydrogen (where the error bars indicate the 1st and 3rd quartiles, and the solid bars indicate CAP emissions while the bars

302

with patterned fills indicate GHG emissions)



303

The present study shows that the California SMR CAP emissions are lower compared to

304

the national CAP emissions per MJ of hydrogen produced when using either the NEI emissions

305

dataset or the CARB emissions dataset for California results. The differences might be attributed

306

to different operational practices, facility energy efficiency, emission control technology, and

307

some other variables.

308

Zapata et al. (2018)[6] reported the average CAP emissions from California’s top three SMR

309

facilities — Air Liquide-El Segundo, Air Products-Carson, and Air Products-Wilmington — based

310

on Califorina Energy Commission (CEC) Board reports.[23, 24] For comparison, the present study

311

also lists the average CAP emissions results for the same top three SMR facilities in California, as

312

shown in Figure 4. Relative to Zapata et al.’s (2018)[6] results, the present study shows pollutant

313

emissions falling within a similar range but with lower VOC and CO emissions and slightly higher

314

NOx and PM10 emissions. The differences might have a couple of causes. First, the present results

315

are based on 2014 emissions data, whereas Zapata et al.’s data are based on 2009 emissions data.

316

The SMR facility operations practices and emissions control practices could have been modified

317

between 2009 and 2014. Second, the assumptions of hydrogen production used in the present study

318

(i.e., an 80% capacity utilization rate and CO2/H2=9.0 [kg/kg]) might contribute to the differences.

319

For example, the individual California SMR facilities could have different utilization rates

320

diverging from the assumed 80% utilization rate.

321

For CO2 emissions, GHGRP data are not accounted for as the data are used to estimate

322

hydrogen production volume, resulting in a constant 75 g CO2/MJ H2. Based on the CDR dataset,

323

the PNNL capacity report (assuming an 80% utilization rate), and industry-provided data, the

324

national SMR facilities have a median CO2 emissions amount of 77.8 g/MJ H2 and a weighed

325

average of 77.7 g CO2 /MJ. The California SMR facilities have a median CO2 emissions amount


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326

of 76.1 g/MJ H2, and a weighted average of 67.8 CO2/MJ H2, based on the PNNL dataset (whereas

327

there was no CDR or industrial data for California). The median emissions amounts for California

328

SMR facilities are similar to those of the national SMR facilities (also see Tables S6 and S7 in the

329

SI).

330

For CH4 emissions, the national SMR facilities have a median emissions value of

331

0.08 mg CH4/MJ H2,

and

California

facilities

have

a

median

emissions

value

of

332

0.65 mg CH4/MJ H2. For N2O emissions, the national SMR facilities’ median value is

333

0.008 mg N2O/MJ H2, and California SMR facilities’ median value is 0.129 mg N2O/MJ H2.

334

Compared to the other pollutants, there are far fewer data for CH4 and N2O. (See Tables S3 and

335

S4 in the SI.)

336

Figure 4 also shows the GHG emissions by using the Global Warming Potential of 1 for

337

CO2, 30 for CH4, and 265 for N2O.[14] The present study shows that the California SMR GHG

338

emissions are slightly lower compared to the national GHG emissions per MJ of hydrogen

339

produced, by using either the NEI emissions dataset or the CARB emissions dataset for California

340

results. The differences in hydrogen production GHG emissions between national SMR facilities

341

and California SMR facilities might be related to different operational practices and facility energy

342

efficiencies, in addition to the assumption of hydrogen production amount (i.e., assuming an 80%

343

utilization rate for all SMR facilities, while that rate would vary for individual facilities).

344 345

SMR CAP and GHG Emissions from Combustion Sources

346

Upon obtaining the total CAP and GHG emissions per MJ of hydrogen produced, the

347

emissions are further itemized as combustion emissions and non-combustion emissions. In the NEI



348

database, the emissions from SMR facilities are further categorized based on the SCC of the

349

following: heater, boiler, engine, flare, fugitive emissions, hydrogen plants (process emissions),

350

and “other.” “Other” refers to any other emissions at the facility not otherwise classified. The

351

actual SCCs cover a wide range, and the vast majority of the “other” emissions report under the

352

SCC for Miscellaneous Industrial Processes Other Not Classified. The emissions from heaters,

353

boilers, and engines are grouped as combustion emissions, whereas the remainder (flare, fugitive,

354

hydrogen plants, and “other”) are regarded as non-combustion emissions. Flare emissions are

355

regarded as non-combustion emissions because flaring is not purposeful combustion to supply

356

energy and is likely not a continuous or a constant source of emissions.

357

For the calculation of combustion emissions, the facilities without any combustion

358

emissions records were excluded from the statistical analysis. However, if one facility has an

359

emissions reporting record for CAP pollutant i, but no emissions reporting for CAP pollutant j,

360

then the pollutant j emissions value is regarded as zero and is included in the data pool. The number

361

of plants reporting combustion emissions is less than the number of plants reporting total

362

emissions. The mathematical expressions are shown in the SI.

363

The statistical data for U.S. SMR combustion-related CAP and GHG emissions are shown

364

in the SI in Table S9, and the median values for CAP and GHG emissions are shown in the SI in

365

Figure S2. The combustion CAP emissions from GREET (2017)[14] are also displayed for

366

comparison. In GREET (2017), the combustion emissions are estimated by multiplying the amount

367

of natural gas combustion by the emissions factors of a natural gas industrial boiler (i.e., assuming

368

100% of natural gas use occurs in industrial boilers).

369

Consistent with the comparison of total CAP emissions for national SMR facilities with

370

those for California SMR facilities, the California combustion CAP emissions were much lower


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371

compared to the national values (the median emissions data for CH4, N2O, and CO2 data are shown

372

in Table S9). For CO2 emissions, only eight facilities reported emissions sourced from combustion,

373

far less than the number of facilities reporting CO2 emissions from overall SMR facilities (see

374

Table S4 in the SI). Only one facility in California reported CO2 emissions from combustion

375

sources, and the data are very low (0.001 g CO2 per MJH2 production), likely indicating some

376

reporting errors. Although fuel combustion (mostly natural gas) is necessary in SMR facilities to

377

supply energy for the endothermic reforming reaction, it appears that many facilities might have

378

not differentiated the combustion-resultant CO2 emissions (subject to reporting in GHGRP

379

Subpart C) from chemical co-produced CO2 emissions (non-combustion emissions) but rather

380

have included all facility emissions in the non-combustion emissions (as emissions for hydrogen

381

plant in GHGRP Subpart P).

382

Thus, the combustion CO2 emissions from SMR facilities were corrected (corr) by

383

assuming a percentage share of combustion-resultant CO2 over total CO2 emissions in SMR

384

facilities. The present study assumes this percentage to be 28.4%, which is the median value of

385

previous research regarding hydrogen production from SMR facilities, as shown in Table 1. With

386

this assumption, the corrected CO2 combustion emissions value is 22.2 g/MJ of H2 production.

387

SMR CAP and GHG Emissions from Non-Combustion Sources

388

Similarly, for the calculation of non-combustion emissions, the facilities without any non-

389

combustion emissions reporting were excluded from the data pool for the statistical analyses.

390

However, if one facility has a record for pollutant i and no record for pollutant j, then the pollutant j

391

emissions in this facility are regarded as zero. The mathematical expressions are shown in the SI.



392

The statistical analyses of non-combustion CAP and GHG emissions of SMR facilities are

393

shown in the SI in Table S10. All of the N2O and CH4 emissions are reported as combustion

394

emissions; thus, the non-combustion emissions of N2O and CH4 are zero. For CO2 emissions, in

395

contrast with the scarce data reporting for combustion emissions, the reporting of non-combustion

396

emissions (emissions subject to GHGRP Subpart P‒hydrogen plant) are prevalent. As stated

397

earlier, the emissions reported in Subpart P likely include the combustion emissions as well; thus,

398

they are corrected by assuming a percentage of total emissions (71.6%=100%–28.4%) for non-

399

combustion CO2 emissions, leading to 55.7 g CO2/MJ hydrogen production. Each SMR facility

400

has different processes for achieving energy efficiency and different operations practices; thus, in

401

practice, different facilities would have different percentages of combustion CO2 emissions vs.

402

non-combustion CO2 emissions. The results of individual plant emissions would differ, more or

403

less, from the actual emissions amount, and the present study aims to estimate the median

404

emissions values of national stand-alone SMR facilities.

405

The non-combustion CAP and GHG emissions median values are shown in the SI in

406

Figure S3 (the median emissions data for CO2 data are shown in the SI in Table S10). The non-

407

combustion data from GREET (2017)[14] were similar to the data used in the present study as they

408

had been updated previously using preliminary results from the present study.[25]

409

The CAP non-combustion emissions in California SMR facilities (per MJ hydrogen) are

410

slightly lower than those of the national SMR facilities, which is consistent with the total emissions

411

trend shown in Figure 4 and the combustion emission trend in the SI in Figure S2.


Page 26 of 33

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412

SMR CAP and GHG Emissions from the Combined Combustion and Non-Combustion

413

Sources

414

The combined total emissions median values, with a breakdown of combustion and non-

415

combustion CAP emissions, are shown in Figure 5. The mathematical expressions are shown in

416

the SI. It is worth noting that combining the median values of the combustion emissions and the

417

median values of non-combustion emissions (the stacked data in Figure 5) does not necessarily

418

result in the same values that match with the median values of total facility emissions (the green

419

and orange diamond marker data in Figure 5). This result occurs because the distribution of

420

combustion emissions vs. non-combustion emissions varies for each pollutant and facility; thus,

421

the median values of each data pool would not necessarily be sourced from the same facility.

422

423 424

Figure 5. The National and California SMR Combustion and Non-combustion CAP and

425

GHG Emissions per MJ of Hydrogen Production



426

The combustion emissions (e.g., various fuels combusted in boilers, heaters) and non-

427

combustion emissions (e.g., unit emissions, flaring emissions) are reported in different sectors or

428

subparts in the NEI database and the GHGRP database. Owing to the speculation of the presence

429

of mis-categorizations occurring between combustion and non-combustion emissions, the total

430

emissions median values (the diamond markers in Figure 5) will provide more reliable,

431

macroscopic estimates of national or regional emissions from SMR facilities. However, the

432

breakdown of combustion and non-combustion emissions can provide flexible guidance for

433

individual facilities or regional facilities striving to “customize” their emissions approach and

434

improve emissions estimations when only limited information is available.

435

Applications and Future Work

436

The present study investigates emissions for U.S. stand-alone SMR facilities, and it derives

437

CAP and GHG emissions per MJ of hydrogen production. The results are aggegated to present

438

national SMR facilities’ median values and California median values, with the former higher than

439

the latter. This study’s newly developed CAP emissions (along with GHG emissions) associated

440

with hydrogen production can fill the knowledge gap to evaluate the full life cycle of

441

environmental impacts of hydrogen applications (e.g., hydrogen used as a transportation fuel for

442

FCEVs). The lower median CAP and GHG emissions for hydrogen production in California

443

compared to the national average could incentivise the deployment of hydrogen FCEVs in

444

California.

445

This study allocates all facility burdens to the hydrogen product. SMR facilities vary

446

significantly in design, operational practices, types of co-products (e.g., steam for export or

447

collected CO2 for sale), and co-product amounts, and these detailed data are often confidential. If

448

more information becomes available, an appropriate allocation of SMR emissions burdens


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449

between hydrogen products and co-products (steam for export and CO2 for sale) would be

450

developed.

451

Supporting Information

452

The Supporting Information is available free of charge on the ACS Publications website at….

453

Table S1 and Table S2 showing the U.S. national SMR facility list and facility-wide CAP and

454

GHG emissions.

455

Table S3 through Table S8 showing the statistical data of overall CAP emissions and GHG

456

emissions per MJ of hydrogen produced in national SMR facilities and in California SMR

457

facilities, using various emission data pools and various methods to estimate hydrogen

458

production amount.

459

Table S9 showing the statistical data of CAP emissions and GHG emissions from combustion

460

sources for per MJ of hydrogen produced in both national and California SMR facilities.

461

Table S10 showing the statistical data of CAP emissions and GHG emissions from non-

462

combustion sources for per MJ of hydrogen produced in both national and California SMR

463

facilities.

464

Figure S1 showing the amount of national SMR facility hydrogen production estimated via

465

various methods.

466

Figure S2 comparing the CAP and GHG emissions from combustion sources for per MJ of

467

hydrogen produced in national SMR facilities with that in CA SMR facilities.

468

Figure S3 comparing the CAP and GHG emissions from non-combustion sources for per MJ of

469

hydrogen produced in national SMR facilities with that in CA SMR facilities.



470

SI also including some mathematical expressions depicting the calculations of the median values

471

of the combined total CAP and GHG emissions per MJ of hydrogen produced in national SMR

472

facilities, from combustion and non-combustion sources.

473

Acknowledgments

474

This research was supported by the Fuel Cell Technologies Office of the U.S. Department of

475

Energy’s Office of Energy Efficiency and Renewable Energy under Contract Number DE-AC02-

476

06CH11357. The authors are grateful to Fred Joseck from the U.S. Department of Energy’s Fuel

477

Cell Technologies Office for his guidance and support. The views and opinions of the authors

478

expressed herein do not necessarily state or reflect those of the United States Government or any

479

agency thereof. Neither the United States Government nor any agency thereof, nor any of their

480

employees, makes any warranty, expressed or implied, or assumes any legal liability or

481

responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product,

482

or process disclosed, or represents that its use would not infringe privately owned rights.

483

References 1

Ramachandran, Ram, and Raghu K. Menon, 1998, “An Overview of Industrial Uses of Hydrogen,” Int. J. Hydrogen Energy, Vol. 23, No. 7, pp. 593–598. 2

U.S. Energy Information Administration, 2018, Hydrogen Explained: Use of Hydrogen, https://www.eia.gov/energyexplained/index.php?page=hydrogen_use, accessed August 31, 2018. 3

U.S. Environmental Protection Agency, 2018, Smog, Soot, and Other Air Pollution from Transportation, https://www.epa.gov/air-pollution-transportation/smog-soot-and-local-airpollution, accessed May 24, 2017. 4

Fuel Cell Technologies Office, undated, Hydrogen Production: Natural Gas Reforming, Energy Efficiency and Renewable Energy, U.S. Department of Energy, https://www.energy.gov/eere/fuelcells/hydrogen-production-natural-gas-reforming, accessed September 5, 2018.


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U.S. Environmental Protection Agency, 2017, Summary of the Clean Air Act, https://www.epa.gov/laws-regulations/summary-clean-air-act, accessed July 27, 2017. 6

Zapata, Christina B., Chris Yang, Sonia Yeh, Joan Ogden, and Michael J. Kleeman, 2018, “Estimating Criteria Pollutant Emissions Using the California Regional Multisector Air Quality Emissions (CA-REMARQUE) Model v1.0,” Geosci. Model Dev., Vol. 11, pp. 1293–1320. 7

Rutkowski, M.D., 2012, H2A Model Version 3, Current (2010) Hydrogen from Natural Gas without CO2 Capture and Sequestration, National Energy Technology Laboratory, U.S. Department of Energy, January 31. 8

Spath, P.L., and M.K. Mann, 2001, Life Cycle Assessment of Hydrogen Production via Natural Gas Steam Reforming, Report No. NREL/TP-570-27637, National Renewable Energy Laboratory, Golden, Colo., February. 9

Wulf, C., and M. Kaltschmitt, 2012, “Life Cycle Assessment of Hydrogen Supply Chain with Special Attention on Hydrogen Refuelling Stations,” International Journal of Hydrogen Energy, Vol. 37, pp. 16711–16721. 10

Bhandari, Ramchandra, Clemens A. Trudewind, and Petra Zapp, 2014, “Life Cycle Assessment of Hydrogen Production via Electrolysis – A Review,” Journal of Cleaner Production, Vol. 85, pp. 151–163. 11

Bonaquist, Dante, 2010, Analysis of CO2 Emissions, Reductions, and Capture for Large-scale Hydrogen Production Plants, https://www.praxair.com//media/corporate/praxairus/documents/reports-papers-case-studies-and-presentations/ourcompany/sustainability/praxair-co2-emissions-reduction-capture-white-paper.pdf?la=en, accessed July 27, 2018. 12

Ruether, John, Massood Ramezan, and Eric Grol, 2005, Life-Cycle Analysis of Greenhouse Gas Emissions for Hydrogen Fuel Production in the United States from LNG and Coal, DOE/NETL-2006/1227, November. 13

Rostrup-Nielsen, Jens R., and Thomas Rostrup-Nielsen, undated, Large-scale Hydrogen Production, TopsØe Technologies, https://www.topsoe.com/sites/default/files/topsoe_large_scale_hydrogen_produc.pdf, accessed July 27, 2018. 14

Argonne National Laboratory, 2017, The Greenhouse Gases, Regulated Emissions, and Energy Use in Transportation Model, Energy Systems Division, https://greet.es.anl.gov/, accessed August 1, 2018. 15

Idaho National Laboratory, 2010, Sensitivity of Hydrogen Production via Steam Methane Reforming to High Temperature Gas-Cooled Reactor Outlet Temperature Process Analysis, Project No. 23843. 16

Energy Efficiency and Renewable Energy, 2018, Fact of the Month #18-01, January 29: There Are 39 Publicly Available Hydrogen Fueling Stations in the United States, U.S. Department of



Energy, https://www.energy.gov/eere/fuelcells/fact-month-18-01-january-29-there-are-39publicly-available-hydrogen-fueling-stations, accessed September 19, 2018. 17

U.S. Environmental Protection Agency, 2016a, 2014 National Emissions Inventory Data, No. Version 1, https://www.epa.gov/air-emissions-inventories/2014-national-emissionsinventory-nei-data, accessed April 25, 2017. 18

U.S. Environmental Protection Agency, 2016c, Source Classification Codes (SCCs), https://ofmpub.epa.gov/sccsearch/, accessed April 25, 2017. 19

U.S. Environmental Protection Agency, 2016b, Greenhouse Gas Reporting Program (GHGRP), https://www.epa.gov/ghgreporting, May 23, 2017. 20

U.S. Environmental Protection Agency, 2012, Chemical Data Reporting under the Toxic Substances Control Act, https://www.epa.gov/chemical-data-reporting, accessed April 5, 2017. 21

Pacific Northwest National Laboratory, 2016, Merchant Hydrogen Plant Capacities in North America, https://h2tools.org/hyarc/hydrogen-data/merchant-hydrogen-plant-capacitiesnorth-america, accessed May 15, 2017. 22

California Air Resouces Board, 2014a, CARB Pollution Mapping Tool, Documentation of California’s 2000–2012 GHG Inventory, https://www.arb.ca.gov/ei/tools/pollution_map/, accessed August 6, 2018. 23

California Air Resources Board, 2010, “Staff Report: Initial Statement of Reasons for Proposed Rulemaking. Regulation for Energy Efficiency and Co-Benefits Assessment of Large Industrial Facilities,” in: Stationary Source Division Emissions Assessment Branch (Ed.), Sacramento, Calif. 24

California Air Resources Board, 2014b, Energy Efficiency and Co-Benefits Assessment of Large Industrial Sources, Hydrogen Sector Public Report, Sacramento, Calif. 25

Young, B., B. Morelli, and T.R. Hawkins, 2017, Creation of Unit Process Data for Life Cycle Assessment of Steam Methane Reforming and Petroleum Refining, Franklin Associates, A Division of Eastern Research Group (ERG), prepared for Argonne National Laboratory, October, https://greet.es.anl.gov/publication-air_pollutants_smr_petroleum, accessed October 26, 2017.

List of Abbreviations CAP CARB CBI CDR CEMS CH4 CO

criteria air pollutant California Air Resources Board confidential business information Chemical Data Reporting continuous emissions monitoring system methane carbon monoxide


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Page 33 of 33


CO2 EPA FCEV GHG GHGRP ICE LCA N2O NEI NOx NO2 O3 Pb PM PNNL SCC SI SMR SO2 TSCA VOC

carbon dioxide U.S. Environmental Protection Agency fuel cell electric vehicle greenhouse gas Greenhouse Gas Reporting Program internal combustion engine life cycle analysis nitrous oxide National Emissions Inventory nitrogen oxides nitrogen dioxide ozone lead particulate matter Pacific Northwest National Laboratory Source Classification Code Supporting Information steam methane reforming sulfur dioxide Toxic Substances Control Act volatile organic compound

Units of measure

btu g kg MJ MT Scf

British thermal unit gram(s) kilogram(s) mega Joule metric ton standard cubic foot


Criteria Air Pollutants and Greenhouse Gas Emissions from Hydrogen

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