Agreement #:
FY10
Level:
WBS #:
Completion Date:
Scheduled Completion:
Platform Area:	Analysis
Title:
Catalytic Fast Pyrolysis with Upgrading to Gasoline and Diesel Blendstocks
Authors:
Christopher Kinchin
Participating Researchers:

Project Name:
Project Leader:
Strategic Analysis
Andy Aden
Key Words:
Catalytic Fast Pyrolysis, GHG Emissions
Reviewed By:
Andy Aden

1.  Abstract
An AspenPlus model was used to simulate catalytic fast pyrolysis of wood to bio-oil, and subsequent upgrading and separation to gasoline and diesel blendstocks.  The results of the simulation show that catalytic fast pyrolysis yields about 50% less bio-oil than conventional fast pyrolysis, but more product gases, char, and water.  The bio-oil from catalytic fast pyrolysis contains less oxygen than bio-oil from conventional fast pyrolysis, resulting in less chemical hydrogen consumption in the upgrading steps.  The separation steps are modeled as commercially available flash drums and distillation columns.  Hydrogen production is modeled as a conventional steam methane reforming hydrogen plant.  More gasoline is produced than diesel, which is in contrast to conventional fast pyrolysis.  The major energy consumers are feedstock size reduction, the air blower for the char combustor, and hydrogen compression steps in the hydrotreating area.  Excess electricity is produced that can be sold to the electric grid.  More research into catalytic fast pyrolysis, particularly upgrading bio-oil derived from catalytic fast pyrolysis, is necessary for future analyses.  An economic analysis was not performed.  The purpose of this analysis is to support lifecycle modeling efforts by the Environmental Protection Agency (EPA).

2.  Introduction
Biomass can be converted to infrastructure-compatible transportation fuels by several different thermochemical processes, such as gasification, pyrolysis, and liquefaction.  Fast pyrolysis is a very promising thermal conversion technology because operating conditions are less severe (lower temperatures and pressures) than gasification and liquefaction.  In fast pyrolysis, biomass is rapidly heated, usually in less than one second, to about 500 °C at or slightly above atmospheric pressure.  The rapid heating thermally decomposes biomass, converting it to pyrolysis vapor, which is later condensed to a liquid bio-oil.
Fast pyrolysis is an economically promising technology for converting biomass to liquid transportation fuels.  However, commercial viability is currently limited due to undesirable characteristics of the bio-oil, such as high oxygen content and instability under storage and heating conditions (Lappas et. al. 2002).  Pyrolysis oil can be upgraded using hydroprocessing technology to improve these characteristics, however this increases the cost of the final product, and commercial hydroprocessing operations are usually geared towards removing sulfur rather than oxygen.  Also, hydroprocessing equipment is more commonly available at capacities on the scale of petroleum refineries rather than biorefineries.
Catalytic fast pyrolysis has the potential to reduce expensive downstream hydroprocessing steps.  An AspenPlus model has been developed to simulate a catalytic fast pyrolysis process and estimate the material and energy flows.  This report describes the model and presents results.  The results reported are limited to the conversion step of the supply chain (biomass to gasoline and diesel blend stocks) and do not include energy inputs incurred in preceding or subsequent stages of the supply chain (feedstock production and logistics, product distribution, end use, etc.).
The purpose of this analysis is to support lifecycle modeling efforts by the Environmental Protection Agency (EPA).  The Renewable Fuel Standard (RFS2) program under the Energy Independence and Security Act (EISA) of 2007 expands the required use of renewable fuels while requiring lifecycle greenhouse gas (GHG) performance threshold standards to ensure that each category of renewable fuel emits fewer GHGs than the petroleum it replaces.  The EPA is performing a lifecycle assessment that includes the entire supply chain for pathways utilizing catalytic pyrolysis: feedstock production and logistics, conversion, distribution, and end use.  The results of the catalytic pyrolysis model reported here will provide the input and output data for the conversion (biomass to liquid fuel) step of the full lifecycle assessment.
3.  Methods and Results
3.1   Overview of AspenPlus Catalytic Fast Pyrolysis Model
To model a catalytic fast pyrolysis process, two previous modeling efforts are modified and combined, one from the National Renewable Energy Laboratory (NREL) and one from Pacific Northwest National Laboratory (PNNL).  The NREL model, "Large-Scale Pyrolysis Oil Production: A Technological and Economic Assessment" (Ringer et. al. 2006), converts wood chips to bio-oil via conventional (non-catalytic) fast pyrolysis.  This model is modified such that the pyrolysis reactor, a circulating fluidized bed, circulates a zeolite catalyst in addition to olivine.
Also, the original NREL Fast Pyrolysis Model produces bio-oil, but does not include additional downstream hydroprocessing and separation steps necessary to convert the bio-oil to finished transportation fuel.  These additional downstream steps are added to the modified (catalytic) NREL Fast Pyrolysis Model.  The additional downstream steps are based on a ChemCAD model developed by Sue Jones at PNNL, "Production of Gasoline and Diesel from Biomass via Fast Pyrolysis, Hydrotreating and Hydrocracking: A Design Case" (Jones et. al. 2009).
The combined AspenPlus model is divided into several areas, each of which is described in the following sections of this report.  A simplified block flow diagram of the process is presented in Figure 1.   Utilities such as electricity, steam production, and cooling water are not included in Figure 1 but are included in the AspenPlus model.
                                    Biomass
                           Drying and Size Reduction
                                  Dry Biomass
                           Catalytic Fast Pyrolysis
                                    Bio-Oil
                                Hydroprocessing
                                UpgradedBio-Oil
                                  Separation
                                   Gasoline
                                    Diesel
                                     Water
                            Hydrogen Recovery Unit
                              Hydrogen Production
Natural Gas
                                      H2
                                      H2
 PSA Tail Gas
                                   Flue Gas
                              Combustion Exhaust
                              Combustion Exhaust
                                   Flue Gas
 H2-Rich Fuel Gas
                 Figure 1.  Block flow diagram of the process.

3.2  Drying and Size Reduction
Wood is received as chips at 50 wt% moisture.  The wood chips are dried to 7 wt% moisture in a wood dryer using hot flue gas from downstream combustion processes (char combustor and natural gas furnaces in the hydroprocessing section).  The chips are then ground to a maximum diameter of 3 mm.  The grinding process is not modeled in AspenPlus, although the power requirement is estimated at 50 kWh/ton (Ringer et. al. 2006).  Small particle size is important in fast pyrolysis operations to ensure the entire wood particle is heated rapidly.  Small particle size reduces mass transfer effects, such as pyrolysis vapors in the particle interior encountering a char layer on the particle surface (Zhang et. al. 2009).  The ground, dried wood is then sent to the pyrolysis reactor.

3.3  Catalytic Fast Pyrolysis
The catalytic step can take place in-situ (in the pyrolysis reactor) or in a separate vessel following the pyrolysis reactor.  The in-situ design is used in this model, and is illustrated in Figure 2.  The pyrolysis reactor is a circulating fluidized bed reactor operating at 500 °C and 20 psia.  Biomass is fed to the pyrolysis reactor, where it mixes with olivine and catalyst.  Commercial operation may require olivine mixed with catalyst, or catalyst alone.  The solids in the reactor are fluidized using recycled product gas.  In the reactor the wood is converted to pyrolysis vapors, water vapor, non-condensable product gases (H2, CO, CO2, CH4, etc.), char, coke, and ash.
The solid pyrolysis products (char, coke, and ash) along with the olivine and catalyst are separated from the pyrolysis vapors, water vapor, and product gases in cyclones.  The solid products are sent to a char combustor where the heat for pyrolysis is generated by combusting char and coke in the char combustor, and recycling the hot olivine and catalyst back to the pyrolysis reactor.
The pyrolysis vapors and water are cooled and quenched in a multi-step process.  The vapors and gases are first cooled and quenched using recycled, condensed bio-oil.  Secondary recovery of uncondensed pyrolysis vapors occurs in a wet ESP (electrostatic precipitator).

   Figure 2. Circulating fluidized bed reactor system (Ringer et. al. 2006)

The product yield of the catalytic pyrolysis reactor is the most significant modification to the NREL Fast Pyrolysis Model.  Catalytic pyrolysis of biomass generally leads to the production of more water, char and product gases compared to conventional (non-catalytic) fast pyrolysis.  However, the liquid product quality and composition is improved (Lappas et. al. 2002).  There are very few published results on catalytic pyrolysis of biomass, and there is considerable variation among the published results.  Therefore, the overall product yield from the pyrolysis reactor is calculated by averaging the results of three literature sources that most closely resemble the process modeled in this report (Aho et. al. 2008, Lappas et. al. 2002, and Zhang et. al. 2009).  The overall pyrolysis yields are presented in Table 1, along with conventional fast pyrolysis yields reported in the PNNL Fast Pyrolysis design report (Jones et. al. 2009).
                     Table 1.  Pyrolysis oil composition.
Product
                        Catalytic Fast Pyrolysis Yield
                             (wt% of dry biomass)
                      Conventional Fast Pyrolysis Yield*
                             (wt% of dry biomass)
Oil
                                     32.7
                                      65
Water
                                     27.9
                                      10
Gas
                                     16.2
                                      12
Char/Coke
                                   20.5/2.7
                                      13
*Jones et. al. 2009.

Ash contents are not reported in the literature sources used to calculate the catalytic pyrolysis yields in Table 1, therefore the yields are on a non-ash basis.  In the AspenPlus model the ash in the wood is assumed to be inert and passes through the pyrolysis reactor unchanged.  Also, char and coke are both combusted in the char combustor, therefore in the AspenPlus model the coke yield is added to the char yield and both are treated as char.
As can be seen in Table 1, catalytic pyrolysis produces less bio-oil, but more water, product gas, and char/coke.  The composition of the bio-oil changes as well.  Catalytic fast pyrolysis produces bio-oil with less oxygen, and generally smaller hydrocarbon molecules.  As a result, catalytic fast pyrolysis oil requires less downstream hydroprocessing than conventional fast pyrolysis oil.  Also, the increased char yield improves the overall heat balance of the process because the heating value of the char and coke are recovered in the char combustor.

3.3.1  Composition of the oil fraction
All three literature sources report the composition of the oil fraction in terms of functional groups (aldehydes, acids, alcohols, ketones, phenols, polyaromatic hydrocarbons, etc.) but only one source, Aho et. al. 2008, lists the chemical compounds determined by gas chromatography-mass spectroscopy (GC-MS).  Therefore, the composition of the oil fraction in the AspenPlus model is based on results from Aho et. al. 2008.  Unfortunately, BTX (benzene, toluene, xylene) compounds are not included in the list of chemical compounds, therefore BTX compounds are added to the list based on results from French and Czernik 2010.  The composition of the oil fraction and yields of each compound used in the AspenPlus model are presented in Table 2.

       Table 2.  Yield and composition of oil fraction in pyrolysis oil.

Product
                                     Yield
                             (wt% of dry biomass)
                                Oil Composition
                             (wt% of oil fraction)

          Acids
                                     1.37
                                     4.18
Acetic Acid, Ethanoic Acid
                                     1.37
                                     4.18
2-Butenoic Acid, Crotonic Acid
                                       0
                                       0
4-Hydroxy-3-methoxy-benzeneacetic acid, Vanilacetic Acid
                                       0
                                       0

          Alcohols
                                     1.38
                                     4.21
Ethylene Glycol, Ethylene Alcohol, 1,2-Ethanediol
                                     1.11
                                     3.40
Glycerin, Glycerol, 1,2,3-Propanetriol
                                     0.17
                                     0.51
Glycidol, 2,3-Epoxy-1-Propanol
                                       0
                                       0
1,2 Benzenediol
                                       0
                                       0
1,4-Benzenediol, Hydroquinone
                                     0.10
                                     0.29

          Phenols
                                     5.78
                                     17.66
Phenol, Carbolic Acid
                                     0.20
                                     0.61
2-Methyl-phenol, O-Cresol
                                     0.14
                                     0.44
3-Methyl-phenol, M-Cresol
                                     0.11
                                     0.34
4-Methyl-phenol, P-Cresol
                                     0.07
                                     0.20
2-Methoxy-phenol, Guaiacol
                                     0.83
                                     2.52
2,4-Dimethyl-phenol, 2,4-Xylenol
                                     0.07
                                     0.20
2-Methoxy-4-methyl-phenol
                                     2.64
                                     8.07
2-methoxy-4-propyl-phenol, 4-Propylguaiacol
                                     0.33
                                     1.01
2-methoxy-4-(1-propenyl)-phenol, Isoeugenol
                                     1.40
                                     4.27

          Aldehydes
                                     4.00
                                     12.24
Glycol-aldehyde, hydroxyacetaldehyde
                                     1.72
                                     5.26
Pentanal, Valeraldehyde
                                     0.23
                                     0.71
Furfural, 2-Furancarboxaldehyde
                                     0.58
                                     1.79
5-methyl-2-furancarboxaldehyde, 5-methylfurfural
                                     0.76
                                     2.34
Isophthalaldehyde
                                       0
                                       0
4-hydroxy-3-methoxy-benzaldehyde, Vanillin
                                     0.70
                                     2.14

          Ketones
                                     9.44
                                     28.85
Acetol, 1-Hydroxy-2-propanone
                                     5.88
                                     17.96
2-Butanone, 1-Hydroxy-2-butanone
                                       0
                                       0
2-Cyclopenten-1-one, Cyclopentenone
                                     0.71
                                     2.16
2-Methyl-2-cyclopenten-1-one
                                     0.84
                                     2.58
2-Hydroxy-3-methyl-2-cyclopenten-1-one, Corylon
                                       0
                                       0
1-(4-Hydroxy-3-methoxyphenyl)-ethanone, Acetophenone, Acetovanillone
                                     2.01
                                     6.15

          PAH's
                                     3.30
                                     10.08
Naphthalene
                                     0.88
                                     2.68
1-Methylnaphthalene
                                     1.53
                                     4.69
Phenanthrene
                                       0
                                       0
Anthracene
                                     0.14
                                     0.44
2,7-Dimethyl-naphthalene
                                     0.52
                                     1.60
1,7-Dimethyl-naphthalene
                                     0.09
                                     0.27
1,4-Dimethyl-naphthalene
                                     0.08
                                     0.24
1,4.5-Trimethyl-naphthalene
                                       0
                                       0
1,4.6-Trimethyl-naphthalene
                                       0
                                       0
1,6.7-Trimethyl-naphthalene
                                     0.06
                                     0.17

          BTX
                                     6.62
                                     20.23
Benzene
                                     0.75
                                     2.28
Toluene
                                     3.73
                                     11.42
Xylene
                                     2.14
                                     6.53

          Other
                                     0.83
                                     2.55
Levoglucosan, 1'6-Anhydro-beta-D-glucopyranose
                                     0.83
                                     2.55

Total
                                     32.72
                                    100.00

Most of the chemical compounds reported in Aho et. al. 2008 are standard components in Aspen Plus.  Compounds not available in AspenPlus are represented by a similar compound in the same functional group.

3.3.2  Composition of product gas fraction
There is significant variation among literature sources regarding the total yield of the product gas fraction (non-condensable gases), but there is generally strong agreement regarding the composition of the product gas: it is almost entirely CO and CO2.  Lappas et. al. 2002 and Zhang et. al. 2009 provide the most detailed analysis of gas composition, therefore the composition of the gas product used in the Aspen model is calculated by averaging these two literature sources.  The yield of each product gas component is calculated by multiplying its composition by the total gas product yield as reported in Table 1 of this report.  Table 3 provides the composition and yields of the product gas.
 Table 3.  Yield and composition of gas product fraction in pyrolysis product.

Product Gas
                                     Yield
                             (wt% of dry biomass)
                                Gas Composition
                             (wt% of product gas)
CO
                                     5.93
                                     36.54
CO2
                                     7.86
                                     48.40
CH4
                                     0.40
                                     2.49
H2
                                     0.03
                                     0.18
C2H4
                                     0.49
                                     3.01
C2H6
                                     0.15
                                     0.92
C3H6
                                     0.33
                                     2.05
C3H8
                                     0.15
                                     0.95
NC4, n-Butane
                                     0.00
                                     0.00
C5's, n-Pentane
                                     0.53
                                     3.28
NC6's, n-Pentane
                                     0.35
                                     2.18
Sum/Total
                                     16.22
                                    100.00

3.3.3  Catalyst
All literature sources used to calculate the pyrolysis product composition use zeolite catalyst ZSM-5 (Lappas and Aho) or HZSM-5 (Zhang).  The purpose of the catalyst is to remove oxygen from the pyrolysis vapors after they have formed, but before they condense, potentially eliminating or reducing downstream hydroprocessing requirements.  The zeolite catalysts remove oxygen from the pyrolysis vapor mostly as water, but also as CO and CO2.  The reaction route for the catalytic conversion of pyrolysis vapors is presented in Zhang et. al. 2009, and is reproduced in Figure 3.  Primary (conventional) fast pyrolysis occurs just as in a non-catalytic environment.  The pyrolysis vapors are then catalytically cracked and partially deoxygenated before leaving the pyrolysis reactor.

   Figure 3.  Catalytic conversion of pyrolysis vapors (Zhang et. al. 2009)

3.4  Hydrotreating
Petroleum refineries generally use two stages of hydrotreating, as did the PNNL design report, therefore two stages are used in the catalytic pyrolysis model.  However, the product oil from catalytic pyrolysis may be sufficiently deoxygenated to require only one hydrotreating step.  More research into upgrading product oil from catalytic pyrolysis is necessary to confidently eliminate either hydrotreating step from the model.
The bio-oil is first pumped to 2500 psia, mixed with hydrogen, and heated to 240 °C (465 °F) before entering the first hydrotreater.  The product from the first hydrotreater is then heated to 371 °C (700 °F) in a furnace before entering the second hydrotreater, which operates at 2015 psia.  The furnace before the second hydrotreaters is fueled by natural gas and PSA tail gas from the hydrogen recovery section.  The hydrotreated oil contains less than 2% oxygen.  A block flow diagram of the hydrotreating area is presented in Figure 4.

Pump
Bio-Oil

1[st] Hydrotreater

2[nd] Hydrotreater
                                    Furnace
Natural Gas
Air
                             Exhaust to Wood Dryer
                                Heat Exchanger
H2
                               Upgraded Bio-Oil
                                     122 F
                                    30 psia
                                     175 F
                                   2500 psia
                                     465 F
                                   2500 psia
                                     483 F
                                   2500 psia
                                     700 F
                                   2500 psia
                                     700 F
                                   2015 psia
                                     426 F
                                   2015 psia
            Figure 4.  Block flow diagram of the hydrotreating area.

The main objective of hydrotreating is to remove oxygen, sulfur, nitrogen, olefins and metals (Parkash 2003).  In a petroleum refinery, hydrogen consumption is dominated by sulfur removal.  Pyrolysis oil, on the other hand, has much less sulfur but more oxygen.  Therefore, in this model the hydrogen consumption is dictated by oxygen removal.  The chemical hydrogen consumption in the hydrotreating section in the PNNL Fast Pyrolysis design report is 5.0 lb/100 lb of dry oil.  In the catalytic pyrolysis model the hydrogen consumption is reduced to 3.5 lb/lb of dry oil based on the reduced oxygen content in the oil.  It should be noted that the chemical hydrogen consumption includes only the hydrogen consumed in the hydrotreaters, but does not include hydrogen losses such as imperfect separation in the hydrogen recovery area.  The amount of hydrogen fed to the hydrotreaters is controlled to maintain a desired hydrogen partial pressure of 1200 psia (Parkash 2003) at the outlet of the second hydrotreater, which results in a large amount of unreacted hydrogen exiting the hydrotreaters.  Hydrogen production and recovery is explained in more detail in the hydrogen production section of this report.  A summary of the hydrotreating conditions is presented in Table 4.

                      Table 4.  Hydrotreating Conditions

Design Parameter
                           1[st] Stage Hydrotreater
                           2[nd] Stage Hydrotreater
Temperature, °C  (°F )
                                   240 (465)
                                   371 (700)
Pressure, psia
                                     2500
                                     2015
Total chemical hydrogen consumption, lb/100 lb dry bio-oil
                                     3.54

Currently no literature sources report the product composition of hydrotreated bio-oil derived from catalytic pyrolysis, therefore an estimation was made based on the composition reported in the PNNL Fast Pyrolysis design report, although molecules greater than C14 were excluded.  For example, in the PNNL fast pyrolysis design report, very large molecules such as diamantane (C18H24) are produced in the hydrotreating process.  In the catalytic pyrolysis AspenPlus model, the largest molecules entering the hydrotreating process are anthracene and phenanthrene (both C14H10), making large hydrotreating products such as diamantane unrealistic.  Therefore, the composition of the hydrotreating product in the AspenPlus model matches the composition of the hydrotreating product in the PNNL model, excluding products greater than C14.  The composition of the hydrotreating product in the PNNL Fast Pyrolysis design report is based on data from Elliot 2007 and Beckman et. al. 1990.  The hydrotreating product stream is then scaled to maintain overall mass balance, and the composition of the gas products (CO and CO2) are adjusted slightly to maintain overall element balances.  Admittedly this is not an ideal strategy for predicting the composition of the hydrotreating product, but until published results are available it provides a reasonable first estimate.

3.5  Separation
The upgraded bio-oil from the hydrotreating area is separated into off-gas, wastewater, and stabilized oil streams in a series of flash drums.  The off-gas is sent to the hydrogen recovery unit (HRU) where hydrogen is recovered and recycled to the hydrotreaters.   Anaerobic digestion can be used to treat the less than 2% organics in the wastewater (Jones et. al. 2009) although the anaerobic digestion is not modeled for this report.  If the anaerobic digestion is on-site, enough biogas can be produced to replace all the natural gas used as fuel (combusted), and about half the natural gas fed to the steam methane reformer (SMR) in the hydrogen production area.  Feeding biogas to a steam methane reformer is currently not practiced commercially, therefore it is not modeled for this report but is an attractive source of renewable methane and may be included in future design cases.
The upgraded bio-oil is further separated into light hydrocarbon (C4 and smaller), gasoline, and diesel streams in a series of distillation columns.  The first distillation column operates similar to a debutanizer in a petroleum refinery.  It removes all C4 and smaller components, which are used as fuel gas in the facility.   Most petroleum refineries separate C4 molecules from C3 and smaller molecules, then send the C4 stream to an alkylation unit to make iso-octane.  These additional separation and alkylation steps are economically justified only if the C4 components in the debutanizer distillate stream are produced in very large volumes.  For this model, the distillate stream from the debutanizer is small enough that further separation and alkylation is probably not economically justified, therefore it is simply used as fuel gas elsewhere in the conversion facility.  This assumption has not been tested, but may be the subject of a sensitivity study in further work.
The liquid product from the debutanizer is sent to a second distillation column, the naphtha splitter, where gasoline range components are separated from heavier diesel range components.  Both gasoline and diesel are sent to product storage.
In the non-catalytic PNNL Fast Pyrolysis design, components heavier than diesel require hydrocracking and an additional separation column.  This highlights one of the advantages of catalytic pyrolysis:  the heavy (greater than diesel range) components are eliminated or reduced to very small amounts, eliminating the need for hydrocracking, although it should again be noted there is very little published research dedicated to upgrading bio-oil from catalytic pyrolysis.  Eliminating the hydrocracking step in this model is a design assumption based on the composition of pyrolysis oil entering the hydrotreating section.
Another consequence of the lack of published data is confidence in the composition and yield of the final products in the AspenPlus model.  The yields of the catalytic pyrolysis step are based on literature values, therefore there is more confidence in the overall volumetric yields of gasoline and diesel than in the composition of the gasoline and diesel products.  The final products are gasoline and diesel blendstock, which will need to be blended with blendstocks from other refineries to achieve desired gasoline and diesel characteristics.

3.6  Hydrogen Production and Recovery
As explained in the separations section, the upgraded bio-oil leaving the hydrotreating area is separated into off-gas, wastewater, and stabilized oil streams in a series of flash drums.  The off-gas is sent to the hydrogen recovery unit (HRU) where excess hydrogen is recovered and recycled to the hydrotreaters.   Makeup hydrogen is produced via steam methane reforming and pressure swing adsorption (PSA) separation.  The hydrogen recovery and hydrogen production areas are not modeled in detail, but rather are modeled based on design rules taken from literature (Parkesh 2003 for hydrogen recovery; Spath and Mann 2001 for hydrogen production).  For the hydrogen recovery area, utilities such as natural gas consumed as fuel and feed, and electricity and steam demand are scaled based on the amount of hydrogen entering the hydrogen recovery area.  For hydrogen production, the utilities are based on the amount of makeup hydrogen produced.  Figure 5 (reproduction of Figure 1) illustrates the integration of the hydrogen recovery and hydrogen production areas into the rest of the model.  Figure 6 is a block flow diagram of the hydrogen production area (Spath and Mann 2001).  Tables 5 and 6 provide utility demands and operating parameters for the hydrogen recovery area and hydrogen production area, respectively.
                                    Biomass
                           Drying and Size Reduction
                                  Dry Biomass
                           Catalytic Fast Pyrolysis
                                    Bio-Oil
                                Hydroprocessing
                                UpgradedBio-Oil
                                  Separation
                                   Gasoline
                                    Diesel
                                     Water
                            Hydrogen Recovery Unit
                              Hydrogen Production
Natural Gas
                                      H2
                                      H2
 PSA Tail Gas
                                   Flue Gas
                              Combustion Exhaust
                              Combustion Exhaust
                                   Flue Gas
 H2-Rich Fuel Gas

                 Figure 5.  Block flow diagram of the process.

 Table 5.  Hydrogen recovery area utility demands and performance data (Parkesh 2003).

Design Parameter
                                     Data
Electricity demand, kWhr per ton of feed
                                     1.08
Steam demand, mmBtu per ton of feed
                                     2.25
Cooling water, gallons per ton of feed
                                    13,240
Hydrogen recovery, percent of H2 in feed
                                      83%
Product hydrogen purity
                                   > 99%

                               Natural Gas Fuel
                         Steam-Methane Reformer (SMR)
                             Natural Gas Feedstock
                                 Hydrogenation
                                  PSA Offgas
                                    ZnO Bed
                         High Temperature Shift (HTS)
                                     Steam
                                     Water
                        Pressure Swing Adsorption (PSA)
                                      H2
                                      H2
                          Low Temperature Shift (LTS)
                                     Steam
                                   Flue Gas

Figure 6.  Block flow diagram of the hydrogen production area (Spath and Mann, 2001).

       Table 6.  Hydrogen Production Plant Data (Spath and Mann, 2001).

Design Parameter
                                     Data
Electricity demand, kWhr/lb H2
                                     0.14
Steam demand, lb/lb H2, @380 psi
                                      9.6
Steam demand production, lb/lb H2, @700 psi
                                     13.8
Natural gas consumed as fuel, lb/lb H2
                                     0.32
Natural gas consumed as feed, lb/lb H2
                                     2.91
Product hydrogen purity
                                   > 99%

3.7  Utilities: Steam and Power Production, Cooling Water
Char and product gas from the pyrolysis step are combusted to generate steam in a waste heat boiler.  Excess steam is also generated in the hydrogen production area.  The steam is then used to generate electricity in a steam turbine, with excess electricity that can be sold to the grid.  The major consumers of electricity are wood grinding in the feed handling area, the air blower for the char combustor, and hydrogen compression steps in the hydrotreating area.  Other consumers of electricity are the electrostatic precipitator and pumps for boiler water, cooling water, bio-oil and fuel product.  An estimate of 700 kW for miscellaneous power usage, such as lighting and administrative areas, is added (Phillips et. al. 2007).
Cooling water is used to condense boiler water and cool raw pyrolysis oil.  Cooling water is supplied to the process at 90°F, and returns to the cooling tower at 110°F.  The cooling tower is not modeled in detail, although the power requirements for pumps and fans are estimated using design equations.
Natural gas is consumed as feed and fuel in the hydrogen production area, and also as furnace fuel in the hydrotreating area.  Table 7 provides utility performance and operating data for electricity, water, and natural gas.

               Table 7.  Utility performance and operating data.

Design Parameter
                                     Data
Excess electricity produced, kWhr/gal fuel product
                                     0.48
Boiler water makeup rate, gal/gal fuel product
                                      0.1
Cooling water makeup rate, gal/gal fuel product
                                      6.1
Total water makeup rate, gal/gal fuel product
                                      6.2
Natural gas consumed as fuel for H2 production, scf/gal fuel product
                                      4.7
Natural gas consumed as feed for H2 production, scf/gal fuel product
                                     42.4
Natural gas consumed as fuel for hydrotreater furnace, scf/gal fuel product
                                      4.8
Total natural gas consumed, scf/gal fuel product
                                     51.9

As can be seen in Table 7, excess electricity is produced although the total water makeup rate is high.  In future revisions of the model, water cooling can be substituted with air cooling (powered by electric fans), which will result in less excess electricity but reduced water demand.

4.  Conclusions and Recommendations
AspenPlus is used to model catalytic fast pyrolysis for gasoline and diesel production.  Product yields and utility demands are estimated, although no economic analysis is performed.  A summary of the process yields and efficiencies is presented in Table 8.  Key findings of the analysis include:
   * Catalytic fast pyrolysis produces less bio-oil but more water, gas, and char than conventional, non-catalytic fast pyrolysis.
   * Catalytically produced pyrolysis oil is partially deoxygenated, which results in less hydrogen required for upgrading.  The chemical hydrogen consumption required to upgrade bio-oil derived from catalytic fast pyrolysis is 3.5 lb/lb of dry bio-oil, compared to 5.0 lb/lb of dry bio-oil for non-catalytic fast pyrolysis oil.
   * Non-catalytic fast pyrolysis produces bio-oil conducive to manufacturing mostly diesel and jet fuel range transportation fuels, with some gasoline-range product.  Conversely, catalytic fast pyrolysis produces bio-oil with a composition slightly more favorable to manufacturing gasoline.  In the AspenPlus model, 54% of the final product is gasoline.
   * Due to very limited amount of published data on catalytic fast pyrolysis, particularly upgrading bio-oil produced from catalytic fast pyrolysis, there is a great deal of uncertainty regarding the composition of the final products.
   * The composition of the bio-oil suggests hydrocracking is not necessary.  According to literature sources, bio-oil produced from catalytic fast pyrolysis is comprised of molecules in the diesel range and smaller.
   * The major electricity consumers are wood grinding in the feed handling area, the combustion air blower for the char combustor, and hydrogen compression steps in the hydrotreating area, although excess electricity is produced and can be sold to the electric grid.
   * Because hydrogen is required for upgrading, natural gas is purchased for use as fuel and feed for hydrogen production and recovery, therefore the facility is not free of fossil fuel consumption, as is the case in biomass gasification followed by mixed alcohol synthesis (Phillips et. al. 2007).

            Table 8.  Overall plant performance and operating data.

Design Parameter
                                     Data
Gasoline blendstock yield, gallons/ton of biomass
                                     34.8
Diesel blendstock yield, gallons/ton of biomass
                                     29.7
Total fuel product yield, gallons/ton of biomass
                                     64.5
Gasoline blendstock yield, mmBtu/ton of biomass
                                      4.2
Diesel blendstock yield, mmBtu/ton of biomass
                                      4.1
Total fuel product yield, mmBtu/ton of biomass
                                      8.3
Gasoline blendstock heating value, mmBtu/gal
                                     0.12
Diesel blendstock heating value, mmBtu/gal
                                     0.14
Total fuel product (weighted average), mmBtu/gal
                                     0.13
Electricity produced, kWhr/gal fuel product
                                      0.48
Total water makeup rate, gal/gal fuel product
                                      6.2
Natural gas combusted, scf/gal fuel product
                                      9.5
Total natural gas consumed, scf/gal fuel product
                                     51.9
Overall plant efficiency, LHV%
                                     46.5
Overall plant efficiency (w/out excess electricity), LHV%
                                     45.9

To achieve higher confidence in the results, more research into catalytic fast pyrolysis and upgrading bio-oil derived from catalytic fast pyrolysis is needed.  Additional data from laboratory experiments will help, although data from continuous bench or pilot scale operations would be ideal.
 Sensitivity analysis on several process variables can be explored:
   * Size reduction of the incoming biomass consumes a very large amount of electricity, therefore understanding the power curves and the maximum particle size required is crucial to correctly estimating and minimizing the power required.
   * Hydrogen is separated from other components (CO, CO2, etc.) in the hydrogen recovery area, although the pressure is reduced and later must be re-pressurized.  If the hydrogen remains at hydrotreating pressures and is simply recycled, with a purge stream to prevent buildup of CO and CO2, the energy-intensive compression step can be eliminated, but at the expense of less pure hydrogen.  Refineries often operate in this configuration.
Also, an economic analysis of the process will provide a first estimate of minimum selling price, as well as identify opportunities and areas of focus for cost reduction.

5.  References
Aho et. al. 2008.  "Catalytic pyrolysis of woody biomass in a fluidized bed reactor: Influence of zeolite structure".  Aho, A.; N. Kumar; K. Eranen; T. Salmi; M. Hupa; D. Yu. Murzin.  Fuel 87 (2008) 2493-2501.
Beckman et. al. 1990.  "Techno-economic Assessment of Selected Biomass Liquefaction Processes".  Beckman, D; D.C. Elliot; B. Gevert; C. Hornel; B. Kjellstrom; A. Ostman; Y. Solantausta; V. Tulnheimo.  Research Report 697, VTT Technical Research Centre of Finland.
Elliot 2007.  "Historical Developments in Hydrotreating Bio-Oils".  Elliot, D.C.  Energy and Fuels 2007, 21, 1792-1815.
French and Czernik 2008.  "Catalytic pyrolysis of biomass for fuels production".  French, Rick;  Stefan Czernik.  Fuel Processing Technology 91 (2010) 25-32.
Lappas et. al. 2002.  "Biomass pyrolysis in a circulating fluid bed reactor for the production of fuels and chemicals".  Lappas, A.A.; M.C. Samolada; D.K. Iatridis; S.S. Voutetakis; I.A. Vasalos.  Fuel 81 (2002) 2087-2095.
Parkash 2003. "Refining Process Handbook".  Pakash, Surinder.  Gulf Professional Publishing/Elsevier, Burlington, MA.  2003.
Phillips et. al. 2007.  "Thermochemical Ethanol via Indirect Gasification and Mixed Alcohol Synthesis of Lignocellulosic Biomass", Phillips, S.; A. Aden; J. Jechura; D. Dayton; T. Eggeman.  April 2007.  NREL Technical Report NREL/TP-510-41168.
Jones et. al. 2009.  "Production of Gasoline and Diesel from Biomass via Fast Pyrolysis; Hydrotreating and Hydrocracking: A Design Case".  Jones, SB; C. Valkenburg; C. Walton; D.C. Elliot; J.E. Holladay; D.J. Stevens; C. Kinchin; and S. Czernik.  Pacific Northwest National Laboratory Report PNNL-18284 Rev. 1.  February 2009.  http://www.pnl.gov/main/publications/external/technical_reports/PNNL-18284.pdf
Ringer et. al. 2006.  "Large-Scale Pyrolysis Oil Production: A Technology Assessment and Economic Analysis".  Ringer, M.; V. Putsche; J. Scahill.  NREL Technical Report NREL/TP-510-37779.  November 2006.  http://www.nrel.gov/docs/fy07osti/37779.pdf
Spath and Mann 2001.  "Life Cycle Analysis of Hydrogen Production via Natural Gas Steam Reforming".  Spath, P. L.; M. K. Mann.  National Renewable Energy Laboratory Technical Report NREL/TP-570-27637.  February 2001.  http://www.nrel.gov/docs/fy01osti/27637.pdf
Zhang et. al. 2009.  "Comparison of non-catalytic and catalytic fast pyrolysis of corncob in a fluidized bed reactor".  Zhang, Huiyan; Rui Xiao; He Huang; and Gang Xiao;  Bioresource Technology 100 (2009) 1428-1434.


[Federal Register: December 24, 2008 (Volume 73, Number 248)]
[Rules and Regulations]
[Page 78991-78994]
[DOCID:fr24de08-21]

=======================================================================
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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 3

[EPA-HQ-OEI-2003-0001; FRL-8757-2]

Extension of Cross-Media Electronic Reporting Rule Deadline for
Authorized Programs

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

-----------------------------------------------------------------------

SUMMARY: EPA is amending the Final Cross-Media Electronic Reporting
Rule (CROMERR) deadline for authorized programs (states, tribes, or
local governments) with existing electronic document receiving systems
to submit an application for EPA approval to revise or modify their
authorized programs. This action will extend the current October 13,
2008, deadline until January 13, 2010.

DATES: This rule is effective on December 24, 2008.

ADDRESSES: The public record for this rulemaking has been established
under Docket ID No. EPA-HQ-OEI-2003-0001, and may be accessed online at
http://www.regulations.gov. Docket materials are also available in hard
copy at the CROMERR Docket, EPA/DC, EPA West, Room 3334, 1301
Constitution Avenue, NW., Washington, DC. The Public Reading Room is
open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding
legal holidays. The telephone number for the Public Reading Room is
(202) 566-1744, and the telephone number for the CROMERR Docket is
(202) 566-1752.
    For additional information about EPA's public docket visit the EPA
Docket Center homepage at http://www.epa.gov/epahome/dockets.htm.

FOR FURTHER INFORMATION CONTACT: Evi Huffer, Office of Environmental
Information (2823T), Environmental Protection Agency, 1200 Pennsylvania
Avenue, NW., Washington, DC 20460;<PHONE_NUMBER><EMAIL_ADDRESS>
or David Schwarz, Office of Environmental Information (2823T),
Environmental Protection Agency, 1200 Pennsylvania Avenue, NW.,
Washington, DC 20460;<PHONE_NUMBER><EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION:

I. What Does This Rule Do?

    This rule provides temporary regulatory relief to states, tribes,
and local governments with ``authorized programs'' as defined in 40
Code of Federal Regulations (CFR) 3.3. Any such authorized program that
operates an

``existing electronic document receiving system'' as defined in 40 CFR
3.3 will have an additional 15 months to submit an application to
revise or modify its authorized program to meet the requirements of 40
CFR Part 3. Specifically, this final rule amends 40 CFR 3.1000(a)(3) by
extending the October 13, 2008, deadline to January 13, 2010.

II. Why Is EPA Taking This Action?

    EPA published a notice of proposed rulemaking on October 17, 2008
(73 FR 61773). As discussed in that proposal, after setting the current
deadline, EPA learned that some states and local agencies currently
working to comply with CROMERR have experienced an unanticipated delay
in the completion of necessary upgrades to their electronic document
receiving systems. EPA believes it is appropriate to extend the
submission deadline for applications related to existing systems by an
additional 15 months.

III. Response to Comments

    EPA received two comments on the proposed rule. The comments
opposed the extension of the application deadline on the basis that the
extension would prevent enforcement of environmental laws. The
commenters stated that states, tribes, and local governments have had
sufficient time to submit applications. One commenter noted that those
states who were not able to meet the October 13, 2008 deadline could
apply for case-by-case extensions.
    EPA's Response:
    EPA disagrees that the extension will prevent enforcement of
environmental laws. As noted in both comments, CROMERR does not require
that states comply with CROMERR by the deadline, but rather directs
them to submit an application to EPA. The mere submission of an
application under CROMERR does not materially impact the enforceability
of environmental programs. In the three years since CROMERR was issued,
EPA has been working closely with states, tribes, and local
governments. While some states and local agencies submitted their
applications before the deadline, other states and local agencies have
been working on completing the necessary upgrades to their electronic
document receiving systems before submitting their application. EPA
believes that requiring states, tribes, and local agencies to file an
incomplete or inadequate application just to meet a regulatory deadline
would be a waste of resources, both for EPA and the state, tribe, or
local agency. Further, some states, tribes, or local agencies may not
qualify for the CROMERR case-by-case extension because it applies only
where the ``state, tribe, or local government needs additional time to
make legislative or regulatory changes. * * *'' EPA believes extension
of the deadline until January 13, 2010, appropriately balances the
purposes of the CROMERR standards and the legitimate need of states,
tribes, and local governments to have additional time to complete the
necessary upgrades to their systems and submit complete applications.

IV. Does This Action Apply to Me?

    This action will affect states, tribes, and local governments that
have an authorized program as defined in 40 CFR 3.3 and also have an
existing electronic document receiving system, as defined in 40 CFR
3.3. For purposes of this rulemaking, the term ``state'' includes the
District of Columbia and the United States territories, as specified in
the applicable statutes. That is, the term ``state'' includes the
District of Columbia, the Commonwealth of Puerto Rico, the Virgin
Islands, Guam, American Samoa, the Commonwealth of Northern Marina
Islands, and the Trust Territory of the Pacific Islands, depending on
the statute.

------------------------------------------------------------------------
           Category                  Examples of affected entities
------------------------------------------------------------------------
Local government.............  Publicly owned treatment works, owners
                                and operators of treatment works
                                treating domestic sewage, local and
                                regional air boards, local and regional
                                waste management authorities, and
                                municipal and other drinking water
                                authorities.
Tribe and State governments..  States, tribes or territories that
                                administer any federal environmental
                                programs delegated, authorized, or
                                approved by EPA under Title 40 of the
                                CFR.
------------------------------------------------------------------------

    This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be affected by this
action. If you have questions regarding the applicability of this
action to a particular entity, consult the person listed in the
preceding FOR FURTHER INFORMATION CONTACT section.

V. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

    This action is not a ``significant regulatory action'' under the
terms of Executive Order 12866 (58 FR 51735, October 4, 1993) and is,
therefore, not subject to review under the EO.

B. Paperwork Reduction Act

    This action does not impose any new information collection burden.
This action merely extends the current due date for submitting
applications under CROMERR for authorized programs with existing
electronic document receiving systems, and imposes no additional
requirements. However, the Office of Management and Budget (OMB) has
previously approved the information collection requirements contained
in the existing regulations (40 CFR Part 3) under the provisions of the
Paperwork Reduction Act, 44 U.S.C. 3501 et seq. and has assigned OMB
control number 2025-0003, EPA ICR number 2002.04. The OMB control
numbers for EPA's regulations in 40 CFR are listed in 40 CFR Part 9.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements under the Administrative
Procedure Act or any other statute unless the agency certifies that the
rule will not have a significant economic impact on a substantial
number of small entities. Small entities include small businesses,
small organizations, and small governmental jurisdictions.
    For purposes of assessing the impacts of this final rule on small
entities, a small entity is defined as: (1) A small business that meets
the definition for small businesses based on SBA size standards at 13
CFR 121.201; (2) a small governmental jurisdiction that is a government
of a city, county, town, school district or special district with a
population of less than 50,000 (Under the RFA definition, States and
tribal governments are not considered small governmental
jurisdictions.); and (3) a small organization that is any not-for-
profit enterprise which is independently owned and operated and is not
dominant in its field.
    After considering the possibility of economic impacts of today's
final rule on small entities, I certify that this

action will not have a significant economic impact on a substantial
number of small entities. The small entities directly regulated by this
final rule are small governmental jurisdictions. In determining whether
a rule has a significant economic impact on a substantial number of
small entities, the impact of concern is any significant adverse
economic impact on small entities, since the primary purpose of the
regulatory flexibility analyses is to identify and address regulatory
alternatives ``which minimize any significant economic impact of the
rule on small entities.'' 5 U.S.C. 603 and 604. Thus, an agency may
certify that a rule will not have a significant economic impact on a
substantial number of small entities if the rule relieves regulatory
burden, or otherwise has a positive economic effect on all of the small
entities subject to the rule.
    This final rule merely extends the current regulatory schedule for
submitting applications under CROMERR for authorized programs with
existing electronic document receiving systems. EPA has therefore
concluded that today's final rule will relieve regulatory burden for
all affected small entities.

D. Unfunded Mandates Reform Act

    This action contains no Federal mandates under the provisions of
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C.
1531-1538 for state, tribe, or local governments or the private sector.
This action merely extends the current due date for submitting
applications under CROMERR for authorized programs with existing
electronic document receiving systems, and imposes no additional
requirements. EPA has determined that this rule does not contain a
federal mandate that may result in expenditures of $100 million or more
for states, tribes, and local governments, in the aggregate, or the
private sector in any one year. Thus, today's action is not subject to
the requirements of sections 202 and 205 of UMRA.
    This action is also not subject to the requirements of section 203
of UMRA because it contains no regulatory requirements that might
significantly or uniquely affect small governments. This action merely
extends the current due date for submitting applications under CROMERR
for authorized programs with existing electronic document receiving
systems, and imposes no additional requirements.

E. Executive Order 13132: Federalism

    Executive Order 13132, entitled ``Federalism'' (64 FR 43255, August
10, 1999), requires EPA to develop an accountable process to ensure
``meaningful and timely input by State and local officials in the
development of regulatory policies that have federalism implications.''
``Policies that have federalism implications'' is defined in the
Executive Order to include regulations that have ``substantial direct
effects on the States, on the relationship between the national
government and the States, or on the distribution of power and
responsibilities among the various levels of government.''
    This action does not have federalism implications. It will not have
substantial direct effects on the states, on the relationship between
the national government and the states, or on the distribution of power
and responsibilities among the various levels of government, as
specified in Executive Order 13132. This action merely extends the
current due date for submitting applications under CROMERR for
authorized programs with existing electronic document receiving
systems, and imposes no additional requirements. Thus, Executive Order
13132 does not apply to this rule.

F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments

    This action does not have tribal implications, as specified in
Executive Order 13175 (65 FR 67249, November 9, 2000). It will neither
impose substantial direct compliance costs on tribal governments, nor
preempt Tribal law. This action merely extends the current due date for
submitting applications under CROMERR for authorized programs with
existing electronic document receiving systems, and imposes no
additional requirements. Thus, Executive Order 13175 does not apply to
this action.

G. Executive Order 13045: Children's Health Protection

    Executive Order 13045, Protection of Children from Environmental
Health Risks and Safety Risks (62 FR 19885, April 23, 1997) applies to
any rule that (1) is determined to be ``economically significant'' as
defined under Executive Order 12866, and (2) concerns an environmental
health or safety risk that EPA has reason to believe may have a
disproportionate effect on children. If the regulatory action meets
both criteria, the Agency must evaluate the environmental health or
safety effects of the planned rule on children, and explain why the
planned regulation is preferable to other potentially effective and
reasonably feasible alternatives considered by the Agency. EPA
interprets Executive Order 13045 as applying only to those regulatory
actions that are based on health or safety risks, such that the
analysis required under section 5-501 of the Order has the potential to
influence the regulation.
    This final rule is not subject to Executive Order 13045 because it
is not an economically significant action as defined by Executive Order
12866 and it does not establish an environmental standard intended to
mitigate health or safety risks. This action merely extends the current
regulatory schedule for submitting applications under CROMERR for
authorized programs with existing electronic document receiving
systems, and imposes no additional requirements.

H. Executive Order 13211: Energy Effects

    This rule is not subject to Executive Order 13211, ``Actions
Concerning Regulations That Significantly Affect Energy Supply,
Distribution, or Use'' (66 FR 28355 (May 22, 2001)) because it is not a
significant regulatory action under Executive Order 12866.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (NTTAA), Public Law 104-113, section 12(d) (15 U.S.C. 272
note) directs EPA to use voluntary consensus standards in its
regulatory activities unless to do so would be inconsistent with
applicable law or otherwise impractical. Voluntary consensus standards
are technical standards (e.g., materials specifications, test methods,
sampling procedures, and business practices) that are developed or
adopted by voluntary consensus standards bodies. The NTTAA directs EPA
to provide Congress, through OMB, with explanations when the Agency
decides not to use available and applicable voluntary consensus
standards.
    Today's action does not involve technical standards. EPA's
compliance with section 12(d) of the National Technology Transfer and
Advancement Act of 1995 (Public Law 104-113, section 12(d) (15 U.S.C.
272 note)) has been addressed in the preamble of the underlying final
rule (70 FR 59848, October 13, 2007).

J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations

    Executive Order 12898 (59 FR 7629 (Feb. 16, 1994)) establishes
federal executive policy on environmental justice. Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the United States.
    EPA has determined that this final rule will not have
disproportionately high and adverse human health or environmental
effects on minority or low-income populations because it does not
affect the level of protection provided to human health or the
environment. This final rule merely extends the current regulatory
schedule for submitting applications under CROMERR for authorized
programs with existing electronic document receiving systems.

K. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement Fairness Act of 1996, generally
provides that before a rule may take effect, the agency promulgating
the rule must submit a rule report, which includes a copy of the rule,
to each House of the Congress and to the Comptroller General of the
United States. EPA will submit a report containing this rule and other
required information to the U.S. Senate, the U.S. House of
Representatives, and the Comptroller General of the United States prior
to publication of the rule in the Federal Register. A major rule cannot
take effect until 60 days after it is publishedin the Federal Register.
This action is not a ``major rule'' as defined by 5 U.S.C. 804(2). This
rule will become effective on December 24, 2008.

List of Subjects in 40 CFR Part 3

    Environmental protection, Conflict of interests, Electronic
records, Electronic reporting requirements, Electronic reports,
Intergovernmental relations.

    Dated: December 19, 2008.
Stephen L. Johnson,
Administrator.

0
Therefore, title 40 chapter I of the Code of Federal Regulations is
amended as follows:

PART 3--ELECTRONIC REPORTING

0
1. The authority citation for Part 3 continues to read as follows:

    Authority: 7 U.S.C. 136 to 136y; 15 U.S.C. 2601 to 2692; 33
U.S.C. 1251 to 1387; 33 U.S.C. 1401 to 1445; 33 U.S.C. 2701 to 2761;
42 U.S.C. 300f to 300j-26; 42 U.S.C. 4852d; 42 U.S.C. 6901-6992k; 42
U.S.C. 7401 to 7671q; 42 U.S.C. 9601 to 9675; 42 U.S.C. 11001 to
11050; 15 U.S.C. 7001; 44 U.S.C. 3504 to 3506.

Subpart D--Electronic Reporting Under EPA-Authorized State, Tribe,
and Local Programs

0
2. Section 3.1000 is amended by revising paragraph (a)(3) to read as
follows:

Sec.  3.1000  How does a state, tribe, or local government revise or
modify its authorized program to allow electronic reporting?

    (a) * * *
    (3) Programs already receiving electronic documents under an
authorized program: A state, tribe, or local government with an
existing electronic document receiving system for an authorized program
must submit an application to revise or modify such authorized program
in compliance with paragraph (a)(1) of this section no later than
January 13, 2010. On a case-by-case basis, this deadline may be
extended by the Administrator, upon request of the state, tribe, or
local government, where the Administrator determines that the state,
tribe, or local government needs additional time to make legislative or
regulatory changes in order to meet the requirements of this part.
* * * * *
 [FR Doc. E8-30680 Filed 12-23-08; 8:45 am]

BILLING CODE 6560-50-P


[Federal Register Volume 87, Number 156 (Monday, August 15, 2022)]
[Rules and Regulations]
[Pages 49991-49993]
[FR Doc No: 2022-17478]

-----------------------------------------------------------------------

DEPARTMENT OF HOMELAND SECURITY

Coast Guard

33 CFR Part 117

[Docket No. USCG-2022-0015]
RIN 1625-AA09

Drawbridge Operation Regulation; Grand Canal, Indian Harbour
Beach, FL

AGENCY: Coast Guard, Department of Homeland Security (DHS).

ACTION: Final rule.

-----------------------------------------------------------------------

SUMMARY: The Coast Guard is changing the operating schedule that
governs the Lansing Island Bridge across Grand Canal, mile 0.7 at
Indian Harbour Beach, FL. A request was made to the Coast Guard to
allow the drawbridge to remain closed to navigation and untended during
the overnight hours due to a lack of requested openings.

DATES: This rule is effective September 14, 2022.

ADDRESSES: To view documents mentioned in this preamble as being
available in the docket, go to https://www.regulations.gov. Type the
docket number USCG-2022-0015 in the ``SEARCH'' box and click
``SEARCH''. In the Document Type column, select ``Supporting & Related
Material.''

FOR FURTHER INFORMATION CONTACT: If you have questions on this rule,
call or email Ms. Jennifer Zercher, Bridge Management Specialist,
Seventh Coast Guard District, telephone<PHONE_NUMBER>, email
[email protected].

SUPPLEMENTARY INFORMATION:

I. Table of Abbreviations

CFR Code of Federal Regulations
DHS Department of Homeland Security
FR Federal Register
OMB Office of Management and Budget
NPRM Notice of Proposed Rulemaking (Advance, Supplemental)
Sec.  Section
U.S.C. United States Code
FL Florida

II. Background Information and Regulatory History

    On February 1, 2022, the Coast Guard published a Test Deviation,
with a request for comments, entitled Drawbridge Operation Regulation;
Grand Canal, Indian Harbour Beach, FL in the Federal Register (87 FR
5401), to test this operating schedule for the Lansing Island Bridge.
Zero comments were received during the test period.
    On June 2, 2022, the Coast Guard published a Notice of Proposed
Rulemaking entitled Drawbridge Operation Regulation; Grand Canal,
Indian Harbour Beach, FL, in the Federal Register (87 FR 33460). There
we stated why we issued the NPRM, and invited comments on our proposed
regulatory action related to this regulatory change. During the comment
period that ended July 5, 2022, we received zero comments.

III. Legal Authority and Need for Rule

    The Coast Guard is issuing this rule under authority 33 U.S.C. 499.
    The Lansing Island Bridge across Grand Canal, mile 0.7, at Indian
Harbour Beach, FL, is a single-leaf bascule bridge with a 16-foot
vertical clearance at mean high water in the closed position. The
normal operating schedule for the bridge is set forth in 33 CFR
117.285(a). Navigation on the waterway consists mainly of recreational
mariners.

    The bridge owner, Lansing Island Homeowners Association, Inc.
requested the Coast Guard consider allowing the drawbridge to remain
closed to navigation and untended during the overnight hours due to a
lack of requested openings. We requested a copy of the bridge logs from
January 1, 2021, through November 30, 2021. After reviewing the logs,
the Coast Guard found the drawbridge provided three openings between
the hours of 10 p.m. and 6 a.m. Two channels provide alternate access
to Grand Canal. Vessels that can pass beneath the bridge without an
opening may do so at any time.

IV. Discussion of Comments, Changes and the Final Rule

    The Coast Guard provided two comment periods totaling 90 days and
received zero comments.

V. Regulatory Analyses

    We developed this rule after considering numerous statutes and
Executive Orders related to rulemaking. Below we summarize our analyses
based on a number of these statutes and Executive Orders.

A. Regulatory Planning and Review

    Executive Orders 12866 and 13563 direct agencies to assess the
costs and benefits of available regulatory alternatives and, if
regulation is necessary, to select regulatory approaches that maximize
net benefits. This rule has not been designated a ``significant
regulatory action,'' under Executive Order 12866. Accordingly, it has
not been reviewed by the Office of Management and Budget (OMB).
    This regulatory action determination is based on the ability that
vessels capable of transiting under the bridge, without an opening, may
do so at any time and alternate routes for vessels to transit Grand
Canal are available.

B. Impact on Small Entities

    The Regulatory Flexibility Act of 1980 (RFA), 5 U.S.C. 601-612, as
amended, requires federal agencies to consider the potential impact of
regulations on small entities during rulemaking. The term ``small
entities'' comprises small businesses, not-for-profit organizations
that are independently owned and operated and are not dominant in their
fields, and governmental jurisdictions with populations of less than
50,000. The Coast Guard received zero comments from the Small Business
Administration on this rule. The Coast Guard certifies under 5 U.S.C.
605(b) that this rule will not have a significant economic impact on a
substantial number of small entities.
    While some owners or operators of vessels intending to transit the
bridge may be small entities, for the reasons stated in section V.A
above, this rule will not have a significant economic impact on any
vessel owner or operator.
    Under section 213(a) of the Small Business Regulatory Enforcement
Fairness Act of 1996 (Pub. L. 104-121), we want to assist small
entities in understanding this rule. If the rule would affect your
small business, organization, or governmental jurisdiction and you have
questions concerning its provisions or options for compliance, please
contact the person listed in the FOR FURTHER INFORMATION CONTACT
section.
    Small businesses may send comments on the actions of Federal
employees who enforce, or otherwise determine compliance with, Federal
regulations to the Small Business and Agriculture Regulatory
Enforcement Ombudsman and the Regional Small Business Regulatory
Fairness Boards. The Ombudsman evaluates these actions annually and
rates each agency's responsiveness to small business. If you wish to
comment on actions by employees of the Coast Guard, call 1-888-REG-FAIR
(1-888-734-3247). The Coast Guard will not retaliate against small
entities that question or complain about this rule or any policy or
action of the Coast Guard.

C. Collection of Information

    This rule calls for no new collection of information under the
Paperwork Reduction Act of 1995 (44 U.S.C. 3501-3520).

D. Federalism and Indian Tribal Government

    A rule has implications for federalism under Executive Order 13132,
Federalism, if it has a substantial direct effect on the States, on the
relationship between the National Government and the States, or on the
distribution of power and responsibilities among the various levels of
government. We have analyzed this rule under that Order and have
determined that it is consistent with the fundamental federalism
principles and preemption requirements described in Executive Order
13132.
    Also, this rule does not have tribal implications under Executive
Order 13175, Consultation and Coordination with Indian Tribal
Governments, because it does not have a substantial direct effect on
one or more Indian tribes, on the relationship between the Federal
Government and Indian tribes, or on the distribution of power and
responsibilities between the Federal Government and Indian tribes.

E. Unfunded Mandates Reform Act

    The Unfunded Mandates Reform Act of 1995 (2 U.S.C. 1531-1538)
requires Federal agencies to assess the effects of their discretionary
regulatory actions. In particular, the Act addresses actions that may
result in the expenditure by a State, local, or tribal government, in
the aggregate, or by the private sector of $100,000,000 (adjusted for
inflation) or more in any one year. Though this rule will not result in
such an expenditure, we do discuss the effects of this rule elsewhere
in this preamble.

F. Environment

    We have analyzed this rule under Department of Homeland Security
Management Directive 023-01, Rev.1, associated implementing
instructions, and Environmental Planning Policy COMDTINST 5090.1
(series) which guide the Coast Guard in complying with the National
Environmental Policy Act of 1969 (NEPA) (42 U.S.C. 4321-4370f). The
Coast Guard has determined that this action is one of a category of
actions that do not individually or cumulatively have a significant
effect on the human environment. This rule promulgates the operating
regulations or procedures for drawbridges and is categorically excluded
from further review, under paragraph L49, of Chapter 3, Table 3-1 of
the U.S. Coast Guard Environmental Planning Implementation Procedures.
    Neither a Record of Environmental Consideration nor a Memorandum
for the Record are required for this rule.

List of Subjects in 33 CFR Part 117

    Bridges.

    For the reasons discussed in the preamble, the Coast Guard amends
33 CFR part 117 as follows:

PART 117--DRAWBRIDGE OPERATION REGULATIONS

0
1. The authority citation for part 117 continues to read as follows:

    Authority:  33 U.S.C. 499; 33 CFR 1.05-1; and Department of
Homeland Security Delegation No. 0170.1.

0
2. Amend Sec.  117.285 by revising paragraph (a) to read as follows:

Sec.  117.285  Grand Canal.

    (a) The draw of the Lansing Island Bridge, mile 0.7, at Indian
Harbour Beach, shall open on signal, except that from 10 p.m. to 6
a.m., daily, the draw need not open for the passage of vessels and will
be untended.
* * * * *

    Dated: August 1, 2022.
Brendan C. McPherson,
Rear Admiral, U.S. Coast Guard, Commander Coast Guard Seventh District.
[FR Doc. 2022-17478 Filed 8-12-22; 8:45 am]
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