hydrogen production natural gas

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emissions per kIn, when operated on natural-gas-derivedhydrogen,would only be about 35% of theemissions or cars with gasoline-fired nternal combustionengines.9.loIn this study, we examine he feasibility of reducing CO2 emissions urther by recovering he carbondioxide from hydrogen production and storing it outside the atmosphere.Both the technical feasibilityand the economic viability are examined.We considerstoring the separatedCO2 n depleted natural gasfields, both without and with enhancednaturalgas ecovery.We begin by describing severalschemes orthe production of hydrogen rom natural gas, with and without sequestration f CO2. Subsequently,wediscuss he basis for our technical and cost calculations and present he results.

SCHEMES FOR THE CONVERSION OF NATURAL GAS TO HYDROGENThe first step in the conventionalmanufactureof hydrogen from natural gas nvolves reforming thenatural gas feedstock with steam at high temperature, o produce a gaseousmixture consisting mainlyof carbon monoxide and hydrogen. Subsequently he gaseousproduct of the reformer is processed nshift reactorsoperatedat much lower temperatures. n these eactors, he carbon monoxide reacts withsteam o produce hydrogenplus CO2. Subsequently,he hydrogenand CO2are separated sing pressure

swing adsorption (PSA) units, the CO2 s vented to the atmosphere, nd the purified hydrogen (up to99.999% pure) is compressed e.g. to 75 bar as an input pressure or a long-distance ransmission ine).Carbon dioxide leaves he hydrogenproduction plant in two streams: n a diluted streamas a componentof the reformer stackgases about 30% of the total CO2) and in a concentrated tream hat is separatedfrom the hydrogen n the PSA unit (about 70% of the total). I I A schematicoverview is given in Fig. I,scheme a).Alternative schemes with CO2 sequestration an be designed. Scheme (b) shown in Fig. 1 is astraightforward extensionof scheme a); instead of venting the concentratedcarbon dioxide stream othe atmosphere, t is compressed nd injected into a depleted natural gas field.Scheme c) in Fig. 1 s an alternative option in which extra naturalgas s recovered rom the depletedfield, as a result of gas reservoir repressurization rom CO2 njection; we call this option enhancedgasrecovery (EGR). This extra gas contains a substantial raction of CO2 (although the co-produced CO2is only a small part of the CO2 njected). In scheme (c), we assume hat this extra gas is mixed withnatural gas extracted from a conventional natural gas field and used for hydrogenproduction.

INPUT DATA FOR THE CALCULATIONSHere we present he technical and cost data for the hydrogen plant, CO2 handling, and enhancednatural gas recovery that provide the basis for our calculations.

Hydrogen productionA hydrogen production plant has been described by Katofksy, I basedon natural gas that is 94.7'1cmethane,2.8% ethane,0.2% carbon dioxide and 2.3% nitrogen/argon (higher heating 39.7 MJ/mJ).Cost figures for the hydrogen production plant are updated rom this earlier study.9.IO or an overview,see Table 1. For the EGR option, the natural gas input is contaminatedwith CO2. Since the contami-nation on average s less han 4% (v/v) we assume hat this does not substantiallyaffect the character-istics of the plant as given in Table I.Compression, ransport and injection of carbon dioxide

The CO2 exiting the hydrogen production plant would be available at a pressureof about 1.3 bar 11For transportof the CO2 a pressureof 80 bar is required. From P-H diagramsof CO2Hendriks4derivesthat the electricity required o attain his pressure s 281 kJe/kg,assuminga five-stagecompressionandan isentropic compressorefficiency of 85%. Above 80 bar, the CO2 s a liquid; the electricity require-ment for compressionabove this pressurecan be calculated as 0.204kJe/kg/bar,'2 assuming an isen-tropic pump efficiency of 70%.The water content of CO2 as it leaves the hydrogen plant is 0.6% by weight. After the third andfourth compression tage, urther water removal akesplace n a knock-outdrum. At 55 bar the solubilityof water in CO2 s at a minimum and reachesa level of 0.06% by weight. Further drying of the CO2


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Hydrogren production from natural gas 163

AG.. "Y"'"f'"'"" 'M"..., .

B..,.,., .. ",--'" ., 'M"..., . ...

COl.'",... .

C,..Ca.2 , 'M"

'120. .,..., EGR,n...G ."' ..CO2. CO2"".." .

Fig. I. Schemes for the production of hydrogen out of natural gas, as they are considered in this paper. Inthese schemes,annual flow rates are given.


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Table]. Overview of the data for hydrogen production used in ourcalculations. The capital requirement is valid for an annual operationtime of 7880 hours per year (90% availability). The figures are validfor a plant with an annual production of 19 PJ per year of hydrogen

compressed to 75 bar.

Natural gas requiremment (GJ/GJ""",uct) 1.11Net electricity requirement (GJe/GJ"mduct) 0.029Capital requirement ($ per GJ"m.Ju"l/ye.,) 10.8Operation and maintenance ($/GJ"n,ojue,) 0.61

is possible, but is assumed o be unnecessary or pipeline transport, according to a Shell study.SCosts of equipment for the compressionof CO2 including the knock-out drum, are estimated o be61200 $/(ton/h).4When CO2 transport s required, here is some freedom o choose he pipeline diameter for a givenCO2 ransport ate. Hendriks et al13 ave performed an economic optimization of the pipeline diameterand found for a rate of 500 tonne CO2 per hour that the cost is minimized if the pipeline diameter schosen o be 0.5 m. We assume his diameter for a 500 tonne per hour CO2 flow rate and that pipelinecross sectionalarea s proportional to flow rate. In the casedescribedby Hendriks et all3 the pressuredrop along the pipeline is 0.12 bar/km. As a base case we assume hat 100 km of CO2 transport sneeded.Hendriks et all3 also derived a formula for the pipeline costs:

1= (300 + 1500 x do.9)x L,where I = investment in fl, we assume hat 1 fl = $0.56), d = pipeline diameter m), L = pipeline length(m). The author of another studyl4 calculates a different optimum pipeline diameter, but comes toabout he samecosts for CO2 transportation: about 3 $/ton CO2 for a distance of 100km (at a rate of500 tonne/hour).For injection of CO2 we assume hat new wells have to be drilled. In general more than one wellis required and a CO2 distribution systemhas to be built on the surface.The costs of the distributionsystem and the wells strongly depend on the field characteristics (depth, permeability). We assumefigures for an average ield and wells having an injection capacity of 40 ton/h, for which the estimatedcost s $96,000 per ton/h injection capacity.4 n all casesoperationand maintenance osts are assumedto be 3.6% of the investment including insurance).Enhancednatural gas recoveryBefore natural gas production begins, a natural gas field typically has a pressure up to 400 bar(depending on the depth of the field and the local pressuregradients). The gas field is consideredasdepleted when the pressurehas dropped to 20-50 bar, even though some of the original amount ofnatural gas remains in the field. If CO2 is injected, some additional natural gas can be produced as aresult of reservoir repressurization.We call this option enhancedgas recovery EGR).As far as the authorsare aware, here s only one publication in the open iterature in which enhancedrecovery of natural gas using CO2 njection is described,namely a report preparedby Shell.s.6 n thatstudy, various simulationswere carried out. Some simulation results were provided by Boutkan.'s Theyare valid for a prototype reservoirconsisting of 5 layers with varying permeabilities see Table 2). Theinitial natural gas content of this reservoir s 70 billion Nm3 (approx. 50 Mtonnes). The original gaspressure s 350 bar; primary production s stopped at a gas pressureof 30 bar.The simulation starts rom the assumption hat at one side of the reservoir,5500 ktonne of CO2 areinjected per annum. At the other side gas is extracted. Due to the fact that the injected CO2 travelsrelatively quickly through he most permeable ayers in the reservoir, he natural gas becomescontami-nated with CO2 after a few years. As soon as this happens, he gas production rate is reduced in thesimulation to such a level that the CO2 production rate does not exceed 5% of the injection rate (275ktonnes per annum). The production levels of CO2 and natural gas (assumed o consist entirely ofmethane n the Shell calculations) are depicted in Fig. 2, both for the prototype reservoir and for areservoir with a higher permeability contrast.

In our calculations, we assume ecovery rates that are averagedover the simulation periods. For the


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Table 3. Results of the cost analysis for the three schemes basecases).Scheme a b cCapital requirement million US$)Hydrogen plant 1082 1082 1082CO2 compressors 30 32CO2 pipelines 110 112CO2 njection 48 50Total 1082 1270 1275Annual costs (million US$)Capital costs 77 90 90O&M Hydrogen plant 61 61 61O&M CO2 compressors I IO&M CO2 pipelines 4 4O&M CO2 njection 2 2Natural gas for hydrogen production 333 333 303'Electricity for hydrogen production 41 41 4Electricity for CO2 compression 15 16Total 511 547 518Costs of hydrogen production ($/GJ-HHV) 5.11 5.47 5.18Avoided CO2 emission (ktonne/year) n.a. 3731 3724Specific CO2 mitigation costs ($/tC) n.a. 35 6'The benefitsof enhanced as recovery are concentratedn the first part of the carbondioxideinjection period and hence the financial benefits are somewhathigher than in the casethat the enhancedgas production would be evenly spread over the whole period. Wehave accounted or this effect by applying levelized discounting. The effect on the costof hydrogen s small: less than 1%.

RESULTS OF THE CALCULATIONSFor eachof the schemes, he averagemass and energy lows are indicated in Fig. 1. For the seques-tration options, CO2 emissions or hydrogen production are reducedby 70%. If hydrogenproduced viathese options were used in fuel-cell cars, the lifecycle CO2 emissions per kIn of driving would beabout 18% of the emissions or comparablegasoline internal combustion engines,compared o 35%without sequestration.17.'8The results of the cost analysis or eachof the schemes re presented n Table 3. The cost of hydrogenproduction s increased7% when he CO2 s sequesteredn a depleted natural gas field [Fig. 1: scheme(b) compared o scheme a)]. However, f CO2 sequestrations combined with EGR, the net additionalcosts are lower: for scheme c) the cost of hydrogen s less than 2% more than for scheme a). Costsof CO2 removal are $35/tC without EGR and $6/tC with EGR.In Table 4, a sensitivity analysis s presented. n most of the cases, he results are not very sensitiveto our assumptions.Cost ncreasesare within a range of about 2% around he basecase. However, hecost dependssensitivelyon the CO2 ransportdistance. f the transportdistance rom the CO2 production

plant to the well is increased rom 100 to 500 kIn, the cost of hydrogen ncreasesby about 9%; theTable4. Results of the sensitivity analysis or the three schemes.

Hydrogen costs Specific carbon$/GJ-HHV mitigation costs$/tCa b c b cBasecases (Table 3) 5.11 5.47 5.18 35 6Gas $5/GJ (insteadof$3/GJ) 7.33 7.69 7.19 35 -14Discount rate 10% (instead of 5%) 5.54 5.97 5.66 42 12Transport distance0 km (instead of 100km) 5.11 5.35 5.06 23 -6Transport distance 500 km (instead of 100 km) 5.11 5.94 5.66 82 54CO2 injection 3 times more expensive 5.11 5.57 5.28 45 17CO2 injection 3 times cheaper 5.11 5.43 5.14 32 3Higher permeability contrast 5.11 5.47 5.30 35 18


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net cost of CO2 removal s zero for 50 km of transportand increases y about$12/tC for each 100 kmof transport.Thus, attentionshould be given to identifying the optimal site for the hydrogen productionfacility. The choice depends, nter alia, on the relative costsof transmitting CO2 and hydrogenand onthe size of the production acility. For the plant sizes consideredhere (see Fig. I), the cost per 100kmof transmitting hydrogen n a pipeline sized such hat the pressure rop is 2.5 bar per 100 km (a pipelinehaving a 84-cm diameter) is estimated o be $ 0.05 per GJ of hydrogen produced,assuming hat thecapital cost for a hydrogenpipeline is 50% more than for natural gas.IS.19his is less than the cost of$ 0.I2/GJ for transmitting CO2 100km (see Table 4), suggesting t is desirable o site the hydrogenplant as close to the natural gas disposal site as possible. The situation s complicated, however, bythe fact that in serving distant hydrogenmarkets without sequestrationt would be less costly to transmitnatural gas from the natural gas field to a hydrogen production plant located near he hydrogenmarket.Savingswould arise wo ways-first from the lower cost of transmitting naturalgas compared o hydro-gen, and second rom the fact that with the hydrogen plant located near he market, he hydrogencouldbe sold at a pressure ower than the 75 bar level appropriate for a plant located near the natural gaswellhead that would provide hydrogen or a long-distance ransmission ine. For a casewhere hydrogenis pressurized o 20 bar at a hydrogen plant sited near a hydrogen market ocated 1100km from thenatural gas field compared o a 75 bar at a hydrogen plant sited near the gas field that would deliverhydrogen o the distant market at 20 bar, the cost of hydrogen has beenestimated or the former caseto be less than for the latter case by an amount equal to half the cost of transmitting hydrogen fromthe natural gas wellhead to the site near he hydrogenmarket. But in light of the much higher estimatedcost of CO2 transmissionper km' the total cost of hydrogen for the seqestration ptions would still beless when the required CO2 transmissiondistance s minimized. This issue equires further study, how-ever, as other different conditions might give different results.

CONCLUSIONSThe major findings of this assessment f hydrogen production from natural gas with sequestrationof the separatedCO2are the following: (i) When hydrogen s produced from natural gas with seques-tration of the separatedCO2, CO2emissions at the plant would be 70% less han without sequestration.If hydrogen produced with sequestrationof the separatedCO2 were used in fuel cell cars, lifecycleCO2 emissions per km would be less than 115 of those for gasoline internal combustionengine cars.(ii) As long as the original natural gas reservoir pressure s not exceeded, torageof the separatedCO2in depleted natural gas fields is a secure option for which the storage capacity s on average abouttwice as much carbonas was in the original natural gas. (iii) The cost of CO2 emoval in the productionof hydrogen from natural gas combined with sequestrationof the separatedCO2 in depleted naturalgas reservoirs s much lower than for CO2 removal schemes or thermal-electric power plants. (iv) Ifthe injection of CO2 nto depleted natural gas reservoirs s used to promote EGR, the net cost of CO2removal can be reduced o a very low level-evenzero in some nstances. v) For the situationsexamined,

the lowest costs for CO2 removal would arise when the hydrogen plant is sited at the depleted naturalgas field in which the recoveredCO2 would be stored, although further study is needed o ascertainwhether this would always be true. (vi) Detailed information on permeabilitiesand permeability con-trasts of natural gas fields and on the state of depletion of various natural gas fields is needed o carryout accurate assessments f this option in specific regions. Exploiting this option requires a planningof natural gas field depletion strategies ong before hydrogen production begins.Acknowledgements-The authors wish to express heir gratitude to V.K. Boutkan (Shell ResearchBV) for providing data on hissimulations of enhancedgas recovery. One of the authors (RHW) thanks the G.R. Dodge Foundation, he Energy Foundation,the W.A. Jones Foundation, and the Merck Fund for financial support for this research.

REFERENCES1. K. Blok, W.C. Turkenburg, C.A. Hendriks, and M. Steinberg, eds., Proc. of the 1st nt. Conf. on CarbonDioxide Removal, Energy ConversoMgmt. 33, 283 (1992).2. P. Riemer, The Captureof CarbonDioxide from Fossil Fuel Fired PowerPlants", EA Greenhouse asR&D Programme, heltenham, K (1993).


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3. P. Riemer ed., Proc. of the Int. Energy Agency Carbon Dioxide Disposal Symposium, Energy Converso Mgmt. ,34,711(1993). t,4. C. A. Hendriks, Carbon Dioxide Removalfrom Coal-Fired Power Plants, Kluwer Academic Publishers,Dord- J

recht (1994).5. "Carbon Dioxide Disposal From Coal-Based Combined Cycle Power Stations in Depletion Gas Fields inthe Netherlands", Ministry of Housing, Physical Planning and Environment, Publikatiereeks Lucht, No. 91(December 1990).6. M. J. van der Burgt, J. Cantle, and V. K. Boutkan, Energy ConversoMgmt. 33,603 (1992).7. R. H. Williams, TechnologyReview 21-30 (April 1994).8. R. H. Williams, "Fuel Cells, Their Fuels and the US Automobile", paperprepared or the First Annual WorldCar 2001 Conference n Riverside, California, Center or Energyand Environmental Studies,Princeton Univer-sity, Princeton, NJ, USA (June 1993).9. R. H. Williams, E. D. Larson,R. E. Katofsky, and J. Chen, Energy or SustainableDevelopment, , 18 (1995).10. R. H. Williams, E. D. Larson, R. E. Katofsky, and J. Chen, "Methanol and Hydrogen from Biomass forTransportation, with Comparisons to Methanol and Hydrogen Production from Natural Gas and Coal",PU/CEES Report No. 292, Center or Energy and Environmental Studies,PrincetonUniversity, Princeton, NJ,USA (July 1995).II. R. E. Katofsky, "The Production of Fluid Fuels from Biomass", PU/CEES ReportNo. 279, Center for Energyand Environmental Studies, Princeton University, Princeton, NJ, USA (June 1993).12. FachverbandKohlensiiure Industrie, "Eigenschaftender Kohlensiiure", Koblenz, Germany (1989).13. C. A. Hendriks, J. C. M. FarIa, and K. Blok, "Verwijdering en opslag van CO2 bij elektriciteitsopwekking

(Recovery and Storage of CO2with Power Plants)", Departmentof Science,Technology and Society, UtrechtUniversity (1992).14. O. Stovholt, Energy ConversoMgmt. 34. 1095 (1993).15. Y. K. Boutkan, Shell ResearchBY, KSEPL, Rijswijk, The Netherlands,Written Communication (2 Nov-ember 1993).16. A. Faaij, K. Blok, and E. Worrell, "Worldwide Comparison of Efficiency and Carbon Dioxide Emissions ofPublic Electricity Generation", Department of Science,Technology and Society, Utrecht University (1994).17. R. H. Williams, "Fuel Decarbonization or Fuel Cell Applications and Sequestrationof the SeparatedCO2",in R. U. Ayres et al eds., Ecorestructuring, UN University Press,Tokyo (forthcoming, 1996).18. R. H. Williams, "Fuel Decarbonization or Fuel Cell Applications and Sequestrationof the SeparatedCO;',PU/CEES Report No. 295. Center or Energy and Environmental Studies,PrincetonUniversity, Princeton, NJ,USA (April 1995).19. D. Christodoulou, "Technology and Economics of the Transmissionof GaseousFuels via Pipelines". Masterof Science n Engineering Thesis, Departmentof Mechanical and AerospaceEngineering,School of Engineer-ing and Applied Science,Princeton,NJ. USA (April 1984).

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hydrogen production natural gas

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