Jered Dean

Robert Braun

Colorado School of Mines

Golden CO 80401

Michael Penev

Christopher Kinchin

National Renewable Energy Laboratory

Golden CO 80401

David MunozColorado School of Mines

Golden CO 80401

Leveling Intermittent RenewableEnergy Production ThroughBiomass Gasification-BasedHybrid SystemsThe increased use of intermittent renewable power in the United States is forcing util-ities to manage increasingly complex supply and demand interactions This paper eval-uates biomass pathways for hydrogen production and how they can be integrated withrenewable resources to improve the efficiency reliability dispatchability and cost ofother renewable technologies Two hybrid concepts were analyzed that involve copro-duction of gaseous hydrogen and electric power from thermochemical biorefineriesBoth of the concepts analyzed share the basic idea of combining intermittent wind-gen-erated electricity with a biomass gasification plant The systems were studied in detailfor process feasibility and economic performance The best performing system was esti-mated to produce hydrogen at a cost of $167=kg The proposed hybrid systems seek toeither fill energy shortfalls by supplying hydrogen to a peaking natural gas turbine orto absorb excess renewable power during low-demand hours Direct leveling of inter-mittent renewable electricity production was proposed utilizing either an indirectlyheated biomass gasifier or a directly heated biomass gasifier The indirect gasificationconcepts studied were found to be cost competitive in cases where value is placed oncontrolling carbon emissions A carbon tax in the range of $26ndash40 per metric ton ofCO2 equivalent (CO2e) emission makes the systems studied cost competitive with steammethane reforming (SMR) to produce hydrogen The direct gasification concept studiedreplaces the air separation unit (ASU) with an electrolyzer bank and is unlikely to becost competitive due to high capital costs Based on a direct replacement of the ASUwith electrolyzers hydrogen can be produced for $027 premium per kilogram Addi-tionally if a nonrenewable grid-mix electricity is used the hybrid system is found tobe a net CO2e emitter [DOI 10111514004788]

Introduction

Wind and biomass are two promising domestic renewableresources Each resource faces unique challenges to large-scaleadoption This paper explores several possible synergies repre-sented by hybridization between wind power and thermochemicalbiomass processing with the goal of improving the economicpromise or efficiency of both

Of the domestic resources available for fuel production bio-mass shows significant promise Recent assessments have shownthat excess of 400 106 tons of biomass are currently availableper year in the United States [1] Some estimates predict that asmuch as 1 109 tons of biomass could be available in the futurewith changes to land management and agricultural practices [2]In addition to high availability thermochemical biomass plantsprovide many opportunities for system integration

Biomass can be converted to fuel and power via two main ther-mochemical conversion pathways Pyrolysis is the thermochemi-cal decomposition of biomass in the absence of oxygen Itproduces a mixture of synthesis gas (syngas) and bio-oil at tem-peratures around 500 C Gasification uses partial oxidation of thefeedstock to provide heat for the reactor and is typically run attemperatures above 800 C The higher temperature produces syn-gas with very little bio-oil (which is considered as an impurity ortar) Gasification is a particularly promising alternative for theproduction of second generation bio-fuels from nonfood cellu-losic biomass

Biomass gasification plants often require external power foroperation when the plants are optimized for fuel production Theuse of renewable sources of power for biorefineries furtherimproves the environmental benefits of thermochemical biomassprocessing [3] however few studies have looked at how todirectly couple intermittent renewable power with thermochemi-cal processing

Wind turbines have quickly become a widely accepted commer-cial source of renewable energy in the United States Over the last29 years utilities in the United States have improved their knowl-edge and ability to manage intermittent electricity sources In spiteof this progress there are two significant issues that remain if large-scale wind power is pursued in the United States [4] location andintermittency The vast majority of land-based wind resources arefound in the rural areas of the middle United States In order to suc-cessfully utilize these resources electricity must be transportedlong distances to demand centers Additionally the intermittency ofwind means installing too much capacity will create grid instabilityunless suitable grid leveling options are available

Transportation of wind-generated power can be accomplishedvia the electrical grid or by converting the electricity to a trans-portable fuel Using the electric grid to transport the power wouldrequire significant updates to the national infrastructure Addi-tional high voltage transmission lines would be needed in manylocations to connect wind resources with urban areas [4] Anotheroption is to convert intermittent electricity into a fuel Severalstudies have been done recently on using electrolyzers to createhydrogen from wind-generated electricity [56]

Portions of national wind resources lie in areas that alsohave biomass availability Therefore biomass could be used tocreate peaking power or wind-generated electricity could be

Contributed by the Advanced Energy Systems Division of ASME for publicationin the JOURNAL OF ENERGY RESOURCES TECHNOLOGY Manuscript received May 272010 final manuscript received July 18 2011 published online October 3 2011Assoc Editor Sarma V Pisupati

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-1Copyright VC 2011 by ASME

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

intermittently utilized by a properly designed biomass plant tocreate transportable fuel The goal of this research is to determinethe technical and economic viability of wind=biomass hybrid sys-tems ASPEN Plus thermodynamic simulation software was used incombination with time value of money economic analysis toexplore the concepts presented

Colocation Feasibility

For wind and biomass hybridization to be feasible the tworesources must be colocated To confirm the possibility of coloca-tion maps were constructed that overlaid class 4 or higher windresources onto biomass resources Based on the US Departmentof Energyrsquos definitions of wind power classes mapped resourceshave average wind speeds of greater than 56 m per second and anaverage wind power density of greater than 200 W=m2 at a heightof 10 m Biomass availability data was taken from a previousstudy [1] and combined with wind resource information with thehelp of the National Renewable Energy Laboratory (NREL) geo-graphic information systems (GIS) group For both of the mapsdepicted in Figs 1 and 2 the wind resources are shown in red andexclude potentially environmentally sensitive lands wind onwater features and small isolated areas The green shading onboth maps indicate that greater than 2000 tons per day (TPD) ofthe specified type of biomass is available within an 80 km (50-mile) radius Given the extent of green-area shading within thesefigures any specific location within a shaded region is viable TheGIS maps do not account for competition for biomass resources(ie other biomass plants in the region) There are areas wherethe wind data are difficult to observe because the spatial resolutionon the wind resources is much finer than the biomass1 so the areasof red can be difficult to distinguish

Figure 1 shows woody biomass resources overlaid on availablewind Woody biomass includes forest residues and mill residuesMill residues include the bark and wood materials produced whenlogs are processed into lumber and wood scraps from factories suchas furniture manufacturers There are small pockets of the north-west and northeast where both class 4 or greater wind and sufficientwoody biomass exist for a colocated combined system

Figure 2 shows agricultural (crop) residue biomass resourcesversus available wind Crop residues considered included cornwheat soybeans cotton sorghum barley oats rice rye canolabeans peas peanuts potatoes safflower sunflower sugarcaneand flaxseed Residue estimates were adjusted down to allow forsoil erosion control animal feed bedding and other existing farmuses consistent with Milbrandt [1] There is significantly moreoverlap of agricultural biomass with wind than woody biomassand wind

Both figures2 show overlap of biomass resources and windavailability The overlap of woody biomass and land-based windis small However some of the areas may have access to sea-based wind resources that were not considered here and windinstallations do exist in areas that have less than class 4 wind Ag-ricultural biomass and wind overlap in a large part of the MidwestThis result shows that wind=biomass hybridization could providea useful service in some areas of the central United States Theconcept will not generally be applicable outside of these areas

Concept Selection

Increased penetration of wind power on the grid will result inunique challenges These challenges include management of inter-mittency with electric power peaking units and in the extremecase finding use for electricity produced by wind when there isless demand than the energy produced Managing intermittencywill drive utilities to invest in additional peaking units andincrease the need for interruptible customers energy storageoptions and dispatchable loads

Direct integration between a thermochemical biomass plant andwind power could allow a hybrid system to manage local intermit-tency or capture stranded wind resources The proposed hybridsystems are intended to fill wind energy shortfalls and=or absorbexcess wind-generated power

A literature review was undertaken to determine the currentstate of research with respect to biomass hybridization The resultsof this literature review were used to refine ideas developed dur-ing the initial brainstorming phase In general each concept gen-erated was ranked on criteria including green-house gasemissions feedstock renewability and availability reliabilitycost fuel production (syngas output per unit biomass) and thestate of the technology The details of the literature review con-cept generation and concept selection process are discussed ingreater detail by Dean et al [7]

Two competing fluidized-bed biomass gasification technologieswere identified as the most promising for further analysis Thesetwo types were chosen due to their relatively high state of technol-ogy readiness and because they provide multiple opportunities forintegration of renewable electricity within a gasification plantOne concept involves direct grid leveling of intermittent wind

Fig 1 Wind and woody biomass resources2

Fig 2 Wind and agricultural biomass resources2

1Wind resources have a special resolution of 1=4 longitude by 1=3 latitudewhereas biomass resource data was available at the county level 2Maps created with the help of Donna Heimiller of the NREL GIS group

031801-2 Vol 133 SEPTEMBER 2011 Transactions of the ASME

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power with an indirectly heated biomass gasification plant Theplant will produce both electricity and hydrogen fuel The otherconcept uses an electrolyzer bank in place of an air separation unit(ASU) for a directly heated biomass gasifier for coproduction offuel and power

Analysis Objectives

The key research objectives were to (i) provide a high-leveltechnical evaluation of integration options of wind-generated elec-tricity with biomass gasification (ii) quantify the amount ofenergy production or energy absorption possible with a 2000 TPDbiorefinery (iii) estimate the cost of hydrogen production for eachhybridization option and (iv) compare the economic results withother hydrogen production systems such as steam methanereforming of natural gas

A plant input capacity of 2000 TPD of biomass was selectedfor the analysis based on resource availability Assuming an 80km (50-mile) collection radius multiple regions throughout thecountry were identified that could support this level of biomassrequirement At scales larger than 2000 TPD the number of possi-ble plant locations in the United States becomes severely limited[1] Woody biomass was used as the plant feedstock for all theconcepts studied Biomass type was not varied due to limitationsof the thermodynamic system model and concerns about the feasi-bility of feeding fibrous agricultural waste reliably Pilot plantssuch as the IGT RENUGAS plant have clearly demonstrated thedifficulty of feeding fibrous feedstock into a gasifier [8]

Based on a fixed biomass throughput baseline directly heatedand indirectly heated gasification plants were established ASPEN

Plus software was employed to determine the plant input and outputparameters for each system The baseline systems were optimizedfor hydrogen production using near term (2012 timeframe) tech-nologies For the indirectly heated gasifier a previously publishedsystem study was used as the baseline [9] Since there was not anexisting model available for the directly heated gasifier case amodel was constructed as part of this research Detailed informationabout the ASPEN Plus models can be found in Ref [10] With indi-rectly and directly heated baseline cases in place each plant wasmodified to incorporate the proposed hybrid concepts

The models for all plants were steady-state Control strategiesand the dynamic effects of intermittent operation were not consid-ered Instead the results of this study are intended to help informthe decision of whether the proposed systems deserve further con-sideration and dynamic simulation

Indirect Gasifier Based Hybrid System

The first concept investigated is based on indirectly heated gasi-fication architecture The schematic of the plant layout is providedin Fig 3 Indirectly heated gasification is a two-stage fluidized-bed process where the heat needed for the reaction is produced byburning char in a separate chamber to heat sand The hot sand isthen circulated through the reaction chamber to drive reactionkinetics

The biomass to hydrogen plant design proposed by Spath et al[9] was used as the baseline design Biomass entering the biorefi-nery is dried then gasified to produce syngas in an atmosphericpressure indirectly heated gasifier Tar is thermally cracked in acatalytic tar cracker The tar cracker must be heated because ofthe relatively low temperature (870 C) of the syngas leaving thegasifier Tar cracking temperatures typically exceed 900 C[911] Particulates and any tars remaining after the tar cracker areremoved from the syngas using a wet scrubber Sulfur is removedfrom the syngas in a two-step process of LO-CAT desulfurizationfollowed by ZnO polishing beds After sulfur has been removedthe carbon monoxide in the syngas stream is shifted towardshydrogen Finally the hydrogen is separated from the syngas viapressure swing adsorption (PSA) and the remaining (purge) gas isburned with a small natural gas trim to provide heat to the tarcracker

Two possible changes to the biorefinery design were investi-gated The first modification allows switching between fuel produc-tion and electricity production based on grid demand (ldquopeakingrdquo)This is accomplished by routing some or all of the syngas from thegasifier to a gas turbine instead of the fuel production reactors Thesecond modification allows the use of surplus electricity by the gas-ifier for heating (ldquosinkingrdquo) The conversion of wind-generatedelectrical energy to thermal energy within the gasifier effectivelyldquosinksrdquo the wind power into hydrogen fuel production Both ofthese operating modes are discussed in further detail in the subse-quent sections Accordingly analysis of each concept was separatedinto the peaking and sinking operating modes The two modifica-tions were analyzed individually to highlight their respective effecton plant performance and economics

An ideal hybrid plant would continuously adjust both electricityuse and fuel production to optimize plant economics Electricity isproduced instead of hydrogen when electricity is the more profita-ble product and vice-versa Similarly electricity is used for heat-ing (or sunk) when electricity costs are low enough that theadditional plant efficiency for hydrogen production offsets thecost of grid electricity

Indirect Gasifier Peaking Modifications Several modifica-tions are required to allow the baseline biorefinery to alternatebetween hydrogen production and electricity production Thesemodifications include adding a gas turbine to the plant and theaddition of several syngas routing provisions

A general electric (GE) F class simple-cycle turbine was chosenfor electricity production [12] The F-class turbines can achieve a20 increase in capacity when run on syngas (eg a turbine ratedfor 75 MW production on natural gas can produce up to 90 MW)depending on the syngas composition [12] The higher power pro-duction is due primarily to higher mass flow through the turbineWhen a nonstandard (low heating value) fuel is burned a higherfuel feed rate is needed to provide the same amount of energy tothe turbine According to one GE technical paper [13] up to 14deviation from catalogue flow rates can typically be achievedwhile avoiding compressor stall

Fig 3 Indirect gasifier baseline system

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-3

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Cooling issues can arise with syngas combustion depending onits composition Increased burner temperatures can shorten theservice life of a turbine as well as significantly increasing NOx

and SOx emissions Based on data from general electric gasifica-tion projects [13] and previous research performed at the NREL[14] syngas compositions similar to the ones used in this studyare typically humidified with steam before combustion to regulatethe turbine inlet temperature Steam was added to the syngas sothat the final fuel gas was 20 water by weight This correspondsto a lower heating value (LHV) of approximately 11 MJ=kg Thesteam was available from the on-site steam cycle

Syngas from the LO-CAT reactor is sent to the gas turbine dur-ing power generation Tar reforming is required because tars arecorrosive and could adversely affect the turbine combustor Inaddition the tar represents a significant portion of the chemicalenergy of the syngas and removal (versus reforming) would resultin a measurable decrease in plant efficiency Therefore directlyafter the tar reformer was the first possible location to split thesyngas stream for combustion However by placing the turbinedownstream of the bulk sulfur removal step emissions of SOx canbe significantly reduced

The system operates in a binary mode meaning that it eitherproduces power or hydrogen but not both at the same time Inaddition to potential dynamic operational issues associated withswitching between the two modes there are several steady-statetechnical challenges due to the high degree of thermal integrationin the base plant Down stream water-gas shift (WGS) catalystbeds are extremely sensitive to air exposure and therefore syngasflow must be maintained or they must be sealed if shut down Inaddition the pressure swing adsorption off-gas from hydrogenproduction is burned to heat the tar reformer This energy must bereplaced when the PSA is not running during power productionFinally the base design includes a thermally integrated steamcycle which is partially fed by syngas cooling steps downstreamof the split location Loss of this heat energy to the steam turbinewill adversely affect the plant power system

The first two technical challenges were both addressed bydiverting only a limited amount of syngas to the gas turbine whenproducing electricity A slipstream of syngas is maintainedthrough the water-gas shift reactors to avoid oxygen poisoning ofthe catalyst After going through the water-gas shift reactors thesyngas is routed to the tar reformer and burned to replace the PSAoff-gas that was previously burned to maintain temperature Thisapproach should keep the sensitive water-gas shift catalysts fromair and also meet the energy demands of the tar reformer systemIn addition all base design systems are kept warm and active(except for the PSA unit) until peaking power is no longer needed

In order to maintain the base plant steam system a portion ofthe exhaust gases from the gas turbine are run through a heatexchanger The heat exchanger exactly replaces heat loss fromcooling steps downstream of the split location

Table 1 summarizes the ASPEN PlusVR simulation results for thepeaking hybrid system When making hydrogen fuel the plant

would have the major input and output variables shown in the H2

production column The power production column shows theinput and output variables when the PSA unit is shut down

The power production value of 77 MW represents the net powerthe plant could produce using a ldquorubberrdquo turbine3 with GE F-classefficiencies The rubber turbine has a gross assumed nameplatecapacity of 806 MW but loses significant power due to plant para-sitic needs When running in a peaking capacity the plant has alow total efficiency of 178-LHV This is compared to an effi-ciency of 497-LHV when producing hydrogen and an expectedstand-alone turbine efficiency of approximately 32

The extremely low power production efficiency is the result ofmultiple factors including the fact that 21 of the syngas streamis used to maintain the water-gas shift reactors and tar cracker atelevated temperature rather than for power production In addi-tion a portion of the power output is used to serve auxiliary elec-trical loads within the plant

Capital costs were estimated using numbers taken from Ref [9]as a starting point In 2005 dollars the cost of a 2000 TPD biorefi-nery is estimated to be approximately $105 106 The cost of thegas turbine and additional heat exchangers were added to this costfor the hybrid case The gas turbine costs were taken from Ref[15] and then adjusted to $2005 using the Chemical EngineeringPlant Cost Index Heat exchanger costs were calculated with thesame scaling factors used in Ref [9] The additional capital costsfor the turbine and exhaust boiler feed water (BFW) preheater arelisted in Table 2

Indirect Gasifier Sinking Modifications Recent studies sug-gest that an indirectly heated gasifier will not produce enoughchar to maintain gasification temperatures therefore raw syngasmust be diverted and combusted to supplement the heat deliveredto the gasifier by the char combustor [16] Therefore during peri-ods of low electricity demand (low purchase price) electric heat-ers could be used to add heat and partially replace the syngasrecycle stream Electric heating allows more hydrogen to be pro-duced per ton of biomass feedstock which increases plantproduction

Supplementing the heat delivered to the gasifier by the charcombustor with electrically generated heat rather than divertingand combusting syngas could be accomplished in multiple ways[10] For this analysis high-power high-temperature electric airheaters were used By preheating the combustion air used inthe syngas and char combustors more heat can be delivered tothe sand per kilogram of char or syngas combusted resulting ina reduced amount of syngas that must be recycled The inten-tion is to allow intermittent use of the combustion air preheat-ers allowing the system to recycle syngas when electricityprices are high and add electric heat when electricity prices arelow

The ASPEN PlusVR simulation results are summarized in Table 3and appear to be promising The amount of syngas that must bediverted is reduced by about 45 by combustion air preheating

Table 1 Peaking system input and outputa

H2 productionmode

Power productionmode

Inputs (MW) Biomass feedb 434 434NG feedc 23 mdashElectricity 10 mdash

Outputs (MW) Electricity mdash 77H2

d 232 mdash

aWhere applicable mass flows were converted to energy flows with thefollowing lower heating valuesbA biomass LHV of 187 MJ=kg bone-dry wood was used [7]cNatural gas LHV of 4714 MJ=kg was used per HyARC database [23]dHydrogen LHV of 12021 MJ=kg was used per HyARC database [23]

Table 2 Indirect gasifier capital costs

Plant area Peaking Sinking

Baseline indirect gasifier planta $1049 M $1049 MTurbine $322 M mdashExhaust BFW preheater $025 M mdashAir duct heater and air blower mdash $158 MTotal $137 M $121 M

aThe baseline plant design and costs are based on Ref [9]

3The term ldquorubberrdquo turbine refers to the fact that the turbine size was set toexactly match fuel stream mass and energy flow as opposed to using an existingstock frame size

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Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

Additionally enough hot combustion products are still producedto dry the incoming biomass

Unlike the peaking modification which produced lower effi-ciency adding electric heat to the plant increases the total plantefficiency (energy in=energy out) from 497 to 503 Eachadditional unit of energy input as electricity produces 056 unitsof hydrogen energy output Therefore while providing a dispatch-able load service to the local utility the hybrid plant operatesmore efficiently

The electric heater capital costs are based on a quote providedby a manufacturer [17] for their largest high-temperature airduct heater Based on that quote a 22 MW air duct heater isestimated to cost $250000 and has an electricity-to-heated airconversion efficiency of 90 Since additional unit savings arenot expected with increasing scale a scaling factor of 09 wasused Finally an installation factor of 247 was assumed for allcost estimates for consistency with other NREL hydrogen analy-ses (H2A) [9] Based on these assumptions the total additionalcapital costs for electrically heating the combustion air amountedto $158 million

Direct Gasifier Based Hybrid System

Directly heated gasifiers typically have a single combustion=reaction chamber and burn a small portion of the biomass feed togenerate the heat needed to drive the gasification reactions Asource of pure oxygen is required for combustion if the syngas isto be used for fuel production to avoid nitrogen dilution of thesyngas For large-scale oxygen production the established methodis to use a cryogenic ASU Electrolysis could provide an alterna-tive to an ASU with the added benefit of producing an additionalpure hydrogen stream

Recent research on the feasibility of combining electrolysiswith gasification concluded that the economic feasibility of thecombination was highly dependent on the price of available elec-tricity [18] The proposed hybrid system could directly addresselectricity price dependence by running the electrolysis systemintermittently based on the cost of electricity

A baseline gasification plant (see Fig 4) and a hybrid plantwere simulated in ASPEN Plus and were compared Both the base-line and hybrid plants have the same general structure biomass isgasified to produce syngas in a high-pressure directly heated gas-ifier Tars are removed and the syngas is cooled before entering asulfur removal step After sulfur has been removed the carbonmonoxide in the syngas stream is shifted towards hydrogenFinally the hydrogen is stripped from the syngas and the remain-ing gas is burned to generate power Figure 4 shows the envi-sioned biomass to hydrogen pathway using the direct gasifier anda cryogenic ASU

The bulk of the chemical processes operate at high pressureThe wet scrubber is run near atmospheric pressure which requirescooling and recompression of the syngas before sulfur removalThe directly heated gasifier operating pressure selected in thisstudy was 24 bar and represents the state of the art in fluidized-bed biomass gasification systems It has been shown that highergasifier operating pressure is generally preferred when consideringgasifier efficiency and the heating value of the syngas [19] How-ever the sensitivity of gasifier performance increases if pressureis rather low For instance a doubling of gasifier pressure onlyincreases gasifier efficiency and heating value by 1ndash2 points[19] A detailed exploration of the effect of gasifier operatingpressure on the merit of the hybrid system proposed herein isbeyond the scope of this analysis but efficiency analyses and bio-refinery performance using pressurized gasifiers are reported else-where [20] Detailed discussion of the design assumptions andsimulation are available in Refs [710]

A cryogenic ASU is used to produce the oxygen for the baselinestudy In addition to producing oxygen a nitrogen stream is avail-able as a byproduct from the ASU and is used as the inert pressur-ization agent for the lock-hopper system To replace the ASUwith electrolyzers the LO-CAT=ZnO sulfur removal steps wouldneed to be replaced with a two-stage Selexol plant The sulfur re-moval change is driven by the need for an inert gas for feed pres-surization Since no nitrogen stream is available from theelectrolyzer carbon dioxide will be used for feed pressurizationinstead Selexol can be configured to remove both sulfur com-pounds and carbon dioxide from the syngas [21]

To replace a single ASU unit for oxygen production multipleelectrolyzers are needed The largest commercial electrolyzer isproduced by StatoilHydro and produces a maximum flow rate of174 kg=h of oxygen (436 kg=h of hydrogen) The StatoilHydroelectrolyzer is an alkaline low-temperature system [22] Whilesignificant research is ongoing for high-temperature advancedelectrolysis systems commercial technology was chosen for thisanalysis

Based on ASPEN simulations a 2000 TPD fluidized-bed biomassgasifier with secondary oxygen injection would need approxi-mately 27800 kg=h of oxygen supplied For this design 160 elec-trolyzers would be needed to replace the ASU This number

Table 3 Sinking system input and outputa

H2 production mode Sinking mode

Input (MW) Biomass feed 434 434NG feed 23 28

Electricity 10 57Output (MW) Electricity mdash mdash

H2 232 261

aWhere applicable mass flows were converted to energy flows with thesame heating values given in Table 1

Fig 4 Direct gasifier baseline system

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-5

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assumes that all electrolysis units run at design capacity 100 ofthe time

Input and output parameters from the electrolysis plant weredetermined from the published ldquoFuture Central Hydrogen Produc-tion from Grid Electrolysisrdquo H2A case [23] Based on ASPEN Plussimulations and the electrolysis H2A case the plant input and out-put values for the hybrid system were estimated The values foreach individual plant and the hybrid case are given in Table 4

The amount of electricity required to power the electrolyzerbank is extremely large when keeping the plant sized at 2000 TPDAssuming a 35 capacity factor for installed wind 970 MW of in-stalled wind capacity would be needed to generate enough averageelectricity for a 2000 TPD plant This is much larger than the totalamount of installed wind power in some states The large electricityneeds render the idea of capturing stranded resources with this scalebiorefinery plant problematic and ultimately infeasible However itis noteworthy that hydrogen production is also increased by 172over the base plant with this hybrid concept

While this study focuses on maintaining a 2000 TPD size biore-finery if instead the plant design objective was to deliver 165MW of hydrogen then the biomass feed requirement could belowered to approximately 920 TPD and the electricity demandreduced by 62 The reduction in biomass feedstock requirementswith this configuration is significant because it increases the num-ber of geographic locations that could support wind=biomasshybrid systems and ultimately lowers the land area requirementsfor sustainable fuel production

Multiple sources were used to estimate the capital costs associ-ated with the directly heated gasifier concepts All electrolyzercosts were calculated using the previously mentioned hydrogenanalysis [23] The majority of costs associated with the fluidizedbed gasifier and feed preparation were taken from a recent publi-cation by Jin et al [25] Gas cleanup costs were scaled based onprevious systems studies completed at the NREL [9] Selexol pri-ces were based on Department of Energy estimates [26] An over-view of the capital costs can be found in Table 5 Detailed costinginformation for both systems is available in Refs [710]

Based on the cost information summarized in Table 5 directreplacement of the ASU with an electrolyzer bank causes a 72increase in the total capital investment required

Economic Model

The hybrid system concepts studied respond dynamically tofluctuations in the energy market either absorbing or providingelectricity on demand To simulate this switching a binary modelwas created for each proposed system based on a specified peak-ing or sinking duty Duty is defined as the percent of hours peryear where either sinking or peaking mode is used

All concepts were assumed to be grid-connected for the analy-sis The hybrid plants are intended to provide grid leveling serv-ices to a local utility that has intermittent wind resources Thisarrangement allows for direct assessment of the market value ofelectricity and avoids inclusion of wind turbine capital costs in thecost of the system For the directly heated gasifier hybrid systemthe effect of stranded operation is discussed briefly in the eco-nomic results section of this paper

Regional Transmission Organization (RTO) day-ahead priceswere used for the cost-of-electricity when available These pricesrepresent the market value of electricity to the local utilities in anarea on an hourly averaged basis The hybrid systems must beprofitable at this low price point to cost effectively trade electric-ity on the energy market When day-ahead market informationwas unavailable load lambda data was used in its place Loadlambda data give the cost of producing one unit of electricity tothe utility for each hour of the year In all cases costs were basedon 2007 year-end data Based on GIS research reported earlier(see Figs 1 and 2) three general areas appear to have overlappingresources of both wind and biomass These areas are served by theNortheast Independent System Operator (NE ISO) Midwest ISO(MISO) and Northwest Interchange (NW Int) Cost of electricityvalues for each of these areas was used in the analysis

To assess the economic potential of each of the proposedhybridizations the yearly inputs and outputs for each plant alongwith applicable capital costs were entered into the H2A AnalysisTool developed by NREL [27] The resulting cost of hydrogenproduced (in dollars per kilogram) was compared to baseline plantresults and also the published steam methane reforming results[28] The analysis was performed in 2005 constant dollars for con-sistency with previous NREL studies [928]

The price of natural gas was held static for each of the regions stud-ied The 2009 Annual Energy Outlook report predicts regional varia-tion of natural gas prices in the US of approximately three dollars permillion Btu [29] The predicted variation translates to approximately10 cents per normal cubic meter The sensitivity analysis for each ofthe hybrid plants shows the effects of a larger 30 variation in naturalgas prices The SMR base case is also sensitive to natural gas priceswith a $010 per normal cubic meter variation in price gas price caus-ing a $047 change in the cost of hydrogen produced [28]

The economic analysis makes several assumptions includingthat current electricity prices are representative of those at thetime of actual plant construction and that sufficient marketdemand for hydrogen exists that all product can be sold Themajor economic assumptions are summarized in Table 6 Addi-tionally values for rate of return and startup times for the plantsare selected to enable comparison with other studies on hydrogenproduction from resources such as methane (see Tables 8 and 9)For this reason all economic assumptions were taken directlyfrom H2A defaults [27]

The effects of carbon costs on system results were taken intoaccount separately as an adjustment to the H2A results Theamount of CO2e per kilogram of hydrogen produced was trackedfor all cases analyzed The emissions for each hybrid system varynot only with the type of hybridization but also with the amountof time spent in each mode of operation Values for these emis-sions are given with the economic results

In addition to including the CO2e emissions from the plantthere is a CO2e credit associated with carbon emissions avoideddue to the renewable nature of any fuel or electricity producedBased on the regional average grid mix anywhere from 483 to 724kg of CO2e are emitted per kilowatt-hour of electricity produced

Table 4 Direct gasifier input and outputa

Baseline plant Hybrid plant

Input (MW) Biomass feedb 411 411NG feed mdash mdash

Electricity mdash 342Output (MW) Electricity 15 mdash

H2 165 449

aWhere applicable mass flows were converted to energy flows with thesame heating values given in Table 1bA biomass LHV of 177 MJ=kg bone-dry wood was used due to slightlydifferent simulation feedstock [24]

Table 5 Direct gasifier capital costs

Plant area Baseline Hybrid

Feed preparation handling $279 M $279 MGasification tar reforming quench $227 M $227 MASU or electrolyzer bank $213 M $992 MGas cleanup $299 M $587 MShift and PSA $186 M $186 MSteam and power generation $204 M $204 MWater and other utilities $21 M $37 MBuildings and structures $64 M $64 MTotal $1493 M $2576 M

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Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

Table 7 details the grid production mix and correspondingemissions for each location studied The values shown in Table 7are assumptions in so much as they are averaged values for largeprocesses or regions Table 7 is actually a calculation matrix Asan example for the column ldquoNE ISOrdquo the calculation for the aver-age greenhouse gas emission for each kilowatt-hour of energyproduced is shown in Eq (1)

0150 9525thorn 0180 8931thorn 0300 5992 frac14 483 (1)

One kilogram of hydrogen has the approximate energy equivalentof 1 gal of gasoline However because hydrogen can be used infuel cells with much higher efficiency 1 kg of hydrogen couldactually offset about 2 gal of gasoline [30] Burning 2 gal of gaso-line produces 1784 kg of CO2e These numbers were used as car-bon credits for each kilogram of hydrogen or megawatt-hour ofelectricity produced by the proposed systems

Economic Results

The proposed indirectly heated gasifier peaking systemswitches between (1) hydrogen production and (2) electricity pro-duction (peaking) driven by the cost of electricity available on thegrid Based on discussions with Xcel Energy in Colorado [34] apeaking duty of 20 was used for the analysis Table 8 summa-rizes the major model inputs by region for the system A contractrate was used for any peaking electricity produced by the plantThis is common practice in the current electricity market and pro-vides a premium price for dispatchable peaking assets The cost ofbiomass feedstock was not varied regionally due to a lack of areliable index or market basis upon which to base the variation

Instead the effect of biomass feedstock cost was investigated aspart of the sensitivity analysis

Based on the economic inputs above and the plant inputs andoutputs previously discussed the cost of hydrogen production ineach area was calculated The results are shown in Table 9 alongwith the cost of hydrogen production for a baseline nonhybri-dized biomass to hydrogen plant and a SMR plant

The additional capital costs of hybridization cannot be justifiedtoday in any of the locations studied There is a $020 to $024 perkilogram premium on hydrogen produced by the proposed hybridsystem compared with a nonhybrid biomass to hydrogen gasifica-tion plant Areas with higher priced electricity move this hybrid-ization closer to economic feasibility with the best results foundin the Northeast

When the hybrid plant is producing electricity the plant usesno natural gas or electricity whereas when the plant is producinghydrogen natural gas is used for balancing the heat duty of theplant and electricity is required to run compressors Taking thedifferences in carbon emissions into account a value of $37ndash40per metric ton of CO2e makes the cost of hydrogen for the pro-posed hybrid system equal to that of SMR depending on the loca-tion This comparison was made assuming that both the hybridplant and SMR plant are subject to the same natural gas cost at agiven location

It is important to note that the baseline biomass to hydrogenplant only requires $23ndash25 per metric ton of CO2e value to becost competitive with hydrogen produced by SMR This meansthat peaking hybridization will only be economically promisingwhen there is some value placed on the additional functionality ofdual mode operation

In order to characterize the effect of various technical and eco-nomic assumptions a sensitivity analysis was performed for thegas turbine peaking system Figure 5 shows the results for the costof hydrogen in tornado chart format Capital costs the cost of bio-mass and the price which peaking electricity can be sold for arethe key inputs Capital costs when varied 630 cause the cost ofhydrogen to vary $025 The cost of biomass was varied from $40to $60 per ton based on projections in Ref [35] and causes thecost of hydrogen to vary by less than $020 The price of peakingelectricity and the plant capacity factor also cause fluctuations ofless than $020 Changes in the cost of electricity bought by theplant the cost of natural gas peaking power output and turbinepeaking duty cause hydrogen costs to vary less than 5

The proposed sinking system switches between (1) hydrogenproduction with syngas recycling for gasifier heat and (2) hydro-gen production with electrical heating (sinking) to decrease the

Table 7 Greenhouse gas assumptions

kg CO2e per kW ha NE ISOb MISOc NW Intd

Coal 9525 150 756 580Oil=petroleum 8931 180 01 10Natural gas 5992 300 36 197Nuclear mdash 280 151 10Renewable mdash 90 56 203Average kg CO2e=kW h mdash 483 743 679

aHyARC Energy Constants and Assumptions H2A Analysis Tool [26]bNE ISO energy sources report [31]cMidwest ISO June monthly report [32]dApproximation based on PacifiCorp 2008 integrated resource plan [33]

Table 8 Peaking system H2A inputs

NE ISO MISO NW Int

Peaking duty 20 20 20Peaking electricity value (cent=kW h) 140 120 115Utility electricity cost (cent=kW h) 592 362 369Utility natural gas cost ($=nm3) 032 032 032Cost of biomass ($=ton)a 4883 4883 4883

aValue taken from the Biomass 2009 Multi-Year Research Developmentand Demonstration Plan (EERE 2009) The 2012 target value is $5070per ton of dry woody biomass in 2007 dollars Taken to 2005 dollars with109 inflation this yields $4883 per ton

Table 9 Peaking system results

$=kg H2 NE ISO MISO NW Int

SMR 140 140 140Biomass to hydrogen baseline 164 164 164Gas turbine hybrid system 184 186 188

Table 6 Economic assumptions

Parameter Value

Constant dollar value 2005Internal rate of return (after-tax) 10Debt=equity 0=100Plant life 40 yearsDepreciation Modified accelerated cost recovery systemDepreciation recovery period 20 yearsConstruction period 2 years

1st year 75 (25 for electrolysis)2nd year 25 (75 for electrolysis)

Start-up time 12 monthsRevenues 50Variable costs 75Fixed costs 100

Working capital 15 of total capital investmentInflation rate 19Total taxes 389Decommissioning costs 10 of depreciable capitalSalvage value 10 of total capital investment

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-7

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

syngas recycle This sinking ability can best be described as a dis-patchable load or demand from the viewpoint of the grid

Based on discussions with Xcel Energy the utility will pay tohave wind-generated electricity used at times (the electricity has anegative cost) and having a dispatchable load would provide avaluable service to the utility [34] Xcel Energy is required byColoradorsquos renewable portfolio standard to accept renewableenergy when it is available The requirement to accept wind elec-tricity regardless of grid demand is not universal and thereforenegative cost wind electricity may not be available in other states

No similar system was found for comparison therefore a sink-ing duty of 20 was used as a starting point for the analysisTable 10 summarizes the major economic model inputs by regionUnlike peaking electricity where a contract rate is used for elec-tricity produced by the plant the sinking analysis simply uses theaverage cost-of-electricity for the cheapest 20 of hours as thesinking electricity cost The utility electricity cost is the averageof the remaining 80 of the hours These costs-of-electricitywould be valid if a plant operator used accurate day-ahead energymarket forecasts to schedule plant operation

Given the economic inputs in Table 10 the cost of hydrogenproduction in each area was calculated The results are shown inTable 11 along with the cost of hydrogen production for a base-line nonhybridized biomass to hydrogen plant and a steam meth-ane reforming plant

There is a $003 to $011 premium on hydrogen produced bythe proposed hybrid system compared with a nonhybrid biomassto hydrogen gasification plant The additional capital costs of the

sinking hybridization are not fully offset by additional revenue inany of the locations studied However the marginal costs foundare small enough that it is difficult to draw any definitive conclu-sion Areas with lower cost electricity move this hybridizationcloser to economic feasibility with the best results found in theNorthwest

Because the premium is small (about 5) it may be acceptablein the long term Recent studies have shown that there is inherentvalue added or welfare effects for electricity storage capacity[36] Whether similar value is added by the proposed sinkinghybrid is unknown A more likely parallel would be the idea ofldquointerruptible customersrdquo which get discounted electricity rates inreturn for intermittent power supply A similar contractual agree-ment could be envisioned for the proposed hybrid where dis-counted electricity rates would be provided in return forintermittent demand

The proposed system is not a direct competitor with storagesystems such as pumped hydroelectric or compressed air energystorage (CAES) Energy storage systems attempt to profit by mar-ket arbitrage (selling electricity back to the grid at a higher pricethan it was bought) whereas the proposed hybrid system sinkscheap electricity into transportation fuel Sinking low cost elec-tricity into fuel could be considered cross-market arbitrage andthe most similar system to this would be electrolysis Comparedto electrolysis the proposed system is significantly less expensiveand has the added benefit of running without electric heat whenelectricity costs are too high

Assuming that all sinking electricity is renewable and takingthe additional differences in carbon emissions into account avalue of $26ndash32 per metric ton of CO2e makes the proposedhybrid cost competitive depending on the location of the system

Fig 5 Peaking system sensitivity (NE ISO)

Table 10 Sinking system H2A inputs

NE ISO MISO NW Int

Plant capacity factor 90 90 90Sinking duty 20 20 20Sinking electricity cost (cent=kW h) 435 220 218Utility electricity cost (cent=kW h) 705 487 469Utility natural gas cost ($=nm3) 032 032 032Cost of biomass ($=ton) 4883 4883 4883

Table 11 Indirect sinking system results

$=kg H2 NE ISO MISO NW Int

SMR 140 140 140Biomass to hydrogen baseline 164 164 164Electric air heater hybrid system 175 167 168

031801-8 Vol 133 SEPTEMBER 2011 Transactions of the ASME

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

At $27 per metric ton of CO2e the combustion air-heater hybrid-ization becomes cost competitive with a methane steam reformingplant in the Northwest assuming both the hybrid plant and SMRplant are subject to the same natural gas cost

In order to characterize the effect of various technical and eco-nomic assumptions a sensitivity analysis was performed for thesinking systems (Fig 6) The sensitivity analysis shows that capi-tal costs the cost of biomass and the plant capacity factor for arethe key inputs Capital costs when varied 630 cause the cost ofhydrogen to vary $018 The cost of biomass was varied from $40per ton to $60 per ton and causes the cost of hydrogen to vary byless than $015 Changes in the sinking duty the added hydrogenproduction due to sinking the cost of natural gas and the cost ofelectricity cause hydrogen costs to vary less than 3

From the sinking duty sensitivity analysis it appears that anincreased sinking duty would be preferable to the 20 assumptionmade Minimum hydrogen production prices occur when the elec-tric heating systems are run approximately 40 of the time Run-ning the electric heaters for more time increases plant hydrogenproduction and decreases plant green house gas emissions

The proposed directly heated gasifier hybrid system replacesthe ASU with an electrolyzer bank An H2A analysis was com-pleted to determine the baseline cost of hydrogen produced by adirectly heated gasification plant that uses electrolysis regardlessof electricity cost and the cost of hydrogen for a directly heatedgasification plant that uses a traditional ASU Table 12 summa-rizes the major model inputs The plant was assumed to be locatedin the Midwest ISO region The results of the analysis along withthe associated carbon emissions are listed in Table 13 Costs forproduction of hydrogen via SMR and for an electrolysis plantonly are also shown for reference purposes

As shown in Table 13 hydrogen produced by a direct gasifier-electrolyzer hybrid plant is significantly more expensive than thatproduced by SMR Electricity costs account for 37 of the overallcost of hydrogen produced (or about $086) Therefore if the costof electricity could be halved by intermittent operation during off-peak hours the savings would bring the cost of hydrogen to $189per kilogram of hydrogen At this price the hybrid system couldcompete with hydrogen produced by a standard direct gasificationplant It is important to note that these costs are approximately15 higher than the $164 per kilogram of hydrogen estimated forthe indirectly heated baseline gasification plant used for compari-son of the indirect hybrid analysis (see Table 11)

The original concept called for the electrolyzer bank to bedirectly coupled with stranded wind resources Typical capacityfactors for wind-generated power are in the 30ndash35 range [37]The effect of intermittent operation on the cost of hydrogen pro-duction was investigated using electrolyzer duties of 20 35and 50 The smaller the duty the larger the number electrolyz-ers needed to produce the same amount of oxygen per year

The effect of reduced electrolyzer duty on the cost of hydrogenis shown in Fig 7 Two curves are plotted The first assumes aconstant electricity price of $433=MWh regardless of the electro-lyzer duty This assumption would represent the scenario if theelectrolyzers were directly coupled with a stranded wind resourceThe second curve uses Midwest ISO market data so that the costof electricity fluctuates with duty These numbers do not considerthe cost of oxygen storage as these costs are assumed small com-pared to the increased electrolyzer capital costs and are identicalfor similar duty

Intermittent operation significantly adds to plant capital costsIf the price of electricity available to the plant does not decrease

Fig 6 Sinking system sensitivity (NW Int)

Table 12 Direct system H2A inputs

MISO

Electrolyzer duty () 100Utility electricity cost (cent=kW h) 433Cost of biomass ($=ton) 4883

Table 13 Direct system results

$=kg H2 Net CO2e=kg H2

SMR $140 68Biomass gasification $213 196Electrolysis $259 145 (178)Electrolysisthorn gasification $232 024 (182)

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-9

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

with intermittent electrolyzer operation then the cost of hydrogenincreases by 22 for a 35 duty However if the cost of electric-ity can be reduced by intermittent operation then the analysisshows that intermittent operation may be preferable to 100 dutyThis result means that the initial concept of capturing strandedresources is less favorable economically than a grid-connectedsinking system

If grid electricity is used then carbon emissions actuallyincrease relative to biomass gasification alone for this hybridiza-tion If upstream emissions for electricity production are takeninto account electrolysis and this proposed hybrid are both netCO2e emitters This makes their justification by carbon valueimpossible unless only renewable electricity is used for operation(renewable energy values are shown in parentheses in Table 13)Since renewable wind energy is inherently intermittent it isunreasonable to assume renewable electricity is used without add-ing the necessary equipment for intermittent operation Onerenewable energy exception would be the use of hydroelectricpower for the systems

Similar to the other hybrid systems investigated hybridizationresults in a price premium There must be some additional justifi-cation for hybridization such as utility demands The baseline bio-mass to hydrogen case with an ASU requires only $35 per metricton of CO2e to be cost competitive with SMR produced hydrogen

assuming both the hybrid plant and SMR plant are subject to thesame natural gas cost at a given location

Electrolyzer-based hybrid system economics are extremely sen-sitive to the cost of electricity (Fig 8) Fluctuations of $001 inthe cost of electricity cause the price of hydrogen to fluctuatemore than $025 per kilogram If the price of electricity were todrop below $004=kW h then the proposed hybrid system couldeconomically compete with a nonhybrid biomass to hydrogenplant However this low price level is unlikely and any energymarket fluctuations would have a dramatic effect on economicviability

Conclusion

The two hybrid concepts analyzed involve coproduction of gase-ous hydrogen and electric power from thermochemical-based biorefi-neries Both of the concepts analyzed share the basic idea ofcombining intermittent wind-generated electricity with a biomassgasification plant Wind availability overlaps biomass resource avail-ability in three areas of the United States making the use of locallyproduced wind electricity for gasification feasible The proposedhybrid systems attempt to either fill wind energy shortfalls by burn-ing syngas in a natural gas turbine or absorb excess renewable powerduring times of low-electricity demand

None of the proposed hybrid systems produced hydrogen forless than a nonhybrid plant could In all cases a premium was paidfor hybridization that could not be offset by the increasedfunctionality

The indirectly heated gasifier hybrid system consists of twoparts (1) producing peaking electricity intermittently with a gasturbine and (2) sinking electricity into electric heaters intermit-tently to boost fuel production efficiency Each of these parts wasanalyzed separately The indirectly heated gasifier hybrid systemis meant to be grid-connected and provide peaking electricity anddispatchable demand (eg an on demand load) to the local utilityto help manage intermittent wind resources

The indirect gasification concepts studied could be cost compet-itive in the near future as value is placed on controlling carbonemissions Carbon values of just under $40 per metric ton ofCO2e make the systems studied cost competitive with steam

Fig 7 Electrolyzer duty versus cost

Fig 8 Direct system sensitivity

031801-10 Vol 133 SEPTEMBER 2011 Transactions of the ASME

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

methane reforming to produce hydrogen However a nonhybridbiomass to hydrogen plant will be more cost competitive in gen-eral so there must be additional operational value placed on peak-ing or sinking for these plants to be economically attractive Thisadditional value is likely to become a reality as additional inter-mittent renewable energy sources such as wind are added to thenational grid

The directly heated gasifier hybrid system involves replacementof the air separation unit with electrolyzers This change allowsfor extra production of hydrogen and intermittent operation Theanalysis for this system assumed direct replacement of the ASUwithout intermittent operation Estimates of the effect of intermit-tent operation on plant economics were made The electrolyzerbank could be either grid-connected to provide a dispatchabledemand to the utility or it could be tied directly to a stranded windsource to convert wind into chemical fuel (H2)

The direct gasification concept studied is unlikely to be cost com-petitive in the near future but may eventually be attractive withlower-cost electrolysis and a smaller biorefinery plant size that issized for a specific hydrogen demand Intermittent operation andstranded operation were found to have worse economics than grid-connected systems High electrolyzer capital costs make the possibleelectricity cost savings of intermittent operation difficult to justifyBased on a direct replacement of the ASU with electrolyzers hydro-gen can be produced for $232 per kilogram However using gridelectricity the hybrid system is a net CO2e emitter For the use ofelectrolysis to make sense in this setting there must be a significantbenefit to the ability to operate intermittently

Acknowledgment

The authors would also like to acknowledge Dr Bob Evans forconceiving the hybrid hydrogen production systems project andDonna Heimiller for performing the GIS mapping

Employees of the Alliance for Sustainable Energy LLC underContract No DE-AC36-08GO28308 with the US Dept ofEnergy have authored this work The United States Governmentretains and the publisher by accepting the article for publicationacknowledges that the United States Government retains a nonex-clusive paid-up irrevocable worldwide license to publish orreproduce the published form of this work or allow others to doso for United States Government purposes

References[1] Milbrandt A 2005 ldquoA Geographic Perspective on the Current Biomass

Resource Availability in the United Statesrdquo National Renewable Energy LabReport No TP-560-39181

[2] Perlack R Wright L Turhollow A Graham R Stokes B and Erbach D2005 Biomass as Feedstock for a Bioenergy and Bioproducts Industry The Tech-nical Feasibility of a Billion-Ton Annual Supply Oak Ridge National LaboratoryOak 853 Ridge TN

[3] Turner J Sverdrup G Mann M Maness P C Kroposki B Ghirardi MEvans J and Blake D 2008 ldquoRenewable Hydrogen Productionrdquo Int JEnergy Res 32 pp 379ndash407

[4] US Department of Energy Energy Efficiency and Renewable Energy Labora-tory 2008 ldquo20 Wind Energy by 2030mdashIncreasing Wind Energyrsquos Contribu-tion to US Electricity Supplyrdquo Report No GO-102008-2567

[5] Levene J Kroposki B and Sverdrup G 2006 ldquoWind Energy and Productionof Hydrogen and ElectricityndashOpportunities for Renewable Hydrogenrdquo NationalRenewable Energy Laboratory Report No CP560-39534

[6] Fingersh L 2004 ldquoOptimization of Utility-Scale Wind-Hydrogen-BatterySystemsrdquo National Renewable Energy Laboratory Report No CP-500-36117

[7] Dean J Braun R Munoz D Penev M and Kinchin C 2010 ldquoAnalysis ofHybrid Hydrogen Systems ndash Final Reportrdquo National Renewable Energy Labo-ratory Report No TP-46934

[8] Gasification Technology Status ndash December 2006 EPRI and the Gasification869 Users Association Palo Alto CA p 1012224

[9] Spath P Aden A Eggeman T Ringer M Wallace B and Jechura J2005 ldquoBiomass to Hydrogen Production Detailed Design and Economics Uti-lizing the Battelle Columbus Laboratory Indirectly-Heated Gasifierrdquo NationalRenewable Energy Laboratory Report No TP-510-37408

[10] Dean J 2010 ldquoLeveling Intermittent Renewable Energy Production ThroughBiomass Gasification-based Hybrid Systemsrdquo MS thesis Colorado School ofMines Golden CO

[11] Devi L Ptasinski K Janssen F van Paasen S Bergman P and Kiel J2005 ldquoCatalytic Decomposition of Biomass Tars Use of Dolomite anUntreated Olivinerdquo Renewable Energy 30 pp 565ndash587

[12] Heavy Duty Gas Turbine Products 2009 General Electric Company FairfieldCT

[13] Drdar D and Jones R 2000 ldquoGE IGCC Technology and Experience withAdvanced Gas Turbinesrdquo GE Power Systems Report No GER-4207

[14] Craig K and Mann M 1996 ldquoCost and Performance Analysis of Biomass-Based Integrated Gasification Combined-Cycle (BIGCC) Power SystemsrdquoNational Renewable Energy Laboratory Report No TP-430-21657

[15] Gas Turbine World 2006 Handbook (Pequot Publishing Inc Fairfield CT2006)

[16] Kinchin C and Bain R 2009 ldquoHydrogen Production from Biomass via Indi-rect Gasification The Impact of NREL Process Development Unit GasifierCorrelationsrdquo National Renewable Energy Laboratory Report No TP-510-44868

[17] Watlow for 22 MW duct heaters Watlow 12001 Lackland Road St LouisMO 63146 personal communication 2009

[18] Gassner M and Marechal F 2008 ldquoThermo-economic Optimization of theIntegration of Electrolysis in Synthetic Natural Gas Production from WoodrdquoEnergy 33 pp 189ndash198

[19] Srinivas T Gupta A V S and Reddy B V 2009 ldquoThermodynamic Equi-librium Model and Exergy Analysis of a Biomass Gasifierrdquo ASME J EnergyResour Technol 131 031801 pp 1ndash7

[20] Braun R J Hanzon L G and Dean J H 2011 ldquoSystem Analysis of Ther-mochemical-based Biorefineries for Coproduction of Hydrogen and Elec-tricityrdquo ASME J Energy Resour Technol 133 012601 pp 1ndash12

[21] Manning F and Thompson R 1991 Oilfield Processing of Petroleum Vol-ume One 904 Natural Gas PennWell Publishing Co Tulsa Oklahoma

[22] StatoilHydro 2009 ldquoHydrogen Technologies World Leader in Electrolysis forHydrogen Solutionsrdquo product brochure Hydrogen Technologies NO-3674Notodden Norway COS 091408 available URL http908wwwelectrolyserscom

[23] US Department of Energy Hydrogen Program 2009 ldquoFuture Central Hydro-gen Production from Grid Electrolysisrdquo H2A analysis wwwhydrogenenergygovh2a_prod_studieshtml

[24] Phyllis Biomass Datapage ldquowood hybrid poplarrdquo ID 806 available URLhttpwwwecnnlphyllis

[25] Jin H Larson E and Celik F 2009 ldquoPerformance and Cost Analysis ofFuture Commercially Mature Gasification-Based Electric Power GenerationFrom Switchgrassrdquo Biofpr 3 pp 142ndash173

[26] Department of Energy 2007 ldquoCost and Performance Baseline for Fossil EnergyPlants Volume 1 Bituminous Coal and Natural Gas to Electricityrdquo Report NoDOE=NETL-2007=1281

[27] US Department of Energy Hydrogen Program 2009 ldquoDOE H2A Analy-sisrdquo wwwhydrogenenergygovh2a_analysishtml

[28] US Department of Energy Hydrogen Program 2009 ldquoFuture Central Hydro-gen Production from Natural Gas with CO2 Sequestrationrdquo H2A analysiswwwhydrogenenergygovh2a_prod_studieshtml

[29] Energy Information Administration Annual Energy Outlook 2009 wwweiadoegovoiafaeoelectricityhtml

[30] Schafer A Heywood J and Weiss M 2006 ldquoFuture Fuel Cell and InternalCombustion Engine Automobile Technologies A 25-Year Life Cycle and FleetImpact Assessmentrdquo Energy 31 pp 2064ndash2087

[31] NE ISO 2009 ldquoEnergy Sources in New Englandrdquo wwwiso-necomnwsissgrid_mktsenrgy_srcs

[32] Doying R 2009 Midwest ISO ldquoJune Monthly Reportrdquo wwwmidwestisoorg[33] PacifiCorp 2009 ldquoIntegrated Resource Plan ndash Volume 1rdquo May 29 2009

wwwpaci-937ficorpcom[34] Frank Novachek 2009 Xcel Energy 414 Nicollet Mall Minneapolis MN

55401 939 personal communication[35] Energy Efficiency and Renewable Energy Department of Energy ldquoBiomass

2009 Multi-Year Research Development and Demonstration Planrdquo www1eer-eenergygovbiomasspdfsmypp_may2009pdf

[36] Sioshansi R Denholm P Jenkin T and Weiss J 2009 ldquoEstimating theValue of Electricity Storage in PJM Arbitrage and Some Welfare EffectrdquoEnergy Econ 31 pp 269ndash277

[37] Kroposki B Levene J Harrison K Sen P K and Novachek F 2006ldquoElectrolysis Information and Opportunities for Electric Power UtilitiesrdquoNational Renewable Energy Laboratory Report No TP-581-40

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-11

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

intermittently utilized by a properly designed biomass plant tocreate transportable fuel The goal of this research is to determinethe technical and economic viability of wind=biomass hybrid sys-tems ASPEN Plus thermodynamic simulation software was used incombination with time value of money economic analysis toexplore the concepts presented

Colocation Feasibility

For wind and biomass hybridization to be feasible the tworesources must be colocated To confirm the possibility of coloca-tion maps were constructed that overlaid class 4 or higher windresources onto biomass resources Based on the US Departmentof Energyrsquos definitions of wind power classes mapped resourceshave average wind speeds of greater than 56 m per second and anaverage wind power density of greater than 200 W=m2 at a heightof 10 m Biomass availability data was taken from a previousstudy [1] and combined with wind resource information with thehelp of the National Renewable Energy Laboratory (NREL) geo-graphic information systems (GIS) group For both of the mapsdepicted in Figs 1 and 2 the wind resources are shown in red andexclude potentially environmentally sensitive lands wind onwater features and small isolated areas The green shading onboth maps indicate that greater than 2000 tons per day (TPD) ofthe specified type of biomass is available within an 80 km (50-mile) radius Given the extent of green-area shading within thesefigures any specific location within a shaded region is viable TheGIS maps do not account for competition for biomass resources(ie other biomass plants in the region) There are areas wherethe wind data are difficult to observe because the spatial resolutionon the wind resources is much finer than the biomass1 so the areasof red can be difficult to distinguish

Figure 1 shows woody biomass resources overlaid on availablewind Woody biomass includes forest residues and mill residuesMill residues include the bark and wood materials produced whenlogs are processed into lumber and wood scraps from factories suchas furniture manufacturers There are small pockets of the north-west and northeast where both class 4 or greater wind and sufficientwoody biomass exist for a colocated combined system

Figure 2 shows agricultural (crop) residue biomass resourcesversus available wind Crop residues considered included cornwheat soybeans cotton sorghum barley oats rice rye canolabeans peas peanuts potatoes safflower sunflower sugarcaneand flaxseed Residue estimates were adjusted down to allow forsoil erosion control animal feed bedding and other existing farmuses consistent with Milbrandt [1] There is significantly moreoverlap of agricultural biomass with wind than woody biomassand wind

Both figures2 show overlap of biomass resources and windavailability The overlap of woody biomass and land-based windis small However some of the areas may have access to sea-based wind resources that were not considered here and windinstallations do exist in areas that have less than class 4 wind Ag-ricultural biomass and wind overlap in a large part of the MidwestThis result shows that wind=biomass hybridization could providea useful service in some areas of the central United States Theconcept will not generally be applicable outside of these areas

Concept Selection

Increased penetration of wind power on the grid will result inunique challenges These challenges include management of inter-mittency with electric power peaking units and in the extremecase finding use for electricity produced by wind when there isless demand than the energy produced Managing intermittencywill drive utilities to invest in additional peaking units andincrease the need for interruptible customers energy storageoptions and dispatchable loads

Direct integration between a thermochemical biomass plant andwind power could allow a hybrid system to manage local intermit-tency or capture stranded wind resources The proposed hybridsystems are intended to fill wind energy shortfalls and=or absorbexcess wind-generated power

A literature review was undertaken to determine the currentstate of research with respect to biomass hybridization The resultsof this literature review were used to refine ideas developed dur-ing the initial brainstorming phase In general each concept gen-erated was ranked on criteria including green-house gasemissions feedstock renewability and availability reliabilitycost fuel production (syngas output per unit biomass) and thestate of the technology The details of the literature review con-cept generation and concept selection process are discussed ingreater detail by Dean et al [7]

Two competing fluidized-bed biomass gasification technologieswere identified as the most promising for further analysis Thesetwo types were chosen due to their relatively high state of technol-ogy readiness and because they provide multiple opportunities forintegration of renewable electricity within a gasification plantOne concept involves direct grid leveling of intermittent wind

Fig 1 Wind and woody biomass resources2

Fig 2 Wind and agricultural biomass resources2

1Wind resources have a special resolution of 1=4 longitude by 1=3 latitudewhereas biomass resource data was available at the county level 2Maps created with the help of Donna Heimiller of the NREL GIS group

031801-2 Vol 133 SEPTEMBER 2011 Transactions of the ASME

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

power with an indirectly heated biomass gasification plant Theplant will produce both electricity and hydrogen fuel The otherconcept uses an electrolyzer bank in place of an air separation unit(ASU) for a directly heated biomass gasifier for coproduction offuel and power

Analysis Objectives

The key research objectives were to (i) provide a high-leveltechnical evaluation of integration options of wind-generated elec-tricity with biomass gasification (ii) quantify the amount ofenergy production or energy absorption possible with a 2000 TPDbiorefinery (iii) estimate the cost of hydrogen production for eachhybridization option and (iv) compare the economic results withother hydrogen production systems such as steam methanereforming of natural gas

A plant input capacity of 2000 TPD of biomass was selectedfor the analysis based on resource availability Assuming an 80km (50-mile) collection radius multiple regions throughout thecountry were identified that could support this level of biomassrequirement At scales larger than 2000 TPD the number of possi-ble plant locations in the United States becomes severely limited[1] Woody biomass was used as the plant feedstock for all theconcepts studied Biomass type was not varied due to limitationsof the thermodynamic system model and concerns about the feasi-bility of feeding fibrous agricultural waste reliably Pilot plantssuch as the IGT RENUGAS plant have clearly demonstrated thedifficulty of feeding fibrous feedstock into a gasifier [8]

Based on a fixed biomass throughput baseline directly heatedand indirectly heated gasification plants were established ASPEN

Plus software was employed to determine the plant input and outputparameters for each system The baseline systems were optimizedfor hydrogen production using near term (2012 timeframe) tech-nologies For the indirectly heated gasifier a previously publishedsystem study was used as the baseline [9] Since there was not anexisting model available for the directly heated gasifier case amodel was constructed as part of this research Detailed informationabout the ASPEN Plus models can be found in Ref [10] With indi-rectly and directly heated baseline cases in place each plant wasmodified to incorporate the proposed hybrid concepts

The models for all plants were steady-state Control strategiesand the dynamic effects of intermittent operation were not consid-ered Instead the results of this study are intended to help informthe decision of whether the proposed systems deserve further con-sideration and dynamic simulation

Indirect Gasifier Based Hybrid System

The first concept investigated is based on indirectly heated gasi-fication architecture The schematic of the plant layout is providedin Fig 3 Indirectly heated gasification is a two-stage fluidized-bed process where the heat needed for the reaction is produced byburning char in a separate chamber to heat sand The hot sand isthen circulated through the reaction chamber to drive reactionkinetics

The biomass to hydrogen plant design proposed by Spath et al[9] was used as the baseline design Biomass entering the biorefi-nery is dried then gasified to produce syngas in an atmosphericpressure indirectly heated gasifier Tar is thermally cracked in acatalytic tar cracker The tar cracker must be heated because ofthe relatively low temperature (870 C) of the syngas leaving thegasifier Tar cracking temperatures typically exceed 900 C[911] Particulates and any tars remaining after the tar cracker areremoved from the syngas using a wet scrubber Sulfur is removedfrom the syngas in a two-step process of LO-CAT desulfurizationfollowed by ZnO polishing beds After sulfur has been removedthe carbon monoxide in the syngas stream is shifted towardshydrogen Finally the hydrogen is separated from the syngas viapressure swing adsorption (PSA) and the remaining (purge) gas isburned with a small natural gas trim to provide heat to the tarcracker

Two possible changes to the biorefinery design were investi-gated The first modification allows switching between fuel produc-tion and electricity production based on grid demand (ldquopeakingrdquo)This is accomplished by routing some or all of the syngas from thegasifier to a gas turbine instead of the fuel production reactors Thesecond modification allows the use of surplus electricity by the gas-ifier for heating (ldquosinkingrdquo) The conversion of wind-generatedelectrical energy to thermal energy within the gasifier effectivelyldquosinksrdquo the wind power into hydrogen fuel production Both ofthese operating modes are discussed in further detail in the subse-quent sections Accordingly analysis of each concept was separatedinto the peaking and sinking operating modes The two modifica-tions were analyzed individually to highlight their respective effecton plant performance and economics

An ideal hybrid plant would continuously adjust both electricityuse and fuel production to optimize plant economics Electricity isproduced instead of hydrogen when electricity is the more profita-ble product and vice-versa Similarly electricity is used for heat-ing (or sunk) when electricity costs are low enough that theadditional plant efficiency for hydrogen production offsets thecost of grid electricity

Indirect Gasifier Peaking Modifications Several modifica-tions are required to allow the baseline biorefinery to alternatebetween hydrogen production and electricity production Thesemodifications include adding a gas turbine to the plant and theaddition of several syngas routing provisions

A general electric (GE) F class simple-cycle turbine was chosenfor electricity production [12] The F-class turbines can achieve a20 increase in capacity when run on syngas (eg a turbine ratedfor 75 MW production on natural gas can produce up to 90 MW)depending on the syngas composition [12] The higher power pro-duction is due primarily to higher mass flow through the turbineWhen a nonstandard (low heating value) fuel is burned a higherfuel feed rate is needed to provide the same amount of energy tothe turbine According to one GE technical paper [13] up to 14deviation from catalogue flow rates can typically be achievedwhile avoiding compressor stall

Fig 3 Indirect gasifier baseline system

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-3

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Cooling issues can arise with syngas combustion depending onits composition Increased burner temperatures can shorten theservice life of a turbine as well as significantly increasing NOx

and SOx emissions Based on data from general electric gasifica-tion projects [13] and previous research performed at the NREL[14] syngas compositions similar to the ones used in this studyare typically humidified with steam before combustion to regulatethe turbine inlet temperature Steam was added to the syngas sothat the final fuel gas was 20 water by weight This correspondsto a lower heating value (LHV) of approximately 11 MJ=kg Thesteam was available from the on-site steam cycle

Syngas from the LO-CAT reactor is sent to the gas turbine dur-ing power generation Tar reforming is required because tars arecorrosive and could adversely affect the turbine combustor Inaddition the tar represents a significant portion of the chemicalenergy of the syngas and removal (versus reforming) would resultin a measurable decrease in plant efficiency Therefore directlyafter the tar reformer was the first possible location to split thesyngas stream for combustion However by placing the turbinedownstream of the bulk sulfur removal step emissions of SOx canbe significantly reduced

The system operates in a binary mode meaning that it eitherproduces power or hydrogen but not both at the same time Inaddition to potential dynamic operational issues associated withswitching between the two modes there are several steady-statetechnical challenges due to the high degree of thermal integrationin the base plant Down stream water-gas shift (WGS) catalystbeds are extremely sensitive to air exposure and therefore syngasflow must be maintained or they must be sealed if shut down Inaddition the pressure swing adsorption off-gas from hydrogenproduction is burned to heat the tar reformer This energy must bereplaced when the PSA is not running during power productionFinally the base design includes a thermally integrated steamcycle which is partially fed by syngas cooling steps downstreamof the split location Loss of this heat energy to the steam turbinewill adversely affect the plant power system

The first two technical challenges were both addressed bydiverting only a limited amount of syngas to the gas turbine whenproducing electricity A slipstream of syngas is maintainedthrough the water-gas shift reactors to avoid oxygen poisoning ofthe catalyst After going through the water-gas shift reactors thesyngas is routed to the tar reformer and burned to replace the PSAoff-gas that was previously burned to maintain temperature Thisapproach should keep the sensitive water-gas shift catalysts fromair and also meet the energy demands of the tar reformer systemIn addition all base design systems are kept warm and active(except for the PSA unit) until peaking power is no longer needed

In order to maintain the base plant steam system a portion ofthe exhaust gases from the gas turbine are run through a heatexchanger The heat exchanger exactly replaces heat loss fromcooling steps downstream of the split location

Table 1 summarizes the ASPEN PlusVR simulation results for thepeaking hybrid system When making hydrogen fuel the plant

would have the major input and output variables shown in the H2

production column The power production column shows theinput and output variables when the PSA unit is shut down

The power production value of 77 MW represents the net powerthe plant could produce using a ldquorubberrdquo turbine3 with GE F-classefficiencies The rubber turbine has a gross assumed nameplatecapacity of 806 MW but loses significant power due to plant para-sitic needs When running in a peaking capacity the plant has alow total efficiency of 178-LHV This is compared to an effi-ciency of 497-LHV when producing hydrogen and an expectedstand-alone turbine efficiency of approximately 32

The extremely low power production efficiency is the result ofmultiple factors including the fact that 21 of the syngas streamis used to maintain the water-gas shift reactors and tar cracker atelevated temperature rather than for power production In addi-tion a portion of the power output is used to serve auxiliary elec-trical loads within the plant

Capital costs were estimated using numbers taken from Ref [9]as a starting point In 2005 dollars the cost of a 2000 TPD biorefi-nery is estimated to be approximately $105 106 The cost of thegas turbine and additional heat exchangers were added to this costfor the hybrid case The gas turbine costs were taken from Ref[15] and then adjusted to $2005 using the Chemical EngineeringPlant Cost Index Heat exchanger costs were calculated with thesame scaling factors used in Ref [9] The additional capital costsfor the turbine and exhaust boiler feed water (BFW) preheater arelisted in Table 2

Indirect Gasifier Sinking Modifications Recent studies sug-gest that an indirectly heated gasifier will not produce enoughchar to maintain gasification temperatures therefore raw syngasmust be diverted and combusted to supplement the heat deliveredto the gasifier by the char combustor [16] Therefore during peri-ods of low electricity demand (low purchase price) electric heat-ers could be used to add heat and partially replace the syngasrecycle stream Electric heating allows more hydrogen to be pro-duced per ton of biomass feedstock which increases plantproduction

Supplementing the heat delivered to the gasifier by the charcombustor with electrically generated heat rather than divertingand combusting syngas could be accomplished in multiple ways[10] For this analysis high-power high-temperature electric airheaters were used By preheating the combustion air used inthe syngas and char combustors more heat can be delivered tothe sand per kilogram of char or syngas combusted resulting ina reduced amount of syngas that must be recycled The inten-tion is to allow intermittent use of the combustion air preheat-ers allowing the system to recycle syngas when electricityprices are high and add electric heat when electricity prices arelow

The ASPEN PlusVR simulation results are summarized in Table 3and appear to be promising The amount of syngas that must bediverted is reduced by about 45 by combustion air preheating

Table 1 Peaking system input and outputa

H2 productionmode

Power productionmode

Inputs (MW) Biomass feedb 434 434NG feedc 23 mdashElectricity 10 mdash

Outputs (MW) Electricity mdash 77H2

d 232 mdash

aWhere applicable mass flows were converted to energy flows with thefollowing lower heating valuesbA biomass LHV of 187 MJ=kg bone-dry wood was used [7]cNatural gas LHV of 4714 MJ=kg was used per HyARC database [23]dHydrogen LHV of 12021 MJ=kg was used per HyARC database [23]

Table 2 Indirect gasifier capital costs

Plant area Peaking Sinking

Baseline indirect gasifier planta $1049 M $1049 MTurbine $322 M mdashExhaust BFW preheater $025 M mdashAir duct heater and air blower mdash $158 MTotal $137 M $121 M

aThe baseline plant design and costs are based on Ref [9]

3The term ldquorubberrdquo turbine refers to the fact that the turbine size was set toexactly match fuel stream mass and energy flow as opposed to using an existingstock frame size

031801-4 Vol 133 SEPTEMBER 2011 Transactions of the ASME

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

Additionally enough hot combustion products are still producedto dry the incoming biomass

Unlike the peaking modification which produced lower effi-ciency adding electric heat to the plant increases the total plantefficiency (energy in=energy out) from 497 to 503 Eachadditional unit of energy input as electricity produces 056 unitsof hydrogen energy output Therefore while providing a dispatch-able load service to the local utility the hybrid plant operatesmore efficiently

The electric heater capital costs are based on a quote providedby a manufacturer [17] for their largest high-temperature airduct heater Based on that quote a 22 MW air duct heater isestimated to cost $250000 and has an electricity-to-heated airconversion efficiency of 90 Since additional unit savings arenot expected with increasing scale a scaling factor of 09 wasused Finally an installation factor of 247 was assumed for allcost estimates for consistency with other NREL hydrogen analy-ses (H2A) [9] Based on these assumptions the total additionalcapital costs for electrically heating the combustion air amountedto $158 million

Direct Gasifier Based Hybrid System

Directly heated gasifiers typically have a single combustion=reaction chamber and burn a small portion of the biomass feed togenerate the heat needed to drive the gasification reactions Asource of pure oxygen is required for combustion if the syngas isto be used for fuel production to avoid nitrogen dilution of thesyngas For large-scale oxygen production the established methodis to use a cryogenic ASU Electrolysis could provide an alterna-tive to an ASU with the added benefit of producing an additionalpure hydrogen stream

Recent research on the feasibility of combining electrolysiswith gasification concluded that the economic feasibility of thecombination was highly dependent on the price of available elec-tricity [18] The proposed hybrid system could directly addresselectricity price dependence by running the electrolysis systemintermittently based on the cost of electricity

A baseline gasification plant (see Fig 4) and a hybrid plantwere simulated in ASPEN Plus and were compared Both the base-line and hybrid plants have the same general structure biomass isgasified to produce syngas in a high-pressure directly heated gas-ifier Tars are removed and the syngas is cooled before entering asulfur removal step After sulfur has been removed the carbonmonoxide in the syngas stream is shifted towards hydrogenFinally the hydrogen is stripped from the syngas and the remain-ing gas is burned to generate power Figure 4 shows the envi-sioned biomass to hydrogen pathway using the direct gasifier anda cryogenic ASU

The bulk of the chemical processes operate at high pressureThe wet scrubber is run near atmospheric pressure which requirescooling and recompression of the syngas before sulfur removalThe directly heated gasifier operating pressure selected in thisstudy was 24 bar and represents the state of the art in fluidized-bed biomass gasification systems It has been shown that highergasifier operating pressure is generally preferred when consideringgasifier efficiency and the heating value of the syngas [19] How-ever the sensitivity of gasifier performance increases if pressureis rather low For instance a doubling of gasifier pressure onlyincreases gasifier efficiency and heating value by 1ndash2 points[19] A detailed exploration of the effect of gasifier operatingpressure on the merit of the hybrid system proposed herein isbeyond the scope of this analysis but efficiency analyses and bio-refinery performance using pressurized gasifiers are reported else-where [20] Detailed discussion of the design assumptions andsimulation are available in Refs [710]

A cryogenic ASU is used to produce the oxygen for the baselinestudy In addition to producing oxygen a nitrogen stream is avail-able as a byproduct from the ASU and is used as the inert pressur-ization agent for the lock-hopper system To replace the ASUwith electrolyzers the LO-CAT=ZnO sulfur removal steps wouldneed to be replaced with a two-stage Selexol plant The sulfur re-moval change is driven by the need for an inert gas for feed pres-surization Since no nitrogen stream is available from theelectrolyzer carbon dioxide will be used for feed pressurizationinstead Selexol can be configured to remove both sulfur com-pounds and carbon dioxide from the syngas [21]

To replace a single ASU unit for oxygen production multipleelectrolyzers are needed The largest commercial electrolyzer isproduced by StatoilHydro and produces a maximum flow rate of174 kg=h of oxygen (436 kg=h of hydrogen) The StatoilHydroelectrolyzer is an alkaline low-temperature system [22] Whilesignificant research is ongoing for high-temperature advancedelectrolysis systems commercial technology was chosen for thisanalysis

Based on ASPEN simulations a 2000 TPD fluidized-bed biomassgasifier with secondary oxygen injection would need approxi-mately 27800 kg=h of oxygen supplied For this design 160 elec-trolyzers would be needed to replace the ASU This number

Table 3 Sinking system input and outputa

H2 production mode Sinking mode

Input (MW) Biomass feed 434 434NG feed 23 28

Electricity 10 57Output (MW) Electricity mdash mdash

H2 232 261

aWhere applicable mass flows were converted to energy flows with thesame heating values given in Table 1

Fig 4 Direct gasifier baseline system

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-5

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assumes that all electrolysis units run at design capacity 100 ofthe time

Input and output parameters from the electrolysis plant weredetermined from the published ldquoFuture Central Hydrogen Produc-tion from Grid Electrolysisrdquo H2A case [23] Based on ASPEN Plussimulations and the electrolysis H2A case the plant input and out-put values for the hybrid system were estimated The values foreach individual plant and the hybrid case are given in Table 4

The amount of electricity required to power the electrolyzerbank is extremely large when keeping the plant sized at 2000 TPDAssuming a 35 capacity factor for installed wind 970 MW of in-stalled wind capacity would be needed to generate enough averageelectricity for a 2000 TPD plant This is much larger than the totalamount of installed wind power in some states The large electricityneeds render the idea of capturing stranded resources with this scalebiorefinery plant problematic and ultimately infeasible However itis noteworthy that hydrogen production is also increased by 172over the base plant with this hybrid concept

While this study focuses on maintaining a 2000 TPD size biore-finery if instead the plant design objective was to deliver 165MW of hydrogen then the biomass feed requirement could belowered to approximately 920 TPD and the electricity demandreduced by 62 The reduction in biomass feedstock requirementswith this configuration is significant because it increases the num-ber of geographic locations that could support wind=biomasshybrid systems and ultimately lowers the land area requirementsfor sustainable fuel production

Multiple sources were used to estimate the capital costs associ-ated with the directly heated gasifier concepts All electrolyzercosts were calculated using the previously mentioned hydrogenanalysis [23] The majority of costs associated with the fluidizedbed gasifier and feed preparation were taken from a recent publi-cation by Jin et al [25] Gas cleanup costs were scaled based onprevious systems studies completed at the NREL [9] Selexol pri-ces were based on Department of Energy estimates [26] An over-view of the capital costs can be found in Table 5 Detailed costinginformation for both systems is available in Refs [710]

Based on the cost information summarized in Table 5 directreplacement of the ASU with an electrolyzer bank causes a 72increase in the total capital investment required

Economic Model

The hybrid system concepts studied respond dynamically tofluctuations in the energy market either absorbing or providingelectricity on demand To simulate this switching a binary modelwas created for each proposed system based on a specified peak-ing or sinking duty Duty is defined as the percent of hours peryear where either sinking or peaking mode is used

All concepts were assumed to be grid-connected for the analy-sis The hybrid plants are intended to provide grid leveling serv-ices to a local utility that has intermittent wind resources Thisarrangement allows for direct assessment of the market value ofelectricity and avoids inclusion of wind turbine capital costs in thecost of the system For the directly heated gasifier hybrid systemthe effect of stranded operation is discussed briefly in the eco-nomic results section of this paper

Regional Transmission Organization (RTO) day-ahead priceswere used for the cost-of-electricity when available These pricesrepresent the market value of electricity to the local utilities in anarea on an hourly averaged basis The hybrid systems must beprofitable at this low price point to cost effectively trade electric-ity on the energy market When day-ahead market informationwas unavailable load lambda data was used in its place Loadlambda data give the cost of producing one unit of electricity tothe utility for each hour of the year In all cases costs were basedon 2007 year-end data Based on GIS research reported earlier(see Figs 1 and 2) three general areas appear to have overlappingresources of both wind and biomass These areas are served by theNortheast Independent System Operator (NE ISO) Midwest ISO(MISO) and Northwest Interchange (NW Int) Cost of electricityvalues for each of these areas was used in the analysis

To assess the economic potential of each of the proposedhybridizations the yearly inputs and outputs for each plant alongwith applicable capital costs were entered into the H2A AnalysisTool developed by NREL [27] The resulting cost of hydrogenproduced (in dollars per kilogram) was compared to baseline plantresults and also the published steam methane reforming results[28] The analysis was performed in 2005 constant dollars for con-sistency with previous NREL studies [928]

The price of natural gas was held static for each of the regions stud-ied The 2009 Annual Energy Outlook report predicts regional varia-tion of natural gas prices in the US of approximately three dollars permillion Btu [29] The predicted variation translates to approximately10 cents per normal cubic meter The sensitivity analysis for each ofthe hybrid plants shows the effects of a larger 30 variation in naturalgas prices The SMR base case is also sensitive to natural gas priceswith a $010 per normal cubic meter variation in price gas price caus-ing a $047 change in the cost of hydrogen produced [28]

The economic analysis makes several assumptions includingthat current electricity prices are representative of those at thetime of actual plant construction and that sufficient marketdemand for hydrogen exists that all product can be sold Themajor economic assumptions are summarized in Table 6 Addi-tionally values for rate of return and startup times for the plantsare selected to enable comparison with other studies on hydrogenproduction from resources such as methane (see Tables 8 and 9)For this reason all economic assumptions were taken directlyfrom H2A defaults [27]

The effects of carbon costs on system results were taken intoaccount separately as an adjustment to the H2A results Theamount of CO2e per kilogram of hydrogen produced was trackedfor all cases analyzed The emissions for each hybrid system varynot only with the type of hybridization but also with the amountof time spent in each mode of operation Values for these emis-sions are given with the economic results

In addition to including the CO2e emissions from the plantthere is a CO2e credit associated with carbon emissions avoideddue to the renewable nature of any fuel or electricity producedBased on the regional average grid mix anywhere from 483 to 724kg of CO2e are emitted per kilowatt-hour of electricity produced

Table 4 Direct gasifier input and outputa

Baseline plant Hybrid plant

Input (MW) Biomass feedb 411 411NG feed mdash mdash

Electricity mdash 342Output (MW) Electricity 15 mdash

H2 165 449

aWhere applicable mass flows were converted to energy flows with thesame heating values given in Table 1bA biomass LHV of 177 MJ=kg bone-dry wood was used due to slightlydifferent simulation feedstock [24]

Table 5 Direct gasifier capital costs

Plant area Baseline Hybrid

Feed preparation handling $279 M $279 MGasification tar reforming quench $227 M $227 MASU or electrolyzer bank $213 M $992 MGas cleanup $299 M $587 MShift and PSA $186 M $186 MSteam and power generation $204 M $204 MWater and other utilities $21 M $37 MBuildings and structures $64 M $64 MTotal $1493 M $2576 M

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Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

Table 7 details the grid production mix and correspondingemissions for each location studied The values shown in Table 7are assumptions in so much as they are averaged values for largeprocesses or regions Table 7 is actually a calculation matrix Asan example for the column ldquoNE ISOrdquo the calculation for the aver-age greenhouse gas emission for each kilowatt-hour of energyproduced is shown in Eq (1)

0150 9525thorn 0180 8931thorn 0300 5992 frac14 483 (1)

One kilogram of hydrogen has the approximate energy equivalentof 1 gal of gasoline However because hydrogen can be used infuel cells with much higher efficiency 1 kg of hydrogen couldactually offset about 2 gal of gasoline [30] Burning 2 gal of gaso-line produces 1784 kg of CO2e These numbers were used as car-bon credits for each kilogram of hydrogen or megawatt-hour ofelectricity produced by the proposed systems

Economic Results

The proposed indirectly heated gasifier peaking systemswitches between (1) hydrogen production and (2) electricity pro-duction (peaking) driven by the cost of electricity available on thegrid Based on discussions with Xcel Energy in Colorado [34] apeaking duty of 20 was used for the analysis Table 8 summa-rizes the major model inputs by region for the system A contractrate was used for any peaking electricity produced by the plantThis is common practice in the current electricity market and pro-vides a premium price for dispatchable peaking assets The cost ofbiomass feedstock was not varied regionally due to a lack of areliable index or market basis upon which to base the variation

Instead the effect of biomass feedstock cost was investigated aspart of the sensitivity analysis

Based on the economic inputs above and the plant inputs andoutputs previously discussed the cost of hydrogen production ineach area was calculated The results are shown in Table 9 alongwith the cost of hydrogen production for a baseline nonhybri-dized biomass to hydrogen plant and a SMR plant

The additional capital costs of hybridization cannot be justifiedtoday in any of the locations studied There is a $020 to $024 perkilogram premium on hydrogen produced by the proposed hybridsystem compared with a nonhybrid biomass to hydrogen gasifica-tion plant Areas with higher priced electricity move this hybrid-ization closer to economic feasibility with the best results foundin the Northeast

When the hybrid plant is producing electricity the plant usesno natural gas or electricity whereas when the plant is producinghydrogen natural gas is used for balancing the heat duty of theplant and electricity is required to run compressors Taking thedifferences in carbon emissions into account a value of $37ndash40per metric ton of CO2e makes the cost of hydrogen for the pro-posed hybrid system equal to that of SMR depending on the loca-tion This comparison was made assuming that both the hybridplant and SMR plant are subject to the same natural gas cost at agiven location

It is important to note that the baseline biomass to hydrogenplant only requires $23ndash25 per metric ton of CO2e value to becost competitive with hydrogen produced by SMR This meansthat peaking hybridization will only be economically promisingwhen there is some value placed on the additional functionality ofdual mode operation

In order to characterize the effect of various technical and eco-nomic assumptions a sensitivity analysis was performed for thegas turbine peaking system Figure 5 shows the results for the costof hydrogen in tornado chart format Capital costs the cost of bio-mass and the price which peaking electricity can be sold for arethe key inputs Capital costs when varied 630 cause the cost ofhydrogen to vary $025 The cost of biomass was varied from $40to $60 per ton based on projections in Ref [35] and causes thecost of hydrogen to vary by less than $020 The price of peakingelectricity and the plant capacity factor also cause fluctuations ofless than $020 Changes in the cost of electricity bought by theplant the cost of natural gas peaking power output and turbinepeaking duty cause hydrogen costs to vary less than 5

The proposed sinking system switches between (1) hydrogenproduction with syngas recycling for gasifier heat and (2) hydro-gen production with electrical heating (sinking) to decrease the

Table 7 Greenhouse gas assumptions

kg CO2e per kW ha NE ISOb MISOc NW Intd

Coal 9525 150 756 580Oil=petroleum 8931 180 01 10Natural gas 5992 300 36 197Nuclear mdash 280 151 10Renewable mdash 90 56 203Average kg CO2e=kW h mdash 483 743 679

aHyARC Energy Constants and Assumptions H2A Analysis Tool [26]bNE ISO energy sources report [31]cMidwest ISO June monthly report [32]dApproximation based on PacifiCorp 2008 integrated resource plan [33]

Table 8 Peaking system H2A inputs

NE ISO MISO NW Int

Peaking duty 20 20 20Peaking electricity value (cent=kW h) 140 120 115Utility electricity cost (cent=kW h) 592 362 369Utility natural gas cost ($=nm3) 032 032 032Cost of biomass ($=ton)a 4883 4883 4883

aValue taken from the Biomass 2009 Multi-Year Research Developmentand Demonstration Plan (EERE 2009) The 2012 target value is $5070per ton of dry woody biomass in 2007 dollars Taken to 2005 dollars with109 inflation this yields $4883 per ton

Table 9 Peaking system results

$=kg H2 NE ISO MISO NW Int

SMR 140 140 140Biomass to hydrogen baseline 164 164 164Gas turbine hybrid system 184 186 188

Table 6 Economic assumptions

Parameter Value

Constant dollar value 2005Internal rate of return (after-tax) 10Debt=equity 0=100Plant life 40 yearsDepreciation Modified accelerated cost recovery systemDepreciation recovery period 20 yearsConstruction period 2 years

1st year 75 (25 for electrolysis)2nd year 25 (75 for electrolysis)

Start-up time 12 monthsRevenues 50Variable costs 75Fixed costs 100

Working capital 15 of total capital investmentInflation rate 19Total taxes 389Decommissioning costs 10 of depreciable capitalSalvage value 10 of total capital investment

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-7

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

syngas recycle This sinking ability can best be described as a dis-patchable load or demand from the viewpoint of the grid

Based on discussions with Xcel Energy the utility will pay tohave wind-generated electricity used at times (the electricity has anegative cost) and having a dispatchable load would provide avaluable service to the utility [34] Xcel Energy is required byColoradorsquos renewable portfolio standard to accept renewableenergy when it is available The requirement to accept wind elec-tricity regardless of grid demand is not universal and thereforenegative cost wind electricity may not be available in other states

No similar system was found for comparison therefore a sink-ing duty of 20 was used as a starting point for the analysisTable 10 summarizes the major economic model inputs by regionUnlike peaking electricity where a contract rate is used for elec-tricity produced by the plant the sinking analysis simply uses theaverage cost-of-electricity for the cheapest 20 of hours as thesinking electricity cost The utility electricity cost is the averageof the remaining 80 of the hours These costs-of-electricitywould be valid if a plant operator used accurate day-ahead energymarket forecasts to schedule plant operation

Given the economic inputs in Table 10 the cost of hydrogenproduction in each area was calculated The results are shown inTable 11 along with the cost of hydrogen production for a base-line nonhybridized biomass to hydrogen plant and a steam meth-ane reforming plant

There is a $003 to $011 premium on hydrogen produced bythe proposed hybrid system compared with a nonhybrid biomassto hydrogen gasification plant The additional capital costs of the

sinking hybridization are not fully offset by additional revenue inany of the locations studied However the marginal costs foundare small enough that it is difficult to draw any definitive conclu-sion Areas with lower cost electricity move this hybridizationcloser to economic feasibility with the best results found in theNorthwest

Because the premium is small (about 5) it may be acceptablein the long term Recent studies have shown that there is inherentvalue added or welfare effects for electricity storage capacity[36] Whether similar value is added by the proposed sinkinghybrid is unknown A more likely parallel would be the idea ofldquointerruptible customersrdquo which get discounted electricity rates inreturn for intermittent power supply A similar contractual agree-ment could be envisioned for the proposed hybrid where dis-counted electricity rates would be provided in return forintermittent demand

The proposed system is not a direct competitor with storagesystems such as pumped hydroelectric or compressed air energystorage (CAES) Energy storage systems attempt to profit by mar-ket arbitrage (selling electricity back to the grid at a higher pricethan it was bought) whereas the proposed hybrid system sinkscheap electricity into transportation fuel Sinking low cost elec-tricity into fuel could be considered cross-market arbitrage andthe most similar system to this would be electrolysis Comparedto electrolysis the proposed system is significantly less expensiveand has the added benefit of running without electric heat whenelectricity costs are too high

Assuming that all sinking electricity is renewable and takingthe additional differences in carbon emissions into account avalue of $26ndash32 per metric ton of CO2e makes the proposedhybrid cost competitive depending on the location of the system

Fig 5 Peaking system sensitivity (NE ISO)

Table 10 Sinking system H2A inputs

NE ISO MISO NW Int

Plant capacity factor 90 90 90Sinking duty 20 20 20Sinking electricity cost (cent=kW h) 435 220 218Utility electricity cost (cent=kW h) 705 487 469Utility natural gas cost ($=nm3) 032 032 032Cost of biomass ($=ton) 4883 4883 4883

Table 11 Indirect sinking system results

$=kg H2 NE ISO MISO NW Int

SMR 140 140 140Biomass to hydrogen baseline 164 164 164Electric air heater hybrid system 175 167 168

031801-8 Vol 133 SEPTEMBER 2011 Transactions of the ASME

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

At $27 per metric ton of CO2e the combustion air-heater hybrid-ization becomes cost competitive with a methane steam reformingplant in the Northwest assuming both the hybrid plant and SMRplant are subject to the same natural gas cost

In order to characterize the effect of various technical and eco-nomic assumptions a sensitivity analysis was performed for thesinking systems (Fig 6) The sensitivity analysis shows that capi-tal costs the cost of biomass and the plant capacity factor for arethe key inputs Capital costs when varied 630 cause the cost ofhydrogen to vary $018 The cost of biomass was varied from $40per ton to $60 per ton and causes the cost of hydrogen to vary byless than $015 Changes in the sinking duty the added hydrogenproduction due to sinking the cost of natural gas and the cost ofelectricity cause hydrogen costs to vary less than 3

From the sinking duty sensitivity analysis it appears that anincreased sinking duty would be preferable to the 20 assumptionmade Minimum hydrogen production prices occur when the elec-tric heating systems are run approximately 40 of the time Run-ning the electric heaters for more time increases plant hydrogenproduction and decreases plant green house gas emissions

The proposed directly heated gasifier hybrid system replacesthe ASU with an electrolyzer bank An H2A analysis was com-pleted to determine the baseline cost of hydrogen produced by adirectly heated gasification plant that uses electrolysis regardlessof electricity cost and the cost of hydrogen for a directly heatedgasification plant that uses a traditional ASU Table 12 summa-rizes the major model inputs The plant was assumed to be locatedin the Midwest ISO region The results of the analysis along withthe associated carbon emissions are listed in Table 13 Costs forproduction of hydrogen via SMR and for an electrolysis plantonly are also shown for reference purposes

As shown in Table 13 hydrogen produced by a direct gasifier-electrolyzer hybrid plant is significantly more expensive than thatproduced by SMR Electricity costs account for 37 of the overallcost of hydrogen produced (or about $086) Therefore if the costof electricity could be halved by intermittent operation during off-peak hours the savings would bring the cost of hydrogen to $189per kilogram of hydrogen At this price the hybrid system couldcompete with hydrogen produced by a standard direct gasificationplant It is important to note that these costs are approximately15 higher than the $164 per kilogram of hydrogen estimated forthe indirectly heated baseline gasification plant used for compari-son of the indirect hybrid analysis (see Table 11)

The original concept called for the electrolyzer bank to bedirectly coupled with stranded wind resources Typical capacityfactors for wind-generated power are in the 30ndash35 range [37]The effect of intermittent operation on the cost of hydrogen pro-duction was investigated using electrolyzer duties of 20 35and 50 The smaller the duty the larger the number electrolyz-ers needed to produce the same amount of oxygen per year

The effect of reduced electrolyzer duty on the cost of hydrogenis shown in Fig 7 Two curves are plotted The first assumes aconstant electricity price of $433=MWh regardless of the electro-lyzer duty This assumption would represent the scenario if theelectrolyzers were directly coupled with a stranded wind resourceThe second curve uses Midwest ISO market data so that the costof electricity fluctuates with duty These numbers do not considerthe cost of oxygen storage as these costs are assumed small com-pared to the increased electrolyzer capital costs and are identicalfor similar duty

Intermittent operation significantly adds to plant capital costsIf the price of electricity available to the plant does not decrease

Fig 6 Sinking system sensitivity (NW Int)

Table 12 Direct system H2A inputs

MISO

Electrolyzer duty () 100Utility electricity cost (cent=kW h) 433Cost of biomass ($=ton) 4883

Table 13 Direct system results

$=kg H2 Net CO2e=kg H2

SMR $140 68Biomass gasification $213 196Electrolysis $259 145 (178)Electrolysisthorn gasification $232 024 (182)

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-9

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

with intermittent electrolyzer operation then the cost of hydrogenincreases by 22 for a 35 duty However if the cost of electric-ity can be reduced by intermittent operation then the analysisshows that intermittent operation may be preferable to 100 dutyThis result means that the initial concept of capturing strandedresources is less favorable economically than a grid-connectedsinking system

If grid electricity is used then carbon emissions actuallyincrease relative to biomass gasification alone for this hybridiza-tion If upstream emissions for electricity production are takeninto account electrolysis and this proposed hybrid are both netCO2e emitters This makes their justification by carbon valueimpossible unless only renewable electricity is used for operation(renewable energy values are shown in parentheses in Table 13)Since renewable wind energy is inherently intermittent it isunreasonable to assume renewable electricity is used without add-ing the necessary equipment for intermittent operation Onerenewable energy exception would be the use of hydroelectricpower for the systems

Similar to the other hybrid systems investigated hybridizationresults in a price premium There must be some additional justifi-cation for hybridization such as utility demands The baseline bio-mass to hydrogen case with an ASU requires only $35 per metricton of CO2e to be cost competitive with SMR produced hydrogen

assuming both the hybrid plant and SMR plant are subject to thesame natural gas cost at a given location

Electrolyzer-based hybrid system economics are extremely sen-sitive to the cost of electricity (Fig 8) Fluctuations of $001 inthe cost of electricity cause the price of hydrogen to fluctuatemore than $025 per kilogram If the price of electricity were todrop below $004=kW h then the proposed hybrid system couldeconomically compete with a nonhybrid biomass to hydrogenplant However this low price level is unlikely and any energymarket fluctuations would have a dramatic effect on economicviability

Conclusion

The two hybrid concepts analyzed involve coproduction of gase-ous hydrogen and electric power from thermochemical-based biorefi-neries Both of the concepts analyzed share the basic idea ofcombining intermittent wind-generated electricity with a biomassgasification plant Wind availability overlaps biomass resource avail-ability in three areas of the United States making the use of locallyproduced wind electricity for gasification feasible The proposedhybrid systems attempt to either fill wind energy shortfalls by burn-ing syngas in a natural gas turbine or absorb excess renewable powerduring times of low-electricity demand

None of the proposed hybrid systems produced hydrogen forless than a nonhybrid plant could In all cases a premium was paidfor hybridization that could not be offset by the increasedfunctionality

The indirectly heated gasifier hybrid system consists of twoparts (1) producing peaking electricity intermittently with a gasturbine and (2) sinking electricity into electric heaters intermit-tently to boost fuel production efficiency Each of these parts wasanalyzed separately The indirectly heated gasifier hybrid systemis meant to be grid-connected and provide peaking electricity anddispatchable demand (eg an on demand load) to the local utilityto help manage intermittent wind resources

The indirect gasification concepts studied could be cost compet-itive in the near future as value is placed on controlling carbonemissions Carbon values of just under $40 per metric ton ofCO2e make the systems studied cost competitive with steam

Fig 7 Electrolyzer duty versus cost

Fig 8 Direct system sensitivity

031801-10 Vol 133 SEPTEMBER 2011 Transactions of the ASME

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

methane reforming to produce hydrogen However a nonhybridbiomass to hydrogen plant will be more cost competitive in gen-eral so there must be additional operational value placed on peak-ing or sinking for these plants to be economically attractive Thisadditional value is likely to become a reality as additional inter-mittent renewable energy sources such as wind are added to thenational grid

The directly heated gasifier hybrid system involves replacementof the air separation unit with electrolyzers This change allowsfor extra production of hydrogen and intermittent operation Theanalysis for this system assumed direct replacement of the ASUwithout intermittent operation Estimates of the effect of intermit-tent operation on plant economics were made The electrolyzerbank could be either grid-connected to provide a dispatchabledemand to the utility or it could be tied directly to a stranded windsource to convert wind into chemical fuel (H2)

The direct gasification concept studied is unlikely to be cost com-petitive in the near future but may eventually be attractive withlower-cost electrolysis and a smaller biorefinery plant size that issized for a specific hydrogen demand Intermittent operation andstranded operation were found to have worse economics than grid-connected systems High electrolyzer capital costs make the possibleelectricity cost savings of intermittent operation difficult to justifyBased on a direct replacement of the ASU with electrolyzers hydro-gen can be produced for $232 per kilogram However using gridelectricity the hybrid system is a net CO2e emitter For the use ofelectrolysis to make sense in this setting there must be a significantbenefit to the ability to operate intermittently

Acknowledgment

The authors would also like to acknowledge Dr Bob Evans forconceiving the hybrid hydrogen production systems project andDonna Heimiller for performing the GIS mapping

Employees of the Alliance for Sustainable Energy LLC underContract No DE-AC36-08GO28308 with the US Dept ofEnergy have authored this work The United States Governmentretains and the publisher by accepting the article for publicationacknowledges that the United States Government retains a nonex-clusive paid-up irrevocable worldwide license to publish orreproduce the published form of this work or allow others to doso for United States Government purposes

References[1] Milbrandt A 2005 ldquoA Geographic Perspective on the Current Biomass

Resource Availability in the United Statesrdquo National Renewable Energy LabReport No TP-560-39181

[2] Perlack R Wright L Turhollow A Graham R Stokes B and Erbach D2005 Biomass as Feedstock for a Bioenergy and Bioproducts Industry The Tech-nical Feasibility of a Billion-Ton Annual Supply Oak Ridge National LaboratoryOak 853 Ridge TN

[3] Turner J Sverdrup G Mann M Maness P C Kroposki B Ghirardi MEvans J and Blake D 2008 ldquoRenewable Hydrogen Productionrdquo Int JEnergy Res 32 pp 379ndash407

[4] US Department of Energy Energy Efficiency and Renewable Energy Labora-tory 2008 ldquo20 Wind Energy by 2030mdashIncreasing Wind Energyrsquos Contribu-tion to US Electricity Supplyrdquo Report No GO-102008-2567

[5] Levene J Kroposki B and Sverdrup G 2006 ldquoWind Energy and Productionof Hydrogen and ElectricityndashOpportunities for Renewable Hydrogenrdquo NationalRenewable Energy Laboratory Report No CP560-39534

[6] Fingersh L 2004 ldquoOptimization of Utility-Scale Wind-Hydrogen-BatterySystemsrdquo National Renewable Energy Laboratory Report No CP-500-36117

[7] Dean J Braun R Munoz D Penev M and Kinchin C 2010 ldquoAnalysis ofHybrid Hydrogen Systems ndash Final Reportrdquo National Renewable Energy Labo-ratory Report No TP-46934

[8] Gasification Technology Status ndash December 2006 EPRI and the Gasification869 Users Association Palo Alto CA p 1012224

[9] Spath P Aden A Eggeman T Ringer M Wallace B and Jechura J2005 ldquoBiomass to Hydrogen Production Detailed Design and Economics Uti-lizing the Battelle Columbus Laboratory Indirectly-Heated Gasifierrdquo NationalRenewable Energy Laboratory Report No TP-510-37408

[10] Dean J 2010 ldquoLeveling Intermittent Renewable Energy Production ThroughBiomass Gasification-based Hybrid Systemsrdquo MS thesis Colorado School ofMines Golden CO

[11] Devi L Ptasinski K Janssen F van Paasen S Bergman P and Kiel J2005 ldquoCatalytic Decomposition of Biomass Tars Use of Dolomite anUntreated Olivinerdquo Renewable Energy 30 pp 565ndash587

[12] Heavy Duty Gas Turbine Products 2009 General Electric Company FairfieldCT

[13] Drdar D and Jones R 2000 ldquoGE IGCC Technology and Experience withAdvanced Gas Turbinesrdquo GE Power Systems Report No GER-4207

[14] Craig K and Mann M 1996 ldquoCost and Performance Analysis of Biomass-Based Integrated Gasification Combined-Cycle (BIGCC) Power SystemsrdquoNational Renewable Energy Laboratory Report No TP-430-21657

[15] Gas Turbine World 2006 Handbook (Pequot Publishing Inc Fairfield CT2006)

[16] Kinchin C and Bain R 2009 ldquoHydrogen Production from Biomass via Indi-rect Gasification The Impact of NREL Process Development Unit GasifierCorrelationsrdquo National Renewable Energy Laboratory Report No TP-510-44868

[17] Watlow for 22 MW duct heaters Watlow 12001 Lackland Road St LouisMO 63146 personal communication 2009

[18] Gassner M and Marechal F 2008 ldquoThermo-economic Optimization of theIntegration of Electrolysis in Synthetic Natural Gas Production from WoodrdquoEnergy 33 pp 189ndash198

[19] Srinivas T Gupta A V S and Reddy B V 2009 ldquoThermodynamic Equi-librium Model and Exergy Analysis of a Biomass Gasifierrdquo ASME J EnergyResour Technol 131 031801 pp 1ndash7

[20] Braun R J Hanzon L G and Dean J H 2011 ldquoSystem Analysis of Ther-mochemical-based Biorefineries for Coproduction of Hydrogen and Elec-tricityrdquo ASME J Energy Resour Technol 133 012601 pp 1ndash12

[21] Manning F and Thompson R 1991 Oilfield Processing of Petroleum Vol-ume One 904 Natural Gas PennWell Publishing Co Tulsa Oklahoma

[22] StatoilHydro 2009 ldquoHydrogen Technologies World Leader in Electrolysis forHydrogen Solutionsrdquo product brochure Hydrogen Technologies NO-3674Notodden Norway COS 091408 available URL http908wwwelectrolyserscom

[23] US Department of Energy Hydrogen Program 2009 ldquoFuture Central Hydro-gen Production from Grid Electrolysisrdquo H2A analysis wwwhydrogenenergygovh2a_prod_studieshtml

[24] Phyllis Biomass Datapage ldquowood hybrid poplarrdquo ID 806 available URLhttpwwwecnnlphyllis

[25] Jin H Larson E and Celik F 2009 ldquoPerformance and Cost Analysis ofFuture Commercially Mature Gasification-Based Electric Power GenerationFrom Switchgrassrdquo Biofpr 3 pp 142ndash173

[26] Department of Energy 2007 ldquoCost and Performance Baseline for Fossil EnergyPlants Volume 1 Bituminous Coal and Natural Gas to Electricityrdquo Report NoDOE=NETL-2007=1281

[27] US Department of Energy Hydrogen Program 2009 ldquoDOE H2A Analy-sisrdquo wwwhydrogenenergygovh2a_analysishtml

[28] US Department of Energy Hydrogen Program 2009 ldquoFuture Central Hydro-gen Production from Natural Gas with CO2 Sequestrationrdquo H2A analysiswwwhydrogenenergygovh2a_prod_studieshtml

[29] Energy Information Administration Annual Energy Outlook 2009 wwweiadoegovoiafaeoelectricityhtml

[30] Schafer A Heywood J and Weiss M 2006 ldquoFuture Fuel Cell and InternalCombustion Engine Automobile Technologies A 25-Year Life Cycle and FleetImpact Assessmentrdquo Energy 31 pp 2064ndash2087

[31] NE ISO 2009 ldquoEnergy Sources in New Englandrdquo wwwiso-necomnwsissgrid_mktsenrgy_srcs

[32] Doying R 2009 Midwest ISO ldquoJune Monthly Reportrdquo wwwmidwestisoorg[33] PacifiCorp 2009 ldquoIntegrated Resource Plan ndash Volume 1rdquo May 29 2009

wwwpaci-937ficorpcom[34] Frank Novachek 2009 Xcel Energy 414 Nicollet Mall Minneapolis MN

55401 939 personal communication[35] Energy Efficiency and Renewable Energy Department of Energy ldquoBiomass

2009 Multi-Year Research Development and Demonstration Planrdquo www1eer-eenergygovbiomasspdfsmypp_may2009pdf

[36] Sioshansi R Denholm P Jenkin T and Weiss J 2009 ldquoEstimating theValue of Electricity Storage in PJM Arbitrage and Some Welfare EffectrdquoEnergy Econ 31 pp 269ndash277

[37] Kroposki B Levene J Harrison K Sen P K and Novachek F 2006ldquoElectrolysis Information and Opportunities for Electric Power UtilitiesrdquoNational Renewable Energy Laboratory Report No TP-581-40

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-11

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

power with an indirectly heated biomass gasification plant Theplant will produce both electricity and hydrogen fuel The otherconcept uses an electrolyzer bank in place of an air separation unit(ASU) for a directly heated biomass gasifier for coproduction offuel and power

Analysis Objectives

The key research objectives were to (i) provide a high-leveltechnical evaluation of integration options of wind-generated elec-tricity with biomass gasification (ii) quantify the amount ofenergy production or energy absorption possible with a 2000 TPDbiorefinery (iii) estimate the cost of hydrogen production for eachhybridization option and (iv) compare the economic results withother hydrogen production systems such as steam methanereforming of natural gas

A plant input capacity of 2000 TPD of biomass was selectedfor the analysis based on resource availability Assuming an 80km (50-mile) collection radius multiple regions throughout thecountry were identified that could support this level of biomassrequirement At scales larger than 2000 TPD the number of possi-ble plant locations in the United States becomes severely limited[1] Woody biomass was used as the plant feedstock for all theconcepts studied Biomass type was not varied due to limitationsof the thermodynamic system model and concerns about the feasi-bility of feeding fibrous agricultural waste reliably Pilot plantssuch as the IGT RENUGAS plant have clearly demonstrated thedifficulty of feeding fibrous feedstock into a gasifier [8]

Based on a fixed biomass throughput baseline directly heatedand indirectly heated gasification plants were established ASPEN

Plus software was employed to determine the plant input and outputparameters for each system The baseline systems were optimizedfor hydrogen production using near term (2012 timeframe) tech-nologies For the indirectly heated gasifier a previously publishedsystem study was used as the baseline [9] Since there was not anexisting model available for the directly heated gasifier case amodel was constructed as part of this research Detailed informationabout the ASPEN Plus models can be found in Ref [10] With indi-rectly and directly heated baseline cases in place each plant wasmodified to incorporate the proposed hybrid concepts

The models for all plants were steady-state Control strategiesand the dynamic effects of intermittent operation were not consid-ered Instead the results of this study are intended to help informthe decision of whether the proposed systems deserve further con-sideration and dynamic simulation

Indirect Gasifier Based Hybrid System

The first concept investigated is based on indirectly heated gasi-fication architecture The schematic of the plant layout is providedin Fig 3 Indirectly heated gasification is a two-stage fluidized-bed process where the heat needed for the reaction is produced byburning char in a separate chamber to heat sand The hot sand isthen circulated through the reaction chamber to drive reactionkinetics

The biomass to hydrogen plant design proposed by Spath et al[9] was used as the baseline design Biomass entering the biorefi-nery is dried then gasified to produce syngas in an atmosphericpressure indirectly heated gasifier Tar is thermally cracked in acatalytic tar cracker The tar cracker must be heated because ofthe relatively low temperature (870 C) of the syngas leaving thegasifier Tar cracking temperatures typically exceed 900 C[911] Particulates and any tars remaining after the tar cracker areremoved from the syngas using a wet scrubber Sulfur is removedfrom the syngas in a two-step process of LO-CAT desulfurizationfollowed by ZnO polishing beds After sulfur has been removedthe carbon monoxide in the syngas stream is shifted towardshydrogen Finally the hydrogen is separated from the syngas viapressure swing adsorption (PSA) and the remaining (purge) gas isburned with a small natural gas trim to provide heat to the tarcracker

Two possible changes to the biorefinery design were investi-gated The first modification allows switching between fuel produc-tion and electricity production based on grid demand (ldquopeakingrdquo)This is accomplished by routing some or all of the syngas from thegasifier to a gas turbine instead of the fuel production reactors Thesecond modification allows the use of surplus electricity by the gas-ifier for heating (ldquosinkingrdquo) The conversion of wind-generatedelectrical energy to thermal energy within the gasifier effectivelyldquosinksrdquo the wind power into hydrogen fuel production Both ofthese operating modes are discussed in further detail in the subse-quent sections Accordingly analysis of each concept was separatedinto the peaking and sinking operating modes The two modifica-tions were analyzed individually to highlight their respective effecton plant performance and economics

An ideal hybrid plant would continuously adjust both electricityuse and fuel production to optimize plant economics Electricity isproduced instead of hydrogen when electricity is the more profita-ble product and vice-versa Similarly electricity is used for heat-ing (or sunk) when electricity costs are low enough that theadditional plant efficiency for hydrogen production offsets thecost of grid electricity

Indirect Gasifier Peaking Modifications Several modifica-tions are required to allow the baseline biorefinery to alternatebetween hydrogen production and electricity production Thesemodifications include adding a gas turbine to the plant and theaddition of several syngas routing provisions

A general electric (GE) F class simple-cycle turbine was chosenfor electricity production [12] The F-class turbines can achieve a20 increase in capacity when run on syngas (eg a turbine ratedfor 75 MW production on natural gas can produce up to 90 MW)depending on the syngas composition [12] The higher power pro-duction is due primarily to higher mass flow through the turbineWhen a nonstandard (low heating value) fuel is burned a higherfuel feed rate is needed to provide the same amount of energy tothe turbine According to one GE technical paper [13] up to 14deviation from catalogue flow rates can typically be achievedwhile avoiding compressor stall

Fig 3 Indirect gasifier baseline system

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-3

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

Cooling issues can arise with syngas combustion depending onits composition Increased burner temperatures can shorten theservice life of a turbine as well as significantly increasing NOx

and SOx emissions Based on data from general electric gasifica-tion projects [13] and previous research performed at the NREL[14] syngas compositions similar to the ones used in this studyare typically humidified with steam before combustion to regulatethe turbine inlet temperature Steam was added to the syngas sothat the final fuel gas was 20 water by weight This correspondsto a lower heating value (LHV) of approximately 11 MJ=kg Thesteam was available from the on-site steam cycle

Syngas from the LO-CAT reactor is sent to the gas turbine dur-ing power generation Tar reforming is required because tars arecorrosive and could adversely affect the turbine combustor Inaddition the tar represents a significant portion of the chemicalenergy of the syngas and removal (versus reforming) would resultin a measurable decrease in plant efficiency Therefore directlyafter the tar reformer was the first possible location to split thesyngas stream for combustion However by placing the turbinedownstream of the bulk sulfur removal step emissions of SOx canbe significantly reduced

The system operates in a binary mode meaning that it eitherproduces power or hydrogen but not both at the same time Inaddition to potential dynamic operational issues associated withswitching between the two modes there are several steady-statetechnical challenges due to the high degree of thermal integrationin the base plant Down stream water-gas shift (WGS) catalystbeds are extremely sensitive to air exposure and therefore syngasflow must be maintained or they must be sealed if shut down Inaddition the pressure swing adsorption off-gas from hydrogenproduction is burned to heat the tar reformer This energy must bereplaced when the PSA is not running during power productionFinally the base design includes a thermally integrated steamcycle which is partially fed by syngas cooling steps downstreamof the split location Loss of this heat energy to the steam turbinewill adversely affect the plant power system

The first two technical challenges were both addressed bydiverting only a limited amount of syngas to the gas turbine whenproducing electricity A slipstream of syngas is maintainedthrough the water-gas shift reactors to avoid oxygen poisoning ofthe catalyst After going through the water-gas shift reactors thesyngas is routed to the tar reformer and burned to replace the PSAoff-gas that was previously burned to maintain temperature Thisapproach should keep the sensitive water-gas shift catalysts fromair and also meet the energy demands of the tar reformer systemIn addition all base design systems are kept warm and active(except for the PSA unit) until peaking power is no longer needed

In order to maintain the base plant steam system a portion ofthe exhaust gases from the gas turbine are run through a heatexchanger The heat exchanger exactly replaces heat loss fromcooling steps downstream of the split location

Table 1 summarizes the ASPEN PlusVR simulation results for thepeaking hybrid system When making hydrogen fuel the plant

would have the major input and output variables shown in the H2

production column The power production column shows theinput and output variables when the PSA unit is shut down

The power production value of 77 MW represents the net powerthe plant could produce using a ldquorubberrdquo turbine3 with GE F-classefficiencies The rubber turbine has a gross assumed nameplatecapacity of 806 MW but loses significant power due to plant para-sitic needs When running in a peaking capacity the plant has alow total efficiency of 178-LHV This is compared to an effi-ciency of 497-LHV when producing hydrogen and an expectedstand-alone turbine efficiency of approximately 32

The extremely low power production efficiency is the result ofmultiple factors including the fact that 21 of the syngas streamis used to maintain the water-gas shift reactors and tar cracker atelevated temperature rather than for power production In addi-tion a portion of the power output is used to serve auxiliary elec-trical loads within the plant

Capital costs were estimated using numbers taken from Ref [9]as a starting point In 2005 dollars the cost of a 2000 TPD biorefi-nery is estimated to be approximately $105 106 The cost of thegas turbine and additional heat exchangers were added to this costfor the hybrid case The gas turbine costs were taken from Ref[15] and then adjusted to $2005 using the Chemical EngineeringPlant Cost Index Heat exchanger costs were calculated with thesame scaling factors used in Ref [9] The additional capital costsfor the turbine and exhaust boiler feed water (BFW) preheater arelisted in Table 2

Indirect Gasifier Sinking Modifications Recent studies sug-gest that an indirectly heated gasifier will not produce enoughchar to maintain gasification temperatures therefore raw syngasmust be diverted and combusted to supplement the heat deliveredto the gasifier by the char combustor [16] Therefore during peri-ods of low electricity demand (low purchase price) electric heat-ers could be used to add heat and partially replace the syngasrecycle stream Electric heating allows more hydrogen to be pro-duced per ton of biomass feedstock which increases plantproduction

Supplementing the heat delivered to the gasifier by the charcombustor with electrically generated heat rather than divertingand combusting syngas could be accomplished in multiple ways[10] For this analysis high-power high-temperature electric airheaters were used By preheating the combustion air used inthe syngas and char combustors more heat can be delivered tothe sand per kilogram of char or syngas combusted resulting ina reduced amount of syngas that must be recycled The inten-tion is to allow intermittent use of the combustion air preheat-ers allowing the system to recycle syngas when electricityprices are high and add electric heat when electricity prices arelow

The ASPEN PlusVR simulation results are summarized in Table 3and appear to be promising The amount of syngas that must bediverted is reduced by about 45 by combustion air preheating

Table 1 Peaking system input and outputa

H2 productionmode

Power productionmode

Inputs (MW) Biomass feedb 434 434NG feedc 23 mdashElectricity 10 mdash

Outputs (MW) Electricity mdash 77H2

d 232 mdash

aWhere applicable mass flows were converted to energy flows with thefollowing lower heating valuesbA biomass LHV of 187 MJ=kg bone-dry wood was used [7]cNatural gas LHV of 4714 MJ=kg was used per HyARC database [23]dHydrogen LHV of 12021 MJ=kg was used per HyARC database [23]

Table 2 Indirect gasifier capital costs

Plant area Peaking Sinking

Baseline indirect gasifier planta $1049 M $1049 MTurbine $322 M mdashExhaust BFW preheater $025 M mdashAir duct heater and air blower mdash $158 MTotal $137 M $121 M

aThe baseline plant design and costs are based on Ref [9]

3The term ldquorubberrdquo turbine refers to the fact that the turbine size was set toexactly match fuel stream mass and energy flow as opposed to using an existingstock frame size

031801-4 Vol 133 SEPTEMBER 2011 Transactions of the ASME

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

Additionally enough hot combustion products are still producedto dry the incoming biomass

Unlike the peaking modification which produced lower effi-ciency adding electric heat to the plant increases the total plantefficiency (energy in=energy out) from 497 to 503 Eachadditional unit of energy input as electricity produces 056 unitsof hydrogen energy output Therefore while providing a dispatch-able load service to the local utility the hybrid plant operatesmore efficiently

The electric heater capital costs are based on a quote providedby a manufacturer [17] for their largest high-temperature airduct heater Based on that quote a 22 MW air duct heater isestimated to cost $250000 and has an electricity-to-heated airconversion efficiency of 90 Since additional unit savings arenot expected with increasing scale a scaling factor of 09 wasused Finally an installation factor of 247 was assumed for allcost estimates for consistency with other NREL hydrogen analy-ses (H2A) [9] Based on these assumptions the total additionalcapital costs for electrically heating the combustion air amountedto $158 million

Direct Gasifier Based Hybrid System

Directly heated gasifiers typically have a single combustion=reaction chamber and burn a small portion of the biomass feed togenerate the heat needed to drive the gasification reactions Asource of pure oxygen is required for combustion if the syngas isto be used for fuel production to avoid nitrogen dilution of thesyngas For large-scale oxygen production the established methodis to use a cryogenic ASU Electrolysis could provide an alterna-tive to an ASU with the added benefit of producing an additionalpure hydrogen stream

Recent research on the feasibility of combining electrolysiswith gasification concluded that the economic feasibility of thecombination was highly dependent on the price of available elec-tricity [18] The proposed hybrid system could directly addresselectricity price dependence by running the electrolysis systemintermittently based on the cost of electricity

A baseline gasification plant (see Fig 4) and a hybrid plantwere simulated in ASPEN Plus and were compared Both the base-line and hybrid plants have the same general structure biomass isgasified to produce syngas in a high-pressure directly heated gas-ifier Tars are removed and the syngas is cooled before entering asulfur removal step After sulfur has been removed the carbonmonoxide in the syngas stream is shifted towards hydrogenFinally the hydrogen is stripped from the syngas and the remain-ing gas is burned to generate power Figure 4 shows the envi-sioned biomass to hydrogen pathway using the direct gasifier anda cryogenic ASU

The bulk of the chemical processes operate at high pressureThe wet scrubber is run near atmospheric pressure which requirescooling and recompression of the syngas before sulfur removalThe directly heated gasifier operating pressure selected in thisstudy was 24 bar and represents the state of the art in fluidized-bed biomass gasification systems It has been shown that highergasifier operating pressure is generally preferred when consideringgasifier efficiency and the heating value of the syngas [19] How-ever the sensitivity of gasifier performance increases if pressureis rather low For instance a doubling of gasifier pressure onlyincreases gasifier efficiency and heating value by 1ndash2 points[19] A detailed exploration of the effect of gasifier operatingpressure on the merit of the hybrid system proposed herein isbeyond the scope of this analysis but efficiency analyses and bio-refinery performance using pressurized gasifiers are reported else-where [20] Detailed discussion of the design assumptions andsimulation are available in Refs [710]

A cryogenic ASU is used to produce the oxygen for the baselinestudy In addition to producing oxygen a nitrogen stream is avail-able as a byproduct from the ASU and is used as the inert pressur-ization agent for the lock-hopper system To replace the ASUwith electrolyzers the LO-CAT=ZnO sulfur removal steps wouldneed to be replaced with a two-stage Selexol plant The sulfur re-moval change is driven by the need for an inert gas for feed pres-surization Since no nitrogen stream is available from theelectrolyzer carbon dioxide will be used for feed pressurizationinstead Selexol can be configured to remove both sulfur com-pounds and carbon dioxide from the syngas [21]

To replace a single ASU unit for oxygen production multipleelectrolyzers are needed The largest commercial electrolyzer isproduced by StatoilHydro and produces a maximum flow rate of174 kg=h of oxygen (436 kg=h of hydrogen) The StatoilHydroelectrolyzer is an alkaline low-temperature system [22] Whilesignificant research is ongoing for high-temperature advancedelectrolysis systems commercial technology was chosen for thisanalysis

Based on ASPEN simulations a 2000 TPD fluidized-bed biomassgasifier with secondary oxygen injection would need approxi-mately 27800 kg=h of oxygen supplied For this design 160 elec-trolyzers would be needed to replace the ASU This number

Table 3 Sinking system input and outputa

H2 production mode Sinking mode

Input (MW) Biomass feed 434 434NG feed 23 28

Electricity 10 57Output (MW) Electricity mdash mdash

H2 232 261

aWhere applicable mass flows were converted to energy flows with thesame heating values given in Table 1

Fig 4 Direct gasifier baseline system

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-5

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

assumes that all electrolysis units run at design capacity 100 ofthe time

Input and output parameters from the electrolysis plant weredetermined from the published ldquoFuture Central Hydrogen Produc-tion from Grid Electrolysisrdquo H2A case [23] Based on ASPEN Plussimulations and the electrolysis H2A case the plant input and out-put values for the hybrid system were estimated The values foreach individual plant and the hybrid case are given in Table 4

The amount of electricity required to power the electrolyzerbank is extremely large when keeping the plant sized at 2000 TPDAssuming a 35 capacity factor for installed wind 970 MW of in-stalled wind capacity would be needed to generate enough averageelectricity for a 2000 TPD plant This is much larger than the totalamount of installed wind power in some states The large electricityneeds render the idea of capturing stranded resources with this scalebiorefinery plant problematic and ultimately infeasible However itis noteworthy that hydrogen production is also increased by 172over the base plant with this hybrid concept

While this study focuses on maintaining a 2000 TPD size biore-finery if instead the plant design objective was to deliver 165MW of hydrogen then the biomass feed requirement could belowered to approximately 920 TPD and the electricity demandreduced by 62 The reduction in biomass feedstock requirementswith this configuration is significant because it increases the num-ber of geographic locations that could support wind=biomasshybrid systems and ultimately lowers the land area requirementsfor sustainable fuel production

Multiple sources were used to estimate the capital costs associ-ated with the directly heated gasifier concepts All electrolyzercosts were calculated using the previously mentioned hydrogenanalysis [23] The majority of costs associated with the fluidizedbed gasifier and feed preparation were taken from a recent publi-cation by Jin et al [25] Gas cleanup costs were scaled based onprevious systems studies completed at the NREL [9] Selexol pri-ces were based on Department of Energy estimates [26] An over-view of the capital costs can be found in Table 5 Detailed costinginformation for both systems is available in Refs [710]

Based on the cost information summarized in Table 5 directreplacement of the ASU with an electrolyzer bank causes a 72increase in the total capital investment required

Economic Model

The hybrid system concepts studied respond dynamically tofluctuations in the energy market either absorbing or providingelectricity on demand To simulate this switching a binary modelwas created for each proposed system based on a specified peak-ing or sinking duty Duty is defined as the percent of hours peryear where either sinking or peaking mode is used

All concepts were assumed to be grid-connected for the analy-sis The hybrid plants are intended to provide grid leveling serv-ices to a local utility that has intermittent wind resources Thisarrangement allows for direct assessment of the market value ofelectricity and avoids inclusion of wind turbine capital costs in thecost of the system For the directly heated gasifier hybrid systemthe effect of stranded operation is discussed briefly in the eco-nomic results section of this paper

Regional Transmission Organization (RTO) day-ahead priceswere used for the cost-of-electricity when available These pricesrepresent the market value of electricity to the local utilities in anarea on an hourly averaged basis The hybrid systems must beprofitable at this low price point to cost effectively trade electric-ity on the energy market When day-ahead market informationwas unavailable load lambda data was used in its place Loadlambda data give the cost of producing one unit of electricity tothe utility for each hour of the year In all cases costs were basedon 2007 year-end data Based on GIS research reported earlier(see Figs 1 and 2) three general areas appear to have overlappingresources of both wind and biomass These areas are served by theNortheast Independent System Operator (NE ISO) Midwest ISO(MISO) and Northwest Interchange (NW Int) Cost of electricityvalues for each of these areas was used in the analysis

To assess the economic potential of each of the proposedhybridizations the yearly inputs and outputs for each plant alongwith applicable capital costs were entered into the H2A AnalysisTool developed by NREL [27] The resulting cost of hydrogenproduced (in dollars per kilogram) was compared to baseline plantresults and also the published steam methane reforming results[28] The analysis was performed in 2005 constant dollars for con-sistency with previous NREL studies [928]

The price of natural gas was held static for each of the regions stud-ied The 2009 Annual Energy Outlook report predicts regional varia-tion of natural gas prices in the US of approximately three dollars permillion Btu [29] The predicted variation translates to approximately10 cents per normal cubic meter The sensitivity analysis for each ofthe hybrid plants shows the effects of a larger 30 variation in naturalgas prices The SMR base case is also sensitive to natural gas priceswith a $010 per normal cubic meter variation in price gas price caus-ing a $047 change in the cost of hydrogen produced [28]

The economic analysis makes several assumptions includingthat current electricity prices are representative of those at thetime of actual plant construction and that sufficient marketdemand for hydrogen exists that all product can be sold Themajor economic assumptions are summarized in Table 6 Addi-tionally values for rate of return and startup times for the plantsare selected to enable comparison with other studies on hydrogenproduction from resources such as methane (see Tables 8 and 9)For this reason all economic assumptions were taken directlyfrom H2A defaults [27]

The effects of carbon costs on system results were taken intoaccount separately as an adjustment to the H2A results Theamount of CO2e per kilogram of hydrogen produced was trackedfor all cases analyzed The emissions for each hybrid system varynot only with the type of hybridization but also with the amountof time spent in each mode of operation Values for these emis-sions are given with the economic results

In addition to including the CO2e emissions from the plantthere is a CO2e credit associated with carbon emissions avoideddue to the renewable nature of any fuel or electricity producedBased on the regional average grid mix anywhere from 483 to 724kg of CO2e are emitted per kilowatt-hour of electricity produced

Table 4 Direct gasifier input and outputa

Baseline plant Hybrid plant

Input (MW) Biomass feedb 411 411NG feed mdash mdash

Electricity mdash 342Output (MW) Electricity 15 mdash

H2 165 449

aWhere applicable mass flows were converted to energy flows with thesame heating values given in Table 1bA biomass LHV of 177 MJ=kg bone-dry wood was used due to slightlydifferent simulation feedstock [24]

Table 5 Direct gasifier capital costs

Plant area Baseline Hybrid

Feed preparation handling $279 M $279 MGasification tar reforming quench $227 M $227 MASU or electrolyzer bank $213 M $992 MGas cleanup $299 M $587 MShift and PSA $186 M $186 MSteam and power generation $204 M $204 MWater and other utilities $21 M $37 MBuildings and structures $64 M $64 MTotal $1493 M $2576 M

031801-6 Vol 133 SEPTEMBER 2011 Transactions of the ASME

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

Table 7 details the grid production mix and correspondingemissions for each location studied The values shown in Table 7are assumptions in so much as they are averaged values for largeprocesses or regions Table 7 is actually a calculation matrix Asan example for the column ldquoNE ISOrdquo the calculation for the aver-age greenhouse gas emission for each kilowatt-hour of energyproduced is shown in Eq (1)

0150 9525thorn 0180 8931thorn 0300 5992 frac14 483 (1)

One kilogram of hydrogen has the approximate energy equivalentof 1 gal of gasoline However because hydrogen can be used infuel cells with much higher efficiency 1 kg of hydrogen couldactually offset about 2 gal of gasoline [30] Burning 2 gal of gaso-line produces 1784 kg of CO2e These numbers were used as car-bon credits for each kilogram of hydrogen or megawatt-hour ofelectricity produced by the proposed systems

Economic Results

The proposed indirectly heated gasifier peaking systemswitches between (1) hydrogen production and (2) electricity pro-duction (peaking) driven by the cost of electricity available on thegrid Based on discussions with Xcel Energy in Colorado [34] apeaking duty of 20 was used for the analysis Table 8 summa-rizes the major model inputs by region for the system A contractrate was used for any peaking electricity produced by the plantThis is common practice in the current electricity market and pro-vides a premium price for dispatchable peaking assets The cost ofbiomass feedstock was not varied regionally due to a lack of areliable index or market basis upon which to base the variation

Instead the effect of biomass feedstock cost was investigated aspart of the sensitivity analysis

Based on the economic inputs above and the plant inputs andoutputs previously discussed the cost of hydrogen production ineach area was calculated The results are shown in Table 9 alongwith the cost of hydrogen production for a baseline nonhybri-dized biomass to hydrogen plant and a SMR plant

The additional capital costs of hybridization cannot be justifiedtoday in any of the locations studied There is a $020 to $024 perkilogram premium on hydrogen produced by the proposed hybridsystem compared with a nonhybrid biomass to hydrogen gasifica-tion plant Areas with higher priced electricity move this hybrid-ization closer to economic feasibility with the best results foundin the Northeast

When the hybrid plant is producing electricity the plant usesno natural gas or electricity whereas when the plant is producinghydrogen natural gas is used for balancing the heat duty of theplant and electricity is required to run compressors Taking thedifferences in carbon emissions into account a value of $37ndash40per metric ton of CO2e makes the cost of hydrogen for the pro-posed hybrid system equal to that of SMR depending on the loca-tion This comparison was made assuming that both the hybridplant and SMR plant are subject to the same natural gas cost at agiven location

It is important to note that the baseline biomass to hydrogenplant only requires $23ndash25 per metric ton of CO2e value to becost competitive with hydrogen produced by SMR This meansthat peaking hybridization will only be economically promisingwhen there is some value placed on the additional functionality ofdual mode operation

In order to characterize the effect of various technical and eco-nomic assumptions a sensitivity analysis was performed for thegas turbine peaking system Figure 5 shows the results for the costof hydrogen in tornado chart format Capital costs the cost of bio-mass and the price which peaking electricity can be sold for arethe key inputs Capital costs when varied 630 cause the cost ofhydrogen to vary $025 The cost of biomass was varied from $40to $60 per ton based on projections in Ref [35] and causes thecost of hydrogen to vary by less than $020 The price of peakingelectricity and the plant capacity factor also cause fluctuations ofless than $020 Changes in the cost of electricity bought by theplant the cost of natural gas peaking power output and turbinepeaking duty cause hydrogen costs to vary less than 5

The proposed sinking system switches between (1) hydrogenproduction with syngas recycling for gasifier heat and (2) hydro-gen production with electrical heating (sinking) to decrease the

Table 7 Greenhouse gas assumptions

kg CO2e per kW ha NE ISOb MISOc NW Intd

Coal 9525 150 756 580Oil=petroleum 8931 180 01 10Natural gas 5992 300 36 197Nuclear mdash 280 151 10Renewable mdash 90 56 203Average kg CO2e=kW h mdash 483 743 679

aHyARC Energy Constants and Assumptions H2A Analysis Tool [26]bNE ISO energy sources report [31]cMidwest ISO June monthly report [32]dApproximation based on PacifiCorp 2008 integrated resource plan [33]

Table 8 Peaking system H2A inputs

NE ISO MISO NW Int

Peaking duty 20 20 20Peaking electricity value (cent=kW h) 140 120 115Utility electricity cost (cent=kW h) 592 362 369Utility natural gas cost ($=nm3) 032 032 032Cost of biomass ($=ton)a 4883 4883 4883

aValue taken from the Biomass 2009 Multi-Year Research Developmentand Demonstration Plan (EERE 2009) The 2012 target value is $5070per ton of dry woody biomass in 2007 dollars Taken to 2005 dollars with109 inflation this yields $4883 per ton

Table 9 Peaking system results

$=kg H2 NE ISO MISO NW Int

SMR 140 140 140Biomass to hydrogen baseline 164 164 164Gas turbine hybrid system 184 186 188

Table 6 Economic assumptions

Parameter Value

Constant dollar value 2005Internal rate of return (after-tax) 10Debt=equity 0=100Plant life 40 yearsDepreciation Modified accelerated cost recovery systemDepreciation recovery period 20 yearsConstruction period 2 years

1st year 75 (25 for electrolysis)2nd year 25 (75 for electrolysis)

Start-up time 12 monthsRevenues 50Variable costs 75Fixed costs 100

Working capital 15 of total capital investmentInflation rate 19Total taxes 389Decommissioning costs 10 of depreciable capitalSalvage value 10 of total capital investment

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-7

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

syngas recycle This sinking ability can best be described as a dis-patchable load or demand from the viewpoint of the grid

Based on discussions with Xcel Energy the utility will pay tohave wind-generated electricity used at times (the electricity has anegative cost) and having a dispatchable load would provide avaluable service to the utility [34] Xcel Energy is required byColoradorsquos renewable portfolio standard to accept renewableenergy when it is available The requirement to accept wind elec-tricity regardless of grid demand is not universal and thereforenegative cost wind electricity may not be available in other states

No similar system was found for comparison therefore a sink-ing duty of 20 was used as a starting point for the analysisTable 10 summarizes the major economic model inputs by regionUnlike peaking electricity where a contract rate is used for elec-tricity produced by the plant the sinking analysis simply uses theaverage cost-of-electricity for the cheapest 20 of hours as thesinking electricity cost The utility electricity cost is the averageof the remaining 80 of the hours These costs-of-electricitywould be valid if a plant operator used accurate day-ahead energymarket forecasts to schedule plant operation

Given the economic inputs in Table 10 the cost of hydrogenproduction in each area was calculated The results are shown inTable 11 along with the cost of hydrogen production for a base-line nonhybridized biomass to hydrogen plant and a steam meth-ane reforming plant

There is a $003 to $011 premium on hydrogen produced bythe proposed hybrid system compared with a nonhybrid biomassto hydrogen gasification plant The additional capital costs of the

sinking hybridization are not fully offset by additional revenue inany of the locations studied However the marginal costs foundare small enough that it is difficult to draw any definitive conclu-sion Areas with lower cost electricity move this hybridizationcloser to economic feasibility with the best results found in theNorthwest

Because the premium is small (about 5) it may be acceptablein the long term Recent studies have shown that there is inherentvalue added or welfare effects for electricity storage capacity[36] Whether similar value is added by the proposed sinkinghybrid is unknown A more likely parallel would be the idea ofldquointerruptible customersrdquo which get discounted electricity rates inreturn for intermittent power supply A similar contractual agree-ment could be envisioned for the proposed hybrid where dis-counted electricity rates would be provided in return forintermittent demand

The proposed system is not a direct competitor with storagesystems such as pumped hydroelectric or compressed air energystorage (CAES) Energy storage systems attempt to profit by mar-ket arbitrage (selling electricity back to the grid at a higher pricethan it was bought) whereas the proposed hybrid system sinkscheap electricity into transportation fuel Sinking low cost elec-tricity into fuel could be considered cross-market arbitrage andthe most similar system to this would be electrolysis Comparedto electrolysis the proposed system is significantly less expensiveand has the added benefit of running without electric heat whenelectricity costs are too high

Assuming that all sinking electricity is renewable and takingthe additional differences in carbon emissions into account avalue of $26ndash32 per metric ton of CO2e makes the proposedhybrid cost competitive depending on the location of the system

Fig 5 Peaking system sensitivity (NE ISO)

Table 10 Sinking system H2A inputs

NE ISO MISO NW Int

Plant capacity factor 90 90 90Sinking duty 20 20 20Sinking electricity cost (cent=kW h) 435 220 218Utility electricity cost (cent=kW h) 705 487 469Utility natural gas cost ($=nm3) 032 032 032Cost of biomass ($=ton) 4883 4883 4883

Table 11 Indirect sinking system results

$=kg H2 NE ISO MISO NW Int

SMR 140 140 140Biomass to hydrogen baseline 164 164 164Electric air heater hybrid system 175 167 168

031801-8 Vol 133 SEPTEMBER 2011 Transactions of the ASME

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

At $27 per metric ton of CO2e the combustion air-heater hybrid-ization becomes cost competitive with a methane steam reformingplant in the Northwest assuming both the hybrid plant and SMRplant are subject to the same natural gas cost

In order to characterize the effect of various technical and eco-nomic assumptions a sensitivity analysis was performed for thesinking systems (Fig 6) The sensitivity analysis shows that capi-tal costs the cost of biomass and the plant capacity factor for arethe key inputs Capital costs when varied 630 cause the cost ofhydrogen to vary $018 The cost of biomass was varied from $40per ton to $60 per ton and causes the cost of hydrogen to vary byless than $015 Changes in the sinking duty the added hydrogenproduction due to sinking the cost of natural gas and the cost ofelectricity cause hydrogen costs to vary less than 3

From the sinking duty sensitivity analysis it appears that anincreased sinking duty would be preferable to the 20 assumptionmade Minimum hydrogen production prices occur when the elec-tric heating systems are run approximately 40 of the time Run-ning the electric heaters for more time increases plant hydrogenproduction and decreases plant green house gas emissions

The proposed directly heated gasifier hybrid system replacesthe ASU with an electrolyzer bank An H2A analysis was com-pleted to determine the baseline cost of hydrogen produced by adirectly heated gasification plant that uses electrolysis regardlessof electricity cost and the cost of hydrogen for a directly heatedgasification plant that uses a traditional ASU Table 12 summa-rizes the major model inputs The plant was assumed to be locatedin the Midwest ISO region The results of the analysis along withthe associated carbon emissions are listed in Table 13 Costs forproduction of hydrogen via SMR and for an electrolysis plantonly are also shown for reference purposes

As shown in Table 13 hydrogen produced by a direct gasifier-electrolyzer hybrid plant is significantly more expensive than thatproduced by SMR Electricity costs account for 37 of the overallcost of hydrogen produced (or about $086) Therefore if the costof electricity could be halved by intermittent operation during off-peak hours the savings would bring the cost of hydrogen to $189per kilogram of hydrogen At this price the hybrid system couldcompete with hydrogen produced by a standard direct gasificationplant It is important to note that these costs are approximately15 higher than the $164 per kilogram of hydrogen estimated forthe indirectly heated baseline gasification plant used for compari-son of the indirect hybrid analysis (see Table 11)

The original concept called for the electrolyzer bank to bedirectly coupled with stranded wind resources Typical capacityfactors for wind-generated power are in the 30ndash35 range [37]The effect of intermittent operation on the cost of hydrogen pro-duction was investigated using electrolyzer duties of 20 35and 50 The smaller the duty the larger the number electrolyz-ers needed to produce the same amount of oxygen per year

The effect of reduced electrolyzer duty on the cost of hydrogenis shown in Fig 7 Two curves are plotted The first assumes aconstant electricity price of $433=MWh regardless of the electro-lyzer duty This assumption would represent the scenario if theelectrolyzers were directly coupled with a stranded wind resourceThe second curve uses Midwest ISO market data so that the costof electricity fluctuates with duty These numbers do not considerthe cost of oxygen storage as these costs are assumed small com-pared to the increased electrolyzer capital costs and are identicalfor similar duty

Intermittent operation significantly adds to plant capital costsIf the price of electricity available to the plant does not decrease

Fig 6 Sinking system sensitivity (NW Int)

Table 12 Direct system H2A inputs

MISO

Electrolyzer duty () 100Utility electricity cost (cent=kW h) 433Cost of biomass ($=ton) 4883

Table 13 Direct system results

$=kg H2 Net CO2e=kg H2

SMR $140 68Biomass gasification $213 196Electrolysis $259 145 (178)Electrolysisthorn gasification $232 024 (182)

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-9

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

with intermittent electrolyzer operation then the cost of hydrogenincreases by 22 for a 35 duty However if the cost of electric-ity can be reduced by intermittent operation then the analysisshows that intermittent operation may be preferable to 100 dutyThis result means that the initial concept of capturing strandedresources is less favorable economically than a grid-connectedsinking system

If grid electricity is used then carbon emissions actuallyincrease relative to biomass gasification alone for this hybridiza-tion If upstream emissions for electricity production are takeninto account electrolysis and this proposed hybrid are both netCO2e emitters This makes their justification by carbon valueimpossible unless only renewable electricity is used for operation(renewable energy values are shown in parentheses in Table 13)Since renewable wind energy is inherently intermittent it isunreasonable to assume renewable electricity is used without add-ing the necessary equipment for intermittent operation Onerenewable energy exception would be the use of hydroelectricpower for the systems

Similar to the other hybrid systems investigated hybridizationresults in a price premium There must be some additional justifi-cation for hybridization such as utility demands The baseline bio-mass to hydrogen case with an ASU requires only $35 per metricton of CO2e to be cost competitive with SMR produced hydrogen

assuming both the hybrid plant and SMR plant are subject to thesame natural gas cost at a given location

Electrolyzer-based hybrid system economics are extremely sen-sitive to the cost of electricity (Fig 8) Fluctuations of $001 inthe cost of electricity cause the price of hydrogen to fluctuatemore than $025 per kilogram If the price of electricity were todrop below $004=kW h then the proposed hybrid system couldeconomically compete with a nonhybrid biomass to hydrogenplant However this low price level is unlikely and any energymarket fluctuations would have a dramatic effect on economicviability

Conclusion

The two hybrid concepts analyzed involve coproduction of gase-ous hydrogen and electric power from thermochemical-based biorefi-neries Both of the concepts analyzed share the basic idea ofcombining intermittent wind-generated electricity with a biomassgasification plant Wind availability overlaps biomass resource avail-ability in three areas of the United States making the use of locallyproduced wind electricity for gasification feasible The proposedhybrid systems attempt to either fill wind energy shortfalls by burn-ing syngas in a natural gas turbine or absorb excess renewable powerduring times of low-electricity demand

None of the proposed hybrid systems produced hydrogen forless than a nonhybrid plant could In all cases a premium was paidfor hybridization that could not be offset by the increasedfunctionality

The indirectly heated gasifier hybrid system consists of twoparts (1) producing peaking electricity intermittently with a gasturbine and (2) sinking electricity into electric heaters intermit-tently to boost fuel production efficiency Each of these parts wasanalyzed separately The indirectly heated gasifier hybrid systemis meant to be grid-connected and provide peaking electricity anddispatchable demand (eg an on demand load) to the local utilityto help manage intermittent wind resources

The indirect gasification concepts studied could be cost compet-itive in the near future as value is placed on controlling carbonemissions Carbon values of just under $40 per metric ton ofCO2e make the systems studied cost competitive with steam

Fig 7 Electrolyzer duty versus cost

Fig 8 Direct system sensitivity

031801-10 Vol 133 SEPTEMBER 2011 Transactions of the ASME

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

methane reforming to produce hydrogen However a nonhybridbiomass to hydrogen plant will be more cost competitive in gen-eral so there must be additional operational value placed on peak-ing or sinking for these plants to be economically attractive Thisadditional value is likely to become a reality as additional inter-mittent renewable energy sources such as wind are added to thenational grid

The directly heated gasifier hybrid system involves replacementof the air separation unit with electrolyzers This change allowsfor extra production of hydrogen and intermittent operation Theanalysis for this system assumed direct replacement of the ASUwithout intermittent operation Estimates of the effect of intermit-tent operation on plant economics were made The electrolyzerbank could be either grid-connected to provide a dispatchabledemand to the utility or it could be tied directly to a stranded windsource to convert wind into chemical fuel (H2)

The direct gasification concept studied is unlikely to be cost com-petitive in the near future but may eventually be attractive withlower-cost electrolysis and a smaller biorefinery plant size that issized for a specific hydrogen demand Intermittent operation andstranded operation were found to have worse economics than grid-connected systems High electrolyzer capital costs make the possibleelectricity cost savings of intermittent operation difficult to justifyBased on a direct replacement of the ASU with electrolyzers hydro-gen can be produced for $232 per kilogram However using gridelectricity the hybrid system is a net CO2e emitter For the use ofelectrolysis to make sense in this setting there must be a significantbenefit to the ability to operate intermittently

Acknowledgment

The authors would also like to acknowledge Dr Bob Evans forconceiving the hybrid hydrogen production systems project andDonna Heimiller for performing the GIS mapping

Employees of the Alliance for Sustainable Energy LLC underContract No DE-AC36-08GO28308 with the US Dept ofEnergy have authored this work The United States Governmentretains and the publisher by accepting the article for publicationacknowledges that the United States Government retains a nonex-clusive paid-up irrevocable worldwide license to publish orreproduce the published form of this work or allow others to doso for United States Government purposes

References[1] Milbrandt A 2005 ldquoA Geographic Perspective on the Current Biomass

Resource Availability in the United Statesrdquo National Renewable Energy LabReport No TP-560-39181

[2] Perlack R Wright L Turhollow A Graham R Stokes B and Erbach D2005 Biomass as Feedstock for a Bioenergy and Bioproducts Industry The Tech-nical Feasibility of a Billion-Ton Annual Supply Oak Ridge National LaboratoryOak 853 Ridge TN

[3] Turner J Sverdrup G Mann M Maness P C Kroposki B Ghirardi MEvans J and Blake D 2008 ldquoRenewable Hydrogen Productionrdquo Int JEnergy Res 32 pp 379ndash407

[4] US Department of Energy Energy Efficiency and Renewable Energy Labora-tory 2008 ldquo20 Wind Energy by 2030mdashIncreasing Wind Energyrsquos Contribu-tion to US Electricity Supplyrdquo Report No GO-102008-2567

[5] Levene J Kroposki B and Sverdrup G 2006 ldquoWind Energy and Productionof Hydrogen and ElectricityndashOpportunities for Renewable Hydrogenrdquo NationalRenewable Energy Laboratory Report No CP560-39534

[6] Fingersh L 2004 ldquoOptimization of Utility-Scale Wind-Hydrogen-BatterySystemsrdquo National Renewable Energy Laboratory Report No CP-500-36117

[7] Dean J Braun R Munoz D Penev M and Kinchin C 2010 ldquoAnalysis ofHybrid Hydrogen Systems ndash Final Reportrdquo National Renewable Energy Labo-ratory Report No TP-46934

[8] Gasification Technology Status ndash December 2006 EPRI and the Gasification869 Users Association Palo Alto CA p 1012224

[9] Spath P Aden A Eggeman T Ringer M Wallace B and Jechura J2005 ldquoBiomass to Hydrogen Production Detailed Design and Economics Uti-lizing the Battelle Columbus Laboratory Indirectly-Heated Gasifierrdquo NationalRenewable Energy Laboratory Report No TP-510-37408

[10] Dean J 2010 ldquoLeveling Intermittent Renewable Energy Production ThroughBiomass Gasification-based Hybrid Systemsrdquo MS thesis Colorado School ofMines Golden CO

[11] Devi L Ptasinski K Janssen F van Paasen S Bergman P and Kiel J2005 ldquoCatalytic Decomposition of Biomass Tars Use of Dolomite anUntreated Olivinerdquo Renewable Energy 30 pp 565ndash587

[12] Heavy Duty Gas Turbine Products 2009 General Electric Company FairfieldCT

[13] Drdar D and Jones R 2000 ldquoGE IGCC Technology and Experience withAdvanced Gas Turbinesrdquo GE Power Systems Report No GER-4207

[14] Craig K and Mann M 1996 ldquoCost and Performance Analysis of Biomass-Based Integrated Gasification Combined-Cycle (BIGCC) Power SystemsrdquoNational Renewable Energy Laboratory Report No TP-430-21657

[15] Gas Turbine World 2006 Handbook (Pequot Publishing Inc Fairfield CT2006)

[16] Kinchin C and Bain R 2009 ldquoHydrogen Production from Biomass via Indi-rect Gasification The Impact of NREL Process Development Unit GasifierCorrelationsrdquo National Renewable Energy Laboratory Report No TP-510-44868

[17] Watlow for 22 MW duct heaters Watlow 12001 Lackland Road St LouisMO 63146 personal communication 2009

[18] Gassner M and Marechal F 2008 ldquoThermo-economic Optimization of theIntegration of Electrolysis in Synthetic Natural Gas Production from WoodrdquoEnergy 33 pp 189ndash198

[19] Srinivas T Gupta A V S and Reddy B V 2009 ldquoThermodynamic Equi-librium Model and Exergy Analysis of a Biomass Gasifierrdquo ASME J EnergyResour Technol 131 031801 pp 1ndash7

[20] Braun R J Hanzon L G and Dean J H 2011 ldquoSystem Analysis of Ther-mochemical-based Biorefineries for Coproduction of Hydrogen and Elec-tricityrdquo ASME J Energy Resour Technol 133 012601 pp 1ndash12

[21] Manning F and Thompson R 1991 Oilfield Processing of Petroleum Vol-ume One 904 Natural Gas PennWell Publishing Co Tulsa Oklahoma

[22] StatoilHydro 2009 ldquoHydrogen Technologies World Leader in Electrolysis forHydrogen Solutionsrdquo product brochure Hydrogen Technologies NO-3674Notodden Norway COS 091408 available URL http908wwwelectrolyserscom

[23] US Department of Energy Hydrogen Program 2009 ldquoFuture Central Hydro-gen Production from Grid Electrolysisrdquo H2A analysis wwwhydrogenenergygovh2a_prod_studieshtml

[24] Phyllis Biomass Datapage ldquowood hybrid poplarrdquo ID 806 available URLhttpwwwecnnlphyllis

[25] Jin H Larson E and Celik F 2009 ldquoPerformance and Cost Analysis ofFuture Commercially Mature Gasification-Based Electric Power GenerationFrom Switchgrassrdquo Biofpr 3 pp 142ndash173

[26] Department of Energy 2007 ldquoCost and Performance Baseline for Fossil EnergyPlants Volume 1 Bituminous Coal and Natural Gas to Electricityrdquo Report NoDOE=NETL-2007=1281

[27] US Department of Energy Hydrogen Program 2009 ldquoDOE H2A Analy-sisrdquo wwwhydrogenenergygovh2a_analysishtml

[28] US Department of Energy Hydrogen Program 2009 ldquoFuture Central Hydro-gen Production from Natural Gas with CO2 Sequestrationrdquo H2A analysiswwwhydrogenenergygovh2a_prod_studieshtml

[29] Energy Information Administration Annual Energy Outlook 2009 wwweiadoegovoiafaeoelectricityhtml

[30] Schafer A Heywood J and Weiss M 2006 ldquoFuture Fuel Cell and InternalCombustion Engine Automobile Technologies A 25-Year Life Cycle and FleetImpact Assessmentrdquo Energy 31 pp 2064ndash2087

[31] NE ISO 2009 ldquoEnergy Sources in New Englandrdquo wwwiso-necomnwsissgrid_mktsenrgy_srcs

[32] Doying R 2009 Midwest ISO ldquoJune Monthly Reportrdquo wwwmidwestisoorg[33] PacifiCorp 2009 ldquoIntegrated Resource Plan ndash Volume 1rdquo May 29 2009

wwwpaci-937ficorpcom[34] Frank Novachek 2009 Xcel Energy 414 Nicollet Mall Minneapolis MN

55401 939 personal communication[35] Energy Efficiency and Renewable Energy Department of Energy ldquoBiomass

2009 Multi-Year Research Development and Demonstration Planrdquo www1eer-eenergygovbiomasspdfsmypp_may2009pdf

[36] Sioshansi R Denholm P Jenkin T and Weiss J 2009 ldquoEstimating theValue of Electricity Storage in PJM Arbitrage and Some Welfare EffectrdquoEnergy Econ 31 pp 269ndash277

[37] Kroposki B Levene J Harrison K Sen P K and Novachek F 2006ldquoElectrolysis Information and Opportunities for Electric Power UtilitiesrdquoNational Renewable Energy Laboratory Report No TP-581-40

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-11

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

Cooling issues can arise with syngas combustion depending onits composition Increased burner temperatures can shorten theservice life of a turbine as well as significantly increasing NOx

and SOx emissions Based on data from general electric gasifica-tion projects [13] and previous research performed at the NREL[14] syngas compositions similar to the ones used in this studyare typically humidified with steam before combustion to regulatethe turbine inlet temperature Steam was added to the syngas sothat the final fuel gas was 20 water by weight This correspondsto a lower heating value (LHV) of approximately 11 MJ=kg Thesteam was available from the on-site steam cycle

Syngas from the LO-CAT reactor is sent to the gas turbine dur-ing power generation Tar reforming is required because tars arecorrosive and could adversely affect the turbine combustor Inaddition the tar represents a significant portion of the chemicalenergy of the syngas and removal (versus reforming) would resultin a measurable decrease in plant efficiency Therefore directlyafter the tar reformer was the first possible location to split thesyngas stream for combustion However by placing the turbinedownstream of the bulk sulfur removal step emissions of SOx canbe significantly reduced

The system operates in a binary mode meaning that it eitherproduces power or hydrogen but not both at the same time Inaddition to potential dynamic operational issues associated withswitching between the two modes there are several steady-statetechnical challenges due to the high degree of thermal integrationin the base plant Down stream water-gas shift (WGS) catalystbeds are extremely sensitive to air exposure and therefore syngasflow must be maintained or they must be sealed if shut down Inaddition the pressure swing adsorption off-gas from hydrogenproduction is burned to heat the tar reformer This energy must bereplaced when the PSA is not running during power productionFinally the base design includes a thermally integrated steamcycle which is partially fed by syngas cooling steps downstreamof the split location Loss of this heat energy to the steam turbinewill adversely affect the plant power system

The first two technical challenges were both addressed bydiverting only a limited amount of syngas to the gas turbine whenproducing electricity A slipstream of syngas is maintainedthrough the water-gas shift reactors to avoid oxygen poisoning ofthe catalyst After going through the water-gas shift reactors thesyngas is routed to the tar reformer and burned to replace the PSAoff-gas that was previously burned to maintain temperature Thisapproach should keep the sensitive water-gas shift catalysts fromair and also meet the energy demands of the tar reformer systemIn addition all base design systems are kept warm and active(except for the PSA unit) until peaking power is no longer needed

In order to maintain the base plant steam system a portion ofthe exhaust gases from the gas turbine are run through a heatexchanger The heat exchanger exactly replaces heat loss fromcooling steps downstream of the split location

Table 1 summarizes the ASPEN PlusVR simulation results for thepeaking hybrid system When making hydrogen fuel the plant

would have the major input and output variables shown in the H2

production column The power production column shows theinput and output variables when the PSA unit is shut down

The power production value of 77 MW represents the net powerthe plant could produce using a ldquorubberrdquo turbine3 with GE F-classefficiencies The rubber turbine has a gross assumed nameplatecapacity of 806 MW but loses significant power due to plant para-sitic needs When running in a peaking capacity the plant has alow total efficiency of 178-LHV This is compared to an effi-ciency of 497-LHV when producing hydrogen and an expectedstand-alone turbine efficiency of approximately 32

The extremely low power production efficiency is the result ofmultiple factors including the fact that 21 of the syngas streamis used to maintain the water-gas shift reactors and tar cracker atelevated temperature rather than for power production In addi-tion a portion of the power output is used to serve auxiliary elec-trical loads within the plant

Capital costs were estimated using numbers taken from Ref [9]as a starting point In 2005 dollars the cost of a 2000 TPD biorefi-nery is estimated to be approximately $105 106 The cost of thegas turbine and additional heat exchangers were added to this costfor the hybrid case The gas turbine costs were taken from Ref[15] and then adjusted to $2005 using the Chemical EngineeringPlant Cost Index Heat exchanger costs were calculated with thesame scaling factors used in Ref [9] The additional capital costsfor the turbine and exhaust boiler feed water (BFW) preheater arelisted in Table 2

Indirect Gasifier Sinking Modifications Recent studies sug-gest that an indirectly heated gasifier will not produce enoughchar to maintain gasification temperatures therefore raw syngasmust be diverted and combusted to supplement the heat deliveredto the gasifier by the char combustor [16] Therefore during peri-ods of low electricity demand (low purchase price) electric heat-ers could be used to add heat and partially replace the syngasrecycle stream Electric heating allows more hydrogen to be pro-duced per ton of biomass feedstock which increases plantproduction

Supplementing the heat delivered to the gasifier by the charcombustor with electrically generated heat rather than divertingand combusting syngas could be accomplished in multiple ways[10] For this analysis high-power high-temperature electric airheaters were used By preheating the combustion air used inthe syngas and char combustors more heat can be delivered tothe sand per kilogram of char or syngas combusted resulting ina reduced amount of syngas that must be recycled The inten-tion is to allow intermittent use of the combustion air preheat-ers allowing the system to recycle syngas when electricityprices are high and add electric heat when electricity prices arelow

The ASPEN PlusVR simulation results are summarized in Table 3and appear to be promising The amount of syngas that must bediverted is reduced by about 45 by combustion air preheating

Table 1 Peaking system input and outputa

H2 productionmode

Power productionmode

Inputs (MW) Biomass feedb 434 434NG feedc 23 mdashElectricity 10 mdash

Outputs (MW) Electricity mdash 77H2

d 232 mdash

aWhere applicable mass flows were converted to energy flows with thefollowing lower heating valuesbA biomass LHV of 187 MJ=kg bone-dry wood was used [7]cNatural gas LHV of 4714 MJ=kg was used per HyARC database [23]dHydrogen LHV of 12021 MJ=kg was used per HyARC database [23]

Table 2 Indirect gasifier capital costs

Plant area Peaking Sinking

Baseline indirect gasifier planta $1049 M $1049 MTurbine $322 M mdashExhaust BFW preheater $025 M mdashAir duct heater and air blower mdash $158 MTotal $137 M $121 M

aThe baseline plant design and costs are based on Ref [9]

3The term ldquorubberrdquo turbine refers to the fact that the turbine size was set toexactly match fuel stream mass and energy flow as opposed to using an existingstock frame size

031801-4 Vol 133 SEPTEMBER 2011 Transactions of the ASME

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

Additionally enough hot combustion products are still producedto dry the incoming biomass

Unlike the peaking modification which produced lower effi-ciency adding electric heat to the plant increases the total plantefficiency (energy in=energy out) from 497 to 503 Eachadditional unit of energy input as electricity produces 056 unitsof hydrogen energy output Therefore while providing a dispatch-able load service to the local utility the hybrid plant operatesmore efficiently

The electric heater capital costs are based on a quote providedby a manufacturer [17] for their largest high-temperature airduct heater Based on that quote a 22 MW air duct heater isestimated to cost $250000 and has an electricity-to-heated airconversion efficiency of 90 Since additional unit savings arenot expected with increasing scale a scaling factor of 09 wasused Finally an installation factor of 247 was assumed for allcost estimates for consistency with other NREL hydrogen analy-ses (H2A) [9] Based on these assumptions the total additionalcapital costs for electrically heating the combustion air amountedto $158 million

Direct Gasifier Based Hybrid System

Directly heated gasifiers typically have a single combustion=reaction chamber and burn a small portion of the biomass feed togenerate the heat needed to drive the gasification reactions Asource of pure oxygen is required for combustion if the syngas isto be used for fuel production to avoid nitrogen dilution of thesyngas For large-scale oxygen production the established methodis to use a cryogenic ASU Electrolysis could provide an alterna-tive to an ASU with the added benefit of producing an additionalpure hydrogen stream

Recent research on the feasibility of combining electrolysiswith gasification concluded that the economic feasibility of thecombination was highly dependent on the price of available elec-tricity [18] The proposed hybrid system could directly addresselectricity price dependence by running the electrolysis systemintermittently based on the cost of electricity

A baseline gasification plant (see Fig 4) and a hybrid plantwere simulated in ASPEN Plus and were compared Both the base-line and hybrid plants have the same general structure biomass isgasified to produce syngas in a high-pressure directly heated gas-ifier Tars are removed and the syngas is cooled before entering asulfur removal step After sulfur has been removed the carbonmonoxide in the syngas stream is shifted towards hydrogenFinally the hydrogen is stripped from the syngas and the remain-ing gas is burned to generate power Figure 4 shows the envi-sioned biomass to hydrogen pathway using the direct gasifier anda cryogenic ASU

The bulk of the chemical processes operate at high pressureThe wet scrubber is run near atmospheric pressure which requirescooling and recompression of the syngas before sulfur removalThe directly heated gasifier operating pressure selected in thisstudy was 24 bar and represents the state of the art in fluidized-bed biomass gasification systems It has been shown that highergasifier operating pressure is generally preferred when consideringgasifier efficiency and the heating value of the syngas [19] How-ever the sensitivity of gasifier performance increases if pressureis rather low For instance a doubling of gasifier pressure onlyincreases gasifier efficiency and heating value by 1ndash2 points[19] A detailed exploration of the effect of gasifier operatingpressure on the merit of the hybrid system proposed herein isbeyond the scope of this analysis but efficiency analyses and bio-refinery performance using pressurized gasifiers are reported else-where [20] Detailed discussion of the design assumptions andsimulation are available in Refs [710]

A cryogenic ASU is used to produce the oxygen for the baselinestudy In addition to producing oxygen a nitrogen stream is avail-able as a byproduct from the ASU and is used as the inert pressur-ization agent for the lock-hopper system To replace the ASUwith electrolyzers the LO-CAT=ZnO sulfur removal steps wouldneed to be replaced with a two-stage Selexol plant The sulfur re-moval change is driven by the need for an inert gas for feed pres-surization Since no nitrogen stream is available from theelectrolyzer carbon dioxide will be used for feed pressurizationinstead Selexol can be configured to remove both sulfur com-pounds and carbon dioxide from the syngas [21]

To replace a single ASU unit for oxygen production multipleelectrolyzers are needed The largest commercial electrolyzer isproduced by StatoilHydro and produces a maximum flow rate of174 kg=h of oxygen (436 kg=h of hydrogen) The StatoilHydroelectrolyzer is an alkaline low-temperature system [22] Whilesignificant research is ongoing for high-temperature advancedelectrolysis systems commercial technology was chosen for thisanalysis

Based on ASPEN simulations a 2000 TPD fluidized-bed biomassgasifier with secondary oxygen injection would need approxi-mately 27800 kg=h of oxygen supplied For this design 160 elec-trolyzers would be needed to replace the ASU This number

Table 3 Sinking system input and outputa

H2 production mode Sinking mode

Input (MW) Biomass feed 434 434NG feed 23 28

Electricity 10 57Output (MW) Electricity mdash mdash

H2 232 261

aWhere applicable mass flows were converted to energy flows with thesame heating values given in Table 1

Fig 4 Direct gasifier baseline system

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-5

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assumes that all electrolysis units run at design capacity 100 ofthe time

Input and output parameters from the electrolysis plant weredetermined from the published ldquoFuture Central Hydrogen Produc-tion from Grid Electrolysisrdquo H2A case [23] Based on ASPEN Plussimulations and the electrolysis H2A case the plant input and out-put values for the hybrid system were estimated The values foreach individual plant and the hybrid case are given in Table 4

The amount of electricity required to power the electrolyzerbank is extremely large when keeping the plant sized at 2000 TPDAssuming a 35 capacity factor for installed wind 970 MW of in-stalled wind capacity would be needed to generate enough averageelectricity for a 2000 TPD plant This is much larger than the totalamount of installed wind power in some states The large electricityneeds render the idea of capturing stranded resources with this scalebiorefinery plant problematic and ultimately infeasible However itis noteworthy that hydrogen production is also increased by 172over the base plant with this hybrid concept

While this study focuses on maintaining a 2000 TPD size biore-finery if instead the plant design objective was to deliver 165MW of hydrogen then the biomass feed requirement could belowered to approximately 920 TPD and the electricity demandreduced by 62 The reduction in biomass feedstock requirementswith this configuration is significant because it increases the num-ber of geographic locations that could support wind=biomasshybrid systems and ultimately lowers the land area requirementsfor sustainable fuel production

Multiple sources were used to estimate the capital costs associ-ated with the directly heated gasifier concepts All electrolyzercosts were calculated using the previously mentioned hydrogenanalysis [23] The majority of costs associated with the fluidizedbed gasifier and feed preparation were taken from a recent publi-cation by Jin et al [25] Gas cleanup costs were scaled based onprevious systems studies completed at the NREL [9] Selexol pri-ces were based on Department of Energy estimates [26] An over-view of the capital costs can be found in Table 5 Detailed costinginformation for both systems is available in Refs [710]

Based on the cost information summarized in Table 5 directreplacement of the ASU with an electrolyzer bank causes a 72increase in the total capital investment required

Economic Model

The hybrid system concepts studied respond dynamically tofluctuations in the energy market either absorbing or providingelectricity on demand To simulate this switching a binary modelwas created for each proposed system based on a specified peak-ing or sinking duty Duty is defined as the percent of hours peryear where either sinking or peaking mode is used

All concepts were assumed to be grid-connected for the analy-sis The hybrid plants are intended to provide grid leveling serv-ices to a local utility that has intermittent wind resources Thisarrangement allows for direct assessment of the market value ofelectricity and avoids inclusion of wind turbine capital costs in thecost of the system For the directly heated gasifier hybrid systemthe effect of stranded operation is discussed briefly in the eco-nomic results section of this paper

Regional Transmission Organization (RTO) day-ahead priceswere used for the cost-of-electricity when available These pricesrepresent the market value of electricity to the local utilities in anarea on an hourly averaged basis The hybrid systems must beprofitable at this low price point to cost effectively trade electric-ity on the energy market When day-ahead market informationwas unavailable load lambda data was used in its place Loadlambda data give the cost of producing one unit of electricity tothe utility for each hour of the year In all cases costs were basedon 2007 year-end data Based on GIS research reported earlier(see Figs 1 and 2) three general areas appear to have overlappingresources of both wind and biomass These areas are served by theNortheast Independent System Operator (NE ISO) Midwest ISO(MISO) and Northwest Interchange (NW Int) Cost of electricityvalues for each of these areas was used in the analysis

To assess the economic potential of each of the proposedhybridizations the yearly inputs and outputs for each plant alongwith applicable capital costs were entered into the H2A AnalysisTool developed by NREL [27] The resulting cost of hydrogenproduced (in dollars per kilogram) was compared to baseline plantresults and also the published steam methane reforming results[28] The analysis was performed in 2005 constant dollars for con-sistency with previous NREL studies [928]

The price of natural gas was held static for each of the regions stud-ied The 2009 Annual Energy Outlook report predicts regional varia-tion of natural gas prices in the US of approximately three dollars permillion Btu [29] The predicted variation translates to approximately10 cents per normal cubic meter The sensitivity analysis for each ofthe hybrid plants shows the effects of a larger 30 variation in naturalgas prices The SMR base case is also sensitive to natural gas priceswith a $010 per normal cubic meter variation in price gas price caus-ing a $047 change in the cost of hydrogen produced [28]

The economic analysis makes several assumptions includingthat current electricity prices are representative of those at thetime of actual plant construction and that sufficient marketdemand for hydrogen exists that all product can be sold Themajor economic assumptions are summarized in Table 6 Addi-tionally values for rate of return and startup times for the plantsare selected to enable comparison with other studies on hydrogenproduction from resources such as methane (see Tables 8 and 9)For this reason all economic assumptions were taken directlyfrom H2A defaults [27]

The effects of carbon costs on system results were taken intoaccount separately as an adjustment to the H2A results Theamount of CO2e per kilogram of hydrogen produced was trackedfor all cases analyzed The emissions for each hybrid system varynot only with the type of hybridization but also with the amountof time spent in each mode of operation Values for these emis-sions are given with the economic results

In addition to including the CO2e emissions from the plantthere is a CO2e credit associated with carbon emissions avoideddue to the renewable nature of any fuel or electricity producedBased on the regional average grid mix anywhere from 483 to 724kg of CO2e are emitted per kilowatt-hour of electricity produced

Table 4 Direct gasifier input and outputa

Baseline plant Hybrid plant

Input (MW) Biomass feedb 411 411NG feed mdash mdash

Electricity mdash 342Output (MW) Electricity 15 mdash

H2 165 449

aWhere applicable mass flows were converted to energy flows with thesame heating values given in Table 1bA biomass LHV of 177 MJ=kg bone-dry wood was used due to slightlydifferent simulation feedstock [24]

Table 5 Direct gasifier capital costs

Plant area Baseline Hybrid

Feed preparation handling $279 M $279 MGasification tar reforming quench $227 M $227 MASU or electrolyzer bank $213 M $992 MGas cleanup $299 M $587 MShift and PSA $186 M $186 MSteam and power generation $204 M $204 MWater and other utilities $21 M $37 MBuildings and structures $64 M $64 MTotal $1493 M $2576 M

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Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

Table 7 details the grid production mix and correspondingemissions for each location studied The values shown in Table 7are assumptions in so much as they are averaged values for largeprocesses or regions Table 7 is actually a calculation matrix Asan example for the column ldquoNE ISOrdquo the calculation for the aver-age greenhouse gas emission for each kilowatt-hour of energyproduced is shown in Eq (1)

0150 9525thorn 0180 8931thorn 0300 5992 frac14 483 (1)

One kilogram of hydrogen has the approximate energy equivalentof 1 gal of gasoline However because hydrogen can be used infuel cells with much higher efficiency 1 kg of hydrogen couldactually offset about 2 gal of gasoline [30] Burning 2 gal of gaso-line produces 1784 kg of CO2e These numbers were used as car-bon credits for each kilogram of hydrogen or megawatt-hour ofelectricity produced by the proposed systems

Economic Results

The proposed indirectly heated gasifier peaking systemswitches between (1) hydrogen production and (2) electricity pro-duction (peaking) driven by the cost of electricity available on thegrid Based on discussions with Xcel Energy in Colorado [34] apeaking duty of 20 was used for the analysis Table 8 summa-rizes the major model inputs by region for the system A contractrate was used for any peaking electricity produced by the plantThis is common practice in the current electricity market and pro-vides a premium price for dispatchable peaking assets The cost ofbiomass feedstock was not varied regionally due to a lack of areliable index or market basis upon which to base the variation

Instead the effect of biomass feedstock cost was investigated aspart of the sensitivity analysis

Based on the economic inputs above and the plant inputs andoutputs previously discussed the cost of hydrogen production ineach area was calculated The results are shown in Table 9 alongwith the cost of hydrogen production for a baseline nonhybri-dized biomass to hydrogen plant and a SMR plant

The additional capital costs of hybridization cannot be justifiedtoday in any of the locations studied There is a $020 to $024 perkilogram premium on hydrogen produced by the proposed hybridsystem compared with a nonhybrid biomass to hydrogen gasifica-tion plant Areas with higher priced electricity move this hybrid-ization closer to economic feasibility with the best results foundin the Northeast

When the hybrid plant is producing electricity the plant usesno natural gas or electricity whereas when the plant is producinghydrogen natural gas is used for balancing the heat duty of theplant and electricity is required to run compressors Taking thedifferences in carbon emissions into account a value of $37ndash40per metric ton of CO2e makes the cost of hydrogen for the pro-posed hybrid system equal to that of SMR depending on the loca-tion This comparison was made assuming that both the hybridplant and SMR plant are subject to the same natural gas cost at agiven location

It is important to note that the baseline biomass to hydrogenplant only requires $23ndash25 per metric ton of CO2e value to becost competitive with hydrogen produced by SMR This meansthat peaking hybridization will only be economically promisingwhen there is some value placed on the additional functionality ofdual mode operation

In order to characterize the effect of various technical and eco-nomic assumptions a sensitivity analysis was performed for thegas turbine peaking system Figure 5 shows the results for the costof hydrogen in tornado chart format Capital costs the cost of bio-mass and the price which peaking electricity can be sold for arethe key inputs Capital costs when varied 630 cause the cost ofhydrogen to vary $025 The cost of biomass was varied from $40to $60 per ton based on projections in Ref [35] and causes thecost of hydrogen to vary by less than $020 The price of peakingelectricity and the plant capacity factor also cause fluctuations ofless than $020 Changes in the cost of electricity bought by theplant the cost of natural gas peaking power output and turbinepeaking duty cause hydrogen costs to vary less than 5

The proposed sinking system switches between (1) hydrogenproduction with syngas recycling for gasifier heat and (2) hydro-gen production with electrical heating (sinking) to decrease the

Table 7 Greenhouse gas assumptions

kg CO2e per kW ha NE ISOb MISOc NW Intd

Coal 9525 150 756 580Oil=petroleum 8931 180 01 10Natural gas 5992 300 36 197Nuclear mdash 280 151 10Renewable mdash 90 56 203Average kg CO2e=kW h mdash 483 743 679

aHyARC Energy Constants and Assumptions H2A Analysis Tool [26]bNE ISO energy sources report [31]cMidwest ISO June monthly report [32]dApproximation based on PacifiCorp 2008 integrated resource plan [33]

Table 8 Peaking system H2A inputs

NE ISO MISO NW Int

Peaking duty 20 20 20Peaking electricity value (cent=kW h) 140 120 115Utility electricity cost (cent=kW h) 592 362 369Utility natural gas cost ($=nm3) 032 032 032Cost of biomass ($=ton)a 4883 4883 4883

aValue taken from the Biomass 2009 Multi-Year Research Developmentand Demonstration Plan (EERE 2009) The 2012 target value is $5070per ton of dry woody biomass in 2007 dollars Taken to 2005 dollars with109 inflation this yields $4883 per ton

Table 9 Peaking system results

$=kg H2 NE ISO MISO NW Int

SMR 140 140 140Biomass to hydrogen baseline 164 164 164Gas turbine hybrid system 184 186 188

Table 6 Economic assumptions

Parameter Value

Constant dollar value 2005Internal rate of return (after-tax) 10Debt=equity 0=100Plant life 40 yearsDepreciation Modified accelerated cost recovery systemDepreciation recovery period 20 yearsConstruction period 2 years

1st year 75 (25 for electrolysis)2nd year 25 (75 for electrolysis)

Start-up time 12 monthsRevenues 50Variable costs 75Fixed costs 100

Working capital 15 of total capital investmentInflation rate 19Total taxes 389Decommissioning costs 10 of depreciable capitalSalvage value 10 of total capital investment

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-7

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syngas recycle This sinking ability can best be described as a dis-patchable load or demand from the viewpoint of the grid

Based on discussions with Xcel Energy the utility will pay tohave wind-generated electricity used at times (the electricity has anegative cost) and having a dispatchable load would provide avaluable service to the utility [34] Xcel Energy is required byColoradorsquos renewable portfolio standard to accept renewableenergy when it is available The requirement to accept wind elec-tricity regardless of grid demand is not universal and thereforenegative cost wind electricity may not be available in other states

No similar system was found for comparison therefore a sink-ing duty of 20 was used as a starting point for the analysisTable 10 summarizes the major economic model inputs by regionUnlike peaking electricity where a contract rate is used for elec-tricity produced by the plant the sinking analysis simply uses theaverage cost-of-electricity for the cheapest 20 of hours as thesinking electricity cost The utility electricity cost is the averageof the remaining 80 of the hours These costs-of-electricitywould be valid if a plant operator used accurate day-ahead energymarket forecasts to schedule plant operation

Given the economic inputs in Table 10 the cost of hydrogenproduction in each area was calculated The results are shown inTable 11 along with the cost of hydrogen production for a base-line nonhybridized biomass to hydrogen plant and a steam meth-ane reforming plant

There is a $003 to $011 premium on hydrogen produced bythe proposed hybrid system compared with a nonhybrid biomassto hydrogen gasification plant The additional capital costs of the

sinking hybridization are not fully offset by additional revenue inany of the locations studied However the marginal costs foundare small enough that it is difficult to draw any definitive conclu-sion Areas with lower cost electricity move this hybridizationcloser to economic feasibility with the best results found in theNorthwest

Because the premium is small (about 5) it may be acceptablein the long term Recent studies have shown that there is inherentvalue added or welfare effects for electricity storage capacity[36] Whether similar value is added by the proposed sinkinghybrid is unknown A more likely parallel would be the idea ofldquointerruptible customersrdquo which get discounted electricity rates inreturn for intermittent power supply A similar contractual agree-ment could be envisioned for the proposed hybrid where dis-counted electricity rates would be provided in return forintermittent demand

The proposed system is not a direct competitor with storagesystems such as pumped hydroelectric or compressed air energystorage (CAES) Energy storage systems attempt to profit by mar-ket arbitrage (selling electricity back to the grid at a higher pricethan it was bought) whereas the proposed hybrid system sinkscheap electricity into transportation fuel Sinking low cost elec-tricity into fuel could be considered cross-market arbitrage andthe most similar system to this would be electrolysis Comparedto electrolysis the proposed system is significantly less expensiveand has the added benefit of running without electric heat whenelectricity costs are too high

Assuming that all sinking electricity is renewable and takingthe additional differences in carbon emissions into account avalue of $26ndash32 per metric ton of CO2e makes the proposedhybrid cost competitive depending on the location of the system

Fig 5 Peaking system sensitivity (NE ISO)

Table 10 Sinking system H2A inputs

NE ISO MISO NW Int

Plant capacity factor 90 90 90Sinking duty 20 20 20Sinking electricity cost (cent=kW h) 435 220 218Utility electricity cost (cent=kW h) 705 487 469Utility natural gas cost ($=nm3) 032 032 032Cost of biomass ($=ton) 4883 4883 4883

Table 11 Indirect sinking system results

$=kg H2 NE ISO MISO NW Int

SMR 140 140 140Biomass to hydrogen baseline 164 164 164Electric air heater hybrid system 175 167 168

031801-8 Vol 133 SEPTEMBER 2011 Transactions of the ASME

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

At $27 per metric ton of CO2e the combustion air-heater hybrid-ization becomes cost competitive with a methane steam reformingplant in the Northwest assuming both the hybrid plant and SMRplant are subject to the same natural gas cost

In order to characterize the effect of various technical and eco-nomic assumptions a sensitivity analysis was performed for thesinking systems (Fig 6) The sensitivity analysis shows that capi-tal costs the cost of biomass and the plant capacity factor for arethe key inputs Capital costs when varied 630 cause the cost ofhydrogen to vary $018 The cost of biomass was varied from $40per ton to $60 per ton and causes the cost of hydrogen to vary byless than $015 Changes in the sinking duty the added hydrogenproduction due to sinking the cost of natural gas and the cost ofelectricity cause hydrogen costs to vary less than 3

From the sinking duty sensitivity analysis it appears that anincreased sinking duty would be preferable to the 20 assumptionmade Minimum hydrogen production prices occur when the elec-tric heating systems are run approximately 40 of the time Run-ning the electric heaters for more time increases plant hydrogenproduction and decreases plant green house gas emissions

The proposed directly heated gasifier hybrid system replacesthe ASU with an electrolyzer bank An H2A analysis was com-pleted to determine the baseline cost of hydrogen produced by adirectly heated gasification plant that uses electrolysis regardlessof electricity cost and the cost of hydrogen for a directly heatedgasification plant that uses a traditional ASU Table 12 summa-rizes the major model inputs The plant was assumed to be locatedin the Midwest ISO region The results of the analysis along withthe associated carbon emissions are listed in Table 13 Costs forproduction of hydrogen via SMR and for an electrolysis plantonly are also shown for reference purposes

As shown in Table 13 hydrogen produced by a direct gasifier-electrolyzer hybrid plant is significantly more expensive than thatproduced by SMR Electricity costs account for 37 of the overallcost of hydrogen produced (or about $086) Therefore if the costof electricity could be halved by intermittent operation during off-peak hours the savings would bring the cost of hydrogen to $189per kilogram of hydrogen At this price the hybrid system couldcompete with hydrogen produced by a standard direct gasificationplant It is important to note that these costs are approximately15 higher than the $164 per kilogram of hydrogen estimated forthe indirectly heated baseline gasification plant used for compari-son of the indirect hybrid analysis (see Table 11)

The original concept called for the electrolyzer bank to bedirectly coupled with stranded wind resources Typical capacityfactors for wind-generated power are in the 30ndash35 range [37]The effect of intermittent operation on the cost of hydrogen pro-duction was investigated using electrolyzer duties of 20 35and 50 The smaller the duty the larger the number electrolyz-ers needed to produce the same amount of oxygen per year

The effect of reduced electrolyzer duty on the cost of hydrogenis shown in Fig 7 Two curves are plotted The first assumes aconstant electricity price of $433=MWh regardless of the electro-lyzer duty This assumption would represent the scenario if theelectrolyzers were directly coupled with a stranded wind resourceThe second curve uses Midwest ISO market data so that the costof electricity fluctuates with duty These numbers do not considerthe cost of oxygen storage as these costs are assumed small com-pared to the increased electrolyzer capital costs and are identicalfor similar duty

Intermittent operation significantly adds to plant capital costsIf the price of electricity available to the plant does not decrease

Fig 6 Sinking system sensitivity (NW Int)

Table 12 Direct system H2A inputs

MISO

Electrolyzer duty () 100Utility electricity cost (cent=kW h) 433Cost of biomass ($=ton) 4883

Table 13 Direct system results

$=kg H2 Net CO2e=kg H2

SMR $140 68Biomass gasification $213 196Electrolysis $259 145 (178)Electrolysisthorn gasification $232 024 (182)

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-9

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

with intermittent electrolyzer operation then the cost of hydrogenincreases by 22 for a 35 duty However if the cost of electric-ity can be reduced by intermittent operation then the analysisshows that intermittent operation may be preferable to 100 dutyThis result means that the initial concept of capturing strandedresources is less favorable economically than a grid-connectedsinking system

If grid electricity is used then carbon emissions actuallyincrease relative to biomass gasification alone for this hybridiza-tion If upstream emissions for electricity production are takeninto account electrolysis and this proposed hybrid are both netCO2e emitters This makes their justification by carbon valueimpossible unless only renewable electricity is used for operation(renewable energy values are shown in parentheses in Table 13)Since renewable wind energy is inherently intermittent it isunreasonable to assume renewable electricity is used without add-ing the necessary equipment for intermittent operation Onerenewable energy exception would be the use of hydroelectricpower for the systems

Similar to the other hybrid systems investigated hybridizationresults in a price premium There must be some additional justifi-cation for hybridization such as utility demands The baseline bio-mass to hydrogen case with an ASU requires only $35 per metricton of CO2e to be cost competitive with SMR produced hydrogen

assuming both the hybrid plant and SMR plant are subject to thesame natural gas cost at a given location

Electrolyzer-based hybrid system economics are extremely sen-sitive to the cost of electricity (Fig 8) Fluctuations of $001 inthe cost of electricity cause the price of hydrogen to fluctuatemore than $025 per kilogram If the price of electricity were todrop below $004=kW h then the proposed hybrid system couldeconomically compete with a nonhybrid biomass to hydrogenplant However this low price level is unlikely and any energymarket fluctuations would have a dramatic effect on economicviability

Conclusion

The two hybrid concepts analyzed involve coproduction of gase-ous hydrogen and electric power from thermochemical-based biorefi-neries Both of the concepts analyzed share the basic idea ofcombining intermittent wind-generated electricity with a biomassgasification plant Wind availability overlaps biomass resource avail-ability in three areas of the United States making the use of locallyproduced wind electricity for gasification feasible The proposedhybrid systems attempt to either fill wind energy shortfalls by burn-ing syngas in a natural gas turbine or absorb excess renewable powerduring times of low-electricity demand

None of the proposed hybrid systems produced hydrogen forless than a nonhybrid plant could In all cases a premium was paidfor hybridization that could not be offset by the increasedfunctionality

The indirectly heated gasifier hybrid system consists of twoparts (1) producing peaking electricity intermittently with a gasturbine and (2) sinking electricity into electric heaters intermit-tently to boost fuel production efficiency Each of these parts wasanalyzed separately The indirectly heated gasifier hybrid systemis meant to be grid-connected and provide peaking electricity anddispatchable demand (eg an on demand load) to the local utilityto help manage intermittent wind resources

The indirect gasification concepts studied could be cost compet-itive in the near future as value is placed on controlling carbonemissions Carbon values of just under $40 per metric ton ofCO2e make the systems studied cost competitive with steam

Fig 7 Electrolyzer duty versus cost

Fig 8 Direct system sensitivity

031801-10 Vol 133 SEPTEMBER 2011 Transactions of the ASME

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

methane reforming to produce hydrogen However a nonhybridbiomass to hydrogen plant will be more cost competitive in gen-eral so there must be additional operational value placed on peak-ing or sinking for these plants to be economically attractive Thisadditional value is likely to become a reality as additional inter-mittent renewable energy sources such as wind are added to thenational grid

The directly heated gasifier hybrid system involves replacementof the air separation unit with electrolyzers This change allowsfor extra production of hydrogen and intermittent operation Theanalysis for this system assumed direct replacement of the ASUwithout intermittent operation Estimates of the effect of intermit-tent operation on plant economics were made The electrolyzerbank could be either grid-connected to provide a dispatchabledemand to the utility or it could be tied directly to a stranded windsource to convert wind into chemical fuel (H2)

The direct gasification concept studied is unlikely to be cost com-petitive in the near future but may eventually be attractive withlower-cost electrolysis and a smaller biorefinery plant size that issized for a specific hydrogen demand Intermittent operation andstranded operation were found to have worse economics than grid-connected systems High electrolyzer capital costs make the possibleelectricity cost savings of intermittent operation difficult to justifyBased on a direct replacement of the ASU with electrolyzers hydro-gen can be produced for $232 per kilogram However using gridelectricity the hybrid system is a net CO2e emitter For the use ofelectrolysis to make sense in this setting there must be a significantbenefit to the ability to operate intermittently

Acknowledgment

The authors would also like to acknowledge Dr Bob Evans forconceiving the hybrid hydrogen production systems project andDonna Heimiller for performing the GIS mapping

Employees of the Alliance for Sustainable Energy LLC underContract No DE-AC36-08GO28308 with the US Dept ofEnergy have authored this work The United States Governmentretains and the publisher by accepting the article for publicationacknowledges that the United States Government retains a nonex-clusive paid-up irrevocable worldwide license to publish orreproduce the published form of this work or allow others to doso for United States Government purposes

References[1] Milbrandt A 2005 ldquoA Geographic Perspective on the Current Biomass

Resource Availability in the United Statesrdquo National Renewable Energy LabReport No TP-560-39181

[2] Perlack R Wright L Turhollow A Graham R Stokes B and Erbach D2005 Biomass as Feedstock for a Bioenergy and Bioproducts Industry The Tech-nical Feasibility of a Billion-Ton Annual Supply Oak Ridge National LaboratoryOak 853 Ridge TN

[3] Turner J Sverdrup G Mann M Maness P C Kroposki B Ghirardi MEvans J and Blake D 2008 ldquoRenewable Hydrogen Productionrdquo Int JEnergy Res 32 pp 379ndash407

[4] US Department of Energy Energy Efficiency and Renewable Energy Labora-tory 2008 ldquo20 Wind Energy by 2030mdashIncreasing Wind Energyrsquos Contribu-tion to US Electricity Supplyrdquo Report No GO-102008-2567

[5] Levene J Kroposki B and Sverdrup G 2006 ldquoWind Energy and Productionof Hydrogen and ElectricityndashOpportunities for Renewable Hydrogenrdquo NationalRenewable Energy Laboratory Report No CP560-39534

[6] Fingersh L 2004 ldquoOptimization of Utility-Scale Wind-Hydrogen-BatterySystemsrdquo National Renewable Energy Laboratory Report No CP-500-36117

[7] Dean J Braun R Munoz D Penev M and Kinchin C 2010 ldquoAnalysis ofHybrid Hydrogen Systems ndash Final Reportrdquo National Renewable Energy Labo-ratory Report No TP-46934

[8] Gasification Technology Status ndash December 2006 EPRI and the Gasification869 Users Association Palo Alto CA p 1012224

[9] Spath P Aden A Eggeman T Ringer M Wallace B and Jechura J2005 ldquoBiomass to Hydrogen Production Detailed Design and Economics Uti-lizing the Battelle Columbus Laboratory Indirectly-Heated Gasifierrdquo NationalRenewable Energy Laboratory Report No TP-510-37408

[10] Dean J 2010 ldquoLeveling Intermittent Renewable Energy Production ThroughBiomass Gasification-based Hybrid Systemsrdquo MS thesis Colorado School ofMines Golden CO

[11] Devi L Ptasinski K Janssen F van Paasen S Bergman P and Kiel J2005 ldquoCatalytic Decomposition of Biomass Tars Use of Dolomite anUntreated Olivinerdquo Renewable Energy 30 pp 565ndash587

[12] Heavy Duty Gas Turbine Products 2009 General Electric Company FairfieldCT

[13] Drdar D and Jones R 2000 ldquoGE IGCC Technology and Experience withAdvanced Gas Turbinesrdquo GE Power Systems Report No GER-4207

[14] Craig K and Mann M 1996 ldquoCost and Performance Analysis of Biomass-Based Integrated Gasification Combined-Cycle (BIGCC) Power SystemsrdquoNational Renewable Energy Laboratory Report No TP-430-21657

[15] Gas Turbine World 2006 Handbook (Pequot Publishing Inc Fairfield CT2006)

[16] Kinchin C and Bain R 2009 ldquoHydrogen Production from Biomass via Indi-rect Gasification The Impact of NREL Process Development Unit GasifierCorrelationsrdquo National Renewable Energy Laboratory Report No TP-510-44868

[17] Watlow for 22 MW duct heaters Watlow 12001 Lackland Road St LouisMO 63146 personal communication 2009

[18] Gassner M and Marechal F 2008 ldquoThermo-economic Optimization of theIntegration of Electrolysis in Synthetic Natural Gas Production from WoodrdquoEnergy 33 pp 189ndash198

[19] Srinivas T Gupta A V S and Reddy B V 2009 ldquoThermodynamic Equi-librium Model and Exergy Analysis of a Biomass Gasifierrdquo ASME J EnergyResour Technol 131 031801 pp 1ndash7

[20] Braun R J Hanzon L G and Dean J H 2011 ldquoSystem Analysis of Ther-mochemical-based Biorefineries for Coproduction of Hydrogen and Elec-tricityrdquo ASME J Energy Resour Technol 133 012601 pp 1ndash12

[21] Manning F and Thompson R 1991 Oilfield Processing of Petroleum Vol-ume One 904 Natural Gas PennWell Publishing Co Tulsa Oklahoma

[22] StatoilHydro 2009 ldquoHydrogen Technologies World Leader in Electrolysis forHydrogen Solutionsrdquo product brochure Hydrogen Technologies NO-3674Notodden Norway COS 091408 available URL http908wwwelectrolyserscom

[23] US Department of Energy Hydrogen Program 2009 ldquoFuture Central Hydro-gen Production from Grid Electrolysisrdquo H2A analysis wwwhydrogenenergygovh2a_prod_studieshtml

[24] Phyllis Biomass Datapage ldquowood hybrid poplarrdquo ID 806 available URLhttpwwwecnnlphyllis

[25] Jin H Larson E and Celik F 2009 ldquoPerformance and Cost Analysis ofFuture Commercially Mature Gasification-Based Electric Power GenerationFrom Switchgrassrdquo Biofpr 3 pp 142ndash173

[26] Department of Energy 2007 ldquoCost and Performance Baseline for Fossil EnergyPlants Volume 1 Bituminous Coal and Natural Gas to Electricityrdquo Report NoDOE=NETL-2007=1281

[27] US Department of Energy Hydrogen Program 2009 ldquoDOE H2A Analy-sisrdquo wwwhydrogenenergygovh2a_analysishtml

[28] US Department of Energy Hydrogen Program 2009 ldquoFuture Central Hydro-gen Production from Natural Gas with CO2 Sequestrationrdquo H2A analysiswwwhydrogenenergygovh2a_prod_studieshtml

[29] Energy Information Administration Annual Energy Outlook 2009 wwweiadoegovoiafaeoelectricityhtml

[30] Schafer A Heywood J and Weiss M 2006 ldquoFuture Fuel Cell and InternalCombustion Engine Automobile Technologies A 25-Year Life Cycle and FleetImpact Assessmentrdquo Energy 31 pp 2064ndash2087

[31] NE ISO 2009 ldquoEnergy Sources in New Englandrdquo wwwiso-necomnwsissgrid_mktsenrgy_srcs

[32] Doying R 2009 Midwest ISO ldquoJune Monthly Reportrdquo wwwmidwestisoorg[33] PacifiCorp 2009 ldquoIntegrated Resource Plan ndash Volume 1rdquo May 29 2009

wwwpaci-937ficorpcom[34] Frank Novachek 2009 Xcel Energy 414 Nicollet Mall Minneapolis MN

55401 939 personal communication[35] Energy Efficiency and Renewable Energy Department of Energy ldquoBiomass

2009 Multi-Year Research Development and Demonstration Planrdquo www1eer-eenergygovbiomasspdfsmypp_may2009pdf

[36] Sioshansi R Denholm P Jenkin T and Weiss J 2009 ldquoEstimating theValue of Electricity Storage in PJM Arbitrage and Some Welfare EffectrdquoEnergy Econ 31 pp 269ndash277

[37] Kroposki B Levene J Harrison K Sen P K and Novachek F 2006ldquoElectrolysis Information and Opportunities for Electric Power UtilitiesrdquoNational Renewable Energy Laboratory Report No TP-581-40

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-11

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

Additionally enough hot combustion products are still producedto dry the incoming biomass

Unlike the peaking modification which produced lower effi-ciency adding electric heat to the plant increases the total plantefficiency (energy in=energy out) from 497 to 503 Eachadditional unit of energy input as electricity produces 056 unitsof hydrogen energy output Therefore while providing a dispatch-able load service to the local utility the hybrid plant operatesmore efficiently

The electric heater capital costs are based on a quote providedby a manufacturer [17] for their largest high-temperature airduct heater Based on that quote a 22 MW air duct heater isestimated to cost $250000 and has an electricity-to-heated airconversion efficiency of 90 Since additional unit savings arenot expected with increasing scale a scaling factor of 09 wasused Finally an installation factor of 247 was assumed for allcost estimates for consistency with other NREL hydrogen analy-ses (H2A) [9] Based on these assumptions the total additionalcapital costs for electrically heating the combustion air amountedto $158 million

Direct Gasifier Based Hybrid System

Directly heated gasifiers typically have a single combustion=reaction chamber and burn a small portion of the biomass feed togenerate the heat needed to drive the gasification reactions Asource of pure oxygen is required for combustion if the syngas isto be used for fuel production to avoid nitrogen dilution of thesyngas For large-scale oxygen production the established methodis to use a cryogenic ASU Electrolysis could provide an alterna-tive to an ASU with the added benefit of producing an additionalpure hydrogen stream

Recent research on the feasibility of combining electrolysiswith gasification concluded that the economic feasibility of thecombination was highly dependent on the price of available elec-tricity [18] The proposed hybrid system could directly addresselectricity price dependence by running the electrolysis systemintermittently based on the cost of electricity

A baseline gasification plant (see Fig 4) and a hybrid plantwere simulated in ASPEN Plus and were compared Both the base-line and hybrid plants have the same general structure biomass isgasified to produce syngas in a high-pressure directly heated gas-ifier Tars are removed and the syngas is cooled before entering asulfur removal step After sulfur has been removed the carbonmonoxide in the syngas stream is shifted towards hydrogenFinally the hydrogen is stripped from the syngas and the remain-ing gas is burned to generate power Figure 4 shows the envi-sioned biomass to hydrogen pathway using the direct gasifier anda cryogenic ASU

The bulk of the chemical processes operate at high pressureThe wet scrubber is run near atmospheric pressure which requirescooling and recompression of the syngas before sulfur removalThe directly heated gasifier operating pressure selected in thisstudy was 24 bar and represents the state of the art in fluidized-bed biomass gasification systems It has been shown that highergasifier operating pressure is generally preferred when consideringgasifier efficiency and the heating value of the syngas [19] How-ever the sensitivity of gasifier performance increases if pressureis rather low For instance a doubling of gasifier pressure onlyincreases gasifier efficiency and heating value by 1ndash2 points[19] A detailed exploration of the effect of gasifier operatingpressure on the merit of the hybrid system proposed herein isbeyond the scope of this analysis but efficiency analyses and bio-refinery performance using pressurized gasifiers are reported else-where [20] Detailed discussion of the design assumptions andsimulation are available in Refs [710]

A cryogenic ASU is used to produce the oxygen for the baselinestudy In addition to producing oxygen a nitrogen stream is avail-able as a byproduct from the ASU and is used as the inert pressur-ization agent for the lock-hopper system To replace the ASUwith electrolyzers the LO-CAT=ZnO sulfur removal steps wouldneed to be replaced with a two-stage Selexol plant The sulfur re-moval change is driven by the need for an inert gas for feed pres-surization Since no nitrogen stream is available from theelectrolyzer carbon dioxide will be used for feed pressurizationinstead Selexol can be configured to remove both sulfur com-pounds and carbon dioxide from the syngas [21]

To replace a single ASU unit for oxygen production multipleelectrolyzers are needed The largest commercial electrolyzer isproduced by StatoilHydro and produces a maximum flow rate of174 kg=h of oxygen (436 kg=h of hydrogen) The StatoilHydroelectrolyzer is an alkaline low-temperature system [22] Whilesignificant research is ongoing for high-temperature advancedelectrolysis systems commercial technology was chosen for thisanalysis

Based on ASPEN simulations a 2000 TPD fluidized-bed biomassgasifier with secondary oxygen injection would need approxi-mately 27800 kg=h of oxygen supplied For this design 160 elec-trolyzers would be needed to replace the ASU This number

Table 3 Sinking system input and outputa

H2 production mode Sinking mode

Input (MW) Biomass feed 434 434NG feed 23 28

Electricity 10 57Output (MW) Electricity mdash mdash

H2 232 261

aWhere applicable mass flows were converted to energy flows with thesame heating values given in Table 1

Fig 4 Direct gasifier baseline system

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-5

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

assumes that all electrolysis units run at design capacity 100 ofthe time

Input and output parameters from the electrolysis plant weredetermined from the published ldquoFuture Central Hydrogen Produc-tion from Grid Electrolysisrdquo H2A case [23] Based on ASPEN Plussimulations and the electrolysis H2A case the plant input and out-put values for the hybrid system were estimated The values foreach individual plant and the hybrid case are given in Table 4

The amount of electricity required to power the electrolyzerbank is extremely large when keeping the plant sized at 2000 TPDAssuming a 35 capacity factor for installed wind 970 MW of in-stalled wind capacity would be needed to generate enough averageelectricity for a 2000 TPD plant This is much larger than the totalamount of installed wind power in some states The large electricityneeds render the idea of capturing stranded resources with this scalebiorefinery plant problematic and ultimately infeasible However itis noteworthy that hydrogen production is also increased by 172over the base plant with this hybrid concept

While this study focuses on maintaining a 2000 TPD size biore-finery if instead the plant design objective was to deliver 165MW of hydrogen then the biomass feed requirement could belowered to approximately 920 TPD and the electricity demandreduced by 62 The reduction in biomass feedstock requirementswith this configuration is significant because it increases the num-ber of geographic locations that could support wind=biomasshybrid systems and ultimately lowers the land area requirementsfor sustainable fuel production

Multiple sources were used to estimate the capital costs associ-ated with the directly heated gasifier concepts All electrolyzercosts were calculated using the previously mentioned hydrogenanalysis [23] The majority of costs associated with the fluidizedbed gasifier and feed preparation were taken from a recent publi-cation by Jin et al [25] Gas cleanup costs were scaled based onprevious systems studies completed at the NREL [9] Selexol pri-ces were based on Department of Energy estimates [26] An over-view of the capital costs can be found in Table 5 Detailed costinginformation for both systems is available in Refs [710]

Based on the cost information summarized in Table 5 directreplacement of the ASU with an electrolyzer bank causes a 72increase in the total capital investment required

Economic Model

The hybrid system concepts studied respond dynamically tofluctuations in the energy market either absorbing or providingelectricity on demand To simulate this switching a binary modelwas created for each proposed system based on a specified peak-ing or sinking duty Duty is defined as the percent of hours peryear where either sinking or peaking mode is used

All concepts were assumed to be grid-connected for the analy-sis The hybrid plants are intended to provide grid leveling serv-ices to a local utility that has intermittent wind resources Thisarrangement allows for direct assessment of the market value ofelectricity and avoids inclusion of wind turbine capital costs in thecost of the system For the directly heated gasifier hybrid systemthe effect of stranded operation is discussed briefly in the eco-nomic results section of this paper

Regional Transmission Organization (RTO) day-ahead priceswere used for the cost-of-electricity when available These pricesrepresent the market value of electricity to the local utilities in anarea on an hourly averaged basis The hybrid systems must beprofitable at this low price point to cost effectively trade electric-ity on the energy market When day-ahead market informationwas unavailable load lambda data was used in its place Loadlambda data give the cost of producing one unit of electricity tothe utility for each hour of the year In all cases costs were basedon 2007 year-end data Based on GIS research reported earlier(see Figs 1 and 2) three general areas appear to have overlappingresources of both wind and biomass These areas are served by theNortheast Independent System Operator (NE ISO) Midwest ISO(MISO) and Northwest Interchange (NW Int) Cost of electricityvalues for each of these areas was used in the analysis

To assess the economic potential of each of the proposedhybridizations the yearly inputs and outputs for each plant alongwith applicable capital costs were entered into the H2A AnalysisTool developed by NREL [27] The resulting cost of hydrogenproduced (in dollars per kilogram) was compared to baseline plantresults and also the published steam methane reforming results[28] The analysis was performed in 2005 constant dollars for con-sistency with previous NREL studies [928]

The price of natural gas was held static for each of the regions stud-ied The 2009 Annual Energy Outlook report predicts regional varia-tion of natural gas prices in the US of approximately three dollars permillion Btu [29] The predicted variation translates to approximately10 cents per normal cubic meter The sensitivity analysis for each ofthe hybrid plants shows the effects of a larger 30 variation in naturalgas prices The SMR base case is also sensitive to natural gas priceswith a $010 per normal cubic meter variation in price gas price caus-ing a $047 change in the cost of hydrogen produced [28]

The economic analysis makes several assumptions includingthat current electricity prices are representative of those at thetime of actual plant construction and that sufficient marketdemand for hydrogen exists that all product can be sold Themajor economic assumptions are summarized in Table 6 Addi-tionally values for rate of return and startup times for the plantsare selected to enable comparison with other studies on hydrogenproduction from resources such as methane (see Tables 8 and 9)For this reason all economic assumptions were taken directlyfrom H2A defaults [27]

The effects of carbon costs on system results were taken intoaccount separately as an adjustment to the H2A results Theamount of CO2e per kilogram of hydrogen produced was trackedfor all cases analyzed The emissions for each hybrid system varynot only with the type of hybridization but also with the amountof time spent in each mode of operation Values for these emis-sions are given with the economic results

In addition to including the CO2e emissions from the plantthere is a CO2e credit associated with carbon emissions avoideddue to the renewable nature of any fuel or electricity producedBased on the regional average grid mix anywhere from 483 to 724kg of CO2e are emitted per kilowatt-hour of electricity produced

Table 4 Direct gasifier input and outputa

Baseline plant Hybrid plant

Input (MW) Biomass feedb 411 411NG feed mdash mdash

Electricity mdash 342Output (MW) Electricity 15 mdash

H2 165 449

aWhere applicable mass flows were converted to energy flows with thesame heating values given in Table 1bA biomass LHV of 177 MJ=kg bone-dry wood was used due to slightlydifferent simulation feedstock [24]

Table 5 Direct gasifier capital costs

Plant area Baseline Hybrid

Feed preparation handling $279 M $279 MGasification tar reforming quench $227 M $227 MASU or electrolyzer bank $213 M $992 MGas cleanup $299 M $587 MShift and PSA $186 M $186 MSteam and power generation $204 M $204 MWater and other utilities $21 M $37 MBuildings and structures $64 M $64 MTotal $1493 M $2576 M

031801-6 Vol 133 SEPTEMBER 2011 Transactions of the ASME

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

Table 7 details the grid production mix and correspondingemissions for each location studied The values shown in Table 7are assumptions in so much as they are averaged values for largeprocesses or regions Table 7 is actually a calculation matrix Asan example for the column ldquoNE ISOrdquo the calculation for the aver-age greenhouse gas emission for each kilowatt-hour of energyproduced is shown in Eq (1)

0150 9525thorn 0180 8931thorn 0300 5992 frac14 483 (1)

One kilogram of hydrogen has the approximate energy equivalentof 1 gal of gasoline However because hydrogen can be used infuel cells with much higher efficiency 1 kg of hydrogen couldactually offset about 2 gal of gasoline [30] Burning 2 gal of gaso-line produces 1784 kg of CO2e These numbers were used as car-bon credits for each kilogram of hydrogen or megawatt-hour ofelectricity produced by the proposed systems

Economic Results

The proposed indirectly heated gasifier peaking systemswitches between (1) hydrogen production and (2) electricity pro-duction (peaking) driven by the cost of electricity available on thegrid Based on discussions with Xcel Energy in Colorado [34] apeaking duty of 20 was used for the analysis Table 8 summa-rizes the major model inputs by region for the system A contractrate was used for any peaking electricity produced by the plantThis is common practice in the current electricity market and pro-vides a premium price for dispatchable peaking assets The cost ofbiomass feedstock was not varied regionally due to a lack of areliable index or market basis upon which to base the variation

Instead the effect of biomass feedstock cost was investigated aspart of the sensitivity analysis

Based on the economic inputs above and the plant inputs andoutputs previously discussed the cost of hydrogen production ineach area was calculated The results are shown in Table 9 alongwith the cost of hydrogen production for a baseline nonhybri-dized biomass to hydrogen plant and a SMR plant

The additional capital costs of hybridization cannot be justifiedtoday in any of the locations studied There is a $020 to $024 perkilogram premium on hydrogen produced by the proposed hybridsystem compared with a nonhybrid biomass to hydrogen gasifica-tion plant Areas with higher priced electricity move this hybrid-ization closer to economic feasibility with the best results foundin the Northeast

When the hybrid plant is producing electricity the plant usesno natural gas or electricity whereas when the plant is producinghydrogen natural gas is used for balancing the heat duty of theplant and electricity is required to run compressors Taking thedifferences in carbon emissions into account a value of $37ndash40per metric ton of CO2e makes the cost of hydrogen for the pro-posed hybrid system equal to that of SMR depending on the loca-tion This comparison was made assuming that both the hybridplant and SMR plant are subject to the same natural gas cost at agiven location

It is important to note that the baseline biomass to hydrogenplant only requires $23ndash25 per metric ton of CO2e value to becost competitive with hydrogen produced by SMR This meansthat peaking hybridization will only be economically promisingwhen there is some value placed on the additional functionality ofdual mode operation

In order to characterize the effect of various technical and eco-nomic assumptions a sensitivity analysis was performed for thegas turbine peaking system Figure 5 shows the results for the costof hydrogen in tornado chart format Capital costs the cost of bio-mass and the price which peaking electricity can be sold for arethe key inputs Capital costs when varied 630 cause the cost ofhydrogen to vary $025 The cost of biomass was varied from $40to $60 per ton based on projections in Ref [35] and causes thecost of hydrogen to vary by less than $020 The price of peakingelectricity and the plant capacity factor also cause fluctuations ofless than $020 Changes in the cost of electricity bought by theplant the cost of natural gas peaking power output and turbinepeaking duty cause hydrogen costs to vary less than 5

The proposed sinking system switches between (1) hydrogenproduction with syngas recycling for gasifier heat and (2) hydro-gen production with electrical heating (sinking) to decrease the

Table 7 Greenhouse gas assumptions

kg CO2e per kW ha NE ISOb MISOc NW Intd

Coal 9525 150 756 580Oil=petroleum 8931 180 01 10Natural gas 5992 300 36 197Nuclear mdash 280 151 10Renewable mdash 90 56 203Average kg CO2e=kW h mdash 483 743 679

aHyARC Energy Constants and Assumptions H2A Analysis Tool [26]bNE ISO energy sources report [31]cMidwest ISO June monthly report [32]dApproximation based on PacifiCorp 2008 integrated resource plan [33]

Table 8 Peaking system H2A inputs

NE ISO MISO NW Int

Peaking duty 20 20 20Peaking electricity value (cent=kW h) 140 120 115Utility electricity cost (cent=kW h) 592 362 369Utility natural gas cost ($=nm3) 032 032 032Cost of biomass ($=ton)a 4883 4883 4883

aValue taken from the Biomass 2009 Multi-Year Research Developmentand Demonstration Plan (EERE 2009) The 2012 target value is $5070per ton of dry woody biomass in 2007 dollars Taken to 2005 dollars with109 inflation this yields $4883 per ton

Table 9 Peaking system results

$=kg H2 NE ISO MISO NW Int

SMR 140 140 140Biomass to hydrogen baseline 164 164 164Gas turbine hybrid system 184 186 188

Table 6 Economic assumptions

Parameter Value

Constant dollar value 2005Internal rate of return (after-tax) 10Debt=equity 0=100Plant life 40 yearsDepreciation Modified accelerated cost recovery systemDepreciation recovery period 20 yearsConstruction period 2 years

1st year 75 (25 for electrolysis)2nd year 25 (75 for electrolysis)

Start-up time 12 monthsRevenues 50Variable costs 75Fixed costs 100

Working capital 15 of total capital investmentInflation rate 19Total taxes 389Decommissioning costs 10 of depreciable capitalSalvage value 10 of total capital investment

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-7

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

syngas recycle This sinking ability can best be described as a dis-patchable load or demand from the viewpoint of the grid

Based on discussions with Xcel Energy the utility will pay tohave wind-generated electricity used at times (the electricity has anegative cost) and having a dispatchable load would provide avaluable service to the utility [34] Xcel Energy is required byColoradorsquos renewable portfolio standard to accept renewableenergy when it is available The requirement to accept wind elec-tricity regardless of grid demand is not universal and thereforenegative cost wind electricity may not be available in other states

No similar system was found for comparison therefore a sink-ing duty of 20 was used as a starting point for the analysisTable 10 summarizes the major economic model inputs by regionUnlike peaking electricity where a contract rate is used for elec-tricity produced by the plant the sinking analysis simply uses theaverage cost-of-electricity for the cheapest 20 of hours as thesinking electricity cost The utility electricity cost is the averageof the remaining 80 of the hours These costs-of-electricitywould be valid if a plant operator used accurate day-ahead energymarket forecasts to schedule plant operation

Given the economic inputs in Table 10 the cost of hydrogenproduction in each area was calculated The results are shown inTable 11 along with the cost of hydrogen production for a base-line nonhybridized biomass to hydrogen plant and a steam meth-ane reforming plant

There is a $003 to $011 premium on hydrogen produced bythe proposed hybrid system compared with a nonhybrid biomassto hydrogen gasification plant The additional capital costs of the

sinking hybridization are not fully offset by additional revenue inany of the locations studied However the marginal costs foundare small enough that it is difficult to draw any definitive conclu-sion Areas with lower cost electricity move this hybridizationcloser to economic feasibility with the best results found in theNorthwest

Because the premium is small (about 5) it may be acceptablein the long term Recent studies have shown that there is inherentvalue added or welfare effects for electricity storage capacity[36] Whether similar value is added by the proposed sinkinghybrid is unknown A more likely parallel would be the idea ofldquointerruptible customersrdquo which get discounted electricity rates inreturn for intermittent power supply A similar contractual agree-ment could be envisioned for the proposed hybrid where dis-counted electricity rates would be provided in return forintermittent demand

The proposed system is not a direct competitor with storagesystems such as pumped hydroelectric or compressed air energystorage (CAES) Energy storage systems attempt to profit by mar-ket arbitrage (selling electricity back to the grid at a higher pricethan it was bought) whereas the proposed hybrid system sinkscheap electricity into transportation fuel Sinking low cost elec-tricity into fuel could be considered cross-market arbitrage andthe most similar system to this would be electrolysis Comparedto electrolysis the proposed system is significantly less expensiveand has the added benefit of running without electric heat whenelectricity costs are too high

Assuming that all sinking electricity is renewable and takingthe additional differences in carbon emissions into account avalue of $26ndash32 per metric ton of CO2e makes the proposedhybrid cost competitive depending on the location of the system

Fig 5 Peaking system sensitivity (NE ISO)

Table 10 Sinking system H2A inputs

NE ISO MISO NW Int

Plant capacity factor 90 90 90Sinking duty 20 20 20Sinking electricity cost (cent=kW h) 435 220 218Utility electricity cost (cent=kW h) 705 487 469Utility natural gas cost ($=nm3) 032 032 032Cost of biomass ($=ton) 4883 4883 4883

Table 11 Indirect sinking system results

$=kg H2 NE ISO MISO NW Int

SMR 140 140 140Biomass to hydrogen baseline 164 164 164Electric air heater hybrid system 175 167 168

031801-8 Vol 133 SEPTEMBER 2011 Transactions of the ASME

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

At $27 per metric ton of CO2e the combustion air-heater hybrid-ization becomes cost competitive with a methane steam reformingplant in the Northwest assuming both the hybrid plant and SMRplant are subject to the same natural gas cost

In order to characterize the effect of various technical and eco-nomic assumptions a sensitivity analysis was performed for thesinking systems (Fig 6) The sensitivity analysis shows that capi-tal costs the cost of biomass and the plant capacity factor for arethe key inputs Capital costs when varied 630 cause the cost ofhydrogen to vary $018 The cost of biomass was varied from $40per ton to $60 per ton and causes the cost of hydrogen to vary byless than $015 Changes in the sinking duty the added hydrogenproduction due to sinking the cost of natural gas and the cost ofelectricity cause hydrogen costs to vary less than 3

From the sinking duty sensitivity analysis it appears that anincreased sinking duty would be preferable to the 20 assumptionmade Minimum hydrogen production prices occur when the elec-tric heating systems are run approximately 40 of the time Run-ning the electric heaters for more time increases plant hydrogenproduction and decreases plant green house gas emissions

The proposed directly heated gasifier hybrid system replacesthe ASU with an electrolyzer bank An H2A analysis was com-pleted to determine the baseline cost of hydrogen produced by adirectly heated gasification plant that uses electrolysis regardlessof electricity cost and the cost of hydrogen for a directly heatedgasification plant that uses a traditional ASU Table 12 summa-rizes the major model inputs The plant was assumed to be locatedin the Midwest ISO region The results of the analysis along withthe associated carbon emissions are listed in Table 13 Costs forproduction of hydrogen via SMR and for an electrolysis plantonly are also shown for reference purposes

As shown in Table 13 hydrogen produced by a direct gasifier-electrolyzer hybrid plant is significantly more expensive than thatproduced by SMR Electricity costs account for 37 of the overallcost of hydrogen produced (or about $086) Therefore if the costof electricity could be halved by intermittent operation during off-peak hours the savings would bring the cost of hydrogen to $189per kilogram of hydrogen At this price the hybrid system couldcompete with hydrogen produced by a standard direct gasificationplant It is important to note that these costs are approximately15 higher than the $164 per kilogram of hydrogen estimated forthe indirectly heated baseline gasification plant used for compari-son of the indirect hybrid analysis (see Table 11)

The original concept called for the electrolyzer bank to bedirectly coupled with stranded wind resources Typical capacityfactors for wind-generated power are in the 30ndash35 range [37]The effect of intermittent operation on the cost of hydrogen pro-duction was investigated using electrolyzer duties of 20 35and 50 The smaller the duty the larger the number electrolyz-ers needed to produce the same amount of oxygen per year

The effect of reduced electrolyzer duty on the cost of hydrogenis shown in Fig 7 Two curves are plotted The first assumes aconstant electricity price of $433=MWh regardless of the electro-lyzer duty This assumption would represent the scenario if theelectrolyzers were directly coupled with a stranded wind resourceThe second curve uses Midwest ISO market data so that the costof electricity fluctuates with duty These numbers do not considerthe cost of oxygen storage as these costs are assumed small com-pared to the increased electrolyzer capital costs and are identicalfor similar duty

Intermittent operation significantly adds to plant capital costsIf the price of electricity available to the plant does not decrease

Fig 6 Sinking system sensitivity (NW Int)

Table 12 Direct system H2A inputs

MISO

Electrolyzer duty () 100Utility electricity cost (cent=kW h) 433Cost of biomass ($=ton) 4883

Table 13 Direct system results

$=kg H2 Net CO2e=kg H2

SMR $140 68Biomass gasification $213 196Electrolysis $259 145 (178)Electrolysisthorn gasification $232 024 (182)

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-9

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

with intermittent electrolyzer operation then the cost of hydrogenincreases by 22 for a 35 duty However if the cost of electric-ity can be reduced by intermittent operation then the analysisshows that intermittent operation may be preferable to 100 dutyThis result means that the initial concept of capturing strandedresources is less favorable economically than a grid-connectedsinking system

If grid electricity is used then carbon emissions actuallyincrease relative to biomass gasification alone for this hybridiza-tion If upstream emissions for electricity production are takeninto account electrolysis and this proposed hybrid are both netCO2e emitters This makes their justification by carbon valueimpossible unless only renewable electricity is used for operation(renewable energy values are shown in parentheses in Table 13)Since renewable wind energy is inherently intermittent it isunreasonable to assume renewable electricity is used without add-ing the necessary equipment for intermittent operation Onerenewable energy exception would be the use of hydroelectricpower for the systems

Similar to the other hybrid systems investigated hybridizationresults in a price premium There must be some additional justifi-cation for hybridization such as utility demands The baseline bio-mass to hydrogen case with an ASU requires only $35 per metricton of CO2e to be cost competitive with SMR produced hydrogen

assuming both the hybrid plant and SMR plant are subject to thesame natural gas cost at a given location

Electrolyzer-based hybrid system economics are extremely sen-sitive to the cost of electricity (Fig 8) Fluctuations of $001 inthe cost of electricity cause the price of hydrogen to fluctuatemore than $025 per kilogram If the price of electricity were todrop below $004=kW h then the proposed hybrid system couldeconomically compete with a nonhybrid biomass to hydrogenplant However this low price level is unlikely and any energymarket fluctuations would have a dramatic effect on economicviability

Conclusion

The two hybrid concepts analyzed involve coproduction of gase-ous hydrogen and electric power from thermochemical-based biorefi-neries Both of the concepts analyzed share the basic idea ofcombining intermittent wind-generated electricity with a biomassgasification plant Wind availability overlaps biomass resource avail-ability in three areas of the United States making the use of locallyproduced wind electricity for gasification feasible The proposedhybrid systems attempt to either fill wind energy shortfalls by burn-ing syngas in a natural gas turbine or absorb excess renewable powerduring times of low-electricity demand

None of the proposed hybrid systems produced hydrogen forless than a nonhybrid plant could In all cases a premium was paidfor hybridization that could not be offset by the increasedfunctionality

The indirectly heated gasifier hybrid system consists of twoparts (1) producing peaking electricity intermittently with a gasturbine and (2) sinking electricity into electric heaters intermit-tently to boost fuel production efficiency Each of these parts wasanalyzed separately The indirectly heated gasifier hybrid systemis meant to be grid-connected and provide peaking electricity anddispatchable demand (eg an on demand load) to the local utilityto help manage intermittent wind resources

The indirect gasification concepts studied could be cost compet-itive in the near future as value is placed on controlling carbonemissions Carbon values of just under $40 per metric ton ofCO2e make the systems studied cost competitive with steam

Fig 7 Electrolyzer duty versus cost

Fig 8 Direct system sensitivity

031801-10 Vol 133 SEPTEMBER 2011 Transactions of the ASME

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

methane reforming to produce hydrogen However a nonhybridbiomass to hydrogen plant will be more cost competitive in gen-eral so there must be additional operational value placed on peak-ing or sinking for these plants to be economically attractive Thisadditional value is likely to become a reality as additional inter-mittent renewable energy sources such as wind are added to thenational grid

The directly heated gasifier hybrid system involves replacementof the air separation unit with electrolyzers This change allowsfor extra production of hydrogen and intermittent operation Theanalysis for this system assumed direct replacement of the ASUwithout intermittent operation Estimates of the effect of intermit-tent operation on plant economics were made The electrolyzerbank could be either grid-connected to provide a dispatchabledemand to the utility or it could be tied directly to a stranded windsource to convert wind into chemical fuel (H2)

The direct gasification concept studied is unlikely to be cost com-petitive in the near future but may eventually be attractive withlower-cost electrolysis and a smaller biorefinery plant size that issized for a specific hydrogen demand Intermittent operation andstranded operation were found to have worse economics than grid-connected systems High electrolyzer capital costs make the possibleelectricity cost savings of intermittent operation difficult to justifyBased on a direct replacement of the ASU with electrolyzers hydro-gen can be produced for $232 per kilogram However using gridelectricity the hybrid system is a net CO2e emitter For the use ofelectrolysis to make sense in this setting there must be a significantbenefit to the ability to operate intermittently

Acknowledgment

The authors would also like to acknowledge Dr Bob Evans forconceiving the hybrid hydrogen production systems project andDonna Heimiller for performing the GIS mapping

Employees of the Alliance for Sustainable Energy LLC underContract No DE-AC36-08GO28308 with the US Dept ofEnergy have authored this work The United States Governmentretains and the publisher by accepting the article for publicationacknowledges that the United States Government retains a nonex-clusive paid-up irrevocable worldwide license to publish orreproduce the published form of this work or allow others to doso for United States Government purposes

References[1] Milbrandt A 2005 ldquoA Geographic Perspective on the Current Biomass

Resource Availability in the United Statesrdquo National Renewable Energy LabReport No TP-560-39181

[2] Perlack R Wright L Turhollow A Graham R Stokes B and Erbach D2005 Biomass as Feedstock for a Bioenergy and Bioproducts Industry The Tech-nical Feasibility of a Billion-Ton Annual Supply Oak Ridge National LaboratoryOak 853 Ridge TN

[3] Turner J Sverdrup G Mann M Maness P C Kroposki B Ghirardi MEvans J and Blake D 2008 ldquoRenewable Hydrogen Productionrdquo Int JEnergy Res 32 pp 379ndash407

[4] US Department of Energy Energy Efficiency and Renewable Energy Labora-tory 2008 ldquo20 Wind Energy by 2030mdashIncreasing Wind Energyrsquos Contribu-tion to US Electricity Supplyrdquo Report No GO-102008-2567

[5] Levene J Kroposki B and Sverdrup G 2006 ldquoWind Energy and Productionof Hydrogen and ElectricityndashOpportunities for Renewable Hydrogenrdquo NationalRenewable Energy Laboratory Report No CP560-39534

[6] Fingersh L 2004 ldquoOptimization of Utility-Scale Wind-Hydrogen-BatterySystemsrdquo National Renewable Energy Laboratory Report No CP-500-36117

[7] Dean J Braun R Munoz D Penev M and Kinchin C 2010 ldquoAnalysis ofHybrid Hydrogen Systems ndash Final Reportrdquo National Renewable Energy Labo-ratory Report No TP-46934

[8] Gasification Technology Status ndash December 2006 EPRI and the Gasification869 Users Association Palo Alto CA p 1012224

[9] Spath P Aden A Eggeman T Ringer M Wallace B and Jechura J2005 ldquoBiomass to Hydrogen Production Detailed Design and Economics Uti-lizing the Battelle Columbus Laboratory Indirectly-Heated Gasifierrdquo NationalRenewable Energy Laboratory Report No TP-510-37408

[10] Dean J 2010 ldquoLeveling Intermittent Renewable Energy Production ThroughBiomass Gasification-based Hybrid Systemsrdquo MS thesis Colorado School ofMines Golden CO

[11] Devi L Ptasinski K Janssen F van Paasen S Bergman P and Kiel J2005 ldquoCatalytic Decomposition of Biomass Tars Use of Dolomite anUntreated Olivinerdquo Renewable Energy 30 pp 565ndash587

[12] Heavy Duty Gas Turbine Products 2009 General Electric Company FairfieldCT

[13] Drdar D and Jones R 2000 ldquoGE IGCC Technology and Experience withAdvanced Gas Turbinesrdquo GE Power Systems Report No GER-4207

[14] Craig K and Mann M 1996 ldquoCost and Performance Analysis of Biomass-Based Integrated Gasification Combined-Cycle (BIGCC) Power SystemsrdquoNational Renewable Energy Laboratory Report No TP-430-21657

[15] Gas Turbine World 2006 Handbook (Pequot Publishing Inc Fairfield CT2006)

[16] Kinchin C and Bain R 2009 ldquoHydrogen Production from Biomass via Indi-rect Gasification The Impact of NREL Process Development Unit GasifierCorrelationsrdquo National Renewable Energy Laboratory Report No TP-510-44868

[17] Watlow for 22 MW duct heaters Watlow 12001 Lackland Road St LouisMO 63146 personal communication 2009

[18] Gassner M and Marechal F 2008 ldquoThermo-economic Optimization of theIntegration of Electrolysis in Synthetic Natural Gas Production from WoodrdquoEnergy 33 pp 189ndash198

[19] Srinivas T Gupta A V S and Reddy B V 2009 ldquoThermodynamic Equi-librium Model and Exergy Analysis of a Biomass Gasifierrdquo ASME J EnergyResour Technol 131 031801 pp 1ndash7

[20] Braun R J Hanzon L G and Dean J H 2011 ldquoSystem Analysis of Ther-mochemical-based Biorefineries for Coproduction of Hydrogen and Elec-tricityrdquo ASME J Energy Resour Technol 133 012601 pp 1ndash12

[21] Manning F and Thompson R 1991 Oilfield Processing of Petroleum Vol-ume One 904 Natural Gas PennWell Publishing Co Tulsa Oklahoma

[22] StatoilHydro 2009 ldquoHydrogen Technologies World Leader in Electrolysis forHydrogen Solutionsrdquo product brochure Hydrogen Technologies NO-3674Notodden Norway COS 091408 available URL http908wwwelectrolyserscom

[23] US Department of Energy Hydrogen Program 2009 ldquoFuture Central Hydro-gen Production from Grid Electrolysisrdquo H2A analysis wwwhydrogenenergygovh2a_prod_studieshtml

[24] Phyllis Biomass Datapage ldquowood hybrid poplarrdquo ID 806 available URLhttpwwwecnnlphyllis

[25] Jin H Larson E and Celik F 2009 ldquoPerformance and Cost Analysis ofFuture Commercially Mature Gasification-Based Electric Power GenerationFrom Switchgrassrdquo Biofpr 3 pp 142ndash173

[26] Department of Energy 2007 ldquoCost and Performance Baseline for Fossil EnergyPlants Volume 1 Bituminous Coal and Natural Gas to Electricityrdquo Report NoDOE=NETL-2007=1281

[27] US Department of Energy Hydrogen Program 2009 ldquoDOE H2A Analy-sisrdquo wwwhydrogenenergygovh2a_analysishtml

[28] US Department of Energy Hydrogen Program 2009 ldquoFuture Central Hydro-gen Production from Natural Gas with CO2 Sequestrationrdquo H2A analysiswwwhydrogenenergygovh2a_prod_studieshtml

[29] Energy Information Administration Annual Energy Outlook 2009 wwweiadoegovoiafaeoelectricityhtml

[30] Schafer A Heywood J and Weiss M 2006 ldquoFuture Fuel Cell and InternalCombustion Engine Automobile Technologies A 25-Year Life Cycle and FleetImpact Assessmentrdquo Energy 31 pp 2064ndash2087

[31] NE ISO 2009 ldquoEnergy Sources in New Englandrdquo wwwiso-necomnwsissgrid_mktsenrgy_srcs

[32] Doying R 2009 Midwest ISO ldquoJune Monthly Reportrdquo wwwmidwestisoorg[33] PacifiCorp 2009 ldquoIntegrated Resource Plan ndash Volume 1rdquo May 29 2009

wwwpaci-937ficorpcom[34] Frank Novachek 2009 Xcel Energy 414 Nicollet Mall Minneapolis MN

55401 939 personal communication[35] Energy Efficiency and Renewable Energy Department of Energy ldquoBiomass

2009 Multi-Year Research Development and Demonstration Planrdquo www1eer-eenergygovbiomasspdfsmypp_may2009pdf

[36] Sioshansi R Denholm P Jenkin T and Weiss J 2009 ldquoEstimating theValue of Electricity Storage in PJM Arbitrage and Some Welfare EffectrdquoEnergy Econ 31 pp 269ndash277

[37] Kroposki B Levene J Harrison K Sen P K and Novachek F 2006ldquoElectrolysis Information and Opportunities for Electric Power UtilitiesrdquoNational Renewable Energy Laboratory Report No TP-581-40

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-11

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

assumes that all electrolysis units run at design capacity 100 ofthe time

Input and output parameters from the electrolysis plant weredetermined from the published ldquoFuture Central Hydrogen Produc-tion from Grid Electrolysisrdquo H2A case [23] Based on ASPEN Plussimulations and the electrolysis H2A case the plant input and out-put values for the hybrid system were estimated The values foreach individual plant and the hybrid case are given in Table 4

The amount of electricity required to power the electrolyzerbank is extremely large when keeping the plant sized at 2000 TPDAssuming a 35 capacity factor for installed wind 970 MW of in-stalled wind capacity would be needed to generate enough averageelectricity for a 2000 TPD plant This is much larger than the totalamount of installed wind power in some states The large electricityneeds render the idea of capturing stranded resources with this scalebiorefinery plant problematic and ultimately infeasible However itis noteworthy that hydrogen production is also increased by 172over the base plant with this hybrid concept

While this study focuses on maintaining a 2000 TPD size biore-finery if instead the plant design objective was to deliver 165MW of hydrogen then the biomass feed requirement could belowered to approximately 920 TPD and the electricity demandreduced by 62 The reduction in biomass feedstock requirementswith this configuration is significant because it increases the num-ber of geographic locations that could support wind=biomasshybrid systems and ultimately lowers the land area requirementsfor sustainable fuel production

Multiple sources were used to estimate the capital costs associ-ated with the directly heated gasifier concepts All electrolyzercosts were calculated using the previously mentioned hydrogenanalysis [23] The majority of costs associated with the fluidizedbed gasifier and feed preparation were taken from a recent publi-cation by Jin et al [25] Gas cleanup costs were scaled based onprevious systems studies completed at the NREL [9] Selexol pri-ces were based on Department of Energy estimates [26] An over-view of the capital costs can be found in Table 5 Detailed costinginformation for both systems is available in Refs [710]

Based on the cost information summarized in Table 5 directreplacement of the ASU with an electrolyzer bank causes a 72increase in the total capital investment required

Economic Model

The hybrid system concepts studied respond dynamically tofluctuations in the energy market either absorbing or providingelectricity on demand To simulate this switching a binary modelwas created for each proposed system based on a specified peak-ing or sinking duty Duty is defined as the percent of hours peryear where either sinking or peaking mode is used

All concepts were assumed to be grid-connected for the analy-sis The hybrid plants are intended to provide grid leveling serv-ices to a local utility that has intermittent wind resources Thisarrangement allows for direct assessment of the market value ofelectricity and avoids inclusion of wind turbine capital costs in thecost of the system For the directly heated gasifier hybrid systemthe effect of stranded operation is discussed briefly in the eco-nomic results section of this paper

Regional Transmission Organization (RTO) day-ahead priceswere used for the cost-of-electricity when available These pricesrepresent the market value of electricity to the local utilities in anarea on an hourly averaged basis The hybrid systems must beprofitable at this low price point to cost effectively trade electric-ity on the energy market When day-ahead market informationwas unavailable load lambda data was used in its place Loadlambda data give the cost of producing one unit of electricity tothe utility for each hour of the year In all cases costs were basedon 2007 year-end data Based on GIS research reported earlier(see Figs 1 and 2) three general areas appear to have overlappingresources of both wind and biomass These areas are served by theNortheast Independent System Operator (NE ISO) Midwest ISO(MISO) and Northwest Interchange (NW Int) Cost of electricityvalues for each of these areas was used in the analysis

To assess the economic potential of each of the proposedhybridizations the yearly inputs and outputs for each plant alongwith applicable capital costs were entered into the H2A AnalysisTool developed by NREL [27] The resulting cost of hydrogenproduced (in dollars per kilogram) was compared to baseline plantresults and also the published steam methane reforming results[28] The analysis was performed in 2005 constant dollars for con-sistency with previous NREL studies [928]

The price of natural gas was held static for each of the regions stud-ied The 2009 Annual Energy Outlook report predicts regional varia-tion of natural gas prices in the US of approximately three dollars permillion Btu [29] The predicted variation translates to approximately10 cents per normal cubic meter The sensitivity analysis for each ofthe hybrid plants shows the effects of a larger 30 variation in naturalgas prices The SMR base case is also sensitive to natural gas priceswith a $010 per normal cubic meter variation in price gas price caus-ing a $047 change in the cost of hydrogen produced [28]

The economic analysis makes several assumptions includingthat current electricity prices are representative of those at thetime of actual plant construction and that sufficient marketdemand for hydrogen exists that all product can be sold Themajor economic assumptions are summarized in Table 6 Addi-tionally values for rate of return and startup times for the plantsare selected to enable comparison with other studies on hydrogenproduction from resources such as methane (see Tables 8 and 9)For this reason all economic assumptions were taken directlyfrom H2A defaults [27]

The effects of carbon costs on system results were taken intoaccount separately as an adjustment to the H2A results Theamount of CO2e per kilogram of hydrogen produced was trackedfor all cases analyzed The emissions for each hybrid system varynot only with the type of hybridization but also with the amountof time spent in each mode of operation Values for these emis-sions are given with the economic results

In addition to including the CO2e emissions from the plantthere is a CO2e credit associated with carbon emissions avoideddue to the renewable nature of any fuel or electricity producedBased on the regional average grid mix anywhere from 483 to 724kg of CO2e are emitted per kilowatt-hour of electricity produced

Table 4 Direct gasifier input and outputa

Baseline plant Hybrid plant

Input (MW) Biomass feedb 411 411NG feed mdash mdash

Electricity mdash 342Output (MW) Electricity 15 mdash

H2 165 449

aWhere applicable mass flows were converted to energy flows with thesame heating values given in Table 1bA biomass LHV of 177 MJ=kg bone-dry wood was used due to slightlydifferent simulation feedstock [24]

Table 5 Direct gasifier capital costs

Plant area Baseline Hybrid

Feed preparation handling $279 M $279 MGasification tar reforming quench $227 M $227 MASU or electrolyzer bank $213 M $992 MGas cleanup $299 M $587 MShift and PSA $186 M $186 MSteam and power generation $204 M $204 MWater and other utilities $21 M $37 MBuildings and structures $64 M $64 MTotal $1493 M $2576 M

031801-6 Vol 133 SEPTEMBER 2011 Transactions of the ASME

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

Table 7 details the grid production mix and correspondingemissions for each location studied The values shown in Table 7are assumptions in so much as they are averaged values for largeprocesses or regions Table 7 is actually a calculation matrix Asan example for the column ldquoNE ISOrdquo the calculation for the aver-age greenhouse gas emission for each kilowatt-hour of energyproduced is shown in Eq (1)

0150 9525thorn 0180 8931thorn 0300 5992 frac14 483 (1)

One kilogram of hydrogen has the approximate energy equivalentof 1 gal of gasoline However because hydrogen can be used infuel cells with much higher efficiency 1 kg of hydrogen couldactually offset about 2 gal of gasoline [30] Burning 2 gal of gaso-line produces 1784 kg of CO2e These numbers were used as car-bon credits for each kilogram of hydrogen or megawatt-hour ofelectricity produced by the proposed systems

Economic Results

The proposed indirectly heated gasifier peaking systemswitches between (1) hydrogen production and (2) electricity pro-duction (peaking) driven by the cost of electricity available on thegrid Based on discussions with Xcel Energy in Colorado [34] apeaking duty of 20 was used for the analysis Table 8 summa-rizes the major model inputs by region for the system A contractrate was used for any peaking electricity produced by the plantThis is common practice in the current electricity market and pro-vides a premium price for dispatchable peaking assets The cost ofbiomass feedstock was not varied regionally due to a lack of areliable index or market basis upon which to base the variation

Instead the effect of biomass feedstock cost was investigated aspart of the sensitivity analysis

Based on the economic inputs above and the plant inputs andoutputs previously discussed the cost of hydrogen production ineach area was calculated The results are shown in Table 9 alongwith the cost of hydrogen production for a baseline nonhybri-dized biomass to hydrogen plant and a SMR plant

The additional capital costs of hybridization cannot be justifiedtoday in any of the locations studied There is a $020 to $024 perkilogram premium on hydrogen produced by the proposed hybridsystem compared with a nonhybrid biomass to hydrogen gasifica-tion plant Areas with higher priced electricity move this hybrid-ization closer to economic feasibility with the best results foundin the Northeast

When the hybrid plant is producing electricity the plant usesno natural gas or electricity whereas when the plant is producinghydrogen natural gas is used for balancing the heat duty of theplant and electricity is required to run compressors Taking thedifferences in carbon emissions into account a value of $37ndash40per metric ton of CO2e makes the cost of hydrogen for the pro-posed hybrid system equal to that of SMR depending on the loca-tion This comparison was made assuming that both the hybridplant and SMR plant are subject to the same natural gas cost at agiven location

It is important to note that the baseline biomass to hydrogenplant only requires $23ndash25 per metric ton of CO2e value to becost competitive with hydrogen produced by SMR This meansthat peaking hybridization will only be economically promisingwhen there is some value placed on the additional functionality ofdual mode operation

In order to characterize the effect of various technical and eco-nomic assumptions a sensitivity analysis was performed for thegas turbine peaking system Figure 5 shows the results for the costof hydrogen in tornado chart format Capital costs the cost of bio-mass and the price which peaking electricity can be sold for arethe key inputs Capital costs when varied 630 cause the cost ofhydrogen to vary $025 The cost of biomass was varied from $40to $60 per ton based on projections in Ref [35] and causes thecost of hydrogen to vary by less than $020 The price of peakingelectricity and the plant capacity factor also cause fluctuations ofless than $020 Changes in the cost of electricity bought by theplant the cost of natural gas peaking power output and turbinepeaking duty cause hydrogen costs to vary less than 5

The proposed sinking system switches between (1) hydrogenproduction with syngas recycling for gasifier heat and (2) hydro-gen production with electrical heating (sinking) to decrease the

Table 7 Greenhouse gas assumptions

kg CO2e per kW ha NE ISOb MISOc NW Intd

Coal 9525 150 756 580Oil=petroleum 8931 180 01 10Natural gas 5992 300 36 197Nuclear mdash 280 151 10Renewable mdash 90 56 203Average kg CO2e=kW h mdash 483 743 679

aHyARC Energy Constants and Assumptions H2A Analysis Tool [26]bNE ISO energy sources report [31]cMidwest ISO June monthly report [32]dApproximation based on PacifiCorp 2008 integrated resource plan [33]

Table 8 Peaking system H2A inputs

NE ISO MISO NW Int

Peaking duty 20 20 20Peaking electricity value (cent=kW h) 140 120 115Utility electricity cost (cent=kW h) 592 362 369Utility natural gas cost ($=nm3) 032 032 032Cost of biomass ($=ton)a 4883 4883 4883

aValue taken from the Biomass 2009 Multi-Year Research Developmentand Demonstration Plan (EERE 2009) The 2012 target value is $5070per ton of dry woody biomass in 2007 dollars Taken to 2005 dollars with109 inflation this yields $4883 per ton

Table 9 Peaking system results

$=kg H2 NE ISO MISO NW Int

SMR 140 140 140Biomass to hydrogen baseline 164 164 164Gas turbine hybrid system 184 186 188

Table 6 Economic assumptions

Parameter Value

Constant dollar value 2005Internal rate of return (after-tax) 10Debt=equity 0=100Plant life 40 yearsDepreciation Modified accelerated cost recovery systemDepreciation recovery period 20 yearsConstruction period 2 years

1st year 75 (25 for electrolysis)2nd year 25 (75 for electrolysis)

Start-up time 12 monthsRevenues 50Variable costs 75Fixed costs 100

Working capital 15 of total capital investmentInflation rate 19Total taxes 389Decommissioning costs 10 of depreciable capitalSalvage value 10 of total capital investment

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-7

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

syngas recycle This sinking ability can best be described as a dis-patchable load or demand from the viewpoint of the grid

Based on discussions with Xcel Energy the utility will pay tohave wind-generated electricity used at times (the electricity has anegative cost) and having a dispatchable load would provide avaluable service to the utility [34] Xcel Energy is required byColoradorsquos renewable portfolio standard to accept renewableenergy when it is available The requirement to accept wind elec-tricity regardless of grid demand is not universal and thereforenegative cost wind electricity may not be available in other states

No similar system was found for comparison therefore a sink-ing duty of 20 was used as a starting point for the analysisTable 10 summarizes the major economic model inputs by regionUnlike peaking electricity where a contract rate is used for elec-tricity produced by the plant the sinking analysis simply uses theaverage cost-of-electricity for the cheapest 20 of hours as thesinking electricity cost The utility electricity cost is the averageof the remaining 80 of the hours These costs-of-electricitywould be valid if a plant operator used accurate day-ahead energymarket forecasts to schedule plant operation

Given the economic inputs in Table 10 the cost of hydrogenproduction in each area was calculated The results are shown inTable 11 along with the cost of hydrogen production for a base-line nonhybridized biomass to hydrogen plant and a steam meth-ane reforming plant

There is a $003 to $011 premium on hydrogen produced bythe proposed hybrid system compared with a nonhybrid biomassto hydrogen gasification plant The additional capital costs of the

sinking hybridization are not fully offset by additional revenue inany of the locations studied However the marginal costs foundare small enough that it is difficult to draw any definitive conclu-sion Areas with lower cost electricity move this hybridizationcloser to economic feasibility with the best results found in theNorthwest

Because the premium is small (about 5) it may be acceptablein the long term Recent studies have shown that there is inherentvalue added or welfare effects for electricity storage capacity[36] Whether similar value is added by the proposed sinkinghybrid is unknown A more likely parallel would be the idea ofldquointerruptible customersrdquo which get discounted electricity rates inreturn for intermittent power supply A similar contractual agree-ment could be envisioned for the proposed hybrid where dis-counted electricity rates would be provided in return forintermittent demand

The proposed system is not a direct competitor with storagesystems such as pumped hydroelectric or compressed air energystorage (CAES) Energy storage systems attempt to profit by mar-ket arbitrage (selling electricity back to the grid at a higher pricethan it was bought) whereas the proposed hybrid system sinkscheap electricity into transportation fuel Sinking low cost elec-tricity into fuel could be considered cross-market arbitrage andthe most similar system to this would be electrolysis Comparedto electrolysis the proposed system is significantly less expensiveand has the added benefit of running without electric heat whenelectricity costs are too high

Assuming that all sinking electricity is renewable and takingthe additional differences in carbon emissions into account avalue of $26ndash32 per metric ton of CO2e makes the proposedhybrid cost competitive depending on the location of the system

Fig 5 Peaking system sensitivity (NE ISO)

Table 10 Sinking system H2A inputs

NE ISO MISO NW Int

Plant capacity factor 90 90 90Sinking duty 20 20 20Sinking electricity cost (cent=kW h) 435 220 218Utility electricity cost (cent=kW h) 705 487 469Utility natural gas cost ($=nm3) 032 032 032Cost of biomass ($=ton) 4883 4883 4883

Table 11 Indirect sinking system results

$=kg H2 NE ISO MISO NW Int

SMR 140 140 140Biomass to hydrogen baseline 164 164 164Electric air heater hybrid system 175 167 168

031801-8 Vol 133 SEPTEMBER 2011 Transactions of the ASME

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

At $27 per metric ton of CO2e the combustion air-heater hybrid-ization becomes cost competitive with a methane steam reformingplant in the Northwest assuming both the hybrid plant and SMRplant are subject to the same natural gas cost

In order to characterize the effect of various technical and eco-nomic assumptions a sensitivity analysis was performed for thesinking systems (Fig 6) The sensitivity analysis shows that capi-tal costs the cost of biomass and the plant capacity factor for arethe key inputs Capital costs when varied 630 cause the cost ofhydrogen to vary $018 The cost of biomass was varied from $40per ton to $60 per ton and causes the cost of hydrogen to vary byless than $015 Changes in the sinking duty the added hydrogenproduction due to sinking the cost of natural gas and the cost ofelectricity cause hydrogen costs to vary less than 3

From the sinking duty sensitivity analysis it appears that anincreased sinking duty would be preferable to the 20 assumptionmade Minimum hydrogen production prices occur when the elec-tric heating systems are run approximately 40 of the time Run-ning the electric heaters for more time increases plant hydrogenproduction and decreases plant green house gas emissions

The proposed directly heated gasifier hybrid system replacesthe ASU with an electrolyzer bank An H2A analysis was com-pleted to determine the baseline cost of hydrogen produced by adirectly heated gasification plant that uses electrolysis regardlessof electricity cost and the cost of hydrogen for a directly heatedgasification plant that uses a traditional ASU Table 12 summa-rizes the major model inputs The plant was assumed to be locatedin the Midwest ISO region The results of the analysis along withthe associated carbon emissions are listed in Table 13 Costs forproduction of hydrogen via SMR and for an electrolysis plantonly are also shown for reference purposes

As shown in Table 13 hydrogen produced by a direct gasifier-electrolyzer hybrid plant is significantly more expensive than thatproduced by SMR Electricity costs account for 37 of the overallcost of hydrogen produced (or about $086) Therefore if the costof electricity could be halved by intermittent operation during off-peak hours the savings would bring the cost of hydrogen to $189per kilogram of hydrogen At this price the hybrid system couldcompete with hydrogen produced by a standard direct gasificationplant It is important to note that these costs are approximately15 higher than the $164 per kilogram of hydrogen estimated forthe indirectly heated baseline gasification plant used for compari-son of the indirect hybrid analysis (see Table 11)

The original concept called for the electrolyzer bank to bedirectly coupled with stranded wind resources Typical capacityfactors for wind-generated power are in the 30ndash35 range [37]The effect of intermittent operation on the cost of hydrogen pro-duction was investigated using electrolyzer duties of 20 35and 50 The smaller the duty the larger the number electrolyz-ers needed to produce the same amount of oxygen per year

The effect of reduced electrolyzer duty on the cost of hydrogenis shown in Fig 7 Two curves are plotted The first assumes aconstant electricity price of $433=MWh regardless of the electro-lyzer duty This assumption would represent the scenario if theelectrolyzers were directly coupled with a stranded wind resourceThe second curve uses Midwest ISO market data so that the costof electricity fluctuates with duty These numbers do not considerthe cost of oxygen storage as these costs are assumed small com-pared to the increased electrolyzer capital costs and are identicalfor similar duty

Intermittent operation significantly adds to plant capital costsIf the price of electricity available to the plant does not decrease

Fig 6 Sinking system sensitivity (NW Int)

Table 12 Direct system H2A inputs

MISO

Electrolyzer duty () 100Utility electricity cost (cent=kW h) 433Cost of biomass ($=ton) 4883

Table 13 Direct system results

$=kg H2 Net CO2e=kg H2

SMR $140 68Biomass gasification $213 196Electrolysis $259 145 (178)Electrolysisthorn gasification $232 024 (182)

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-9

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

with intermittent electrolyzer operation then the cost of hydrogenincreases by 22 for a 35 duty However if the cost of electric-ity can be reduced by intermittent operation then the analysisshows that intermittent operation may be preferable to 100 dutyThis result means that the initial concept of capturing strandedresources is less favorable economically than a grid-connectedsinking system

If grid electricity is used then carbon emissions actuallyincrease relative to biomass gasification alone for this hybridiza-tion If upstream emissions for electricity production are takeninto account electrolysis and this proposed hybrid are both netCO2e emitters This makes their justification by carbon valueimpossible unless only renewable electricity is used for operation(renewable energy values are shown in parentheses in Table 13)Since renewable wind energy is inherently intermittent it isunreasonable to assume renewable electricity is used without add-ing the necessary equipment for intermittent operation Onerenewable energy exception would be the use of hydroelectricpower for the systems

Similar to the other hybrid systems investigated hybridizationresults in a price premium There must be some additional justifi-cation for hybridization such as utility demands The baseline bio-mass to hydrogen case with an ASU requires only $35 per metricton of CO2e to be cost competitive with SMR produced hydrogen

assuming both the hybrid plant and SMR plant are subject to thesame natural gas cost at a given location

Electrolyzer-based hybrid system economics are extremely sen-sitive to the cost of electricity (Fig 8) Fluctuations of $001 inthe cost of electricity cause the price of hydrogen to fluctuatemore than $025 per kilogram If the price of electricity were todrop below $004=kW h then the proposed hybrid system couldeconomically compete with a nonhybrid biomass to hydrogenplant However this low price level is unlikely and any energymarket fluctuations would have a dramatic effect on economicviability

Conclusion

The two hybrid concepts analyzed involve coproduction of gase-ous hydrogen and electric power from thermochemical-based biorefi-neries Both of the concepts analyzed share the basic idea ofcombining intermittent wind-generated electricity with a biomassgasification plant Wind availability overlaps biomass resource avail-ability in three areas of the United States making the use of locallyproduced wind electricity for gasification feasible The proposedhybrid systems attempt to either fill wind energy shortfalls by burn-ing syngas in a natural gas turbine or absorb excess renewable powerduring times of low-electricity demand

None of the proposed hybrid systems produced hydrogen forless than a nonhybrid plant could In all cases a premium was paidfor hybridization that could not be offset by the increasedfunctionality

The indirectly heated gasifier hybrid system consists of twoparts (1) producing peaking electricity intermittently with a gasturbine and (2) sinking electricity into electric heaters intermit-tently to boost fuel production efficiency Each of these parts wasanalyzed separately The indirectly heated gasifier hybrid systemis meant to be grid-connected and provide peaking electricity anddispatchable demand (eg an on demand load) to the local utilityto help manage intermittent wind resources

The indirect gasification concepts studied could be cost compet-itive in the near future as value is placed on controlling carbonemissions Carbon values of just under $40 per metric ton ofCO2e make the systems studied cost competitive with steam

Fig 7 Electrolyzer duty versus cost

Fig 8 Direct system sensitivity

031801-10 Vol 133 SEPTEMBER 2011 Transactions of the ASME

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

methane reforming to produce hydrogen However a nonhybridbiomass to hydrogen plant will be more cost competitive in gen-eral so there must be additional operational value placed on peak-ing or sinking for these plants to be economically attractive Thisadditional value is likely to become a reality as additional inter-mittent renewable energy sources such as wind are added to thenational grid

The directly heated gasifier hybrid system involves replacementof the air separation unit with electrolyzers This change allowsfor extra production of hydrogen and intermittent operation Theanalysis for this system assumed direct replacement of the ASUwithout intermittent operation Estimates of the effect of intermit-tent operation on plant economics were made The electrolyzerbank could be either grid-connected to provide a dispatchabledemand to the utility or it could be tied directly to a stranded windsource to convert wind into chemical fuel (H2)

The direct gasification concept studied is unlikely to be cost com-petitive in the near future but may eventually be attractive withlower-cost electrolysis and a smaller biorefinery plant size that issized for a specific hydrogen demand Intermittent operation andstranded operation were found to have worse economics than grid-connected systems High electrolyzer capital costs make the possibleelectricity cost savings of intermittent operation difficult to justifyBased on a direct replacement of the ASU with electrolyzers hydro-gen can be produced for $232 per kilogram However using gridelectricity the hybrid system is a net CO2e emitter For the use ofelectrolysis to make sense in this setting there must be a significantbenefit to the ability to operate intermittently

Acknowledgment

The authors would also like to acknowledge Dr Bob Evans forconceiving the hybrid hydrogen production systems project andDonna Heimiller for performing the GIS mapping

Employees of the Alliance for Sustainable Energy LLC underContract No DE-AC36-08GO28308 with the US Dept ofEnergy have authored this work The United States Governmentretains and the publisher by accepting the article for publicationacknowledges that the United States Government retains a nonex-clusive paid-up irrevocable worldwide license to publish orreproduce the published form of this work or allow others to doso for United States Government purposes

References[1] Milbrandt A 2005 ldquoA Geographic Perspective on the Current Biomass

Resource Availability in the United Statesrdquo National Renewable Energy LabReport No TP-560-39181

[2] Perlack R Wright L Turhollow A Graham R Stokes B and Erbach D2005 Biomass as Feedstock for a Bioenergy and Bioproducts Industry The Tech-nical Feasibility of a Billion-Ton Annual Supply Oak Ridge National LaboratoryOak 853 Ridge TN

[3] Turner J Sverdrup G Mann M Maness P C Kroposki B Ghirardi MEvans J and Blake D 2008 ldquoRenewable Hydrogen Productionrdquo Int JEnergy Res 32 pp 379ndash407

[4] US Department of Energy Energy Efficiency and Renewable Energy Labora-tory 2008 ldquo20 Wind Energy by 2030mdashIncreasing Wind Energyrsquos Contribu-tion to US Electricity Supplyrdquo Report No GO-102008-2567

[5] Levene J Kroposki B and Sverdrup G 2006 ldquoWind Energy and Productionof Hydrogen and ElectricityndashOpportunities for Renewable Hydrogenrdquo NationalRenewable Energy Laboratory Report No CP560-39534

[6] Fingersh L 2004 ldquoOptimization of Utility-Scale Wind-Hydrogen-BatterySystemsrdquo National Renewable Energy Laboratory Report No CP-500-36117

[7] Dean J Braun R Munoz D Penev M and Kinchin C 2010 ldquoAnalysis ofHybrid Hydrogen Systems ndash Final Reportrdquo National Renewable Energy Labo-ratory Report No TP-46934

[8] Gasification Technology Status ndash December 2006 EPRI and the Gasification869 Users Association Palo Alto CA p 1012224

[9] Spath P Aden A Eggeman T Ringer M Wallace B and Jechura J2005 ldquoBiomass to Hydrogen Production Detailed Design and Economics Uti-lizing the Battelle Columbus Laboratory Indirectly-Heated Gasifierrdquo NationalRenewable Energy Laboratory Report No TP-510-37408

[10] Dean J 2010 ldquoLeveling Intermittent Renewable Energy Production ThroughBiomass Gasification-based Hybrid Systemsrdquo MS thesis Colorado School ofMines Golden CO

[11] Devi L Ptasinski K Janssen F van Paasen S Bergman P and Kiel J2005 ldquoCatalytic Decomposition of Biomass Tars Use of Dolomite anUntreated Olivinerdquo Renewable Energy 30 pp 565ndash587

[12] Heavy Duty Gas Turbine Products 2009 General Electric Company FairfieldCT

[13] Drdar D and Jones R 2000 ldquoGE IGCC Technology and Experience withAdvanced Gas Turbinesrdquo GE Power Systems Report No GER-4207

[14] Craig K and Mann M 1996 ldquoCost and Performance Analysis of Biomass-Based Integrated Gasification Combined-Cycle (BIGCC) Power SystemsrdquoNational Renewable Energy Laboratory Report No TP-430-21657

[15] Gas Turbine World 2006 Handbook (Pequot Publishing Inc Fairfield CT2006)

[16] Kinchin C and Bain R 2009 ldquoHydrogen Production from Biomass via Indi-rect Gasification The Impact of NREL Process Development Unit GasifierCorrelationsrdquo National Renewable Energy Laboratory Report No TP-510-44868

[17] Watlow for 22 MW duct heaters Watlow 12001 Lackland Road St LouisMO 63146 personal communication 2009

[18] Gassner M and Marechal F 2008 ldquoThermo-economic Optimization of theIntegration of Electrolysis in Synthetic Natural Gas Production from WoodrdquoEnergy 33 pp 189ndash198

[19] Srinivas T Gupta A V S and Reddy B V 2009 ldquoThermodynamic Equi-librium Model and Exergy Analysis of a Biomass Gasifierrdquo ASME J EnergyResour Technol 131 031801 pp 1ndash7

[20] Braun R J Hanzon L G and Dean J H 2011 ldquoSystem Analysis of Ther-mochemical-based Biorefineries for Coproduction of Hydrogen and Elec-tricityrdquo ASME J Energy Resour Technol 133 012601 pp 1ndash12

[21] Manning F and Thompson R 1991 Oilfield Processing of Petroleum Vol-ume One 904 Natural Gas PennWell Publishing Co Tulsa Oklahoma

[22] StatoilHydro 2009 ldquoHydrogen Technologies World Leader in Electrolysis forHydrogen Solutionsrdquo product brochure Hydrogen Technologies NO-3674Notodden Norway COS 091408 available URL http908wwwelectrolyserscom

[23] US Department of Energy Hydrogen Program 2009 ldquoFuture Central Hydro-gen Production from Grid Electrolysisrdquo H2A analysis wwwhydrogenenergygovh2a_prod_studieshtml

[24] Phyllis Biomass Datapage ldquowood hybrid poplarrdquo ID 806 available URLhttpwwwecnnlphyllis

[25] Jin H Larson E and Celik F 2009 ldquoPerformance and Cost Analysis ofFuture Commercially Mature Gasification-Based Electric Power GenerationFrom Switchgrassrdquo Biofpr 3 pp 142ndash173

[26] Department of Energy 2007 ldquoCost and Performance Baseline for Fossil EnergyPlants Volume 1 Bituminous Coal and Natural Gas to Electricityrdquo Report NoDOE=NETL-2007=1281

[27] US Department of Energy Hydrogen Program 2009 ldquoDOE H2A Analy-sisrdquo wwwhydrogenenergygovh2a_analysishtml

[28] US Department of Energy Hydrogen Program 2009 ldquoFuture Central Hydro-gen Production from Natural Gas with CO2 Sequestrationrdquo H2A analysiswwwhydrogenenergygovh2a_prod_studieshtml

[29] Energy Information Administration Annual Energy Outlook 2009 wwweiadoegovoiafaeoelectricityhtml

[30] Schafer A Heywood J and Weiss M 2006 ldquoFuture Fuel Cell and InternalCombustion Engine Automobile Technologies A 25-Year Life Cycle and FleetImpact Assessmentrdquo Energy 31 pp 2064ndash2087

[31] NE ISO 2009 ldquoEnergy Sources in New Englandrdquo wwwiso-necomnwsissgrid_mktsenrgy_srcs

[32] Doying R 2009 Midwest ISO ldquoJune Monthly Reportrdquo wwwmidwestisoorg[33] PacifiCorp 2009 ldquoIntegrated Resource Plan ndash Volume 1rdquo May 29 2009

wwwpaci-937ficorpcom[34] Frank Novachek 2009 Xcel Energy 414 Nicollet Mall Minneapolis MN

55401 939 personal communication[35] Energy Efficiency and Renewable Energy Department of Energy ldquoBiomass

2009 Multi-Year Research Development and Demonstration Planrdquo www1eer-eenergygovbiomasspdfsmypp_may2009pdf

[36] Sioshansi R Denholm P Jenkin T and Weiss J 2009 ldquoEstimating theValue of Electricity Storage in PJM Arbitrage and Some Welfare EffectrdquoEnergy Econ 31 pp 269ndash277

[37] Kroposki B Levene J Harrison K Sen P K and Novachek F 2006ldquoElectrolysis Information and Opportunities for Electric Power UtilitiesrdquoNational Renewable Energy Laboratory Report No TP-581-40

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-11

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

Table 7 details the grid production mix and correspondingemissions for each location studied The values shown in Table 7are assumptions in so much as they are averaged values for largeprocesses or regions Table 7 is actually a calculation matrix Asan example for the column ldquoNE ISOrdquo the calculation for the aver-age greenhouse gas emission for each kilowatt-hour of energyproduced is shown in Eq (1)

0150 9525thorn 0180 8931thorn 0300 5992 frac14 483 (1)

One kilogram of hydrogen has the approximate energy equivalentof 1 gal of gasoline However because hydrogen can be used infuel cells with much higher efficiency 1 kg of hydrogen couldactually offset about 2 gal of gasoline [30] Burning 2 gal of gaso-line produces 1784 kg of CO2e These numbers were used as car-bon credits for each kilogram of hydrogen or megawatt-hour ofelectricity produced by the proposed systems

Economic Results

The proposed indirectly heated gasifier peaking systemswitches between (1) hydrogen production and (2) electricity pro-duction (peaking) driven by the cost of electricity available on thegrid Based on discussions with Xcel Energy in Colorado [34] apeaking duty of 20 was used for the analysis Table 8 summa-rizes the major model inputs by region for the system A contractrate was used for any peaking electricity produced by the plantThis is common practice in the current electricity market and pro-vides a premium price for dispatchable peaking assets The cost ofbiomass feedstock was not varied regionally due to a lack of areliable index or market basis upon which to base the variation

Instead the effect of biomass feedstock cost was investigated aspart of the sensitivity analysis

Based on the economic inputs above and the plant inputs andoutputs previously discussed the cost of hydrogen production ineach area was calculated The results are shown in Table 9 alongwith the cost of hydrogen production for a baseline nonhybri-dized biomass to hydrogen plant and a SMR plant

The additional capital costs of hybridization cannot be justifiedtoday in any of the locations studied There is a $020 to $024 perkilogram premium on hydrogen produced by the proposed hybridsystem compared with a nonhybrid biomass to hydrogen gasifica-tion plant Areas with higher priced electricity move this hybrid-ization closer to economic feasibility with the best results foundin the Northeast

When the hybrid plant is producing electricity the plant usesno natural gas or electricity whereas when the plant is producinghydrogen natural gas is used for balancing the heat duty of theplant and electricity is required to run compressors Taking thedifferences in carbon emissions into account a value of $37ndash40per metric ton of CO2e makes the cost of hydrogen for the pro-posed hybrid system equal to that of SMR depending on the loca-tion This comparison was made assuming that both the hybridplant and SMR plant are subject to the same natural gas cost at agiven location

It is important to note that the baseline biomass to hydrogenplant only requires $23ndash25 per metric ton of CO2e value to becost competitive with hydrogen produced by SMR This meansthat peaking hybridization will only be economically promisingwhen there is some value placed on the additional functionality ofdual mode operation

In order to characterize the effect of various technical and eco-nomic assumptions a sensitivity analysis was performed for thegas turbine peaking system Figure 5 shows the results for the costof hydrogen in tornado chart format Capital costs the cost of bio-mass and the price which peaking electricity can be sold for arethe key inputs Capital costs when varied 630 cause the cost ofhydrogen to vary $025 The cost of biomass was varied from $40to $60 per ton based on projections in Ref [35] and causes thecost of hydrogen to vary by less than $020 The price of peakingelectricity and the plant capacity factor also cause fluctuations ofless than $020 Changes in the cost of electricity bought by theplant the cost of natural gas peaking power output and turbinepeaking duty cause hydrogen costs to vary less than 5

The proposed sinking system switches between (1) hydrogenproduction with syngas recycling for gasifier heat and (2) hydro-gen production with electrical heating (sinking) to decrease the

Table 7 Greenhouse gas assumptions

kg CO2e per kW ha NE ISOb MISOc NW Intd

Coal 9525 150 756 580Oil=petroleum 8931 180 01 10Natural gas 5992 300 36 197Nuclear mdash 280 151 10Renewable mdash 90 56 203Average kg CO2e=kW h mdash 483 743 679

aHyARC Energy Constants and Assumptions H2A Analysis Tool [26]bNE ISO energy sources report [31]cMidwest ISO June monthly report [32]dApproximation based on PacifiCorp 2008 integrated resource plan [33]

Table 8 Peaking system H2A inputs

NE ISO MISO NW Int

Peaking duty 20 20 20Peaking electricity value (cent=kW h) 140 120 115Utility electricity cost (cent=kW h) 592 362 369Utility natural gas cost ($=nm3) 032 032 032Cost of biomass ($=ton)a 4883 4883 4883

aValue taken from the Biomass 2009 Multi-Year Research Developmentand Demonstration Plan (EERE 2009) The 2012 target value is $5070per ton of dry woody biomass in 2007 dollars Taken to 2005 dollars with109 inflation this yields $4883 per ton

Table 9 Peaking system results

$=kg H2 NE ISO MISO NW Int

SMR 140 140 140Biomass to hydrogen baseline 164 164 164Gas turbine hybrid system 184 186 188

Table 6 Economic assumptions

Parameter Value

Constant dollar value 2005Internal rate of return (after-tax) 10Debt=equity 0=100Plant life 40 yearsDepreciation Modified accelerated cost recovery systemDepreciation recovery period 20 yearsConstruction period 2 years

1st year 75 (25 for electrolysis)2nd year 25 (75 for electrolysis)

Start-up time 12 monthsRevenues 50Variable costs 75Fixed costs 100

Working capital 15 of total capital investmentInflation rate 19Total taxes 389Decommissioning costs 10 of depreciable capitalSalvage value 10 of total capital investment

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-7

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

syngas recycle This sinking ability can best be described as a dis-patchable load or demand from the viewpoint of the grid

Based on discussions with Xcel Energy the utility will pay tohave wind-generated electricity used at times (the electricity has anegative cost) and having a dispatchable load would provide avaluable service to the utility [34] Xcel Energy is required byColoradorsquos renewable portfolio standard to accept renewableenergy when it is available The requirement to accept wind elec-tricity regardless of grid demand is not universal and thereforenegative cost wind electricity may not be available in other states

No similar system was found for comparison therefore a sink-ing duty of 20 was used as a starting point for the analysisTable 10 summarizes the major economic model inputs by regionUnlike peaking electricity where a contract rate is used for elec-tricity produced by the plant the sinking analysis simply uses theaverage cost-of-electricity for the cheapest 20 of hours as thesinking electricity cost The utility electricity cost is the averageof the remaining 80 of the hours These costs-of-electricitywould be valid if a plant operator used accurate day-ahead energymarket forecasts to schedule plant operation

Given the economic inputs in Table 10 the cost of hydrogenproduction in each area was calculated The results are shown inTable 11 along with the cost of hydrogen production for a base-line nonhybridized biomass to hydrogen plant and a steam meth-ane reforming plant

There is a $003 to $011 premium on hydrogen produced bythe proposed hybrid system compared with a nonhybrid biomassto hydrogen gasification plant The additional capital costs of the

sinking hybridization are not fully offset by additional revenue inany of the locations studied However the marginal costs foundare small enough that it is difficult to draw any definitive conclu-sion Areas with lower cost electricity move this hybridizationcloser to economic feasibility with the best results found in theNorthwest

Because the premium is small (about 5) it may be acceptablein the long term Recent studies have shown that there is inherentvalue added or welfare effects for electricity storage capacity[36] Whether similar value is added by the proposed sinkinghybrid is unknown A more likely parallel would be the idea ofldquointerruptible customersrdquo which get discounted electricity rates inreturn for intermittent power supply A similar contractual agree-ment could be envisioned for the proposed hybrid where dis-counted electricity rates would be provided in return forintermittent demand

The proposed system is not a direct competitor with storagesystems such as pumped hydroelectric or compressed air energystorage (CAES) Energy storage systems attempt to profit by mar-ket arbitrage (selling electricity back to the grid at a higher pricethan it was bought) whereas the proposed hybrid system sinkscheap electricity into transportation fuel Sinking low cost elec-tricity into fuel could be considered cross-market arbitrage andthe most similar system to this would be electrolysis Comparedto electrolysis the proposed system is significantly less expensiveand has the added benefit of running without electric heat whenelectricity costs are too high

Assuming that all sinking electricity is renewable and takingthe additional differences in carbon emissions into account avalue of $26ndash32 per metric ton of CO2e makes the proposedhybrid cost competitive depending on the location of the system

Fig 5 Peaking system sensitivity (NE ISO)

Table 10 Sinking system H2A inputs

NE ISO MISO NW Int

Plant capacity factor 90 90 90Sinking duty 20 20 20Sinking electricity cost (cent=kW h) 435 220 218Utility electricity cost (cent=kW h) 705 487 469Utility natural gas cost ($=nm3) 032 032 032Cost of biomass ($=ton) 4883 4883 4883

Table 11 Indirect sinking system results

$=kg H2 NE ISO MISO NW Int

SMR 140 140 140Biomass to hydrogen baseline 164 164 164Electric air heater hybrid system 175 167 168

031801-8 Vol 133 SEPTEMBER 2011 Transactions of the ASME

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

At $27 per metric ton of CO2e the combustion air-heater hybrid-ization becomes cost competitive with a methane steam reformingplant in the Northwest assuming both the hybrid plant and SMRplant are subject to the same natural gas cost

In order to characterize the effect of various technical and eco-nomic assumptions a sensitivity analysis was performed for thesinking systems (Fig 6) The sensitivity analysis shows that capi-tal costs the cost of biomass and the plant capacity factor for arethe key inputs Capital costs when varied 630 cause the cost ofhydrogen to vary $018 The cost of biomass was varied from $40per ton to $60 per ton and causes the cost of hydrogen to vary byless than $015 Changes in the sinking duty the added hydrogenproduction due to sinking the cost of natural gas and the cost ofelectricity cause hydrogen costs to vary less than 3

From the sinking duty sensitivity analysis it appears that anincreased sinking duty would be preferable to the 20 assumptionmade Minimum hydrogen production prices occur when the elec-tric heating systems are run approximately 40 of the time Run-ning the electric heaters for more time increases plant hydrogenproduction and decreases plant green house gas emissions

The proposed directly heated gasifier hybrid system replacesthe ASU with an electrolyzer bank An H2A analysis was com-pleted to determine the baseline cost of hydrogen produced by adirectly heated gasification plant that uses electrolysis regardlessof electricity cost and the cost of hydrogen for a directly heatedgasification plant that uses a traditional ASU Table 12 summa-rizes the major model inputs The plant was assumed to be locatedin the Midwest ISO region The results of the analysis along withthe associated carbon emissions are listed in Table 13 Costs forproduction of hydrogen via SMR and for an electrolysis plantonly are also shown for reference purposes

As shown in Table 13 hydrogen produced by a direct gasifier-electrolyzer hybrid plant is significantly more expensive than thatproduced by SMR Electricity costs account for 37 of the overallcost of hydrogen produced (or about $086) Therefore if the costof electricity could be halved by intermittent operation during off-peak hours the savings would bring the cost of hydrogen to $189per kilogram of hydrogen At this price the hybrid system couldcompete with hydrogen produced by a standard direct gasificationplant It is important to note that these costs are approximately15 higher than the $164 per kilogram of hydrogen estimated forthe indirectly heated baseline gasification plant used for compari-son of the indirect hybrid analysis (see Table 11)

The original concept called for the electrolyzer bank to bedirectly coupled with stranded wind resources Typical capacityfactors for wind-generated power are in the 30ndash35 range [37]The effect of intermittent operation on the cost of hydrogen pro-duction was investigated using electrolyzer duties of 20 35and 50 The smaller the duty the larger the number electrolyz-ers needed to produce the same amount of oxygen per year

The effect of reduced electrolyzer duty on the cost of hydrogenis shown in Fig 7 Two curves are plotted The first assumes aconstant electricity price of $433=MWh regardless of the electro-lyzer duty This assumption would represent the scenario if theelectrolyzers were directly coupled with a stranded wind resourceThe second curve uses Midwest ISO market data so that the costof electricity fluctuates with duty These numbers do not considerthe cost of oxygen storage as these costs are assumed small com-pared to the increased electrolyzer capital costs and are identicalfor similar duty

Intermittent operation significantly adds to plant capital costsIf the price of electricity available to the plant does not decrease

Fig 6 Sinking system sensitivity (NW Int)

Table 12 Direct system H2A inputs

MISO

Electrolyzer duty () 100Utility electricity cost (cent=kW h) 433Cost of biomass ($=ton) 4883

Table 13 Direct system results

$=kg H2 Net CO2e=kg H2

SMR $140 68Biomass gasification $213 196Electrolysis $259 145 (178)Electrolysisthorn gasification $232 024 (182)

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-9

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

with intermittent electrolyzer operation then the cost of hydrogenincreases by 22 for a 35 duty However if the cost of electric-ity can be reduced by intermittent operation then the analysisshows that intermittent operation may be preferable to 100 dutyThis result means that the initial concept of capturing strandedresources is less favorable economically than a grid-connectedsinking system

If grid electricity is used then carbon emissions actuallyincrease relative to biomass gasification alone for this hybridiza-tion If upstream emissions for electricity production are takeninto account electrolysis and this proposed hybrid are both netCO2e emitters This makes their justification by carbon valueimpossible unless only renewable electricity is used for operation(renewable energy values are shown in parentheses in Table 13)Since renewable wind energy is inherently intermittent it isunreasonable to assume renewable electricity is used without add-ing the necessary equipment for intermittent operation Onerenewable energy exception would be the use of hydroelectricpower for the systems

Similar to the other hybrid systems investigated hybridizationresults in a price premium There must be some additional justifi-cation for hybridization such as utility demands The baseline bio-mass to hydrogen case with an ASU requires only $35 per metricton of CO2e to be cost competitive with SMR produced hydrogen

assuming both the hybrid plant and SMR plant are subject to thesame natural gas cost at a given location

Electrolyzer-based hybrid system economics are extremely sen-sitive to the cost of electricity (Fig 8) Fluctuations of $001 inthe cost of electricity cause the price of hydrogen to fluctuatemore than $025 per kilogram If the price of electricity were todrop below $004=kW h then the proposed hybrid system couldeconomically compete with a nonhybrid biomass to hydrogenplant However this low price level is unlikely and any energymarket fluctuations would have a dramatic effect on economicviability

Conclusion

The two hybrid concepts analyzed involve coproduction of gase-ous hydrogen and electric power from thermochemical-based biorefi-neries Both of the concepts analyzed share the basic idea ofcombining intermittent wind-generated electricity with a biomassgasification plant Wind availability overlaps biomass resource avail-ability in three areas of the United States making the use of locallyproduced wind electricity for gasification feasible The proposedhybrid systems attempt to either fill wind energy shortfalls by burn-ing syngas in a natural gas turbine or absorb excess renewable powerduring times of low-electricity demand

None of the proposed hybrid systems produced hydrogen forless than a nonhybrid plant could In all cases a premium was paidfor hybridization that could not be offset by the increasedfunctionality

The indirectly heated gasifier hybrid system consists of twoparts (1) producing peaking electricity intermittently with a gasturbine and (2) sinking electricity into electric heaters intermit-tently to boost fuel production efficiency Each of these parts wasanalyzed separately The indirectly heated gasifier hybrid systemis meant to be grid-connected and provide peaking electricity anddispatchable demand (eg an on demand load) to the local utilityto help manage intermittent wind resources

The indirect gasification concepts studied could be cost compet-itive in the near future as value is placed on controlling carbonemissions Carbon values of just under $40 per metric ton ofCO2e make the systems studied cost competitive with steam

Fig 7 Electrolyzer duty versus cost

Fig 8 Direct system sensitivity

031801-10 Vol 133 SEPTEMBER 2011 Transactions of the ASME

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

methane reforming to produce hydrogen However a nonhybridbiomass to hydrogen plant will be more cost competitive in gen-eral so there must be additional operational value placed on peak-ing or sinking for these plants to be economically attractive Thisadditional value is likely to become a reality as additional inter-mittent renewable energy sources such as wind are added to thenational grid

The directly heated gasifier hybrid system involves replacementof the air separation unit with electrolyzers This change allowsfor extra production of hydrogen and intermittent operation Theanalysis for this system assumed direct replacement of the ASUwithout intermittent operation Estimates of the effect of intermit-tent operation on plant economics were made The electrolyzerbank could be either grid-connected to provide a dispatchabledemand to the utility or it could be tied directly to a stranded windsource to convert wind into chemical fuel (H2)

The direct gasification concept studied is unlikely to be cost com-petitive in the near future but may eventually be attractive withlower-cost electrolysis and a smaller biorefinery plant size that issized for a specific hydrogen demand Intermittent operation andstranded operation were found to have worse economics than grid-connected systems High electrolyzer capital costs make the possibleelectricity cost savings of intermittent operation difficult to justifyBased on a direct replacement of the ASU with electrolyzers hydro-gen can be produced for $232 per kilogram However using gridelectricity the hybrid system is a net CO2e emitter For the use ofelectrolysis to make sense in this setting there must be a significantbenefit to the ability to operate intermittently

Acknowledgment

The authors would also like to acknowledge Dr Bob Evans forconceiving the hybrid hydrogen production systems project andDonna Heimiller for performing the GIS mapping

Employees of the Alliance for Sustainable Energy LLC underContract No DE-AC36-08GO28308 with the US Dept ofEnergy have authored this work The United States Governmentretains and the publisher by accepting the article for publicationacknowledges that the United States Government retains a nonex-clusive paid-up irrevocable worldwide license to publish orreproduce the published form of this work or allow others to doso for United States Government purposes

References[1] Milbrandt A 2005 ldquoA Geographic Perspective on the Current Biomass

Resource Availability in the United Statesrdquo National Renewable Energy LabReport No TP-560-39181

[2] Perlack R Wright L Turhollow A Graham R Stokes B and Erbach D2005 Biomass as Feedstock for a Bioenergy and Bioproducts Industry The Tech-nical Feasibility of a Billion-Ton Annual Supply Oak Ridge National LaboratoryOak 853 Ridge TN

[3] Turner J Sverdrup G Mann M Maness P C Kroposki B Ghirardi MEvans J and Blake D 2008 ldquoRenewable Hydrogen Productionrdquo Int JEnergy Res 32 pp 379ndash407

[4] US Department of Energy Energy Efficiency and Renewable Energy Labora-tory 2008 ldquo20 Wind Energy by 2030mdashIncreasing Wind Energyrsquos Contribu-tion to US Electricity Supplyrdquo Report No GO-102008-2567

[5] Levene J Kroposki B and Sverdrup G 2006 ldquoWind Energy and Productionof Hydrogen and ElectricityndashOpportunities for Renewable Hydrogenrdquo NationalRenewable Energy Laboratory Report No CP560-39534

[6] Fingersh L 2004 ldquoOptimization of Utility-Scale Wind-Hydrogen-BatterySystemsrdquo National Renewable Energy Laboratory Report No CP-500-36117

[7] Dean J Braun R Munoz D Penev M and Kinchin C 2010 ldquoAnalysis ofHybrid Hydrogen Systems ndash Final Reportrdquo National Renewable Energy Labo-ratory Report No TP-46934

[8] Gasification Technology Status ndash December 2006 EPRI and the Gasification869 Users Association Palo Alto CA p 1012224

[9] Spath P Aden A Eggeman T Ringer M Wallace B and Jechura J2005 ldquoBiomass to Hydrogen Production Detailed Design and Economics Uti-lizing the Battelle Columbus Laboratory Indirectly-Heated Gasifierrdquo NationalRenewable Energy Laboratory Report No TP-510-37408

[10] Dean J 2010 ldquoLeveling Intermittent Renewable Energy Production ThroughBiomass Gasification-based Hybrid Systemsrdquo MS thesis Colorado School ofMines Golden CO

[11] Devi L Ptasinski K Janssen F van Paasen S Bergman P and Kiel J2005 ldquoCatalytic Decomposition of Biomass Tars Use of Dolomite anUntreated Olivinerdquo Renewable Energy 30 pp 565ndash587

[12] Heavy Duty Gas Turbine Products 2009 General Electric Company FairfieldCT

[13] Drdar D and Jones R 2000 ldquoGE IGCC Technology and Experience withAdvanced Gas Turbinesrdquo GE Power Systems Report No GER-4207

[14] Craig K and Mann M 1996 ldquoCost and Performance Analysis of Biomass-Based Integrated Gasification Combined-Cycle (BIGCC) Power SystemsrdquoNational Renewable Energy Laboratory Report No TP-430-21657

[15] Gas Turbine World 2006 Handbook (Pequot Publishing Inc Fairfield CT2006)

[16] Kinchin C and Bain R 2009 ldquoHydrogen Production from Biomass via Indi-rect Gasification The Impact of NREL Process Development Unit GasifierCorrelationsrdquo National Renewable Energy Laboratory Report No TP-510-44868

[17] Watlow for 22 MW duct heaters Watlow 12001 Lackland Road St LouisMO 63146 personal communication 2009

[18] Gassner M and Marechal F 2008 ldquoThermo-economic Optimization of theIntegration of Electrolysis in Synthetic Natural Gas Production from WoodrdquoEnergy 33 pp 189ndash198

[19] Srinivas T Gupta A V S and Reddy B V 2009 ldquoThermodynamic Equi-librium Model and Exergy Analysis of a Biomass Gasifierrdquo ASME J EnergyResour Technol 131 031801 pp 1ndash7

[20] Braun R J Hanzon L G and Dean J H 2011 ldquoSystem Analysis of Ther-mochemical-based Biorefineries for Coproduction of Hydrogen and Elec-tricityrdquo ASME J Energy Resour Technol 133 012601 pp 1ndash12

[21] Manning F and Thompson R 1991 Oilfield Processing of Petroleum Vol-ume One 904 Natural Gas PennWell Publishing Co Tulsa Oklahoma

[22] StatoilHydro 2009 ldquoHydrogen Technologies World Leader in Electrolysis forHydrogen Solutionsrdquo product brochure Hydrogen Technologies NO-3674Notodden Norway COS 091408 available URL http908wwwelectrolyserscom

[23] US Department of Energy Hydrogen Program 2009 ldquoFuture Central Hydro-gen Production from Grid Electrolysisrdquo H2A analysis wwwhydrogenenergygovh2a_prod_studieshtml

[24] Phyllis Biomass Datapage ldquowood hybrid poplarrdquo ID 806 available URLhttpwwwecnnlphyllis

[25] Jin H Larson E and Celik F 2009 ldquoPerformance and Cost Analysis ofFuture Commercially Mature Gasification-Based Electric Power GenerationFrom Switchgrassrdquo Biofpr 3 pp 142ndash173

[26] Department of Energy 2007 ldquoCost and Performance Baseline for Fossil EnergyPlants Volume 1 Bituminous Coal and Natural Gas to Electricityrdquo Report NoDOE=NETL-2007=1281

[27] US Department of Energy Hydrogen Program 2009 ldquoDOE H2A Analy-sisrdquo wwwhydrogenenergygovh2a_analysishtml

[28] US Department of Energy Hydrogen Program 2009 ldquoFuture Central Hydro-gen Production from Natural Gas with CO2 Sequestrationrdquo H2A analysiswwwhydrogenenergygovh2a_prod_studieshtml

[29] Energy Information Administration Annual Energy Outlook 2009 wwweiadoegovoiafaeoelectricityhtml

[30] Schafer A Heywood J and Weiss M 2006 ldquoFuture Fuel Cell and InternalCombustion Engine Automobile Technologies A 25-Year Life Cycle and FleetImpact Assessmentrdquo Energy 31 pp 2064ndash2087

[31] NE ISO 2009 ldquoEnergy Sources in New Englandrdquo wwwiso-necomnwsissgrid_mktsenrgy_srcs

[32] Doying R 2009 Midwest ISO ldquoJune Monthly Reportrdquo wwwmidwestisoorg[33] PacifiCorp 2009 ldquoIntegrated Resource Plan ndash Volume 1rdquo May 29 2009

wwwpaci-937ficorpcom[34] Frank Novachek 2009 Xcel Energy 414 Nicollet Mall Minneapolis MN

55401 939 personal communication[35] Energy Efficiency and Renewable Energy Department of Energy ldquoBiomass

2009 Multi-Year Research Development and Demonstration Planrdquo www1eer-eenergygovbiomasspdfsmypp_may2009pdf

[36] Sioshansi R Denholm P Jenkin T and Weiss J 2009 ldquoEstimating theValue of Electricity Storage in PJM Arbitrage and Some Welfare EffectrdquoEnergy Econ 31 pp 269ndash277

[37] Kroposki B Levene J Harrison K Sen P K and Novachek F 2006ldquoElectrolysis Information and Opportunities for Electric Power UtilitiesrdquoNational Renewable Energy Laboratory Report No TP-581-40

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-11

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

syngas recycle This sinking ability can best be described as a dis-patchable load or demand from the viewpoint of the grid

Based on discussions with Xcel Energy the utility will pay tohave wind-generated electricity used at times (the electricity has anegative cost) and having a dispatchable load would provide avaluable service to the utility [34] Xcel Energy is required byColoradorsquos renewable portfolio standard to accept renewableenergy when it is available The requirement to accept wind elec-tricity regardless of grid demand is not universal and thereforenegative cost wind electricity may not be available in other states

No similar system was found for comparison therefore a sink-ing duty of 20 was used as a starting point for the analysisTable 10 summarizes the major economic model inputs by regionUnlike peaking electricity where a contract rate is used for elec-tricity produced by the plant the sinking analysis simply uses theaverage cost-of-electricity for the cheapest 20 of hours as thesinking electricity cost The utility electricity cost is the averageof the remaining 80 of the hours These costs-of-electricitywould be valid if a plant operator used accurate day-ahead energymarket forecasts to schedule plant operation

Given the economic inputs in Table 10 the cost of hydrogenproduction in each area was calculated The results are shown inTable 11 along with the cost of hydrogen production for a base-line nonhybridized biomass to hydrogen plant and a steam meth-ane reforming plant

There is a $003 to $011 premium on hydrogen produced bythe proposed hybrid system compared with a nonhybrid biomassto hydrogen gasification plant The additional capital costs of the

sinking hybridization are not fully offset by additional revenue inany of the locations studied However the marginal costs foundare small enough that it is difficult to draw any definitive conclu-sion Areas with lower cost electricity move this hybridizationcloser to economic feasibility with the best results found in theNorthwest

Because the premium is small (about 5) it may be acceptablein the long term Recent studies have shown that there is inherentvalue added or welfare effects for electricity storage capacity[36] Whether similar value is added by the proposed sinkinghybrid is unknown A more likely parallel would be the idea ofldquointerruptible customersrdquo which get discounted electricity rates inreturn for intermittent power supply A similar contractual agree-ment could be envisioned for the proposed hybrid where dis-counted electricity rates would be provided in return forintermittent demand

The proposed system is not a direct competitor with storagesystems such as pumped hydroelectric or compressed air energystorage (CAES) Energy storage systems attempt to profit by mar-ket arbitrage (selling electricity back to the grid at a higher pricethan it was bought) whereas the proposed hybrid system sinkscheap electricity into transportation fuel Sinking low cost elec-tricity into fuel could be considered cross-market arbitrage andthe most similar system to this would be electrolysis Comparedto electrolysis the proposed system is significantly less expensiveand has the added benefit of running without electric heat whenelectricity costs are too high

Assuming that all sinking electricity is renewable and takingthe additional differences in carbon emissions into account avalue of $26ndash32 per metric ton of CO2e makes the proposedhybrid cost competitive depending on the location of the system

Fig 5 Peaking system sensitivity (NE ISO)

Table 10 Sinking system H2A inputs

NE ISO MISO NW Int

Plant capacity factor 90 90 90Sinking duty 20 20 20Sinking electricity cost (cent=kW h) 435 220 218Utility electricity cost (cent=kW h) 705 487 469Utility natural gas cost ($=nm3) 032 032 032Cost of biomass ($=ton) 4883 4883 4883

Table 11 Indirect sinking system results

$=kg H2 NE ISO MISO NW Int

SMR 140 140 140Biomass to hydrogen baseline 164 164 164Electric air heater hybrid system 175 167 168

031801-8 Vol 133 SEPTEMBER 2011 Transactions of the ASME

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

At $27 per metric ton of CO2e the combustion air-heater hybrid-ization becomes cost competitive with a methane steam reformingplant in the Northwest assuming both the hybrid plant and SMRplant are subject to the same natural gas cost

In order to characterize the effect of various technical and eco-nomic assumptions a sensitivity analysis was performed for thesinking systems (Fig 6) The sensitivity analysis shows that capi-tal costs the cost of biomass and the plant capacity factor for arethe key inputs Capital costs when varied 630 cause the cost ofhydrogen to vary $018 The cost of biomass was varied from $40per ton to $60 per ton and causes the cost of hydrogen to vary byless than $015 Changes in the sinking duty the added hydrogenproduction due to sinking the cost of natural gas and the cost ofelectricity cause hydrogen costs to vary less than 3

From the sinking duty sensitivity analysis it appears that anincreased sinking duty would be preferable to the 20 assumptionmade Minimum hydrogen production prices occur when the elec-tric heating systems are run approximately 40 of the time Run-ning the electric heaters for more time increases plant hydrogenproduction and decreases plant green house gas emissions

The proposed directly heated gasifier hybrid system replacesthe ASU with an electrolyzer bank An H2A analysis was com-pleted to determine the baseline cost of hydrogen produced by adirectly heated gasification plant that uses electrolysis regardlessof electricity cost and the cost of hydrogen for a directly heatedgasification plant that uses a traditional ASU Table 12 summa-rizes the major model inputs The plant was assumed to be locatedin the Midwest ISO region The results of the analysis along withthe associated carbon emissions are listed in Table 13 Costs forproduction of hydrogen via SMR and for an electrolysis plantonly are also shown for reference purposes

As shown in Table 13 hydrogen produced by a direct gasifier-electrolyzer hybrid plant is significantly more expensive than thatproduced by SMR Electricity costs account for 37 of the overallcost of hydrogen produced (or about $086) Therefore if the costof electricity could be halved by intermittent operation during off-peak hours the savings would bring the cost of hydrogen to $189per kilogram of hydrogen At this price the hybrid system couldcompete with hydrogen produced by a standard direct gasificationplant It is important to note that these costs are approximately15 higher than the $164 per kilogram of hydrogen estimated forthe indirectly heated baseline gasification plant used for compari-son of the indirect hybrid analysis (see Table 11)

The original concept called for the electrolyzer bank to bedirectly coupled with stranded wind resources Typical capacityfactors for wind-generated power are in the 30ndash35 range [37]The effect of intermittent operation on the cost of hydrogen pro-duction was investigated using electrolyzer duties of 20 35and 50 The smaller the duty the larger the number electrolyz-ers needed to produce the same amount of oxygen per year

The effect of reduced electrolyzer duty on the cost of hydrogenis shown in Fig 7 Two curves are plotted The first assumes aconstant electricity price of $433=MWh regardless of the electro-lyzer duty This assumption would represent the scenario if theelectrolyzers were directly coupled with a stranded wind resourceThe second curve uses Midwest ISO market data so that the costof electricity fluctuates with duty These numbers do not considerthe cost of oxygen storage as these costs are assumed small com-pared to the increased electrolyzer capital costs and are identicalfor similar duty

Intermittent operation significantly adds to plant capital costsIf the price of electricity available to the plant does not decrease

Fig 6 Sinking system sensitivity (NW Int)

Table 12 Direct system H2A inputs

MISO

Electrolyzer duty () 100Utility electricity cost (cent=kW h) 433Cost of biomass ($=ton) 4883

Table 13 Direct system results

$=kg H2 Net CO2e=kg H2

SMR $140 68Biomass gasification $213 196Electrolysis $259 145 (178)Electrolysisthorn gasification $232 024 (182)

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-9

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

with intermittent electrolyzer operation then the cost of hydrogenincreases by 22 for a 35 duty However if the cost of electric-ity can be reduced by intermittent operation then the analysisshows that intermittent operation may be preferable to 100 dutyThis result means that the initial concept of capturing strandedresources is less favorable economically than a grid-connectedsinking system

If grid electricity is used then carbon emissions actuallyincrease relative to biomass gasification alone for this hybridiza-tion If upstream emissions for electricity production are takeninto account electrolysis and this proposed hybrid are both netCO2e emitters This makes their justification by carbon valueimpossible unless only renewable electricity is used for operation(renewable energy values are shown in parentheses in Table 13)Since renewable wind energy is inherently intermittent it isunreasonable to assume renewable electricity is used without add-ing the necessary equipment for intermittent operation Onerenewable energy exception would be the use of hydroelectricpower for the systems

Similar to the other hybrid systems investigated hybridizationresults in a price premium There must be some additional justifi-cation for hybridization such as utility demands The baseline bio-mass to hydrogen case with an ASU requires only $35 per metricton of CO2e to be cost competitive with SMR produced hydrogen

assuming both the hybrid plant and SMR plant are subject to thesame natural gas cost at a given location

Electrolyzer-based hybrid system economics are extremely sen-sitive to the cost of electricity (Fig 8) Fluctuations of $001 inthe cost of electricity cause the price of hydrogen to fluctuatemore than $025 per kilogram If the price of electricity were todrop below $004=kW h then the proposed hybrid system couldeconomically compete with a nonhybrid biomass to hydrogenplant However this low price level is unlikely and any energymarket fluctuations would have a dramatic effect on economicviability

Conclusion

The two hybrid concepts analyzed involve coproduction of gase-ous hydrogen and electric power from thermochemical-based biorefi-neries Both of the concepts analyzed share the basic idea ofcombining intermittent wind-generated electricity with a biomassgasification plant Wind availability overlaps biomass resource avail-ability in three areas of the United States making the use of locallyproduced wind electricity for gasification feasible The proposedhybrid systems attempt to either fill wind energy shortfalls by burn-ing syngas in a natural gas turbine or absorb excess renewable powerduring times of low-electricity demand

None of the proposed hybrid systems produced hydrogen forless than a nonhybrid plant could In all cases a premium was paidfor hybridization that could not be offset by the increasedfunctionality

The indirectly heated gasifier hybrid system consists of twoparts (1) producing peaking electricity intermittently with a gasturbine and (2) sinking electricity into electric heaters intermit-tently to boost fuel production efficiency Each of these parts wasanalyzed separately The indirectly heated gasifier hybrid systemis meant to be grid-connected and provide peaking electricity anddispatchable demand (eg an on demand load) to the local utilityto help manage intermittent wind resources

The indirect gasification concepts studied could be cost compet-itive in the near future as value is placed on controlling carbonemissions Carbon values of just under $40 per metric ton ofCO2e make the systems studied cost competitive with steam

Fig 7 Electrolyzer duty versus cost

Fig 8 Direct system sensitivity

031801-10 Vol 133 SEPTEMBER 2011 Transactions of the ASME

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

methane reforming to produce hydrogen However a nonhybridbiomass to hydrogen plant will be more cost competitive in gen-eral so there must be additional operational value placed on peak-ing or sinking for these plants to be economically attractive Thisadditional value is likely to become a reality as additional inter-mittent renewable energy sources such as wind are added to thenational grid

The directly heated gasifier hybrid system involves replacementof the air separation unit with electrolyzers This change allowsfor extra production of hydrogen and intermittent operation Theanalysis for this system assumed direct replacement of the ASUwithout intermittent operation Estimates of the effect of intermit-tent operation on plant economics were made The electrolyzerbank could be either grid-connected to provide a dispatchabledemand to the utility or it could be tied directly to a stranded windsource to convert wind into chemical fuel (H2)

The direct gasification concept studied is unlikely to be cost com-petitive in the near future but may eventually be attractive withlower-cost electrolysis and a smaller biorefinery plant size that issized for a specific hydrogen demand Intermittent operation andstranded operation were found to have worse economics than grid-connected systems High electrolyzer capital costs make the possibleelectricity cost savings of intermittent operation difficult to justifyBased on a direct replacement of the ASU with electrolyzers hydro-gen can be produced for $232 per kilogram However using gridelectricity the hybrid system is a net CO2e emitter For the use ofelectrolysis to make sense in this setting there must be a significantbenefit to the ability to operate intermittently

Acknowledgment

The authors would also like to acknowledge Dr Bob Evans forconceiving the hybrid hydrogen production systems project andDonna Heimiller for performing the GIS mapping

Employees of the Alliance for Sustainable Energy LLC underContract No DE-AC36-08GO28308 with the US Dept ofEnergy have authored this work The United States Governmentretains and the publisher by accepting the article for publicationacknowledges that the United States Government retains a nonex-clusive paid-up irrevocable worldwide license to publish orreproduce the published form of this work or allow others to doso for United States Government purposes

References[1] Milbrandt A 2005 ldquoA Geographic Perspective on the Current Biomass

Resource Availability in the United Statesrdquo National Renewable Energy LabReport No TP-560-39181

[2] Perlack R Wright L Turhollow A Graham R Stokes B and Erbach D2005 Biomass as Feedstock for a Bioenergy and Bioproducts Industry The Tech-nical Feasibility of a Billion-Ton Annual Supply Oak Ridge National LaboratoryOak 853 Ridge TN

[3] Turner J Sverdrup G Mann M Maness P C Kroposki B Ghirardi MEvans J and Blake D 2008 ldquoRenewable Hydrogen Productionrdquo Int JEnergy Res 32 pp 379ndash407

[4] US Department of Energy Energy Efficiency and Renewable Energy Labora-tory 2008 ldquo20 Wind Energy by 2030mdashIncreasing Wind Energyrsquos Contribu-tion to US Electricity Supplyrdquo Report No GO-102008-2567

[5] Levene J Kroposki B and Sverdrup G 2006 ldquoWind Energy and Productionof Hydrogen and ElectricityndashOpportunities for Renewable Hydrogenrdquo NationalRenewable Energy Laboratory Report No CP560-39534

[6] Fingersh L 2004 ldquoOptimization of Utility-Scale Wind-Hydrogen-BatterySystemsrdquo National Renewable Energy Laboratory Report No CP-500-36117

[7] Dean J Braun R Munoz D Penev M and Kinchin C 2010 ldquoAnalysis ofHybrid Hydrogen Systems ndash Final Reportrdquo National Renewable Energy Labo-ratory Report No TP-46934

[8] Gasification Technology Status ndash December 2006 EPRI and the Gasification869 Users Association Palo Alto CA p 1012224

[9] Spath P Aden A Eggeman T Ringer M Wallace B and Jechura J2005 ldquoBiomass to Hydrogen Production Detailed Design and Economics Uti-lizing the Battelle Columbus Laboratory Indirectly-Heated Gasifierrdquo NationalRenewable Energy Laboratory Report No TP-510-37408

[10] Dean J 2010 ldquoLeveling Intermittent Renewable Energy Production ThroughBiomass Gasification-based Hybrid Systemsrdquo MS thesis Colorado School ofMines Golden CO

[11] Devi L Ptasinski K Janssen F van Paasen S Bergman P and Kiel J2005 ldquoCatalytic Decomposition of Biomass Tars Use of Dolomite anUntreated Olivinerdquo Renewable Energy 30 pp 565ndash587

[12] Heavy Duty Gas Turbine Products 2009 General Electric Company FairfieldCT

[13] Drdar D and Jones R 2000 ldquoGE IGCC Technology and Experience withAdvanced Gas Turbinesrdquo GE Power Systems Report No GER-4207

[14] Craig K and Mann M 1996 ldquoCost and Performance Analysis of Biomass-Based Integrated Gasification Combined-Cycle (BIGCC) Power SystemsrdquoNational Renewable Energy Laboratory Report No TP-430-21657

[15] Gas Turbine World 2006 Handbook (Pequot Publishing Inc Fairfield CT2006)

[16] Kinchin C and Bain R 2009 ldquoHydrogen Production from Biomass via Indi-rect Gasification The Impact of NREL Process Development Unit GasifierCorrelationsrdquo National Renewable Energy Laboratory Report No TP-510-44868

[17] Watlow for 22 MW duct heaters Watlow 12001 Lackland Road St LouisMO 63146 personal communication 2009

[18] Gassner M and Marechal F 2008 ldquoThermo-economic Optimization of theIntegration of Electrolysis in Synthetic Natural Gas Production from WoodrdquoEnergy 33 pp 189ndash198

[19] Srinivas T Gupta A V S and Reddy B V 2009 ldquoThermodynamic Equi-librium Model and Exergy Analysis of a Biomass Gasifierrdquo ASME J EnergyResour Technol 131 031801 pp 1ndash7

[20] Braun R J Hanzon L G and Dean J H 2011 ldquoSystem Analysis of Ther-mochemical-based Biorefineries for Coproduction of Hydrogen and Elec-tricityrdquo ASME J Energy Resour Technol 133 012601 pp 1ndash12

[21] Manning F and Thompson R 1991 Oilfield Processing of Petroleum Vol-ume One 904 Natural Gas PennWell Publishing Co Tulsa Oklahoma

[22] StatoilHydro 2009 ldquoHydrogen Technologies World Leader in Electrolysis forHydrogen Solutionsrdquo product brochure Hydrogen Technologies NO-3674Notodden Norway COS 091408 available URL http908wwwelectrolyserscom

[23] US Department of Energy Hydrogen Program 2009 ldquoFuture Central Hydro-gen Production from Grid Electrolysisrdquo H2A analysis wwwhydrogenenergygovh2a_prod_studieshtml

[24] Phyllis Biomass Datapage ldquowood hybrid poplarrdquo ID 806 available URLhttpwwwecnnlphyllis

[25] Jin H Larson E and Celik F 2009 ldquoPerformance and Cost Analysis ofFuture Commercially Mature Gasification-Based Electric Power GenerationFrom Switchgrassrdquo Biofpr 3 pp 142ndash173

[26] Department of Energy 2007 ldquoCost and Performance Baseline for Fossil EnergyPlants Volume 1 Bituminous Coal and Natural Gas to Electricityrdquo Report NoDOE=NETL-2007=1281

[27] US Department of Energy Hydrogen Program 2009 ldquoDOE H2A Analy-sisrdquo wwwhydrogenenergygovh2a_analysishtml

[28] US Department of Energy Hydrogen Program 2009 ldquoFuture Central Hydro-gen Production from Natural Gas with CO2 Sequestrationrdquo H2A analysiswwwhydrogenenergygovh2a_prod_studieshtml

[29] Energy Information Administration Annual Energy Outlook 2009 wwweiadoegovoiafaeoelectricityhtml

[30] Schafer A Heywood J and Weiss M 2006 ldquoFuture Fuel Cell and InternalCombustion Engine Automobile Technologies A 25-Year Life Cycle and FleetImpact Assessmentrdquo Energy 31 pp 2064ndash2087

[31] NE ISO 2009 ldquoEnergy Sources in New Englandrdquo wwwiso-necomnwsissgrid_mktsenrgy_srcs

[32] Doying R 2009 Midwest ISO ldquoJune Monthly Reportrdquo wwwmidwestisoorg[33] PacifiCorp 2009 ldquoIntegrated Resource Plan ndash Volume 1rdquo May 29 2009

wwwpaci-937ficorpcom[34] Frank Novachek 2009 Xcel Energy 414 Nicollet Mall Minneapolis MN

55401 939 personal communication[35] Energy Efficiency and Renewable Energy Department of Energy ldquoBiomass

2009 Multi-Year Research Development and Demonstration Planrdquo www1eer-eenergygovbiomasspdfsmypp_may2009pdf

[36] Sioshansi R Denholm P Jenkin T and Weiss J 2009 ldquoEstimating theValue of Electricity Storage in PJM Arbitrage and Some Welfare EffectrdquoEnergy Econ 31 pp 269ndash277

[37] Kroposki B Levene J Harrison K Sen P K and Novachek F 2006ldquoElectrolysis Information and Opportunities for Electric Power UtilitiesrdquoNational Renewable Energy Laboratory Report No TP-581-40

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-11

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

At $27 per metric ton of CO2e the combustion air-heater hybrid-ization becomes cost competitive with a methane steam reformingplant in the Northwest assuming both the hybrid plant and SMRplant are subject to the same natural gas cost

In order to characterize the effect of various technical and eco-nomic assumptions a sensitivity analysis was performed for thesinking systems (Fig 6) The sensitivity analysis shows that capi-tal costs the cost of biomass and the plant capacity factor for arethe key inputs Capital costs when varied 630 cause the cost ofhydrogen to vary $018 The cost of biomass was varied from $40per ton to $60 per ton and causes the cost of hydrogen to vary byless than $015 Changes in the sinking duty the added hydrogenproduction due to sinking the cost of natural gas and the cost ofelectricity cause hydrogen costs to vary less than 3

From the sinking duty sensitivity analysis it appears that anincreased sinking duty would be preferable to the 20 assumptionmade Minimum hydrogen production prices occur when the elec-tric heating systems are run approximately 40 of the time Run-ning the electric heaters for more time increases plant hydrogenproduction and decreases plant green house gas emissions

The proposed directly heated gasifier hybrid system replacesthe ASU with an electrolyzer bank An H2A analysis was com-pleted to determine the baseline cost of hydrogen produced by adirectly heated gasification plant that uses electrolysis regardlessof electricity cost and the cost of hydrogen for a directly heatedgasification plant that uses a traditional ASU Table 12 summa-rizes the major model inputs The plant was assumed to be locatedin the Midwest ISO region The results of the analysis along withthe associated carbon emissions are listed in Table 13 Costs forproduction of hydrogen via SMR and for an electrolysis plantonly are also shown for reference purposes

As shown in Table 13 hydrogen produced by a direct gasifier-electrolyzer hybrid plant is significantly more expensive than thatproduced by SMR Electricity costs account for 37 of the overallcost of hydrogen produced (or about $086) Therefore if the costof electricity could be halved by intermittent operation during off-peak hours the savings would bring the cost of hydrogen to $189per kilogram of hydrogen At this price the hybrid system couldcompete with hydrogen produced by a standard direct gasificationplant It is important to note that these costs are approximately15 higher than the $164 per kilogram of hydrogen estimated forthe indirectly heated baseline gasification plant used for compari-son of the indirect hybrid analysis (see Table 11)

The original concept called for the electrolyzer bank to bedirectly coupled with stranded wind resources Typical capacityfactors for wind-generated power are in the 30ndash35 range [37]The effect of intermittent operation on the cost of hydrogen pro-duction was investigated using electrolyzer duties of 20 35and 50 The smaller the duty the larger the number electrolyz-ers needed to produce the same amount of oxygen per year

The effect of reduced electrolyzer duty on the cost of hydrogenis shown in Fig 7 Two curves are plotted The first assumes aconstant electricity price of $433=MWh regardless of the electro-lyzer duty This assumption would represent the scenario if theelectrolyzers were directly coupled with a stranded wind resourceThe second curve uses Midwest ISO market data so that the costof electricity fluctuates with duty These numbers do not considerthe cost of oxygen storage as these costs are assumed small com-pared to the increased electrolyzer capital costs and are identicalfor similar duty

Intermittent operation significantly adds to plant capital costsIf the price of electricity available to the plant does not decrease

Fig 6 Sinking system sensitivity (NW Int)

Table 12 Direct system H2A inputs

MISO

Electrolyzer duty () 100Utility electricity cost (cent=kW h) 433Cost of biomass ($=ton) 4883

Table 13 Direct system results

$=kg H2 Net CO2e=kg H2

SMR $140 68Biomass gasification $213 196Electrolysis $259 145 (178)Electrolysisthorn gasification $232 024 (182)

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-9

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

with intermittent electrolyzer operation then the cost of hydrogenincreases by 22 for a 35 duty However if the cost of electric-ity can be reduced by intermittent operation then the analysisshows that intermittent operation may be preferable to 100 dutyThis result means that the initial concept of capturing strandedresources is less favorable economically than a grid-connectedsinking system

If grid electricity is used then carbon emissions actuallyincrease relative to biomass gasification alone for this hybridiza-tion If upstream emissions for electricity production are takeninto account electrolysis and this proposed hybrid are both netCO2e emitters This makes their justification by carbon valueimpossible unless only renewable electricity is used for operation(renewable energy values are shown in parentheses in Table 13)Since renewable wind energy is inherently intermittent it isunreasonable to assume renewable electricity is used without add-ing the necessary equipment for intermittent operation Onerenewable energy exception would be the use of hydroelectricpower for the systems

Similar to the other hybrid systems investigated hybridizationresults in a price premium There must be some additional justifi-cation for hybridization such as utility demands The baseline bio-mass to hydrogen case with an ASU requires only $35 per metricton of CO2e to be cost competitive with SMR produced hydrogen

assuming both the hybrid plant and SMR plant are subject to thesame natural gas cost at a given location

Electrolyzer-based hybrid system economics are extremely sen-sitive to the cost of electricity (Fig 8) Fluctuations of $001 inthe cost of electricity cause the price of hydrogen to fluctuatemore than $025 per kilogram If the price of electricity were todrop below $004=kW h then the proposed hybrid system couldeconomically compete with a nonhybrid biomass to hydrogenplant However this low price level is unlikely and any energymarket fluctuations would have a dramatic effect on economicviability

Conclusion

The two hybrid concepts analyzed involve coproduction of gase-ous hydrogen and electric power from thermochemical-based biorefi-neries Both of the concepts analyzed share the basic idea ofcombining intermittent wind-generated electricity with a biomassgasification plant Wind availability overlaps biomass resource avail-ability in three areas of the United States making the use of locallyproduced wind electricity for gasification feasible The proposedhybrid systems attempt to either fill wind energy shortfalls by burn-ing syngas in a natural gas turbine or absorb excess renewable powerduring times of low-electricity demand

None of the proposed hybrid systems produced hydrogen forless than a nonhybrid plant could In all cases a premium was paidfor hybridization that could not be offset by the increasedfunctionality

The indirectly heated gasifier hybrid system consists of twoparts (1) producing peaking electricity intermittently with a gasturbine and (2) sinking electricity into electric heaters intermit-tently to boost fuel production efficiency Each of these parts wasanalyzed separately The indirectly heated gasifier hybrid systemis meant to be grid-connected and provide peaking electricity anddispatchable demand (eg an on demand load) to the local utilityto help manage intermittent wind resources

The indirect gasification concepts studied could be cost compet-itive in the near future as value is placed on controlling carbonemissions Carbon values of just under $40 per metric ton ofCO2e make the systems studied cost competitive with steam

Fig 7 Electrolyzer duty versus cost

Fig 8 Direct system sensitivity

031801-10 Vol 133 SEPTEMBER 2011 Transactions of the ASME

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

methane reforming to produce hydrogen However a nonhybridbiomass to hydrogen plant will be more cost competitive in gen-eral so there must be additional operational value placed on peak-ing or sinking for these plants to be economically attractive Thisadditional value is likely to become a reality as additional inter-mittent renewable energy sources such as wind are added to thenational grid

The directly heated gasifier hybrid system involves replacementof the air separation unit with electrolyzers This change allowsfor extra production of hydrogen and intermittent operation Theanalysis for this system assumed direct replacement of the ASUwithout intermittent operation Estimates of the effect of intermit-tent operation on plant economics were made The electrolyzerbank could be either grid-connected to provide a dispatchabledemand to the utility or it could be tied directly to a stranded windsource to convert wind into chemical fuel (H2)

The direct gasification concept studied is unlikely to be cost com-petitive in the near future but may eventually be attractive withlower-cost electrolysis and a smaller biorefinery plant size that issized for a specific hydrogen demand Intermittent operation andstranded operation were found to have worse economics than grid-connected systems High electrolyzer capital costs make the possibleelectricity cost savings of intermittent operation difficult to justifyBased on a direct replacement of the ASU with electrolyzers hydro-gen can be produced for $232 per kilogram However using gridelectricity the hybrid system is a net CO2e emitter For the use ofelectrolysis to make sense in this setting there must be a significantbenefit to the ability to operate intermittently

Acknowledgment

The authors would also like to acknowledge Dr Bob Evans forconceiving the hybrid hydrogen production systems project andDonna Heimiller for performing the GIS mapping

Employees of the Alliance for Sustainable Energy LLC underContract No DE-AC36-08GO28308 with the US Dept ofEnergy have authored this work The United States Governmentretains and the publisher by accepting the article for publicationacknowledges that the United States Government retains a nonex-clusive paid-up irrevocable worldwide license to publish orreproduce the published form of this work or allow others to doso for United States Government purposes

References[1] Milbrandt A 2005 ldquoA Geographic Perspective on the Current Biomass

Resource Availability in the United Statesrdquo National Renewable Energy LabReport No TP-560-39181

[2] Perlack R Wright L Turhollow A Graham R Stokes B and Erbach D2005 Biomass as Feedstock for a Bioenergy and Bioproducts Industry The Tech-nical Feasibility of a Billion-Ton Annual Supply Oak Ridge National LaboratoryOak 853 Ridge TN

[3] Turner J Sverdrup G Mann M Maness P C Kroposki B Ghirardi MEvans J and Blake D 2008 ldquoRenewable Hydrogen Productionrdquo Int JEnergy Res 32 pp 379ndash407

[4] US Department of Energy Energy Efficiency and Renewable Energy Labora-tory 2008 ldquo20 Wind Energy by 2030mdashIncreasing Wind Energyrsquos Contribu-tion to US Electricity Supplyrdquo Report No GO-102008-2567

[5] Levene J Kroposki B and Sverdrup G 2006 ldquoWind Energy and Productionof Hydrogen and ElectricityndashOpportunities for Renewable Hydrogenrdquo NationalRenewable Energy Laboratory Report No CP560-39534

[6] Fingersh L 2004 ldquoOptimization of Utility-Scale Wind-Hydrogen-BatterySystemsrdquo National Renewable Energy Laboratory Report No CP-500-36117

[7] Dean J Braun R Munoz D Penev M and Kinchin C 2010 ldquoAnalysis ofHybrid Hydrogen Systems ndash Final Reportrdquo National Renewable Energy Labo-ratory Report No TP-46934

[8] Gasification Technology Status ndash December 2006 EPRI and the Gasification869 Users Association Palo Alto CA p 1012224

[9] Spath P Aden A Eggeman T Ringer M Wallace B and Jechura J2005 ldquoBiomass to Hydrogen Production Detailed Design and Economics Uti-lizing the Battelle Columbus Laboratory Indirectly-Heated Gasifierrdquo NationalRenewable Energy Laboratory Report No TP-510-37408

[10] Dean J 2010 ldquoLeveling Intermittent Renewable Energy Production ThroughBiomass Gasification-based Hybrid Systemsrdquo MS thesis Colorado School ofMines Golden CO

[11] Devi L Ptasinski K Janssen F van Paasen S Bergman P and Kiel J2005 ldquoCatalytic Decomposition of Biomass Tars Use of Dolomite anUntreated Olivinerdquo Renewable Energy 30 pp 565ndash587

[12] Heavy Duty Gas Turbine Products 2009 General Electric Company FairfieldCT

[13] Drdar D and Jones R 2000 ldquoGE IGCC Technology and Experience withAdvanced Gas Turbinesrdquo GE Power Systems Report No GER-4207

[14] Craig K and Mann M 1996 ldquoCost and Performance Analysis of Biomass-Based Integrated Gasification Combined-Cycle (BIGCC) Power SystemsrdquoNational Renewable Energy Laboratory Report No TP-430-21657

[15] Gas Turbine World 2006 Handbook (Pequot Publishing Inc Fairfield CT2006)

[16] Kinchin C and Bain R 2009 ldquoHydrogen Production from Biomass via Indi-rect Gasification The Impact of NREL Process Development Unit GasifierCorrelationsrdquo National Renewable Energy Laboratory Report No TP-510-44868

[17] Watlow for 22 MW duct heaters Watlow 12001 Lackland Road St LouisMO 63146 personal communication 2009

[18] Gassner M and Marechal F 2008 ldquoThermo-economic Optimization of theIntegration of Electrolysis in Synthetic Natural Gas Production from WoodrdquoEnergy 33 pp 189ndash198

[19] Srinivas T Gupta A V S and Reddy B V 2009 ldquoThermodynamic Equi-librium Model and Exergy Analysis of a Biomass Gasifierrdquo ASME J EnergyResour Technol 131 031801 pp 1ndash7

[20] Braun R J Hanzon L G and Dean J H 2011 ldquoSystem Analysis of Ther-mochemical-based Biorefineries for Coproduction of Hydrogen and Elec-tricityrdquo ASME J Energy Resour Technol 133 012601 pp 1ndash12

[21] Manning F and Thompson R 1991 Oilfield Processing of Petroleum Vol-ume One 904 Natural Gas PennWell Publishing Co Tulsa Oklahoma

[22] StatoilHydro 2009 ldquoHydrogen Technologies World Leader in Electrolysis forHydrogen Solutionsrdquo product brochure Hydrogen Technologies NO-3674Notodden Norway COS 091408 available URL http908wwwelectrolyserscom

[23] US Department of Energy Hydrogen Program 2009 ldquoFuture Central Hydro-gen Production from Grid Electrolysisrdquo H2A analysis wwwhydrogenenergygovh2a_prod_studieshtml

[24] Phyllis Biomass Datapage ldquowood hybrid poplarrdquo ID 806 available URLhttpwwwecnnlphyllis

[25] Jin H Larson E and Celik F 2009 ldquoPerformance and Cost Analysis ofFuture Commercially Mature Gasification-Based Electric Power GenerationFrom Switchgrassrdquo Biofpr 3 pp 142ndash173

[26] Department of Energy 2007 ldquoCost and Performance Baseline for Fossil EnergyPlants Volume 1 Bituminous Coal and Natural Gas to Electricityrdquo Report NoDOE=NETL-2007=1281

[27] US Department of Energy Hydrogen Program 2009 ldquoDOE H2A Analy-sisrdquo wwwhydrogenenergygovh2a_analysishtml

[28] US Department of Energy Hydrogen Program 2009 ldquoFuture Central Hydro-gen Production from Natural Gas with CO2 Sequestrationrdquo H2A analysiswwwhydrogenenergygovh2a_prod_studieshtml

[29] Energy Information Administration Annual Energy Outlook 2009 wwweiadoegovoiafaeoelectricityhtml

[30] Schafer A Heywood J and Weiss M 2006 ldquoFuture Fuel Cell and InternalCombustion Engine Automobile Technologies A 25-Year Life Cycle and FleetImpact Assessmentrdquo Energy 31 pp 2064ndash2087

[31] NE ISO 2009 ldquoEnergy Sources in New Englandrdquo wwwiso-necomnwsissgrid_mktsenrgy_srcs

[32] Doying R 2009 Midwest ISO ldquoJune Monthly Reportrdquo wwwmidwestisoorg[33] PacifiCorp 2009 ldquoIntegrated Resource Plan ndash Volume 1rdquo May 29 2009

wwwpaci-937ficorpcom[34] Frank Novachek 2009 Xcel Energy 414 Nicollet Mall Minneapolis MN

55401 939 personal communication[35] Energy Efficiency and Renewable Energy Department of Energy ldquoBiomass

2009 Multi-Year Research Development and Demonstration Planrdquo www1eer-eenergygovbiomasspdfsmypp_may2009pdf

[36] Sioshansi R Denholm P Jenkin T and Weiss J 2009 ldquoEstimating theValue of Electricity Storage in PJM Arbitrage and Some Welfare EffectrdquoEnergy Econ 31 pp 269ndash277

[37] Kroposki B Levene J Harrison K Sen P K and Novachek F 2006ldquoElectrolysis Information and Opportunities for Electric Power UtilitiesrdquoNational Renewable Energy Laboratory Report No TP-581-40

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-11

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

with intermittent electrolyzer operation then the cost of hydrogenincreases by 22 for a 35 duty However if the cost of electric-ity can be reduced by intermittent operation then the analysisshows that intermittent operation may be preferable to 100 dutyThis result means that the initial concept of capturing strandedresources is less favorable economically than a grid-connectedsinking system

If grid electricity is used then carbon emissions actuallyincrease relative to biomass gasification alone for this hybridiza-tion If upstream emissions for electricity production are takeninto account electrolysis and this proposed hybrid are both netCO2e emitters This makes their justification by carbon valueimpossible unless only renewable electricity is used for operation(renewable energy values are shown in parentheses in Table 13)Since renewable wind energy is inherently intermittent it isunreasonable to assume renewable electricity is used without add-ing the necessary equipment for intermittent operation Onerenewable energy exception would be the use of hydroelectricpower for the systems

Similar to the other hybrid systems investigated hybridizationresults in a price premium There must be some additional justifi-cation for hybridization such as utility demands The baseline bio-mass to hydrogen case with an ASU requires only $35 per metricton of CO2e to be cost competitive with SMR produced hydrogen

assuming both the hybrid plant and SMR plant are subject to thesame natural gas cost at a given location

Electrolyzer-based hybrid system economics are extremely sen-sitive to the cost of electricity (Fig 8) Fluctuations of $001 inthe cost of electricity cause the price of hydrogen to fluctuatemore than $025 per kilogram If the price of electricity were todrop below $004=kW h then the proposed hybrid system couldeconomically compete with a nonhybrid biomass to hydrogenplant However this low price level is unlikely and any energymarket fluctuations would have a dramatic effect on economicviability

Conclusion

The two hybrid concepts analyzed involve coproduction of gase-ous hydrogen and electric power from thermochemical-based biorefi-neries Both of the concepts analyzed share the basic idea ofcombining intermittent wind-generated electricity with a biomassgasification plant Wind availability overlaps biomass resource avail-ability in three areas of the United States making the use of locallyproduced wind electricity for gasification feasible The proposedhybrid systems attempt to either fill wind energy shortfalls by burn-ing syngas in a natural gas turbine or absorb excess renewable powerduring times of low-electricity demand

None of the proposed hybrid systems produced hydrogen forless than a nonhybrid plant could In all cases a premium was paidfor hybridization that could not be offset by the increasedfunctionality

The indirectly heated gasifier hybrid system consists of twoparts (1) producing peaking electricity intermittently with a gasturbine and (2) sinking electricity into electric heaters intermit-tently to boost fuel production efficiency Each of these parts wasanalyzed separately The indirectly heated gasifier hybrid systemis meant to be grid-connected and provide peaking electricity anddispatchable demand (eg an on demand load) to the local utilityto help manage intermittent wind resources

The indirect gasification concepts studied could be cost compet-itive in the near future as value is placed on controlling carbonemissions Carbon values of just under $40 per metric ton ofCO2e make the systems studied cost competitive with steam

Fig 7 Electrolyzer duty versus cost

Fig 8 Direct system sensitivity

031801-10 Vol 133 SEPTEMBER 2011 Transactions of the ASME

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

methane reforming to produce hydrogen However a nonhybridbiomass to hydrogen plant will be more cost competitive in gen-eral so there must be additional operational value placed on peak-ing or sinking for these plants to be economically attractive Thisadditional value is likely to become a reality as additional inter-mittent renewable energy sources such as wind are added to thenational grid

The directly heated gasifier hybrid system involves replacementof the air separation unit with electrolyzers This change allowsfor extra production of hydrogen and intermittent operation Theanalysis for this system assumed direct replacement of the ASUwithout intermittent operation Estimates of the effect of intermit-tent operation on plant economics were made The electrolyzerbank could be either grid-connected to provide a dispatchabledemand to the utility or it could be tied directly to a stranded windsource to convert wind into chemical fuel (H2)

The direct gasification concept studied is unlikely to be cost com-petitive in the near future but may eventually be attractive withlower-cost electrolysis and a smaller biorefinery plant size that issized for a specific hydrogen demand Intermittent operation andstranded operation were found to have worse economics than grid-connected systems High electrolyzer capital costs make the possibleelectricity cost savings of intermittent operation difficult to justifyBased on a direct replacement of the ASU with electrolyzers hydro-gen can be produced for $232 per kilogram However using gridelectricity the hybrid system is a net CO2e emitter For the use ofelectrolysis to make sense in this setting there must be a significantbenefit to the ability to operate intermittently

Acknowledgment

The authors would also like to acknowledge Dr Bob Evans forconceiving the hybrid hydrogen production systems project andDonna Heimiller for performing the GIS mapping

Employees of the Alliance for Sustainable Energy LLC underContract No DE-AC36-08GO28308 with the US Dept ofEnergy have authored this work The United States Governmentretains and the publisher by accepting the article for publicationacknowledges that the United States Government retains a nonex-clusive paid-up irrevocable worldwide license to publish orreproduce the published form of this work or allow others to doso for United States Government purposes

References[1] Milbrandt A 2005 ldquoA Geographic Perspective on the Current Biomass

Resource Availability in the United Statesrdquo National Renewable Energy LabReport No TP-560-39181

[2] Perlack R Wright L Turhollow A Graham R Stokes B and Erbach D2005 Biomass as Feedstock for a Bioenergy and Bioproducts Industry The Tech-nical Feasibility of a Billion-Ton Annual Supply Oak Ridge National LaboratoryOak 853 Ridge TN

[3] Turner J Sverdrup G Mann M Maness P C Kroposki B Ghirardi MEvans J and Blake D 2008 ldquoRenewable Hydrogen Productionrdquo Int JEnergy Res 32 pp 379ndash407

[4] US Department of Energy Energy Efficiency and Renewable Energy Labora-tory 2008 ldquo20 Wind Energy by 2030mdashIncreasing Wind Energyrsquos Contribu-tion to US Electricity Supplyrdquo Report No GO-102008-2567

[5] Levene J Kroposki B and Sverdrup G 2006 ldquoWind Energy and Productionof Hydrogen and ElectricityndashOpportunities for Renewable Hydrogenrdquo NationalRenewable Energy Laboratory Report No CP560-39534

[6] Fingersh L 2004 ldquoOptimization of Utility-Scale Wind-Hydrogen-BatterySystemsrdquo National Renewable Energy Laboratory Report No CP-500-36117

[7] Dean J Braun R Munoz D Penev M and Kinchin C 2010 ldquoAnalysis ofHybrid Hydrogen Systems ndash Final Reportrdquo National Renewable Energy Labo-ratory Report No TP-46934

[8] Gasification Technology Status ndash December 2006 EPRI and the Gasification869 Users Association Palo Alto CA p 1012224

[9] Spath P Aden A Eggeman T Ringer M Wallace B and Jechura J2005 ldquoBiomass to Hydrogen Production Detailed Design and Economics Uti-lizing the Battelle Columbus Laboratory Indirectly-Heated Gasifierrdquo NationalRenewable Energy Laboratory Report No TP-510-37408

[10] Dean J 2010 ldquoLeveling Intermittent Renewable Energy Production ThroughBiomass Gasification-based Hybrid Systemsrdquo MS thesis Colorado School ofMines Golden CO

[11] Devi L Ptasinski K Janssen F van Paasen S Bergman P and Kiel J2005 ldquoCatalytic Decomposition of Biomass Tars Use of Dolomite anUntreated Olivinerdquo Renewable Energy 30 pp 565ndash587

[12] Heavy Duty Gas Turbine Products 2009 General Electric Company FairfieldCT

[13] Drdar D and Jones R 2000 ldquoGE IGCC Technology and Experience withAdvanced Gas Turbinesrdquo GE Power Systems Report No GER-4207

[14] Craig K and Mann M 1996 ldquoCost and Performance Analysis of Biomass-Based Integrated Gasification Combined-Cycle (BIGCC) Power SystemsrdquoNational Renewable Energy Laboratory Report No TP-430-21657

[15] Gas Turbine World 2006 Handbook (Pequot Publishing Inc Fairfield CT2006)

[16] Kinchin C and Bain R 2009 ldquoHydrogen Production from Biomass via Indi-rect Gasification The Impact of NREL Process Development Unit GasifierCorrelationsrdquo National Renewable Energy Laboratory Report No TP-510-44868

[17] Watlow for 22 MW duct heaters Watlow 12001 Lackland Road St LouisMO 63146 personal communication 2009

[18] Gassner M and Marechal F 2008 ldquoThermo-economic Optimization of theIntegration of Electrolysis in Synthetic Natural Gas Production from WoodrdquoEnergy 33 pp 189ndash198

[19] Srinivas T Gupta A V S and Reddy B V 2009 ldquoThermodynamic Equi-librium Model and Exergy Analysis of a Biomass Gasifierrdquo ASME J EnergyResour Technol 131 031801 pp 1ndash7

[20] Braun R J Hanzon L G and Dean J H 2011 ldquoSystem Analysis of Ther-mochemical-based Biorefineries for Coproduction of Hydrogen and Elec-tricityrdquo ASME J Energy Resour Technol 133 012601 pp 1ndash12

[21] Manning F and Thompson R 1991 Oilfield Processing of Petroleum Vol-ume One 904 Natural Gas PennWell Publishing Co Tulsa Oklahoma

[22] StatoilHydro 2009 ldquoHydrogen Technologies World Leader in Electrolysis forHydrogen Solutionsrdquo product brochure Hydrogen Technologies NO-3674Notodden Norway COS 091408 available URL http908wwwelectrolyserscom

[23] US Department of Energy Hydrogen Program 2009 ldquoFuture Central Hydro-gen Production from Grid Electrolysisrdquo H2A analysis wwwhydrogenenergygovh2a_prod_studieshtml

[24] Phyllis Biomass Datapage ldquowood hybrid poplarrdquo ID 806 available URLhttpwwwecnnlphyllis

[25] Jin H Larson E and Celik F 2009 ldquoPerformance and Cost Analysis ofFuture Commercially Mature Gasification-Based Electric Power GenerationFrom Switchgrassrdquo Biofpr 3 pp 142ndash173

[26] Department of Energy 2007 ldquoCost and Performance Baseline for Fossil EnergyPlants Volume 1 Bituminous Coal and Natural Gas to Electricityrdquo Report NoDOE=NETL-2007=1281

[27] US Department of Energy Hydrogen Program 2009 ldquoDOE H2A Analy-sisrdquo wwwhydrogenenergygovh2a_analysishtml

[28] US Department of Energy Hydrogen Program 2009 ldquoFuture Central Hydro-gen Production from Natural Gas with CO2 Sequestrationrdquo H2A analysiswwwhydrogenenergygovh2a_prod_studieshtml

[29] Energy Information Administration Annual Energy Outlook 2009 wwweiadoegovoiafaeoelectricityhtml

[30] Schafer A Heywood J and Weiss M 2006 ldquoFuture Fuel Cell and InternalCombustion Engine Automobile Technologies A 25-Year Life Cycle and FleetImpact Assessmentrdquo Energy 31 pp 2064ndash2087

[31] NE ISO 2009 ldquoEnergy Sources in New Englandrdquo wwwiso-necomnwsissgrid_mktsenrgy_srcs

[32] Doying R 2009 Midwest ISO ldquoJune Monthly Reportrdquo wwwmidwestisoorg[33] PacifiCorp 2009 ldquoIntegrated Resource Plan ndash Volume 1rdquo May 29 2009

wwwpaci-937ficorpcom[34] Frank Novachek 2009 Xcel Energy 414 Nicollet Mall Minneapolis MN

55401 939 personal communication[35] Energy Efficiency and Renewable Energy Department of Energy ldquoBiomass

2009 Multi-Year Research Development and Demonstration Planrdquo www1eer-eenergygovbiomasspdfsmypp_may2009pdf

[36] Sioshansi R Denholm P Jenkin T and Weiss J 2009 ldquoEstimating theValue of Electricity Storage in PJM Arbitrage and Some Welfare EffectrdquoEnergy Econ 31 pp 269ndash277

[37] Kroposki B Levene J Harrison K Sen P K and Novachek F 2006ldquoElectrolysis Information and Opportunities for Electric Power UtilitiesrdquoNational Renewable Energy Laboratory Report No TP-581-40

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-11

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm

methane reforming to produce hydrogen However a nonhybridbiomass to hydrogen plant will be more cost competitive in gen-eral so there must be additional operational value placed on peak-ing or sinking for these plants to be economically attractive Thisadditional value is likely to become a reality as additional inter-mittent renewable energy sources such as wind are added to thenational grid

The directly heated gasifier hybrid system involves replacementof the air separation unit with electrolyzers This change allowsfor extra production of hydrogen and intermittent operation Theanalysis for this system assumed direct replacement of the ASUwithout intermittent operation Estimates of the effect of intermit-tent operation on plant economics were made The electrolyzerbank could be either grid-connected to provide a dispatchabledemand to the utility or it could be tied directly to a stranded windsource to convert wind into chemical fuel (H2)

The direct gasification concept studied is unlikely to be cost com-petitive in the near future but may eventually be attractive withlower-cost electrolysis and a smaller biorefinery plant size that issized for a specific hydrogen demand Intermittent operation andstranded operation were found to have worse economics than grid-connected systems High electrolyzer capital costs make the possibleelectricity cost savings of intermittent operation difficult to justifyBased on a direct replacement of the ASU with electrolyzers hydro-gen can be produced for $232 per kilogram However using gridelectricity the hybrid system is a net CO2e emitter For the use ofelectrolysis to make sense in this setting there must be a significantbenefit to the ability to operate intermittently

Acknowledgment

The authors would also like to acknowledge Dr Bob Evans forconceiving the hybrid hydrogen production systems project andDonna Heimiller for performing the GIS mapping

Employees of the Alliance for Sustainable Energy LLC underContract No DE-AC36-08GO28308 with the US Dept ofEnergy have authored this work The United States Governmentretains and the publisher by accepting the article for publicationacknowledges that the United States Government retains a nonex-clusive paid-up irrevocable worldwide license to publish orreproduce the published form of this work or allow others to doso for United States Government purposes

References[1] Milbrandt A 2005 ldquoA Geographic Perspective on the Current Biomass

Resource Availability in the United Statesrdquo National Renewable Energy LabReport No TP-560-39181

[2] Perlack R Wright L Turhollow A Graham R Stokes B and Erbach D2005 Biomass as Feedstock for a Bioenergy and Bioproducts Industry The Tech-nical Feasibility of a Billion-Ton Annual Supply Oak Ridge National LaboratoryOak 853 Ridge TN

[3] Turner J Sverdrup G Mann M Maness P C Kroposki B Ghirardi MEvans J and Blake D 2008 ldquoRenewable Hydrogen Productionrdquo Int JEnergy Res 32 pp 379ndash407

[4] US Department of Energy Energy Efficiency and Renewable Energy Labora-tory 2008 ldquo20 Wind Energy by 2030mdashIncreasing Wind Energyrsquos Contribu-tion to US Electricity Supplyrdquo Report No GO-102008-2567

[5] Levene J Kroposki B and Sverdrup G 2006 ldquoWind Energy and Productionof Hydrogen and ElectricityndashOpportunities for Renewable Hydrogenrdquo NationalRenewable Energy Laboratory Report No CP560-39534

[6] Fingersh L 2004 ldquoOptimization of Utility-Scale Wind-Hydrogen-BatterySystemsrdquo National Renewable Energy Laboratory Report No CP-500-36117

[7] Dean J Braun R Munoz D Penev M and Kinchin C 2010 ldquoAnalysis ofHybrid Hydrogen Systems ndash Final Reportrdquo National Renewable Energy Labo-ratory Report No TP-46934

[8] Gasification Technology Status ndash December 2006 EPRI and the Gasification869 Users Association Palo Alto CA p 1012224

[9] Spath P Aden A Eggeman T Ringer M Wallace B and Jechura J2005 ldquoBiomass to Hydrogen Production Detailed Design and Economics Uti-lizing the Battelle Columbus Laboratory Indirectly-Heated Gasifierrdquo NationalRenewable Energy Laboratory Report No TP-510-37408

[10] Dean J 2010 ldquoLeveling Intermittent Renewable Energy Production ThroughBiomass Gasification-based Hybrid Systemsrdquo MS thesis Colorado School ofMines Golden CO

[11] Devi L Ptasinski K Janssen F van Paasen S Bergman P and Kiel J2005 ldquoCatalytic Decomposition of Biomass Tars Use of Dolomite anUntreated Olivinerdquo Renewable Energy 30 pp 565ndash587

[12] Heavy Duty Gas Turbine Products 2009 General Electric Company FairfieldCT

[13] Drdar D and Jones R 2000 ldquoGE IGCC Technology and Experience withAdvanced Gas Turbinesrdquo GE Power Systems Report No GER-4207

[14] Craig K and Mann M 1996 ldquoCost and Performance Analysis of Biomass-Based Integrated Gasification Combined-Cycle (BIGCC) Power SystemsrdquoNational Renewable Energy Laboratory Report No TP-430-21657

[15] Gas Turbine World 2006 Handbook (Pequot Publishing Inc Fairfield CT2006)

[16] Kinchin C and Bain R 2009 ldquoHydrogen Production from Biomass via Indi-rect Gasification The Impact of NREL Process Development Unit GasifierCorrelationsrdquo National Renewable Energy Laboratory Report No TP-510-44868

[17] Watlow for 22 MW duct heaters Watlow 12001 Lackland Road St LouisMO 63146 personal communication 2009

[18] Gassner M and Marechal F 2008 ldquoThermo-economic Optimization of theIntegration of Electrolysis in Synthetic Natural Gas Production from WoodrdquoEnergy 33 pp 189ndash198

[19] Srinivas T Gupta A V S and Reddy B V 2009 ldquoThermodynamic Equi-librium Model and Exergy Analysis of a Biomass Gasifierrdquo ASME J EnergyResour Technol 131 031801 pp 1ndash7

[20] Braun R J Hanzon L G and Dean J H 2011 ldquoSystem Analysis of Ther-mochemical-based Biorefineries for Coproduction of Hydrogen and Elec-tricityrdquo ASME J Energy Resour Technol 133 012601 pp 1ndash12

[21] Manning F and Thompson R 1991 Oilfield Processing of Petroleum Vol-ume One 904 Natural Gas PennWell Publishing Co Tulsa Oklahoma

[22] StatoilHydro 2009 ldquoHydrogen Technologies World Leader in Electrolysis forHydrogen Solutionsrdquo product brochure Hydrogen Technologies NO-3674Notodden Norway COS 091408 available URL http908wwwelectrolyserscom

[23] US Department of Energy Hydrogen Program 2009 ldquoFuture Central Hydro-gen Production from Grid Electrolysisrdquo H2A analysis wwwhydrogenenergygovh2a_prod_studieshtml

[24] Phyllis Biomass Datapage ldquowood hybrid poplarrdquo ID 806 available URLhttpwwwecnnlphyllis

[25] Jin H Larson E and Celik F 2009 ldquoPerformance and Cost Analysis ofFuture Commercially Mature Gasification-Based Electric Power GenerationFrom Switchgrassrdquo Biofpr 3 pp 142ndash173

[26] Department of Energy 2007 ldquoCost and Performance Baseline for Fossil EnergyPlants Volume 1 Bituminous Coal and Natural Gas to Electricityrdquo Report NoDOE=NETL-2007=1281

[27] US Department of Energy Hydrogen Program 2009 ldquoDOE H2A Analy-sisrdquo wwwhydrogenenergygovh2a_analysishtml

[28] US Department of Energy Hydrogen Program 2009 ldquoFuture Central Hydro-gen Production from Natural Gas with CO2 Sequestrationrdquo H2A analysiswwwhydrogenenergygovh2a_prod_studieshtml

[29] Energy Information Administration Annual Energy Outlook 2009 wwweiadoegovoiafaeoelectricityhtml

[30] Schafer A Heywood J and Weiss M 2006 ldquoFuture Fuel Cell and InternalCombustion Engine Automobile Technologies A 25-Year Life Cycle and FleetImpact Assessmentrdquo Energy 31 pp 2064ndash2087

[31] NE ISO 2009 ldquoEnergy Sources in New Englandrdquo wwwiso-necomnwsissgrid_mktsenrgy_srcs

[32] Doying R 2009 Midwest ISO ldquoJune Monthly Reportrdquo wwwmidwestisoorg[33] PacifiCorp 2009 ldquoIntegrated Resource Plan ndash Volume 1rdquo May 29 2009

wwwpaci-937ficorpcom[34] Frank Novachek 2009 Xcel Energy 414 Nicollet Mall Minneapolis MN

55401 939 personal communication[35] Energy Efficiency and Renewable Energy Department of Energy ldquoBiomass

2009 Multi-Year Research Development and Demonstration Planrdquo www1eer-eenergygovbiomasspdfsmypp_may2009pdf

[36] Sioshansi R Denholm P Jenkin T and Weiss J 2009 ldquoEstimating theValue of Electricity Storage in PJM Arbitrage and Some Welfare EffectrdquoEnergy Econ 31 pp 269ndash277

[37] Kroposki B Levene J Harrison K Sen P K and Novachek F 2006ldquoElectrolysis Information and Opportunities for Electric Power UtilitiesrdquoNational Renewable Energy Laboratory Report No TP-581-40

Journal of Energy Resources Technology SEPTEMBER 2011 Vol 133 031801-11

Downloaded 03 Oct 2011 to 1386720243 Redistribution subject to ASME license or copyright see httpwwwasmeorgtermsTerms_Usecfm