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DECARBONIZED FUEL PRODUCTION FACILITY -A TECHNICAL STRATEGY FOR COAL

IN THE NEXT CENTURY

Presented at1999 Gasification Technologies Conference

October 17-20, 1999San Francisco, California

Joseph S. BadinEnergetics, Incorporated

7164 Gateway DriveColumbia, Maryland 21046

Michael R. DeLallo, P.E.Michael G. Klett, P.E.

Michael D. Rutkowski, P.E.Parsons Infrastructure & Technology Group Inc.

2675 Morgantown RoadReading, Pennsylvania 19607

Jerome R. TemchinU.S. Department of Energy

1000 Independence Avenue, S.W.Washington, D.C. 20585

ABSTRACT

The U.S. electricity market is undergoing a transformation driven by changes such asderegulation of power generation, more stringent environmental regulations, climate changeconcerns, and other market forces. With these changes come new players such as merchantpower plants. The industry is also counting on new gas-fired generation to meet demand.Environmental initiatives concerning PM 2.5, air toxics, mercury control, and CO2 reductioncould adversely impact the economic viability of coal. The future use of coal to produceelectricity is uncertain and possibly in peril unless we recognize that in the coming decades, thetraditional means of how energy (both electricity and fuel) is generated, transported, and utilizedwill likely be very different from what it is today. In this paper, we describe a technical strategyfor the coal industry that can help assure coal’s competitiveness during the next century aselectricity markets evolve and are reshaped by these changes. Recently, the U.S. Department ofEnergy unveiled a new concept, “Vision 21” – a futuristic way of combining high-efficiencypower technologies with advanced coal processing technologies and environmental controls tocreate a near-zero discharge, multi-product energy complex. This paper presents a

conceptualization of a Vision 21 plant that focuses on production of hydrogen from coal. It willshow how the concept can help assure that coal can remain competitive with natural gas as a fuelfor baseload electricity generation for existing and new power plants. It can also provide afeedstock for chemical and liquid fuels production, even if emissions of carbon dioxide must becontrolled. This paper presents hydrogen delivery scenarios for the power sector that provide thebasis for the projected economic and technical performance objectives.

INTRODUCTION

Coal has been, and continues to be, one of the major energy sources utilized in the United States.Over one billion tons of coal are mined in the U.S. annually. The large majority of U.S. coal isused for the production of electricity. Approximately 55 percent of all electricity produced in theU.S. today is fueled by coal.

However, the long-term competitiveness of coal is uncertain. Competition from low-cost andefficient options such as natural gas combined-cycle plants are reducing the dominance of coal inthe electric power market. Likewise, new and more stringent environmental requirements,especially those related to ozone non-attainment, acid rain, and global climate change, furtherthreaten the competitiveness of coal. Finally, the deregulation of the electric power industry isplacing capital risk and financial return at the forefront of decision-making, placing even morepressure on the generation options that require large capital investments.

To address these and other concerns and to ensure that the coal remains a viable option in thefuture, the U.S. Department of Energy has created a new program—Vision 21. Vision 21 isintended to develop the enabling technologies to allow the private sector to combine high-efficiency power technologies with advanced coal processing technologies and environmentalcontrols systems. The result will be energy complexes that could produce cost-competitivemultiple products that are in demand in the marketplace while discharging near-zero levels ofpollution, including CO2. Research on the Vision 21 enabling technologies is expected to resultin technology options that could be introduced to the marketplace by 2020.

Within DOE, the Office of Planning and Environment within the Office of Coal and PowerSystems (C&PS) is responsible for evaluating the reasonableness of C&PS strategic goals, andviews the evaluation of innovative systems in fossil energy power generation and liquid fuelsproduction as key elements in that assessment. The Advanced Research Program within theC&PS supports basic research and the development of innovative systems in fossil energy powergeneration and liquid fuels production. Several research targets have been identified, includinglow-cost O2 separation and high-temperature H2 separation. In support of this program,conceptual systems and cost analyses are being developed by the Parsons Corporation for a coalprocessing plant to produce hydrogen while recovering carbon dioxide (CO2) for offsiteprocessing or sequestration. This has been referred to as a decarbonized fuel plant. The scope ofwork for this analysis entails the following:

• Identify alternative processes and technologies utilized for production of hydrogen from coal,

• Review the technical and economic characteristics of developmental materials andtechnologies for separating hydrogen and oxygen from gas mixtures,

• Conceptualize process plant designs that utilize developing technologies and materials,resulting in costs of product and CO2 sequestration significantly lower than with conventionalapproaches,

• Compare the costs of decarbonized fuel plants with plants designed to produce syngas andhydrogen from coal utilizing conventional technology,

• Perform sensitivity analyses on the baseline conceptual decarbonized fuel plants to determinethe effect of modifying plant design on cost of product,

• Perform hydrogen delivery scenarios to describe the conceptual infrastructure needed to linkdecarbonized fuel plants to power markets and to other commodity markets, and

• Present data and results on this study at periodic conferences and workshops.

With an increased interest in greenhouse gas sequestration and production of hydrogen from coal,conceptual designs and resulting economic analyses of syngas and hydrogen plants utilizingconventional technologies were also developed. The conventional approaches includedprocesses such as coal gasification, shift conversion, acid gas removal, and pressure swingadsorption to produce hydrogen. The results of previous studies indicated that the economics ofproducing syngas and hydrogen from coal by conventional methods is not presently costcompetitive (see References 1, 2, and 3).

An alternative plant was conceived for producing hydrogen from coal utilizing a hydrogenseparation device (HSD) now being developed by Oak Ridge National Laboratory (ORNL) (seeReference 4). The HSD is based on a high-temperature membrane separation concept that can bedesigned to selectively separate hydrogen from other gases. By utilizing the HSD, it should beconceptually possible to separate hydrogen from CO2 passively and economically.

HYDROGEN SEPARATION DEVICE (HSD)

The HSD is a high-temperature membrane device in a shell and tube configuration, with thehigh-pressure side being on the outside of the inorganic membrane tubes. The inorganicmembrane is designed to have pore sizes of controlled diameters, and it can be made of Al2O3 orother ceramic materials. According to ORNL (see Reference 4), the confidential manufacturingprocess is sufficiently flexible to accommodate a variety of gas compositions and designrequirements. The resultant membrane is similar in design to a packed bed through whichinterstitial pores can be controlled to less than 5 angstroms, while acting like a molecular sieve(that is, it excludes larger molecules).

The separation factor (SF) for hydrogen is high, increasing with higher temperatures. Thedefinition of SF is the rate at which hydrogen passes through, relative to the balance of moleculespassing through. That is, the purity of hydrogen resulting from an SF of 1,000 would becalculated as follows:

Purity = (1.0 - 1/1000) x 100 = 99.90%

The balance is made up of the other gases in the initial mixture.

Pressurized syngas, to which steam has been added, enters the shell-side of the HSD, which isassumed to have gas contact catalytic properties that promote the water-gas shift reaction. The

hydrogen-deficient surface caused by hydrogen migrating through the membrane will result insome water gas shift reaction occurring.

It was assumed that, as hydrogen is extracted from the gas stream through the HSD membrane,gas composition at the catalytic surface will become hydrogen deficient and, with excess steam,equilibrium will be shifted to convert available CO to CO2 and hydrogen. The hydrogen willthen migrate to the HSD membrane surface and be transported across. Eventually the CO willreach an equilibrium level at the system temperature with the remaining hydrogen.

The HSD transports hydrogen across the membrane in proportion to the relative hydrogen partialpressure differentials, where P1 equals the upstream hydrogen pressure, and P2 equals the producthydrogen pressure. The HSD is designed to operate at an equilibrium temperature of 1823 °Fand at 950 psia. At 950 psia upstream (assuming 42 percent hydrogen), 95 percent of thehydrogen will be separated, with a downstream pressure of 20 psia, according to the followingrelationship:

H2 transport = (1 - P2/P1) x 100 = % transport

= (1 - 20/(950 x 0.42)) x 100 = 95% transport

Fuel value remaining in the separated gas will be about 5 percent of the original feed gas. At thattemperature, the hydrogen purity will be 99.9 percent. The hydrogen stream leaving the HSD at20 psia and 1823 °F passes through a HRSG and a compressor, which reduces hydrogen streamtemperature to 117 °F. The steam raised in the HRSG is added to the steam that is injected intothe raw gas coming from the gasifier to promote the shift reaction.

APPROACH

The conceptual decarbonized fuel plant design was initiated on the basis of integrating the HSDconcept into a coal-based gasification facility. Sufficient information was obtained from ORNLto characterize operational and interface requirements of the HSD and to prepare a conceptualdesign basis, including operating temperature, operating pressure, differential pressure, hydrogenseparation factor, hydrogen purity, membrane transport rate, and membrane element costestimates. Two additional variations of the decarbonized fuel plant were also generated to makethe design less aggressive in order to reduce technical risk.

In addition to the baseline decarbonized fuel plants, two other plant designs were also prepared:one for producing synthesis gas (syngas) from coal, and the other for producing hydrogen fromcoal. The coal input and other basic design parameters were retained from the baseline plant toensure valid performance and economic comparisons.

Heat and material balances and process flow diagrams were prepared for the conceptual plantdesigns using the ASPEN™ simulation code, and capital cost estimates were prepared. The basisfor cost estimating the HSD utilized non-proprietary guidelines provided by ORNL, combinedwith previous Parsons cost estimating of large ceramic filter vessels. The cost estimates forbalances of plant were factored from previous Parsons coal gasification and power plant designs.Finally, the cost of product was determined on a dollars per MMBtu basis.

Baseline Decarbonized Fuel Plant with ATS Expansion Turbine

The baseline hydrogen concept shown in Figure 1 consists of the Destec coal gasificationprocess, having a two-stage slurry-feed entrained-flow design. The Destec process was selectedin lieu of other processes due to the ability to adjust the relative flows to the two stages. Thisallows achievement of the required gasifier exit temperature without incurring the cost of a wasteheat boiler.

Key process components included in the plant are a Destec high-pressure slurry-feed gasifier, theORNL HSD, and the ATS turbine expander. The selected processes exhibit some uniquefeatures that result in a simplification of plant design, and may contribute to lowering of capitalcost. The high-pressure syngas produced in the gasifier is quenched to 1905 °F as a result ofadjustments in the second stage of the gasifier, thereby eliminating the requirement for a fire tubeheat exchanger. The hot raw gas is cleaned of larger particulates in a cyclone and has aconsiderable amount of steam added, ensuring adequate water content for the high-temperatureshift reaction to occur, albeit reduced in temperature to 1456 °F. Following the cyclone, the gasis cleaned of remaining particles with a ceramic candle filter. The gas enters the HSD at 1456 °Fand leaves the HSD at 1823 °F as a result of the exothermic shift reaction. The hydrogenproduced from the HSD is better than 99.5 percent pure. It goes through a heat recovery steamgenerator (HRSG) and then is compressed to 346 psia.

The CO2-rich gas leaving the HSD at 950 psia contains about 5 percent of the fuel value of theinlet syngas stream. This gas goes to the ATS combustor where oxygen is injected to convertCO, hydrogen, and H2S to CO2, H2O, and SO2, respectively. Steam is also injected into thecombustor to moderate the temperature to 2610 °F. The hot gas is expanded to 20 psia and1173 °F through the ATS turbine expander to produce 120 MW electric power. The gas iscooled in a HRSG, and steam produced is combined with other steam produced from cooling thehydrogen for process applications. There is no power produced from steam. The CO2-rich gas isthen treated like flue gas and goes through a wet limestone forced-oxidation flue gas desulfurizer(FGD) to remove SO2. The CO2 product is cooled to 100 °F and sent offsite.

< 10% Ash

Figure 1Baseline Hydrogen Plant

Oxygen BlownEntrained Bed

Gasifier

ASU

CandleFilter

ATSCombustor

ATSExpander

H2 SeparationDevice

ShellSide

HRSG

SulfurRemoval

Air

O

O

Pittsburgh #8Coal

Steam

Power120 MW

CO2

Gypsum

1020 psia1905°°°°F

1000 psia1455°°°°F

950 psia1823°°°°F

20 psia1823°°°°F

902 psia2610°°°°F

20 psia1173°°°°F

250°°°°F

100°°°°F

408 TPD>99.5% H2

346 psia

Water

HRSG

Steam

2

2

Table 1 presents the performance summary for the plant. For comparative purposes and to arriveat a figure of merit for the plant design, an effective thermal efficiency (ETE) was derived for theplant performance based on HHV thermal value of hydrogen produced and off-site power sales,divided by the fuel input to the plant. The formula is:

ETE = (Hydrogen Heating Value + Electrical Btu Equivalent) Fuel Heating Value (HHV)

ETE = 34,004 lb H2/h x 61,095 Btu/lb + 42,000 kW x 3,414 Btu/kWh 221,631 lb coal/h x 12,450 Btu/lb

ETE = 80.5%

Table 1Performance Summary

Coal Feed 221,631 lb/h

Limestone Sorbent 25,188 lb/h

Oxygen Feed (95%) 252,369 lb/h

Hydrogen Product Stream 34,004 lb/h

CO2 Product Stream 603,324 lb/h

Gypsum to Stack (MF) 33,276 lb/h

Gross Power Production 120 MW

Auxiliary Power Requirement 78 MW

Net Power Production 42 MW

Effective Thermal Efficiency (ETE), HHV 80.5%

Baseline Decarbonized Fuel Plant with ATS Expansion Turbine and 1000 ºF Filter

The baseline hydrogen concept shown in Figure 2 reduces the temperature of the fuel gas streamfrom 1456 ºF to 1000 ºF before the gas is filtered. This temperature is more in the range ofpresent technology for filtering reducing gases. Table 2 presents the performance summary forthe plant. For comparative purposes and to arrive at a figure of merit for the plant design, anETE was derived for the plant performance based on HHV thermal value of hydrogen producedand off-site power sales, divided by the fuel input to the plant.



Limestone Sorbent 25,188 lb/h




Gypsum to Stack (MF) 32,688 lb/h





< 10% Ash

Steam

Figure 2

Hydrogen Plant with 1000 °°°°F Candle Filter

1020 psia

CandleFilter

ATSCombustor

ATSExpander

H2 SeparationDevice

ShellSide

HRSG

SulfurRemoval

O2

Power120 MW

CO2

Gypsum

950 psia1437°°°°F

20 psia1437°°°°F

902 psia2610°°°°F

20 psia1173°°°°F 250°°°°F

100°°°°F

421 TPD>99.5% H 2

346 psia

HRSG

Gasifier

ASUAir

O2

Pittsburgh #8Coal

1905°°°°F

Water


HX

Steam

1000°°°°F

Baseline Decarbonized Fuel Plant with Conventional Expansion Turbine and Hot GasCleanup

The baseline hydrogen concept shown in Figure 3 substitutes a conventional turbine for an ATSturbine and removes sulfur from the fuel gas upstream of the HSD and the gas turbine. Thisconcept reduces the temperature of the fuel gas stream from the gasifier to 1100 ºF before the gasis desulfurized and filtered in a transport reactor desulfurizer and a ceramic candle filter. Thiseliminates the need for a downstream FGD unit. Table 3 presents the performance summary forthe plant. For comparative purposes and to arrive at a figure of merit for the plant design, anETE was derived for the plant performance.

Figure 3

Hydrogen Plant with Hot Gas Desulfurization

and Conventional Turbine Expander

1020 psia1905 °°°°F

ASUAir

O2

Pittsburgh #8Coal

<10% Ash

Water


Gasifier

HX CandleFilter

Combustor

ConventionalExpander

H2 SeparationDevice

ShellSide

HRSG

O2

Power94 MW

CO2

950 psia1402 °°°°F

20 psia1402 °°°°F

902 psia2100 °°°°F

20 psia894 °°°°F

422 TPD>99.5% H 2

346 psia

HRSG

Quench Water

Steam

1100°°°°FHot GasSulfur

Removal

SulfuricAcidPlant

H2SO4

230 TPD

1100°°°°F

Table 3. Performance Summary





Sulfuric Acid Product 19,482 lb/h





Plant to Produce Syngas from Coal Gasification without CO2 Capture

The conventional syngas plant concept shown in Figure 4 consists of the same Destec gasifierand coal input as used for the hydrogen plant. The raw gas from the gasifier is cooled to 625 °F,and particulates are removed with a ceramic candle filter. A nahcolite bed is used to removechlorides from the gas, followed by a proprietary amine acid gas removal process. Sulfuric acidis manufactured from the H2S and sold off-site. The syngas product is available at 346 psia.Table 4 presents the performance summary for the plant. For comparative purposes and to arriveat a figure of merit for the plant design, an ETE was derived for the plant performance.

Figure 4

Synthesis Gas Fuel Plant


Gasifier

ASU

CandleFilter

Air

O2

Pittsburgh #8Coal

< 10% Ash 1900°°°°F

Water 625°°°°F400 psia

Air

NAHCOLITEChlorideGuard

Acid GasRemoval

SulfuricAcid Plant

346 psia 117°°°°F

230 TPDH2SO4

SYNGAS

H2S

55,000 MMBtu/day




Syngas Product Stream @ 5,609 Btu/lb 411,421 lb/h

CO2 Product Stream None

Sulfuric Acid Byproduct 19,210 lb/h

Gross Power Production 27.1 MW

Auxiliary Power Requirement 36.0 MW

Net Power Purchased 8.9 MW


Plant to Produce Syngas from Coal Gasification with CO2 Capture

As a sensitivity activity, the impact of capturing CO2 for sequestration was also analyzed for thesyngas plant. The sulfur removal unit of the plant was modified to selectively remove H2S andCO2. A two-stage Selexol process was used, which removes H2S from the cooled syngas andthen removes CO2 from the desulfurized syngas. The unit consists of two absorbers: the firstabsorbs H2S from the cooled syngas, providing a desulfurized syngas, and the second absorbsCO2 from the desulfurized syngas. The two absorbers are integrated, with solvent flowingbetween them.

Table 5 presents the performance summary for the plant. For comparative purposes and to arriveat a figure of merit for the plant design, an ETE was derived for the plant performance.




Syngas Product Stream @ 7,049 Btu/lb 320,872 lb/h



Gross Power Production 24.2 MW

Auxiliary Power Requirement 40.2 MW

Net Power Purchased 16.0 MW


Conventional Plant to Produce Hydrogen from Coal Gasification

The conventional hydrogen plant concept shown in Figure 5 consists of the same Destec gasifierand coal input as used for the hydrogen plant. The raw gas from the gasifier is cooled to 625 °F,and particulates are removed with a ceramic candle filter. The fuel gas is shifted in a shiftconverter, then cooled, and CO2 and H2S are recovered in a double-stage Selexol unit. Sulfuricacid is manufactured from the H2S and sold off-site. The hydrogen product is purified in apressure swing adsorption (PSA) unit. Table 6 presents the performance summary for the plant.For comparative purposes and to arrive at a figure of merit for the plant design, an ETE wasderived for the plant performance.

< 10% Ash

Figure 5

Conventional Hydrogen Plant


Gasifier

ASU

CandleFilter

Air

O2

Pittsburgh #8Coal

1900°°°°F

Water625°°°°F400 psia

Air

ShiftConverter

2-StageAcid GasRemoval

SulfuricAcid Plant

310 psia

230 TPDH2SO4

Hydrogen

H2S

318 TPD

SteamCO2

Product

Fuel Gas

PSA











COST ESTIMATE

Approach to Cost Estimating

Economics in this report are stated, primarily, in terms of levelized cost of product, $/short ton($/ton) or $/MMBtu. The cost of product is developed from the identified financial parametersand: 1) the total capital requirement of the plant (TCR), 2) the fixed operating and maintenancecost (fixed O&M), 3) the non-fuel variable operating and maintenance costs (variable O&M),4) the consumables and byproducts costs and credits, and 5) the fuel costs.

An integrated gasification combined cycle (IGCC) cost model was used as the basis fordeveloping the bulk of the balance-of-plant costs portion of the estimate. Use of this modelassured consistency in the evaluation of these balance-of-plant costs. The capital cost for thegasifiers, gas cleanup including CO2 removal, and the ATS turbine was based on recent studiesconducted by Parsons (see References 1, 2, and 3). Destec gasifier pricing was further adjustedto reflect the impact of using a total quench in the second stage rather than a firetube boiler,followed by a ceramic candle filter. Transport gasifier pricing was based on a recent repoweringstudy, adjusted for oxygen performance (see Reference 5). Balance-of-plant process system costswere estimated from cost curves developed by Parsons, based in large part on the results ofcompleted construction projects.

Costs for the HSD were developed independently of the cost model, based on several majorassumptions listed below:

• The H2 ceramic molecular sieve membrane requirement was calculated utilizing themembrane coefficient R&D goal stated by ORNL (see Reference 4):

0.1 Std cc/minute/cm2/cm Hg PH2 differential

Using this coefficient and a hydrogen pressure of 905 cm Hg differential pressure, theEnglish coefficient on hydrogen weight basis becomes:

1.0 lb H2/h/ft2

This coefficient is convenient due to the heat and material balance being expressed in lb/h.

• The cost of the ceramic molecular sieve material was based on a unit cost of $100/ft2. ORNLindicated that commercially available filters cost about $300/ft2, and they project thehydrogen filter to be one-third of that cost.

• The shell and tube configuration can be conceived as being similar in design to shell and tubeheat exchangers, except that the heat exchange surfaces are replaced by the ceramicmolecular sieve.

• The cost base for the ceramic candle filter was the Westinghouse design used in pressurizedfluidized-bed combustion (PFBC) hot gas cleanup applications. For the HSD, the cost of theshell and internals was applied, excluding the ceramic candles. The cost of the ceramic

candles was replaced by the cost of the ceramic molecular sieve. On the basis of the typical34,000 pounds of hydrogen per hour, 34,000 square feet of molecular sieve are required forthe nominal 410-ton hydrogen per day capacity facility. It was determined that themembranes could be contained in two vessels with a tube bundle configuration of 2.3-inch-diameter tubes by 25 feet long. Each 16-foot-diameter vessel contains 4,096 tubes.

Production Costs (Operation and Maintenance)

The production costs for the plant consist of several broad categories of cost elements. Thesecost elements include operating labor, maintenance material and labor, administrative andsupport labor, consumables (water and water treating chemicals, limestone, solid waste disposalcosts, byproducts such as power sales, and fuel costs). Note that production costs do not includecapital charges and should not be confused with cost of product.

Cost Results

The results of the cost estimating activity are summarized in Table 7.

The cost of product values incorporates the annual equivalent of the capital cost and theproduction costs that were previously addressed. The mechanics and basis of the model used todetermine the cost of product is included in Table 8.

POWER MARKET SCENARIOS FOR HYDROGEN DELIVERY

Most new power plants built in the U.S. are expected to be merchant plants. Merchant powerplants include existing, repowered, as well as new greenfield units. Most operating merchantplants are comprised of existing plants that have been recently sold by utilities and are typicallynatural gas-fired capacity. Utility restructuring is encouraging such conversions. As much as50,000 MW of new merchant power generating capacity could be built between now and early inthe next century. (See References 6, 7, and 8.) As shown in Figure 6, Texas, California, NewEngland, New York, Pennsylvania, and Illinois are most rapidly opening to competition andplanned merchant capacity. It is also interesting to note that the largest state producers of coalare Wyoming, West Virginia, Kentucky, Pennsylvania, Texas, and Illinois. Figure 7 presents themost likely delivery corridors that could link coal resources to the growing merchant plantmarket by delivering decarbonized fuel (hydrogen) to these gas-fired facilities.

Competitive advantages can be gained by early market entrants with merchant plants strategicallysited near gas pipelines and power transmission corridors. Location near both infrastructuresallow the profitable management of the “spark gap”—the difference between the equivalentmarket price of a kilowatt hour leaving the merchant plant and the cost of the fuel input to theplant. There is a dire need for the expansion of natural gas pipelines. In the next few years,about 12.5 billion cubic feet of new pipeline capacity will be needed in the U.S. Capacity ofhigh-voltage power lines are suffering constraints, thereby opening the market to moredistributed generation technologies. The decarbonized fuel plant helps take advantage of marketopportunities in managing the spark gap and in providing price stability to the merchant plant’sfuel costs.

Table 7Decarbonized Fuel Plant and Syngas Plant Configuration Comparisons

BaselineDecarbonized

Fuel PlantATS Expansion

Turbine


Fuel PlantATS ExpansionTurbine 1000 ºF

Filter


Fuel PlantConventional

ExpansionTurbine with

Hot GasCleanup

Syngas fromCoal

Gasificationwithout CO2

Capture

Syngas fromCoal

Gasificationwith CO2

Capture

Hydrogen fromCoal

Gasificationwith CO2

Capture

Gasifier Entrained flow Entrained flow Entrained flow Entrained flow Entrained flow Entrained flow

ASU Cryogenic Cryogenic Cryogenic Cryogenic Cryogenic Cryogenic

Turbine Expander ATS ATS Conventional N/A N/A N/A

H2/Syngas Production 408 tpd 421 tpd 422 tpd 4,937 tpd 3,850 tpd 318 tpd

Heating value, Btu/lb 61,095 61,095 61,095 5,609 7,049 61,095

Net Power Sales 42 MW 51 MW 18 MW (9 MW) (16 MW) 36 MW

Effective ThermalEfficiency

80.5% 84.0% 80.2% 82.5% 80.0% 63.1%

Total Plant Cost,$1,000

$306,605 $353,260 $349,735 $253,445 $291,399 $374,273

H2/Syngas ProductCost, $/MMBtu

$4.05 $4.27 $4.27 $3.42 $4.81 $5.57

Table 8Estimate Basis and Financial Criteria for Calculating the Revenue Requirements

General Data/CharacteristicsCase Title IGCC-ATS HydrogenUnit Size 421.2 H2 tpdLocation Middletown, USAFuel Pittsburgh No. 8 coalLevelized Capacity Factor /

Preproduction (equiv. months)95% / 1 months

Capital Cost Year Dollars(reference year dollars)

1997 (January)

Delivered Cost of Fuel $1.00/MMBtuDesign / Construction Period 2.5 yearsPlant Startup Date (first year dollars) 2000 (January)Land Area / Unit Cost 100 acres / $1,500/acre

Financial CriteriaProject Book Life 30 yearsProject Tax Life 20 yearsTax Depreciation Method Accel. based on ACRS classFederal Income Tax Rate 34.0%State Income Tax Rate 6.0%Economic Basis Constant dollars over book life

Capital Structure % of Total Cost (%)Common Equity 20 16.5Debt 80 6.3

Weighted Cost of Capital (after tax) 6.4%

Over Book Life 1997 to 2000Escalation Rates

General 0 % per year 0 % per yearPrimary Fuel -1.1% per year -0.6% per year

Figure 6Existing and Planned Merchant Capacity by State

Megawatt Capacity by State

1,180

1,181

5,710

525

405

3,489

1,025

6,017

2651,836

8002,000

2,160

740

300

250

260

570

108500

3,810

Figure 7Decarbonized Fuel Production Facilities

— Decarbonized Fuel/Power Market Corridors —

• Infrastructure will be developed linking coal resources to the growing merchant powerplant sites. The Northeast and Southwest corridors will develop first due to higherelectricity costs and more active restructuring in these areas.

SOUTHW E ST CORRIDOR

NORTHEAS

T

CORRID

OR

CE

NTR

AL

NO

RTHWEST

Figure 8 shows various decarbonized fuel storage and transport scenarios. All scenariostransport and store hydrogen as a compressed gas, resulting in some storage benefit from linepack. The scenarios are also based on the baseline decarbonized fuel plant with ATS expansionturbine with a hydrogen gate cost of $4.05/MMBtu. Carbon sequestration costs of $10/toncarbon (DOE goal) and $50/ton carbon are also included. The scenarios are given in Table 9.

Table 9Description of Storage and Transport Scenarios

Case Description

A1. No storage, 10 mile pipeline to a merchant plant (200 MWe)

A2. Underground depleted well, 12 hours storage, 10 mile pipeline to amerchant plant

A3. Case A1. with 100 mile pipeline

A4 Case A2. with 100 mile pipeline

B1 On-site, above ground compressed gas storage, 12 hours

C1. 10 mile pipeline to underground storage and 10 mile pipeline to severaldistributed generators (10 MWe each)

C2. Case C1. with on-site above ground storage, 12 hours at distributedgenerators

Pipeline costs were based on moving hydrogen at the rate of 408 tpd. This is equivalent to157 MMscfd or 49,853 MMBtu/d. Pipeline costs were estimated to be $1MM/mile andcompressors to be $1100/hp. Compressor power was to allow a pressure drop of about 0.0277psi/100 feet.

Storage capital costs were based on the sum of power and capacity costs. Conversions of 1m3 H2

= 3.5663 kW and 1 kg H2 = 39.4 kWh on a higher heating value basis. The cost of undergroundstorage in depleted wells can be expressed as: $30/kW + $0.04/kWh.

The cost of above-ground compressed hydrogen is $40/kW + $15/kWh. (See Reference 9).Figure 9 presents the results of the decarbonized fuel storage and transport scenarios. Keyfindings are:

• With no carbon sequestration in the study cases, hydrogen costs range from $4.17/MMBtu to$5.95/MMBtu delivered.

• With $10/t carbon sequestration costs, hydrogen costs range from $4.56/MMBtu to$6.35/MMBtu delivered.

• With $50/t carbon sequestration costs, hydrogen costs range from $6.15/MMBtu to$7.93/MMBtu delivered.

Figure 9Decarbonized Fuel Storage and Transport Scenarios

0

1

2

3

4

5

6

7

8

9

10

Baseline

Sce n

ario

Del

i ver

e d H

co s

t ($

/MM

Btu

)2

A110 milespipeline,

no storagemerchant

10 miles,12 hr storage

wells,merchant

100 miles,pipeline,

no storagemerchant

100 miles,12 hr.

storage wells,merchant

12 hr.,above-ground

storage

10 miles,12 hr. storagewells, 10 miles12 hr. storage

dist. gen.

10 miles,12 hr. storage

10 miles,dist. gen.

A2 A3 A4 B1 C1 C2

Decarbonized Fuel Plant Gate

Storage & Transport

$10/ton C sequestration cost

$50/ton C sequestration cost

at gate

Figure 8Decarbonized Fuel Storage and Transport Scenarios

A1

A1 +

A3 +

C1 +

10 mile pipeline

100 mile pipeline

10 miles 10 miles

A2

A3

A4

B1

C1

C2

DecarbonizedFuel Plant



Depleted well12 hr. storage


MerchantPower Plant

MerchantPower Plant

DistributedGenerators

GateH2

Depleted Natural Gas/Oil Wells - 12 hr. storage

Depleted Natural Gas/Oil Wells - 12 hr. storage

On-site, 12 hr. storageAbove-groundcompressed gas

On-site, 12 hr. storageAbove-groundcompressed gas


Fuel Plant

GateH2

• With the 100-mile pipeline, no storage scenario has a break-even cost with the on-site, 12-hour above-ground storage scenario.

• Overall, for the scenarios studied, storage and transport added $0.12 - $1.9/MMBtu to theplant gate cost.

From this analysis, it is apparent that the cost of delivered hydrogen is very dependent on thedelivery distance and the storage technology used.

CONCLUSIONS

By preparing the plant design, economics, and scenarios for the decarbonized fuel plants, it hasbeen shown that the potential exists for producing and delivering economically competitivehydrogen from coal. The baseline decarbonized fuel plants utilize a combination of commercialand developmental processes. This design effort has also served to identify the research goalsthat need to be attained to result in the economical production of decarbonized fuel. It is alsopossible to produce separate streams from the plant containing predominantly CO2, solid waste,and sulfur.

To effectively design such a plant, the key process areas are identified as the particulate filter andthe HSD. The particulate filter prevents char and ash from infiltrating the HSD and the turbineexpander, whereas the HSD is required for separating a pure hydrogen stream from the synthesisgas. Additionally, the potential exists for significant further reduction in capital and operatingcosts by exploring the utilization of ionic-transfer membranes for air separation.

REFERENCES

1. “Orimulsion: CO2 Capture in Power Generation: Hydrogen Production; and MethanolProduction,” IEA Greenhouse Gas R&D Programme, Report No. PH2/11, May 1997.

2. Final Report, “Bellefonte Completion Project Fossil Repowering Phase I Screening Study,”TVA Contract TV-96889V, 1997.

3. “Nitrogen Fixation by Ammonia Synthesis for CO2 Sequestration,” U.S. Department ofEnergy, FETC, Pittsburgh, Pennsylvania, 1997.

4. Conference call, Parsons Power and Oak Ridge National Laboratory (Rod Judkins, DougFain), September 2, 1997.

5. “Advanced Technology Repowering,” U.S. Department of Energy, FETC/Morgantown,DE-AC21-94M31166, Task 1, Final Draft Report, 1997.

6. “An Overview of the Market for New Merchant Power Plants,” J. Sebesta and E. Stenby,PowerGen ’98 Conference, December 1998.

7. “Seller’s Market,” J. Bodington, Independent Energy, September 1999.

8. “Rise of the Merchant Class,” R. Swanekamp, Power, September/October 1999.

9. “Technology Characterizations for the Energy, Economics, Environment PathwayAnalysis,” J. Badin and J.P. DiPietro, Energetics, Incorporated, U.S. Department of EnergyHydrogen Program, April 1995.

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