aep tech assessment - h2 from biomass

8/2/2019 AEP Tech Assessment - H2 From Biomass

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H2 PRODUCTION VIA BIOMASS GASIFICATIONAdvanced Energy Pathways (AEP) Project

Task 4.1 Technology Assessments of Vehicle Fuels and Technologies

Public Interest Energy Research (PIER) Program

California Energy Commission

July 2007

Prepared by:

UC Davis, Institute of Transportation Studies (ITS-Davis)One Shields Ave, Davis, CA 95616

Authors:

Rob Williams, Nathan Parker, Christopher Yang, Joan Ogden and Bryan Jenkins

1. Introduction.......................................................................................................................................22. Technical Description.......................................................................................................................3

2.1 How it works Biomass gasification.......................................................................................3

2.1.1 Types of Gasifiers..............................................................................................................42.1.2 Co-production of Electricity..............................................................................................9

2.2 Feedstock Issues........................................................................................................................92.2.1 Biomass Sizing, Collection and Transport........................................................................92.2.2 Moisture Content..............................................................................................................112.2.3 Ash Content .....................................................................................................................11

2.3 Important factors controlling efficiency, emissions...............................................................122.4 Critical technology components..............................................................................................12

2.4.1 Feed Handling .................................................................................................................122.4.2 Gas Cleaning....................................................................................................................132.4.3 Gas Conditioning..............................................................................................................13

2.4.4 Hydrogen Separation .......................................................................................................132.5 Key attributes and benefits......................................................................................................13

3. Performance Metrics......................................................................................................................143.1 Efficiency and Energy Use......................................................................................................143.2 Emissions.................................................................................................................................153.3 R&D focus and impact on key metrics...................................................................................163.4 Costs........................................................................................................................................17

3.4.1 Capital Costs.....................................................................................................................193.4.2 Operating Costs................................................................................................................223.4.3 Lifecycle/levelized...........................................................................................................23

4. Penetration issues...........................................................................................................................23

4.1 Current projects.......................................................................................................................234.2 Feedstock issues (California Context)....................................................................................244.3 Key technical and economic barriers......................................................................................284.4 Potential Timeline For Biomass Gasification Plants..............................................................28

5. Conclusions.....................................................................................................................................286. References:.....................................................................................................................................30


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1. INTRODUCTION

There are several potential pathways for hydrogen production from biomass.1 These include

thermochemical routes (gasification, pyrolysis, supercritical water or hydrothermal) and biochemical routes (anaerobic digestion, dark- and photo-fermentation, and direct/indirect

biophotolysis) [1]. Other than anaerobic digestion to produce methane for reforming, essentially allbiomass and biochemical routes to hydrogen are developmental with demonstrations at lab or pilotscale only. Direct hydrogen production via anaerobic digestion is also developmental. There areseveral examples of the use of biogas from anaerobic digestion (AD) to fuel stationary fuel cells.

Water

Organic

acids

Photo fermentation

Direct/indirect biophotolysis

Reforming,

Uprading, &Separation

Separation

Biomass

Dark fermentation

Hydrogen

Direct gasification

Indirect gasification

Supercritical water gasification

Pyrolysis

Methane

Anaerobic digestion

Thermochemical conversion

Biochemical conversion

Figure 1 Hydrogen pathways from biomass and biochemistry (adapted from [1])

Regarding thermochemical routes, there are several principal candidate gasifier types as well asfeedstock modification scenarios for hydrogen production from biomass. Candidate gasifier typesare oxygen-blown direct fired entrained flow or circulating fluidized bed (pressurized oratmospheric), and indirectly heated air blown, atmospheric fluidized bed designs. Scenarios for

feedstock modification or pre-treatment include pyrolysis or torrefaction to transform biomass intosomething more easily handled, transported, and/or fed to a gasifier.

Supercritical water gasification (sometimes called hydrothermal treatment) occurs at relatively lowtemperature (500 700 C) and in water at high pressure (near or above the critical point, 221 bar

1Biomass is living or recently living material. The definition in Federal statute (7 USC 7624 303) is: Any organic matter that isavailable on a renewable or recurring basis, including agricultural crops and trees, wood and wood wastes and residues, plants(including aquatic plants), grasses, residues, fibers, and animal wastes, municipal wastes, and other waste materials.


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or 3200 psi).

Biochemical routes to hydrogen include steam methane reforming of biogas from anaerobicdigestion (including landfill gas), as well as direct hydrogen production from AD by inhibiting themethane forming bacteria. Dark and photo-fermentative and two stage dark/photo fermentative

production of hydrogen is theoretically possible with anaerobic hydrogen producing enzymes aswell as bio-photolysis of water by algae.

Estimates of commercial hydrogen production capacity for biomass and biochemical routes areshown in 1 (adapted with modifications from [1] ). Because AD and steam methane reforming(SMR) are commercial technologies now and extensive development needed to commercialize thedark/photo-fermentation and biophotolysis routes, AD with SMR is expected to remain the bestcommercial choice for small scale biomass to hydrogen route [1, 2].

The remainder of this report discusses issues related to large scale (at least in terms of biomass)hydrogen production from biomass gasification.

1 10 100 1,000

Hygrogen Production Capacity (1000 kg/day )

Anaerobic Digestion

Dark&Photo Fermentation

Biophotolysis

Supercritical Water Gasfication

Gasification / Pyrolysis

Figure 2 Estimated capacity ranges for biomass/bio-derived H2 production (adapted from [1])

2. TECHNICAL DESCRIPTION

2.1 How it works Biomass gasification

Gasification is the conversion of (usually solid) carbonaceous material into fuel gases (synthesisgas, producer gas). It is commonly accomplished via partial oxidation of the feedstock using sub-stoichiometric (insufficient) air or oxygen or by indirect heating (with or without steam). Theproduct, or synthesis gas (syngas), is principally CO, H2, methane, and lighter hydrocarbons, H2O,PM, tar, alkali vapors, nitrogen and sulfur compounds, and depending on the process used, cancontain significant amounts of CO2 and N2, the latter mostly from air. High temperature (>1200C)oxygen-gasification processes produce syngas with very low concentrations of hydrocarbons andhigher concentrations of CO and H2. Gasification processes also produce liquids (tars, oils, andother condensates) and solids (char, ash) from solid feedstocks. The combustion of gasification-derived fuel gases generates the same categories of products as direct combustion of solids, but


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pollution control and conversion efficiencies may be improved.

The product gas, synthesis gas or syngas, from biomass gasification can be further processed toproduce hydrogen or a range of liquid fuels including methanol, ethanol, mixed alcohols andgasoline- or diesel-range hydrocarbons.

The raw product gas (CO, H2, light hydrocarbons, tars, particulate material, and other) undergoesextensive clean up to remove catalyst poisons and other undesirable components. This is followedby gas processing/reforming where the methane and higher hydrocarbons are reformed into CO,CO2, and H2. The gas is then sent to water gas shift reactors to convert nearly all of the CO to H 2and CO2 (consuming some H2O vapor). The resulting gas is mainly hydrogen and carbondioxide. The hydrogen is separated from the stream usually by pressure swing adsorption (PSA)(2.1). The PSA generally employs a molecular sieve, allowing hydrogen to pass through andadsorbing impurities at high pressure then desorbing the impurities as reject gas at low pressure.This process requires electricity input for the compression power, and hydrogen purities of99.999% can be achieved [1].

Steam

CombustorHeat

PSA

Reject

Gasifier Gas

Cleanup ReformerWater Gas Shift

Reactors

Ash

PSA

Product

Hydrogen

electricity

Feedstock

Processing

Figure 3 Schematic of gasification to hydrogen production system.

Biomass gasification for the production of hydrogen is not practiced commercially at present.Gasification technology of a type suitable for H2 synthesis has been demonstrated for electricity production using biomass feedstocks. The technology has been used extensively for liquidhydrocarbon production from coal and petroleum coke. The steam reformer, water-gas shiftreactors, and PSA are components of the mature steam methane reformation (SMR) technologies,though they may require adjustment for optimal use with syngas. There is uncertainty as to the bestgasification technology for producing hydrogen from biomass feedstocks especially in feedstockhandling and gas cleanup.

2.1.1 Types of Gasifiers

Gasifier types include the fixed bed (updraft or downdraft), fluidized or bubbling bed,circulating fluidized bed, and entrained flow (2.1.1-8). The units can operate at atmospheric orhigher pressure. The gasification medium is generally either air (air-blown), oxygen (oxygen-blown), steam, or a combinations of these.

With direct gasification, heat for the process is supplied within the reactor by partial combustion ofthe feedstock. Indirect gasification refers to systems that use external heating to drive the


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gasification reactions (heat must be transferred into the reactor by some mechanism; for bestefficiency, the source of the external heat should be from combustion of the unreacted char (fixedcarbon) from the indirect gasification reactor). Examples of indirect gasifiers include the FastInternal Circulating Fluidized Bed (FICFB) gasifier, currently operating at Gssing, Austria andthe Battelle Columbus Laboratory (BCL) design which was demonstrated in Burlington, Vermont

(Figures 9 and 10).2

For high quality (high energy content) synthesis gas, direct gasification needs to be oxygen-blownin order to avoid nitrogen dilution from air. Indirect gasification can produce a suitable synthesisgas using air as oxidant.

Figure 4 Schematic of fixed-bed updraft

gasifier [5]

Figure 5 Schematic of fixed-bed downdraft

gasifier [5]

2.1.1.1 Fixed Bed Gasifiers

In the fixed-bed updraft configuration, air (oxidant) flows countercurrent to the fuel. It is suitablefor relatively high moisture fuels (


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held stationary while the reaction front passes through it, or the bed can move through reaction ormechanical displacement. Often, they are suction type gasifiers attached to an engine. Thesegasifier types would not likely be the preferred choice for hydrogen or liquid fuels production frombiomass, although parallel trains of such gasifiers have been used with coal for this purpose.

Ash

Product Gas

Freeboard

Fluid Bed

Biomass

Air/SteamPlenum

Figure 6 Bubbling bed reactor [5]Figure 7 Circulating fluidized bed reactor

[5]

2.1.1.2 Fluidized BedsFluidized bed reactors contain a bed of relatively small particles of inorganic material (often sandor small diameter ceramic beads or gravel). The bed is fluidized by blowing hot oxidant up fromthe bottom (individual particles are lifted by aerodynamic drag, and become suspended orentrained on the gas stream at velocities for which the drag force becomes equal to or exceeds thegravitational force or weight). When fluidized, the bed behaves much like a liquid. When the bedmedia is hot enough, biomass is injected either into the bed or onto the surface (bubbling beds) andcan begin to combust or gasify depending on the amount of oxygen available.

Bubbling fluidized bed reactors have relatively slow velocity air, oxygen, or steam flow andtherefore have lower particle entrainment in the gas leaving the reactor. The bed material is

concentrated in the lower dense-bed region because the freeboard section above the bed has alarger diameter and lower gas velocity. The gas velocity in the freeboard section is too low tocontinue to suspend bed particles, which fall back into the bed region. The design is simple but haslower capacity and potentially less uniform reactor temperature distribution than circulatingfluidized beds.

The circulating fluidized bed uses higher gas velocities but offers higher conversion rates andefficiencies. Instead of a freeboard section, the reactor diameter remains essentially constant,

Product

Fluidizing Air, O2, or

ProductGas

Fuel


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which keeps bed and fuel particles suspended. The bed material flows up with the fluidizing gasand is carried over into a cyclone which separates most of the particles from the gas stream whichare re-injected (recirculate) into the lower part of the bed. Ideally, the fuel particles are smallenough to completely react before carried over into the cyclone, but in practice large fuel particlesrecirculate with bed media until small and light enough to be carried out with the product gas

exiting the cyclone or other separation device. Oxygen fired circulating fluidized bed gasifiers arecandidates for the production of hydrogen and liquid fuels.

Figure 8 Schematic of an entrained flow gasifier [6]

2.1.1.3 Entrained Flow

Entrained flow gasifiers are used extensively by the petroleum to convert petroleum residues (e.g.,petroleum coke) to useful products and energy. Most coal gasification is done with entrained flowsystems.

Entrained flow gasifiers have high gas velocities and high material throughput. Consequently, time

for reaction (residence time) is short which requires the feedstock to be of very small particle size,a liquid or liquid slurry. The systems are generally oxygen blown and can be pressurized oratmospheric. High temperature (>1250 C) is generated from combustion in oxygen which meltsthe ash (sometimes called slagging gasifier) and requires reactor cooling. Little to no tar is formedas the feedstock is essentially completely converted to H2, CO, CO2, and H2O.


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2.1.1.4 Raw Syngas Characteristics

Air-blown gasifiers produce a low energy gas (~ 150 Btu ft-3) composed of CO, H2, CO2, CH4,

higher light hydrocarbons, H2O, PM, alkali vapors, nitrogen and sulfur compounds, and 40-50%N2. The N2 is a diluent and is from the air gasification medium.

Oxygen-blown gasifiers produce a medium energy gas (~ 350 Btu ft-3

) composed of similarcompounds but much less nitrogen. An air separation plant is needed to create a pure or enrichedoxygen stream to use for the gasification medium.

Properly designed and operated air-blown indirect gasifiers produce a medium Btu gas because thecombustion reactor is separate from the gas producing reactor. The products of combustion and theair borne nitrogen are therefore separate from the synthesis gas stream.

Table 1. Approximate composition of raw syngas from gasified biomass

Air-blownProducer Gas

(vol. %)

Oxygen-blownSynthesis Gas

(vol. %)

Indirect-fired-steamgasification Synthesis

Gas (vol. %) [3, 7]CO 22 38 19

H2 14 20 20

CH4 5 15 8

C2H2 and higher low 5 3H20 2 4 38

CO2 11 18 11

N2 46 trace trace

Plus tars, PM, and other


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Figure 9 Schematic of the Fast InternalCirculating Fluidized Bed (FICFB)gasifier, Gssing, Austria [8]

Figure 10 Schematic of the Battelle/FERCOgasifier

2.1.2 Co-production of Electricity

Co-production of electricity is possible with many biorefinery configurations, includingthermochemical hydrogen production from biomass. The economics of producing hydrogen can beimproved by co-producing some quantity of electricity from the PSA purge gas and a portion ofthe synthesis gas.

2.2 Feedstock Issues

Biomass includes a great variety of possible feedstocks including residues from agriculture,forestry and forest products, and urban (municipal solid waste) to purpose-grown energy crops.Different biomass feedstocks will require different preparation and handling and performdifferently in the gasification facility. Facility designs must account for the feedstocks availablefor use.

Biomass is generally distributed and has a relatively low energy density when compared to coal,crude oil or refined liquid fuels. Consequently, the costs of gathering and transporting a dispersedresource need to be balanced against conversion plant economies of scale.

2.2.1 Biomass Sizing, Collection and Transport

Some feedstocks will need to be cut, chipped or milled to smaller size. The required final form ofbiomass feedstock will depend on the reactor, characteristics of the biomass, transportation,storage, and handling/feeding logistics.

Feedstocks such as grasses and bagasse can be densified, reducing transportation costs andsimplifying handling and reactor feeding. Densification incurs costs and energy penalties so itscosts should be offset by transportation and handling savings. With other situations or feedstocks,it may make sense to transform the biomass before transportation or conversion to improvelogistics, handling, or feeding and/or reduce transportation costs.

One example is to utilize regional pyrolysis facilities to convert biomass feedstocks into arelatively energy-dense liquid, which would then be more efficiently transported to a centralfacility for upgrading or hydrogen production (2.2.1). Another might be to employ a processsimilar to pyrolysis called torrefaction which removes moisture and some of the volatile materialfrom biomass leaving a char that is easily ground up and behaves in a manner physically similar tocoal in a gasifier.


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RPRP RPRP

RPRP

Resource Region

or Waste Shed

Regional

Pyrolysis Facility

Central

Refinery

Pyrolysis

oil transport

Figure 11 Concept of regional pyrolysis facilities with transport of bio-oils to a central refinery.(adapted from [9])

Amount of Energy in a Truckload of Biomass

The maximum allowable gross vehicle weight (GVW) in California is 80,000 lbs. but is higher insome western states [10] [11]. Empty tractor-trailer combinations weigh approximately 25,000 -30,000 lbs. which allows for payloads from 50,000 - 55,000 lbs [12] [13].

The net energy per truckload of several types of biomass and pyrolysis oil (bio-oil) are shown inTable 2. A truck load of woodchips contains about 250 GJ (237 MM Btu), while a load of baledswitchgrass might reach 347 GJ (329 MM Btu). A load of pyrolysis oil is approximately 386 GJ(366 MM Btu).

The table assumes payload for each biomass type is set at 25 tons (22.7 metric tonnes). Baledmaterial typically has a moisture content of 15% or less to prevent excessive microbial activity that

could lead to internal heating creating a combustion hazard. Woodchips or sawdust are typically 45- 50% moisture. Energy content ranges from 16 20 MJ/kg (HHV, dry basis) for herbaceous andwoody biomass, while pyrolysis oils average about 17 MJ/kg (HHV, wet basis) [14, 15].However, whereas trucks transporting wood chips are typically weight limited, even for driedfeedstock, trucks hauling bales may be volume limited and handle reduced payloads.


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deposit downstream on cool surfaces or particles and impede flow or heat transfer over time. Theycan also inhibit catalyst performance. Designing gas cleaning systems to remove alkali vapor andpotential catalyst poisons is critical with biomass derived synthesis gas. Leaching of the feedstockwith water can improve ash chemistry by removing many of the offending elements [17-21]. Thisadds expense and moisture that will need to be dealt with.

2.3 Important factors controlling efficiency, emissions

The nominal system design and biomass type and characteristics will define nominal or averageefficiency and emissions. Off-spec or degraded performance of components (i.e., catalysts, gascleaning components, emissions control systems, etc.) will affect product yield and/or emissions.Proper component monitoring and maintenance can minimize performance problems.

Changes in biomass feedstock or handling can be expected to impact efficiency and possiblyemissions as well. For example, increases in biomass moisture which can occur from seasonal

rains falling on uncovered biomass storage, or from feedstock that is harvested, handled andprepared differently from specifications can reduce yield by requiring more up-front drying andprocessing. Emissions may increase as well depending on how the feedstock dryer operates, ifemployed.

2.4 Critical technology components

There are many examples of fixed bed, fluidized bed, and circulating fluidized bed gasifiers usingbiomass feedstock and air as the gasifying medium (direct gasification). The product gas is used inheat and power applications (in steam boilers or reciprocating engines). There are fewer examples

of indirect gasification using biomass (i.e., Batelle/FERCO demonstration at Burlington, VT andthe current FICFB gasifier at Gssing, Austria).

There is limited experience with biomass in entrained flow gasifiers as well as with pressurizedoxygen-blown systems. These systems need development and demonstration.

Significant progress has been made with hot-gas cleaning systems for biomass integrated gasifiercombined cycle (BIGCC) power systems [22]. More gas clean-up work is needed for the morestringent syngas requirements for H2, chemicals, and liquid fuels production.

2.4.1 Feed Handling

Biomass handling and injection into gasifiers are critical processes needing further development.Because of short residence times in entrained flow gasifiers, the feedstock needs to becontinuously added to the gasifier as small particles or as liquid slurry. For pressurized gasifiers,injecting solid fuel particles is a challenge requiring air-lock systems for fuel injection. Moreexperience is required with feeding a range of biomass feedstocks in commercial scale entrainedflow and/or pressurized gasifiers.


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hydrogen to about $5 per kilogram of hydrogen depending on the size of the facility, theprocessing technology used and the cost of the feedstock.

3. PERFORMANCE METRICS

3.1 Efficiency and Energy Use

Hydrogen conversion efficiencies for biomass gasification facilities are predicted to be between30-80% based on the higher heating value of the input biomass (Table 3 and 3.1) [1, 23, 25, 26].The range is due to a number of factors including amount of supplementary fuel use (natural gas,electricity), co-production of electricity, size of facility, assumptions about future technologyimprovements, gasifier type, and the level of integration of the system.

Table 3. Summary of Energy Inputs and Performance of Biomass Hydrogen in Literature

Study3

Facility Size

(kg H2/day)

Biomass Input

(kg/kg H2)

Net Electricity

(kWh/kg H2)

Natural Gas Input

(mmBtu/kg H2)

Katofsky 165,000 9.74 -3.09 0.0000

Katofsky 150,000 10.60 -4.18 0.0000

Katofsky 171,000 9.37 -4.87 0.0000

Katofsky 176,000 9.03 -3.87 0.0000

Hamelinck 157,710 11.73 -0.11 0.0000

Hamelinck 184,361 10.04 -2.92 0.0000

Hamelinck 90,659 20.41 19.11 0.0000

Lau 2003 39,000 11.34 -2.28 0.0000

Lau 2003 42,050 9.54 -2.04 0.0000

Lau 2003 44,150 9.95 -1.90 0.0000

Spath 2005 (NREL) 148,966 13.43 -1.64 0.0053

Spath 2005 (NREL) 151,400 13.21 -1.63 0.0112

NAS 2004 24,000 18.38 -6.44 0.0000

NAS 2004 24,000 11.90 -3.11 0.0000

Larson 2005 172,800 26.28 39.03 0.0000

Larson 2005 378,720 11.99 2.60 0.0000Larson 2005 179,280 25.33 29.18 0.0000

Larson 2005 380,160 11.95 0.63 0.0000

Simbeck And

Chang150,000 9.90 -4.89 0.0000

3 See Table 6 and [32-38] for more information.


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improvements in the following component areas will lead to lower hydrogencost.

Feed preparation, handling, injection

The generally low bulk density and fibrous nature of biomass presents challenges in transporting,handling, and storing large quantities of biomass. While preparation and feeding systems forwoody biomass in atmospheric gasifiers are developed, much work remains to develop reliablehandling and feed systems for pressurized gasifiers especially when using low density fibrous andherbaceous biomass.

Conversion (gasifiers)Most biomass gasification experience is with atmospheric pressure air-blown systems that producea gas suitable for heat and power production. More understanding and experience is needed withbiomass fired in oxygen-blown high pressure gasifiers. The influence of catalytic bed additives,reactor design and operating conditions on hydrogen yield in the syngas needs to be done.

Low-cost and reliable high temperature heat transfer materials and strategies are needed to improveperformance of indirect gasifiers.

Lower cost small scale air separation/oxygen enrichment systems are needed to improveeconomics of biomass syngas production.

Gas clean-upSignificant progress has been made with hot-gas cleaning systems for biomass integrated gasifiercombined cycle (BIGCC) power systems. More gas clean-up work is needed to meet the morestringent syngas requirements for H2, chemicals, and liquid fuels production. For best thermal

efficiency, gas handling and cleaning should occur without intermediate cooling stages and nearfinal product H2 pressures.

CatalystsDepending on the effectiveness of gas cleaning stages, catalysts that are less susceptible todeactivation (or poisoning) from trace compounds typical to biomass (e.g., alkali metals, chlorineand sometimes sulfur) need development. Robust and effective catalysts that can be economicallyproduced are critical to biomass syngas production and conversion.

3.4 Costs

Plant-gate hydrogen production costs are expected to range from about $1- $5 per kg H2 ($7-$35GJ-1) for mature biomass to hydrogen gasification systems (Figure 12) [32-39]. Depending on

design and capacity, the capital, O&M, feedstock costs, and power co-product or purchase, wouldcontribute between 40-64%, 14-22%, 30-50%, and -33 - +9% of total hydrogen production costsrespectively (3.4).


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0.0

1.0

2.0

3.0

4.0

5.0

6.0

0 200,000 400,000 600,000 800,000 1,000,000

Hydrogen Capacity (kg/day)

Katofsky,1993

Hamelinck, 2000

Spath, et al., 2003

NAS, 2004

Spath, et al., 2005

Larson, 2006

Figure 13 Levelized cost of biomass-to-H2 vs. production capacity

-50

-25

0

25

50

75

100

125

150

1 2 3

Power (+/-)

Feedstock

O&M

Capital

Elect.Co-prod. No Co-prod. No Co-prod.

[Hamelinck & Faaij (2002)] [Lau et al., (2002)]Figure 14 Distribution of Capital, O&M, Feedstock, Co-product portion of H2 production cost

[23, 25]


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3.4.1 Capital Costs

There is a wide range of capital cost estimates in the literature due to the different designs and costassumptions. 3.4.1 shows capital cost estimates versus hydrogen production capacity from sevenstudies of biomass to hydrogen [32-39].

C = 0.0208M0.7768

R2

= 0.7792

0

100

200

300

400

500

600

700

800

900

1,000

0 200,000 400,000 600,000 800,000 1,000,000

M, Hydrogen Capacity (kg/day)

Katofsky,1993

Hamelinck, 2000

Spath, et al., 2003

NAS, 2004

Spath, et al., 2005

Larson, 2006

Lau, et al., 2003

Figure 15 Estimated Capital Cost for Biomass-to-hydrogen Gasification Facilities


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Study

- Gasifier

Facility

Size

(MWth)

Hydrogen

Capacity

(kg H2/day)Feedstock H2 Eff.

Overall

Eff.

Capital

Cost

(million)

Capital

per kg

H2 Cap.

Scaling

Factor

Feedstock

Cost

Levelized

Cost of

H2

IRR

Spath et al(2003) 15%

- BCL 72.7 22,737 Wood 51.4% NA $53.80 $2,366 - $0.89/GJ $2.62

- BCL 242.1 75,790 Wood 51.4% NA $128.80 $1,699 0.725 $2.49/GJ $2.36

- BCL 363.2 113,685 Wood 51.4% NA $172.30 $1,516 0.72 $2.49/GJ $2.19

- IGT 72 22,737 Wood 52.0% NA $72.00 $3,167 - $0.89/GJ $3.17

- IGT 239.6 75,790 Wood 52.0% NA $169.40 $2,235 0.71 $2.49/GJ $2.70

- IGT 359.5 113,685 Wood 52.0% NA $227.20 $1,999 0.72 $2.49/GJ $2.49

NAS (2004) 16%

- Shell 95 24,000 Wood 41.5% 38.9% $125.84 $5,243 - $2.94/GJ $4.82 CRF

- Advanced 61.5 24,000 Wood 64.1% 61.3% $61.36 $2,557 - $1.97/GJ $2.30

Spath et al(2005) 10%

- BCL current 466.9 140,800 Poplar 49.6% 51.0% $162.80 $1,156 - $1.58/GJ $1.46

- BCL future 466.9 151,400 Poplar 53.3% 53.3% $153.10 $1,011 - $1.58/GJ $1.31

Larson et al(2006) 10%

- IGT H2 983 172,800 Switchgrass 28.8% 57.5% $480.50 $2,781 - $3.12/GJ $1.53

- IGT H2 983 378,720 Switchgrass 63.2% 67.5% $462.80 $1,222 - $3.12/GJ $1.27

- IGT H2 CCS 983 179,280 Switchgrass 29.9% 52.2% $535.60 $2,988 - $3.12/GJ $1.96

- IGT H2 CCS 983 380,160 Switchgrass 63.4% 64.6% $491.90 $1,294 - $3.12/GJ $1.39


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3.4.2 Operating Costs

Non-feedstock O&M costs can range between 14-22% of the hydrogen production cost. Feedstock procurement, storage, handling, and preparation costs can range from 30 to 50% of finalproduction costs.

The cost of biomass feedstock will vary greatly due to a number of factors, mainly type of biomass, harvest methods, delivery distances, preparation requirements and market factors.Whether the feedstock is a purpose grown energy crop, forest or agricultural residue or a wastestream will greatly impact the cost structure of procurement. Waste streams may be available atnegative costs where a biorefinery could collect a tipping fee similar to a landfill. Forest and fieldresidues could be made available at the full cost of harvest, this includes nutrient replacement, firereduction benefits and other costs or benefits of the harvest. Purpose grown crops will need toreceive a price that would make them an attractive agricultural commodity as they will need tocompete for agricultural resources (land, water, labor).

Figure 16 Estimated biomass resource cost curve based on California resource estimates(excludes storage and onsite processing and handling costs) [40, 41]

Large facilities will need to draw feedstock from increasingly large areas and competition for

feedstock will be a concern. Feedstock costs may well be higher than $36/BDT ($2/GJ) with adeveloped liquid biofuels industry competing for purpose grown energy crops and existingresources.

The harvest, transport and storage costs will depend on the feedstock, the terrain, and thegeographic density of the resource. Low yielding feedstock or difficult terrain lead to high harvestcosts. Transportation distances are critical for the delivered cost of biomass feedstock. Forexample, 3.4.2 shows how delivery distance affects the delivered cost of rice straw in California.


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The road type that the biomass trucks must drive will also effect the cost of delivery. Thedelivered biomass must be prepared to meet the requirements of the gasifier (size, moisturecontent, etc.). Costs for size reduction, drying, and other processing operations will need to beadded to the delivered cost of the feedstock.

$0.00

$1.00

$2.00

$3.00

$4.00

0 25 50 75 100 125 150

Distance (km)

Figure 17 Delivered cost of rice straw as a function of delivery distance

Other uses of biomass and the scarcity of the resource are important market factors in determiningthe cost of biomass feedstock. If biomass can be utilized profitably in another industry, the cost ofbiomass for hydrogen will reflect this opportunity cost. There is a limited supply of biomass

resources and as they become more and more exploited, the scarcity of the resource will impact thecost through market interactions. This will also be important on a seasonal and yearly timeframeas fluctuations in biomass production will cause market shortages and surpluses possibly leading tovolatility in biomass prices.

3.4.3 Lifecycle/levelized

The levelized plant-gate hydrogen production costs are expected to range from about $1- $5 per kgH2 ($7-$35 GJ

-1). The cost of hydrogen is sensitive to feedstock cost and type as well as the size ofthe plant.

4. PENETRATION ISSUES

4.1 Current projects

There are no known operating biomass gasifiers in California. There is approximately 950 MW ofoperating biopower capacity in California (about 600 MW from approximately 30 solid fuelcombustion steam turbine systems, 275 MW from landfill gas systems and the remainder from

D e liver e d C ostofR ic e S tr aw ($/G J)


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the resource potential [29].

Figure 18 California biomass resource distribution and amount [29]

Potential contributions to future electricity, heat, biofuels, and hydrogen supplies are significant.The current technical biomass resource in California represents 2.5 million tons per year ofhydrogen potential (4.2). Although biomass will be used for multiple purposes, maximum energypotentials within any one product category based on full use of the resources presently availableare of the order of 10 percent of statewide demand in each of electricity and transportation sectors[29].

0 20 40 60 80 100

Total

Urban

Forestry

Agriculture

Biomass (Million BDT/year)

Potential Feedstock

Gross Biomass


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Table 7. Total energy potentials for available California biomass feedstock by energy category(adapted from [29])

2.5 Million tons/y30532Hydrogen(bio + thermal)

106 BCF/y

methane

1065 +

Landfill gas and WWTP

Biomethane

1.7 BGY

diesel equivalent

25027Thermochemical

Biofuel

2.3 BGY

ethanol equivalent

18832Biochemical

Biofuel

11,700 MWt35032Heat

4,650 MWe

9,050 MWt

118 (35 TWh)

230

32Electricity

CHP Heat

Total Capacity

Energy in Product

(Trillion Btu/year)

Biomass

(Million BDT/year)Category

2.5 Million tons/y30532Hydrogen(bio + thermal)

106 BCF/y

methane

1065 +

Landfill gas and WWTP

Biomethane

1.7 BGY

diesel equivalent

25027Thermochemical

Biofuel

2.3 BGY

ethanol equivalent

18832Biochemical

Biofuel

11,700 MWt35032Heat

4,650 MWe

9,050 MWt

118 (35 TWh)

230

32Electricity

CHP Heat

Total Capacity

Energy in Product

(Trillion Btu/year)

Biomass

(Million BDT/year)Category

BDT = bone dry ton. BCF = billion cubic feet. BGY = billion gallons per year. MWe = megawatt electric. MWt =megawatt thermal (heat). TWh = terawatt-hour (billion kWh). WWTP = wastewater treatment plant. 1 ton = 2000 lbs.Biochemical conversion is based on fermentation to ethanol. Thermochemical is based on gasification followed byFischer-Tropsch synthesis. Biomethane is methane derived from anaerobic digestion of biomass. Biofuel capacitiesshown are based on assumed low yields for dedicated crops (see [29] for more detail). Tonnage for thermochemical

biofuel assumed to be constrained by moisture content.

Existing biopower facilities consume about 5 million BDT/year of biomass. About half the amountcomes from forestry and forest product residues and about 1/3 is from urban wood residues [41].Another 6 8 million BDT per year is processed in compost and mulch facilities [51].

We consider residual biomass as a near to mid term source for hydrogen production in California.The technically available resource rules out biomass that is impractical to collect such as manurefrom range cattle or a portion of the forest thinnings in steep terrain or far from roads. Alsoexcluded are a fraction of agricultural residues that must be left in the fields for erosion control andsoil health and biomass in protected forest and riparian zones and wetlands. With the exception ofmill residues and some urban wood and green waste, most of this resource is currently not beingused.

Hydrogen production from much of this diverse resource base can be accomplished with twotechnologies, gasification and biogas reforming. Gasification produces hydrogen from dry biomass

feedstocks through the process described earlier. Most estimates place gasification conversionefficiency between 51% and 65% (the full range of estimates is 30-80%, Figure 12). Biogas, amethane-rich gas, can be produced from the wet biomass feedstocks through anaerobic digestion.Biogas, including landfill gas, can be converted to hydrogen through steam methane reformation.Current-practice steam methane reformers achieve 70% efficiency [NAS]. Biogas reformers maybe less efficient.

The statewide biomass hydrogen production potential from the technically available waste biomass


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resource is calculated with assumed conversion efficiencies of 55% for gasification and 65% forbiogas reforming.

Waste biomass resources in California could provide 6,500 tonnes of hydrogen per day fortransportation fuel. As seen in Figure 19, the biomass in municipal solid waste (MSW) represents

the single largest resource available for exploitation. Waste products from various forestryoperations, including forest and chaparral thinning operations for fire prevention, are the four nextlargest resources. Other important resources are the residues from orchards and field crops andlandfill gas.

On an energy basis, the biomass hydrogen production potential represents 16% of the gasolineconsumed in California in 2004. Additionally, the greater efficiency of a fuel cell vehicle shouldbe taken into account when comparing hydrogen and gasoline energy. A hydrogen fuel cellvehicle is expected to achieve fuel economies up to 2.5 times that of conventional gasoline internalcombustion engine powered vehicle with the same level of performance (Weiss et al. 2003, NRC2004). We estimate that 8.1 million vehicles could be fueled by Californias biomass hydrogen

potential. This assumes hydrogen fuel cell vehicles are driven 15,000 per year with a fueleconomy of 51.5 miles per gasoline gallon equivalent (current fleet fuel economy is 20.6 mpg). Forreference, there are currently over 25 million light duty vehicles in California. It is not likely thatall the technically available biomass will be economically viable for hydrogen production. Despitethese limitations, the result found here points toward significant contributions possible frombiomass hydrogen.

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

Waste Water Biogas

Landfill GasFood Processing Wastes

Orchard Prunnings

Field Crop Residues

Manures

Chaparral

Forest Thinnings

Logging Slash

Mill Residue

Biomass in MSW

Figure 19 Hydrogen Production Potential from Biomass Residue in California


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4.3 Key technical and economic barriers

Biomass gasification for electricity production has not yet been demonstrated to be competitivewith conventional fossil power generation, especially in the absence of CCS or greenhouse gasreduction requirements, which is the primary reason few systems are currently operating. Biomass

gasification systems that produce both heat and power (combined heat and power, or CHP) aremore cost effective when a thermal host is available, and several dozen facilities are operating,mostly in Europe.

For biomass systems that would produce high quality syngas for hydrogen, biofuels, or chemicalproduction, the main technical and economic barrier is the lack of commercially operating or large-scale demonstration facilities.

There is much interest in biomass gasification for liquid fuels production and large research effortsare ongoing in Europe, but no commercial systems are operating. Efforts in the US have laggedsince the US DOE de-emphasized thermochemical conversion systems in favor of the sugar

fermentation platform for biofuel research (i.e., research on enzymatic hydrolysis of cellulose).5

Systems components, such as hot gas cleaning, reformer catalysts, etc. need proving at commercialor near commercial scale. Experience and learning from multiple demonstrations will improveefficiencies and reduce costs. Commercial scale demonstration of high quality syngas fromgasified biomass is needed.6

4.4 Potential Timeline For Biomass Gasification Plants

Hydrogen from biomass gasification is not expected to develop in the near term due to costs, lackof demonstrated technology and lack of widespread hydrogen market and infrastructure.Depending on the amount of research effort and market pull, viable biomass gasification forhydrogen production is estimated to be possible in as little as 5 years to as long as 20 years.Gasification for liquid fuels synthesis may, however, spur development of commercial systems inthe nearer term, benefiting the eventual application to hydrogen generation.

As part of the California Hydrogen Highway action plan, the state has indicated that it intends toinitially implement a 20% RPS for hydrogen production which will increase over time (including agoal of 33% renewable by 2010). This would have a large impact on the importance of biomass-based H2 production, since it is expected to be the least cost renewably produced H2.

5. CONCLUSIONS

Hydrogen from biomass would be considered renewable and have low lifecycle greenhouse gasemissions. Biomass derived hydrogen pathways include thermochemical routes (gasification,

5 Though in August, 2006, the National Biomass Research and Development Technical Advisory Committee recommended new

federal effort in the thermochemical biofuels platform.6 The status of the Choren facility in Germany (demonstration of biomass to Fischer-Tropsch diesel) is uncertain.


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pyrolysis, supercritical water) and biochemical routes (anaerobic digestion, dark and photofermentation, and direct/indirect biophotolysis). With the exception of stationary fuel cellsoperating on biogas from anaerobic digestion and methane reforming, essentially all biomass tohydrogen routes are developmental with demonstrations at lab or pilot scale only.

The thermochemical pathways, gasification and pyrolysis followed by gasification, are best suitedfor larger scale biomass to hydrogen production (20 200 tonnes H2 per day). Candidate gasifier

types are oxygen-blown direct fired entrained flow or circulating fluidized bed (pressurized oratmospheric), and indirectly heated, air blown, atmospheric fluidized bed designs.

Conversion efficiencies for hydrogen from biomass gasification are predicted to be between 30-80% (based on HHV of input biomass) depending on gasifier type, amount of coproductelectricity, feedstock characteristics, and future technology improvements. With potential technicalbiomass resource in California approaching 35 to 40 million dry tons per year, biomass derived H2production potential is 2.5 million tons annually (assuming use of all available biomass). Plant-gate hydrogen production costs are expected to range from about $1- $5 per kg H 2 ($7-$35 GJ

-1)

for mature biomass to hydrogen gasification systems. The price range depends on scale, feedstockcosts, and conversion system design, among others.

Biomass can be difficult to gather, handle, store, and prepare. The conversion technology forhydrogen generation is in an early stage of development. There are no commercial biomassgasification systems producing the high quality syngas necessary for hydrogen production or liquidfuels synthesis. Components needing RD&D include reactor design and operation, gas cleaning,catalyst durability and selectivity, and feedstock cost and availability, preparation, handling, andfeeding, Pilot and commercial scale systems need demonstrating with a variety of feedstocks.

At projected costs, biomass is likely to be the lowest cost resource for the production of renewable

hydrogen, at least in the nearer term. Depending upon whether the technical and political issuessurrounding nuclear energy and carbon capture and sequestration are resolved, it may also be thelowest cost low-carbon H2 production resource. While biomass is not expected to provide enoughprimary energy to supply a majority of H2 for light-duty transportation, biohydrogen is likely to bean important contributor to near-to-medium term hydrogen supplies, especially if renewable H2standards are widely enacted.

Biomass-to-hydrdogen via the gasification/syngas route will benefit from the research anddevelopment efforts directed at the thermochemical production of liquid biofuels. By the timehydrogen vehicles and infrastructure are widely deployed, advanced biofuels will have beencommercialized and much of the needed component R&D needed for biomass-toH2 systemscompleted. With sustained emphasis on basic research and pilot- and larger-scale facilitydemonstration, biomass will likely prove an early contributor to renewable and sustainablehydrogen production.


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6. REFERENCES:

aep tech assessment - h2 from biomass

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