hydrogen production with psa

\PERGAMON International Journal of Hydrogen Energy 13 "0888# 394313

9259!2088:88:,19[99 0888 International Association for Hydrogen Energy[ Published by Elsevier Science Ltd[ All rights reservedPII] S 9 2 5 9 ! 2 0 8 8 " 8 7 # 9 9 0 9 4 ! 9

Economics of hydrogen recovery processes for thepuri_cation of hydroprocessor purge and o}!gases

S[ Peramanu\ B[G[ Cox\ B[B[ PrudenUniversity of Calgary\ Calgary\ Alberta\ Canada

Abstract

Pressure swing adsorption\ membranes and countercurrent gas!liquid contacting were evaluated for the puri_cationof hydrocracker and hydrotreater purge and o}!gases[ Industrial cases relevant to upgrading and re_ning were examined\and the most economic and technically suitable options were determined[

For pressure swing adsorption "PSA#\ surprisingly\ the best economics were at lower recoveries\ when tail gas metfuel gas pressure requirements[ This eliminated tail gas compression which is relatively expensive[ Membranes weremarginally better than PSA at higher feed pressures "6[9 MPa#\ and there was no advantage in combining theseprocesses due to loss of economies of scale[ Countercurrent gas!liquid contacting\ which recovers hydrogen near feedpressure\ has an advantage over both PSA and membrane when the feed pressure is high[

A sensitivity analysis indicated that high feed gas capacity\ high purity\ and a low fuel gas price favor hydrogenrecovery processes[ The impact of increased recovery and purity on the economics of hydrogen recovery was negligiblecompared to the e}ect of unit sizes "economy of scale#[ 0888 International Association for Hydrogen Energy[Published by Elsevier Science Ltd[ All rights reserved[

Abbreviations] CC!ABS\ Countercurrent packed column absorber unit^ MEMB\ Membrane unit^ MIX!SEP\ Mixer!separator unit^ NO!HRU\ No hydrogen recovery unit^ PSA!HP\ Pressure swing adsorption unit with high pressure tailgas^ PSA!LP\ Pressure swing adsorption unit with low pressure tail gas[

0[ Introduction

The need for hydrogen in re_ning is expected to growdue to more stringent environmental regulations\ pri!marily in the decrease in aromatics in automotive fuels[Hydrocracking processes will come on stream and beexpanded to upgrade more low quality heavier feedstocks\ and hydrotreating processes are needed toimprove the quality of gasoline\ diesel and furnace fuels[As the demand for hydrogen grows\ its management andconservation as a basic raw material is becoming increas!ingly more important to ensure optimum economics[Additionally\ recent studies by the Other Six LeasingOperations "OSLO# group and by the Alberta Chamberof Resources "ACR# identi_ed high pressure hydro!cracking as the most economic options for future upgra!

Corresponding author[ E!mail] subodhacs[ucalgary[ca

ding of plants[ These plants will use more hydrogen athigher pressures than existing plants\ and as the hydrogenfacilities can represent over one!third of the upgradercost\ it is important to carefully study hydrogen man!agement options[

Hydrocracking and hydrotreating operations generatean o}!gas stream of unreacted hydrogen\ combined withthe gas!make from the reactor[ This stream which is atpressures of 02[719[6 MPa typically contains 6974)hydrogen\ with C0C5\ H1S and other impurities[ To pre!vent a buildup of these impurities during recycle to thehydroprocessing reactor\ either a purge stream is takenor the entire stream is processed as shown in Fig[ 0[The resultant o}!gas stream is combined with makeuphydrogen from a hydrogen plant and recycled to thehydroprocessor unit at constant hydrogen purity[ If thepurge gas stream is of high enough purity and pressure itcan be cascaded to downstream hydrotreaters\ and if itis low pressure or low purity it will likely be used asfuel gas[ Neither of these practices is always the most

S[ Peramanu et al[ : International Journal of Hydrogen Energy 13 "0888# 394313395

Fig[ 0[ CANMET hydrocracker high pressure hydrogen recovery scheme[

economic and it may be economically advantageous torecover hydrogen from this purge gas in a hydrogenrecovery unit "HRU# and use it as part of the makeuprequirements[

To justify recovering hydrogen from purge or o}!gas\it is important to clearly identify the cost and incentiveson which the comparisons will be based[ If the capacityof an existing hydrogen plant is limited\ recovery ofhydrogen from waste streams may postpone the need forincremental hydrogen production facilities or additionalhydrogen plants[ Any hydrogen that can be recoveredwill reduce the size of a new hydrogen plant\ which canreduce the investment for this new plant or lower theoperating costs for natural gas feed and fuel to an existingplant[ It will also be advantageous to recover the hydro!gen at the highest possible pressure to reduce compressioncosts[ Depending on the pressure of the recovered hydro!gen\ the size and operating horsepower of the makeupcompressor may be reduced if recovered hydrogen isavailable as feed to it|s second or third stage[ The tail gasfrom the hydrogen recovery unit is used either as fuelor as feed to hydrotreaters\ depending on its hydrogencontent and pressure[ Its value as fuel gas will probablybe less than hydrotreater feed gas[ Fuel gas is valued forits energy content as equivalent natural gas\ and hydro!treater feed gas is valued for its hydrogen content[ Theeconomic incentives for recovering hydrogen may di}erfor a new plant vs a retro_t to an existing plant whereequipment already exists[ For a new plant\ depending onreliability and operating factors\ the designer may notwant to downsize the hydrogen plant based on HRUcapability[ In this case\ if hydrogen makeup capacityand compression is already installed\ only operating costsavings are realized by the HRU[

The most common processes for recovering hydrogen

from hydrocracker o}!gas are pressure swing adsorption\selective permeation using polymer membranes\ cryo!genic separation\ and gas!liquid contacting[ To selectwhich technology is best for a given application\ adetailed evaluation is required that examines related pro!cess parameters\ project considerations and economics[

Recovery of hydrogen has been studied extensivelyby academia and industry[ The selection of hydrogenpuri_cation processes for various re_nery applicationsand the need to use the right type of equipment for agiven situation have been studied by number of authors0\ 1\ 2[ Bollinger et al[ 3 analysed how membranes canimprove the economics of using purge in a hydrocrackerapplication and Spillman 4 discussed how the use ofmembranes can justify the recovery of hydrogen in vari!ous re_nery applications[

Suppliers of puri_cation equipment market di}erentprocesses to recover hydrogen\ and provide assistancein choosing the right system for each application[ Thecommonly known suppliers are UOP\ Air Products andDupont[ An article 5 was published by UOP that dis!cusses the principles of operation of each process\ theproject characteristics to be considered and the selectionguidelines for various applications[ UOP have also pub!lished an article 6 that discusses the strategies for man!aging hydrogen for various feeds and products[ The sup!pliers of puri_cation equipment have done extensiveresearch on improving the e.ciency of existing sep!aration technologies[ However\ as manufacturers con!tinue to improve the e.ciency and reduce the cost of theirpuri_cation equipment\ the selection and optimization ofa hydrogen puri_cation process must be re!evaluated tore~ect current economics[

The primary objective of this study was to identifyfruitful areas for hydrogen separation research\ and to

S[ Peramanu et al[ : International Journal of Hydrogen Energy 13 "0888# 394313 396

show where di}erent commercial schemes could be moreeconomic[ Four industry case studies were undertakenin order to compare the separation technologies underdi}erent feed purity and pressure conditions[ Speci_cresults from each study case were used to reach someoverall conclusions\ and a number of sensitivity caseswere run to analyse the impact of project size\ feed purity\fuel gas price\ improved recovery and the potential fornew technology[

1[ Separation processes

The separation processes\ namely pressure swingadsorption\ polymeric membranes\ cryogenic separationand gas!liquid contacting are based on di}erent sep!aration principles\ and therefore the process charac!teristics di}er signi_cantly[ New separation technologiesare also emerging that could improve recoveries or pro!duce hydrogen at higher product pressures[

1[0[ Pressure swin adsorption "PSA#

PSA is a hydrogen recovery process in which theimpurities "CH3\ CO1\ CO\ H1O etc[# in a gas stream areremoved in adsorbent beds[ The adsorbents are normallymade of molecular sieve\ activated carbon\ activated alu!mina or silica gel depending on speci_c application[ Theimpurities adsorbed at higher partial pressure aredesorbed at lower partial pressure[ Since very little hydro!gen is adsorbed relative to methane and other light hydro!carbons\ high pressure hydrogen is recovered[ Theadsorber beds are regenerated by reducing the pressurefrom feed to tail gas pressure and then purging with aportion of the product hydrogen[ The operation is on acyclic basis where each bed is controlled at a di}erentstep in its sequence[ Since there is a low pressure drop"9[96 MPa# through the PSA unit\ product hydrogen isavailable near feed pressure[ The process features veryhigh product purity "88)# and moderate hydrogenrecovery "5489)# depending on the tail gas pressure[The recoveries are moderate because a part of the producthydrogen is normally utilized for regenerating the beds[A correlation by UOP 5 indicated that recovery is fairlyinsensitive to feed pressure with 02[6816[47 MPa beingabout the optimum[ It was also found that tail gas pres!sure has the greatest e}ect on recovery\ with low pressure"9[923 MPa# tail gas having 0419) better recovery than9[30 MPa tail gas[ However the cost to compress lowpressure tail gas to enter the 9[30 MPa fuel gas systemcan be signi_cant and the operating pressure of a PSAsystem must be optimized[

PSA systems require an elaborate interconnecting pip!ing system with process control to continually cycle thevalves through their pressurization and depressurizationsequence[ Up to 01 adsorbers can be operated in concert

for high ~ow rates and when high purity is required[ Theadsorbents are very durable and normally last the life ofthe project[

PSA systems are insensitive to changes in feed com!position giving constant product purity and recovery[They also have a good turndown ratio\ and are veryreliable despite their complex valve system[ Expansionwill likely require a complete new unit\ and bed diametersare limited\ as plug ~ow operation is desirable[

1[1[ Membrane separation

Membrane separation processes use di}erences in rela!tive permeation rates of the feed gas to e}ect a separation[Faster permeating components in the feed\ such as hydro!gen\ pass through the membrane to the low pressure sideby dissolving into the polymer membrane on the highpressure side and di}using through to the low pressureside[ The slower permeating hydrocarbons are retainedon the high pressure side[ High permeation rates are dueto high solubilities\ high di}usivities\ or both[ The drivingforce is the di}erence in partial pressure\ with the highestdriving force giving the highest recovery[ The polymericmembranes used for separation are cellulose acetate\polyacetate\ polysulfonate\ polyamide and polyimide[Membrane systems recover hydrogen at moderate purity"8984)# and moderate recovery "7489)#[ Additionalmembrane area is required for higher recoveries[ A cor!relation by UOP 5 indicated a tradeo} between recoveryand purity\ with a signi_cant decrease in recovery with aslight increase in purity[

A membrane unit is installed as a skid!mounted mod!ule having either hollow tubes or ~at sheets for the mem!brane itself[ A preheater exchanger and separator isrequired to knock out any heavy components that couldcondense and damage the membrane[ Hydrogen sulphidecan damage the membrane and must be removed fromthe feed gas\ usually by amine treating[ The membraneshave to be replaced every _ve years[ The permeate hydro!gen pressure is usually taken as low as possible to max!imize the pressure di}erential[ This pressure is usuallythe same as that of the hydrogen plant so both streamscan be fed to the _rst stage of the makeup compressor[The tail gas pressure is near feed pressure and is let downfor use as fuel gas[ Energy from the let down in pressurecould drive a turbine if the ~ow rate is signi_cant[

Changes in feed composition will have a large a}ecton product purity[ A unit can be turned down with littlepenalty in recovery[ Membranes have no moving partsand are extremely reliable[ Additional modules can beadded for expansion or increased recovery[

1[2[ Cryoenic separation

The cryogenic separation processes 1 utilize partialcondensation to remove the hydrocarbon impurities from


the product hydrogen[ The process takes advantage ofthe di}erences in volatilities of the feed components toe}ect the separation[ Hydrogen has a high volatility com!pared to methane and other light hydrocarbons[ Thehydrocarbon impurities are condensed by Joule!Thomp!son refrigeration derived from throttling the condensedliquid hydrocarbons[ The process is best used when thefeed pressure is low\ the feed hydrogen content is lessthan 39) and there are higher concentrations of heavierhydrocarbons which can be easily condensed[ There isalso a trade!o} between hydrogen purity\ recovery\ andtail gas pressure with moderate purities "8984)# beingachieved with high recoveries "8984)# when the tail gaspressure is kept low "9[96 MPa#[

Cryogenic separation is best at high throughputs orwhen hydrocarbon components must be isolated[ How!ever it is cost intensive and has less ~exibility in processingvarying feed compositions[ Sometimes the processrequires supplemental refrigeration[ The process is con!sidered less reliable than PSA or a membrane and thefeed needs pretreatment or else freezing can occur[ Dueto apparent disadvantages of cryogenic separation forhydrogen puri_cation\ it was not considered in this study[

1[3[ Gas!liquid contactin

Gas!liquid contacting has been used for many years topurify gas streams[ The absorption of light hydrocarbonsfrom a hydrogen stream into hydrocarbon solvents istermed the sponge oil process[ The hydrocarbon solventsused for absorption can be either pure or mixed[ Themixed solvents are obtained from re_nery streams whichlie in the range of gasoline to gas oil[ One importantadvantage of this process is that the product hydrogenleaving the system is near feed pressure which reducemakeup compression requirements[ In the mixer!sep!arator gas!liquid contacting process the high pressurehydrogen stream is contacted with a liquid in a highpressure unit where the hydrocarbon gases are selectivelyabsorbed in the liquid[ The gas and liquid phases are thenseparated in a high pressure separator to obtain puri_edhydrogen[ The liquid containing dissolved gas is regen!erated by ~ashing at a low pressure[ The regeneratedliquid is recycled to the mixer[ The desorbed gas from thelow pressure separator will be at a lower hydrogen con!tent and is typically used as fuel gas[

An advanced form of this process has been researchedby Peramanu 7 to identify process improvements usinga countercurrent contacting unit and better solvents[ Thisproject was carried out at the University of Calgary as apart of the Industrial Hydrogen Chair Program[ Coun!tercurrent contacting provided higher purity and recov!ery than a mixer!separator unit because of a higher con!centration driving force[ Solvents such as iso!octane\ n!octane\ 0!octane and methyl cyclohexane are moste.cient and selective for absorbing light hydrocarbons

than conventional solvent which is modeled by toluene8[ It is expected that re_nery and chemical streams con!taining components with a structure similar to these sol!vents would be good candidates for the sponge oilprocess[ It was also identi_ed 09 that the presence ofethane in the hydrogen stream increases methane sel!ectivity and the addition of a heavier para.n compound"eicosane# in toluene increases the absorption capacityof a toluene solution[ Mass transfer measurements werecarried out 00 as well\ in a high pressure packed columnabsorber\ to collect design data up to 06[13 MPa and at11>C[

The countercurrent absorption process provides amoderate purity "7484)# and high recovery "7484)#[Pretreatment is generally not required since the recir!culating solvent is normally insensitive to the impuritiespresent[

1[4[ New technoloies

New technologies are being developed such as vacuumswing adsorption "VSA#\ advanced pressure swingadsorption "APSA# and selective surface ~ow "SSF#membranes[ The performance and cost expectations indi!cate further potential for improving the economics ofhydrogen recovery[

1[4[0[ Vacuum swin adsorptionThis process is under development by Air Products

and Chemicals Ltd[ In this process the tail gas side of theadsorber is under partial vacuum\ with normal pressureson the feed side[ This may not be attractive for hydrogenseparation as the tail gas requires an extensive recom!pression[ It would\ perhaps\ be better in a separationwhere the tail gas can be vented[

1[4[1[ Advanced pressure swin adsorptionAn advanced pressure swing adsorption for hydrogen

recovery is currently under development by HighquestEngineering 01[ This system operates at low workingpressures and will separate hydrogen from low con!centration o}!gases[ The system uses a proprietary con!trol operation using multiport valves instead of multiplebed cycles with pressure equalization between bedsundergoing pressurization and depressurization steps[The rotary multiport valve design allows higher cyclefrequencies and smaller beds[

1[4[2[ Selective surface ~ow membraneSelective surface ~ow membranes are being developed

by Air Products and Chemicals Ltd[ and are now com!mercially available[ The hydrogen separation e.cienciesof selective surface ~ow membranes in the presence ofother components have been studied 02\ 03[ Unlikeother polymeric membranes the selective surface ~owmembranes allow non!hydrogen components "CH3\ CO1\


CO\ H1S etc[# to ~ow through and thereby retain theproduct hydrogen near feed pressure[

2[ Factors in~uencing the economics

Process variables which must be de_ned and analysedinclude feed composition\ feed and process pressure\ ~owrate\ HRU product purity\ makeup compressor feed andmakeup compressor interstage pressures[ Higher purityhydrogen is usually more valuable for hydrotreater feedor as makeup hydrogen[ Higher pressure product hydro!gen will be more valuable as this reduces makeup com!pression costs 04[ Tail gas from the hydrogen recoveryunit will be more valuable as fuel gas if its pressure isabove 9[3 MPa[ Any tail gas at lower pressure will requirecompression to enter the fuel gas system[ The feed andinterstage pressures of the makeup compressor are alsovery important and set the optional product pressures[

Project related factors are not as well de_ned butshould be included as part of the decision criteria inselecting a hydrogen recovery unit[ These include opera!ting ~exibility\ turndown\ reliability\ maintenance\ andthe capability for future expansion[ If the pressure orcomposition of the o}!gas changes as a result of variationin the hydroprocesssor operation\ the hydrogen recoveryunit will need to maintain performance[ When a com!bination of purge streams are sent to the hydrogen recov!ery unit\ a change in composition or ~ow rate of any onestream will a}ect the overall feed composition[ A goodhydrogen recovery unit must be able to handle less than099) feed capacity[ Operation of a hydroprocessordepends on a reliable supply of hydrogen feed and if partof the makeup hydrogen is coming from the hydrogenrecovery unit\ this unit must have close to 099)reliability[ If there could be a need to expand the hydro!gen recovery unit later\ this will have to be factored intothe unit design[

3[ Study basis

Four case studies were analysed to evaluate the econ!omics of di}erent recovery process options]

"0# CANMET Hydrocracker "High pressure o}!gas#["1# Petro!Canada Hydrocracker "High pressure purge

gas#["2# Imperial Oil Upgrader "Moderate pressure o}!gas#["3# Syncrude Hydrotreater "Low pressure purge gas#[

In order to make a fair comparison each case studyand its recovery option were evaluated in the samemanner[ The material balance for each recovery optionwas simulated using the HYSIM process simulator sof!tware to develop the feed basis\ calculate the product and

tail gas rates and composition\ and compute compressorhorse power requirements[ The material balance infor!mation was then used to calculate utility requirements\the sizing basis for each major piece of equipment\ andcapital and operating costs[ All the costs represented inthis article are in Canadian dollars[ A material balancewas made around the hydroprocessor based on the con!sumption of hydrogen in the reaction\ gas make in thereactor\ solution losses and recycle gas rate to determinethe o}!gas rate and composition[

3[0[ Capital cost

Capital costs were based on total installed costs thatincluded all equipment costs and transportation\ instal!lation costs\ indirect costs such as project managementand support facilities\ and other non!equipment such ascivil\ electrical\ instrumentation\ piping and engineering[Capital costs for the hydrogen puri_cation system\incremental makeup hydrogen plant\ makeup and recyclecompressor\ and fuel gas compressor were costed usingImperial Oil|s cost correlations and vendor input[

Di}erent equipment is used for each hydrogen recov!ery process depending on the process conditions[Depending on the recovery option this may include allor part of the following]

, a complete stand!alone steam methane reforminghydrogen plant

, a PSA unit or a membrane unit with feed knockoutdrum and product cooler

, countercurrent absorption column and liquid cir!culation pump

, static mixer and high pressure separator, high and low pressure separators, amine absorption and regeneration towers with recir!

culating pumps, 2 stage reciprocal compressor with interstage coolers

"makeup compressor#, 2 stage reciprocal compressor with interstage coolers

"hydrogen product compressor#, oil injected screw compressor "fuel gas compressor#

3[1[ Operatin cost

Operating costs included raw materials\ utilities\energy\ replacements costs and other _xed and variablecosts such as labor and maintenance[ The energy costsdepend on the predicted price for natural gas and elec!tricity[ The natural gas and the fuel gas were valuedfor their energy content[ Operating costs were calculatedbased on Cdn ,1[9:GJ for natural gas feed and fuel tothe hydrogen plant\ and Cdn ,9[93:kwh for electricalpower[


3[2[ Lost fuel as cost

When a HRU is used the tail gas is used as fuel gas\whereas\ for the option of not using any HRU "{noHRU|# the entire feed stream is used as fuel gas[ There!fore\ the fuel gas from {no HRU| will be of high volumeand hydrogen purity than HRU fuel gas[ The tail gaswhen used as fuel gas was valued same as that of naturalgas at Cdn ,1[9:GJ[ Since it was necessary to account theHRU fuel gas credits with respect {no HRU| fuel gascredit\ the lost fuel gas cost for each HRU was calculatedby subtracting it|s fuel gas credit from that of {no HRU|[

3[3[ Economic comparison

The process recovery options for each case study werecompared on the same economic basis[ The capital chargewas calculated by depreciating the total capital cost over09 years at 09) return on investment and no salvage[The total processing cost\ which is the sum of the capitalcharge and the operating cost\ could not give a fair com!parison since it did not include the lost fuel gas cost[Therefore\ the economic comparison was made using theresultant cost which is the sum of capital charge\ opera!ting cost and lost fuel gas cost[

4[ CANMET hydrocracker

The CANMET|s hydrocracking process was used as abasis for the _rst case study[ The hydrocracker plant wasassumed to process 2079 m2:d of Cold Lake vacuumbottoms[ The hydrocracker o}!gas has a purity of 63)hydrogen at 02[23 MPa[ A simpli_ed process ~ow diag!ram is shown in Fig[ 0 where the dotted lines representoptional streams or units depending on the HRU used[The product hydrogen is mixed with makeup hydrogenfrom a high purity steam methane reforming unit toadjust the recycle stream to 74) hydrogen and 4[986std Mm2:d[ These constraints together with a makeuphydrogen purity of 88[8) limit the recovery of hydrogenby the HRU for a given purity[

Recovery options were PSA with 9[0 MPa tail gasand 76) recovery\ PSA with 9[3 MPa tail gas and 56)recovery\ membrane with 89) recovery\ mixer!separatorwith toluene solvent and 89) recovery\ countercurrentabsorber with iso!octane solvent and 85) recovery\ andthe option of {no HRU|[ In the PSA and membraneoptions\ a small purge stream is processed to remove gasmake impurities\ whereas the whole o}!gas stream istreated using gas!liquid contacting[

Table 0 gives the material balance for each option andTable 1 gives the cost sheet[ Figure 1 gives the combinedcapital\ operating and lost fuel gas costs on an annualcost basis[ The gas!liquid contacting processes gave bettereconomics than the membrane and PSA options due to

Fig[ 1[ CANMET hydrocracker high pressure hydrogen recov!ery economics[

reduction in the cost of compression as given in Table 1[The countercurrent absorber has better economics thanthe mixer!separator since both mixing and phase sep!aration occur in a single unit[ With higher recovery thecountercurrent absorber needed a smaller hydrogenplant[ It was found that PSA with a low tail gas pressure"9[0 MPa# gives higher costs than that with a high tail gaspressure "9[3 MPa# because of the cost of compression[Overall\ recovery of hydrogen from the hydrocrackerwould realize annual savings of Cdn ,00 million withimplementation of a countercurrent absorber system[

5[ Petro!Canada hydrocracker

A Petro!Canada hydrocracker was used as the basisfor the second case study[ The simpli_ed diagram in Fig[2 also shows the hydrogen recovery from low pressureo}!gas[ This is considered in the sensitivity analysis[ Cur!rently 9[005 std Mm2:d of high pressure o}!gas is purgedfrom a total o}!gas of 4[893 std Mm2:d to remove 9[9954std Mm2:d of impurities not removed elsewhere as lowpressure solution o}!gas in the process[ The recycle gasreturned to the reactor is adjusted to 5[628 std Mm2:dand 84) purity by adding 9[840 std Mm2:d of 88[7)makeup hydrogen[ The o}!gas stream from the hydro!cracker has a purity of 83[3) hydrogen and a pressureof 06[47 MPa[ Currently this hydrocracker purge gasstream\ containing 9[009 std Mm2:d of makeup hydro!gen\ is used as part of the makeup hydrogen to a distillatehydrotreater[

In the analysis the rate of purge gas feed to the HRU is


Table 0CANMET hydrocracker o}!gas material balance

Units PSA!LP PSA!HP MEMB MIX!SEP CC!ABS NO!HRU

Feed basisVolumetric rate std Mm2:d 0[194 0[194 0[238 3[365 3[365 0[191Temperature >C 26[85 26[85 26[85 26[67 26[67 27[99Pressure MPa 02[23 02[23 02[23 02[23 02[23 00[66H1 purity ) 62[5 62[5 62[5 62[5 62[5 62[5

HRUH1 recovery ) 75[86 55[43 78[87 78[82 84[58 9[9Product rate std Mm2:d 9[685 9[598 9[845 2[615 2[805 9[9Product pressure MPa 1[65 1[65 1[65 02[96 02[96 9[9Product H1 purity ) 88[7 88[7 85[1 68[4 79[4 9[9Tail gas rate std Mm2:d 9[398 9[485 9[282 9[609 9410 0[191Tail gas pressure MPa 9[03 9[44 6[33 0[27 0[27 00[66Tail gas H1 purity ) 11[6 35[7 07[6 35[6 16[1 62[5Liquid circulation rate m2:h 9[9 9[9 9[9 441 397 9[9Pump power kW 9[9 9[9 9[9 203[65 121[54 9[9

Amine scrubberFeed rate std Mm2:d 3[355 3[355 3[355 9[609 9\410 9[336Feed pressure MPa 02[37 02[37 02[37 0[27 0[27 02[37Product rate std Mm2:d 042[45 042[45 042[45 11[36 04[68 042[45Amine rate m2:h 69 69 69 69 69 69Pump power kW 28[81 28[81 28[81 28[81 28[81 28[81

H1 recycleRecovered H1 rate std Mm

2:d 9[683 9[597 9[808 1[852 20[42 9[9SMR H1 rate std Mm

2:d 0[046 0[233 0[039 0[258 00[79 0[838Bypass H1 std Mm

2:d 1[270 1[270 1[162 9[9 9[9 1[272Total recycle H1 rate std Mm

2:d 3[221 3[221 3[221 3[221 3[221 3[221Recycle H1 purity ) 74[99 74[99 73[88 73[88 74[99 74[99

Electric powerHRU kW 0[5 0[5 9[6 9[9 9[9 9[9HRU tail gas compressor kW 0106 9[9 9[9 9[9 9[9 9[9H1compressor stage 0 kW 1524 1823 1714 0664 0429 1415H1compressor stage 1 kW 1323 1600 1509 0696 0361 1329H1compressor stage 2 kW 2642 2646 2644 2685 2685 2648

Cooling waterProduct cooler m2:h 0[0 9[8 05[4 9[9 9[9 9[9Intercooler stage 01 m2:h\ 57 57 62 35 28 54Intercooler stage 12 m2:h 51 51 56 30 25 51

SteamHRU kg:h 9 9 0269 9 9 9

kept constant at 9[005 std Mm2:d[ Recovery of hydrogenfrom an HRU would be combined with the maximumproduction of the hydrogen plant "9[840 std Mm2:d# toincrease the total hydrogen feed to the hydrocracker\allowing increased throughput to that unit[ The optionsanalysed were PSA with 9[0 MPa tail gas and 78) recov!ery\ PSA with 9[3 MPa tail gas and 65) recovery\ mem!brane with 89) recovery\ countercurrent absorber withiso!octane solvent and 89) recovery and {no HRU|[ Thetail gas from each option was used as fuel gas\ although the

tail gases from some of the options were rich in hydrogen[The material balance for each recovery option is sum!

marized in Table 2 and the cost sheet is given in Table 3[The comparison of combined capital\ operating and lostfuel gas costs on an annual cost basis is represented inFig[ 3[ An absorber operated at 89) recovery is shownto be the best process option[ However\ it is evidentthat there is little incentive to add an HRU due to pooreconomies of scale for the HRU relative to the cost ofthe hydrogen plant and makeup compressor[


Table 1CANMET hydrocracker o}!gas cost sheet

Basis PSA!LP PSA!HP MEMB MIX!SEP CC!ABS NO!HRU

Capital costs "Cdn M,#H1 plant 59[91 55[04 48[34 55[85 59[79 73[13HRU 01[47 09[77 6[19 8[12 8[94 9[9Amine unit 02[46 02[46 02[46 00[94 09[69 02[46

COMP:HXHRU tail gas compressor 6[721 9[9 9[9 9[9 9[9 9[9Makeup H1 compressors 40[24 32[41 34[23 24[89 22[42 32[99

Sub!total 026[41 023[01 014[45 012[03 003[97 039[70

Operating costs "Cdn M,:y#H1 plant

Natural gas ,1[9:GJ 00[55 02[43 00[38 02[79 00[78 08[53Electricity ,9[93:kWh 9[14 9[18 9[14 9[29 9[14 9[31Other "per std Mm2:d# ,9[355M:y 9[41 9[59 9[40 9[50 9[42 9[76Fixed "per std Mm2:d# ,9[585M:y 9[66 9[78 9[65 9[80 9[67 0[29

HRUSteam ,3[28:t 9[9 9[9 9[9490 9[9 9[9 9[9Cooling water ,9[92:m2 9[9 9[9 9[993 9[9 9[9 9[9Power ,9[93:kWh 9[990 9[990 9[9 9[094 9[966 9[9Replacement capital 09) of cap 9[9 9[9 9[619 9[9 9[9 9[9

Amine unitLean pump ,9[93:kWh 9[902 9[902 9[902 9[902 9[902 9[902Steam ,1[9:GJ 9[249 9[249 9[249 9[249 9[249 9[249

COMP:HXHRU tail gas compressor ,9[93:kWh 9[394 9[9 9[9 9[9 9[9 9[9Makeup compressor ,9[93:kWh 1[825 1[825 2[959 1[312 1[152 1[890Cooling water ,9[93:kWh 9[922 9[922 9[928 9[911 9[908 9[921

Sub!total 05[82 07[55 06[13 07[42 05[07 14[42

Lost fuel gas costs "Cdn M,:y#Fuel gas value credit ,1[9:GJ 09[14 00[68 09[17 02[36 00[81 05[65

Lost fuel gas 5[40 3[86 5[37 2[18 3[73 9[9

Economics "Cdn M,:y#Capital charge 24[56 23[68 21[46 20[83 18[48 25[41Operating costs 05[82 07[55 06[13 07[42 05[07 14[42Lost fuel gas 5[40 3[86 5[37 2[18 3[73 9[9

Total 48[00 47[31 45[18 42[65 49[50 51[94

6[ Imperial oil upgrader

A representative heavy oil upgrader\ based on ImperialOil|s planned project for Cold Lake\ was used as the basisfor the third case study[ A preliminary design had beencompleted for a plant but the project was later shelved[Data from this preliminary design\ which are internallyconsistent and realistic\ were used for this case[ A sim!pli_ed process diagram is shown in Fig[ 4[ Hydrogen isrecovered from high and low pressure purge gases fromthe high conversion MICROCAT hydroprocessor"MRC#\ naphtha distillate hydrotreater "NDHT# and gasoil hydrotreater "GOHT# units[ The low pressure purgegases are compressed and combined with the high pres!

sure gases for feed to the HRU[ For a feed of 5259 m2:d\a combined purge of 0[234 std Mm2:d at 7[85 MPa is fedto the HRU[

Recovery options were PSA with 9[0 MPa tail gasand 76) recovery\ PSA with 9[3 MPa tail gas and 56)recovery\ membrane with 89) recovery and {no HRU|[The gas!liquid contacting processes were not evaluatedfor this case because these processes are not economicalfor feed pressures less than 09[23 MPa[ All purge gaseshave been presweetened in their own amine scrubberunits to remove H1S[ High purity makeup hydrogen fromtwo steam methane reforming plants is added to therecovered hydrogen to return 5[062 std Mm2:d of hydro!gen to the hydroprocessors[ This makeup is compressed


Fig[ 2[ Petro!Canada hydrocracker high and low pressure hydrogen recovery schemes[

Fig[ 3[ Petro!Canada hydrocracker high pressure hydrogenrecovery economics[

to 06[13 MPa in a three!stage reciprocal compressor[ Tailgas from the HRU is sent to fuel gas in all the options[It was identi_ed 05 that recovery systems with combinedPSA and membrane would not be advantageous sincethey su}er from economies of scale[

Table 4 gives the material balance for the upgraderand Table 5 gives the cost sheet[ Figure 5 compares thecombined capital operating and lost fuel gas costs on anannual cost basis[ PSA with high pressure tail gas is themost economic process compared to other options[ Insummary\ recovery of hydrogen from the hydroprocessorcould realize annual savings of Cdn ,1[4 million[

7[ Syncrude hydrotreater

Syncrude|s hydrotreater purge gas was used as thebasis for the fourth case study[ A simpli_ed process ~owdiagram is shown in Fig[ 6[ To maintain purity in therecycle loop of their hydrotreaters\ 0[305 std Mm2:d oflow pressure o}!gas is purged at 72) hydrogen to remove9[128 std Mm2:d of impurities[ The purge gas has a pres!sure of 1[37 MPa and is currently used as fuel gas[

The HRU options were PSA with 9[0 MPa tail gas


Fig[ 4[ Imperial Oil upgrader moderate pressure hydrogen recovery scheme[

Fig[ 5[ Imperial Oil upgrader moderate pressure hydrogen recov!ery economics[

and 74) recovery\ PSA with 9[3 MPa tail gas and 64)recovery\ membrane with 89) recovery and the optionof {no HRU|[ Again\ since the o}!gas pressure was quitelow the gas!liquid contacting processes were notconsidered[ The recovery systems were modeled to deter!mine product compression requirements\ utilities and thecapital cost basis[

The material balance for each recovery option is givenin Table 6 and the cost sheet is given in Table 7[ Themembrane option requires an additional product com!

pressor compared to PSA\ which inputs its producthydrogen directly into the _rst stage of the makeup com!pressor[ Figure 7 compares combined capital\ operatingand lost fuel gas costs on an annual cost basis[ A PSAunit operated at high tail gas pressure has the lowest cost[In summary\ recovery of hydrogen from the hydrotreaterpurge gas stream would realize annual savings of at leastCdn ,00 million relative to {no HRU| option[

8[ Sensitivity analysis

A number of sensitivity analyses were carried out tostudy the economic e}ect due to various factors[ Projectsize\ feed purity\ fuel gas price and improvement in recov!ery were studied for Petro!Canada|s low pressure o}!gasand the impact of the ideal recovery process was studiedwith the basis of Petro!Canada|s high pressure o}!gas[The schematic diagram of Petro!Canada|s low pressureand high pressure o}!gas recovery processes is given inFig[ 2[

A number of low pressure o}!gas streams are producedin the re_nery that are potential candidates for hydrogenrecovery[ The hydrocracker generated 9[981 std Mm2:dof low pressure o}!gas from the hot and low pressureseparators and the naphtha reformer produced 9[172 stdMm2:d of low pressure hydrogen[ The hydrocracker o}!gas has 76[3) hydrogen at a pressure of 1[10 MPa\ andthe naphtha reformer o}!gas has 72) hydrogen and apressure of 0[27 MPa[ Both of these streams are currentlyused as fuel gas[ If the hydrogen is recovered from theseo}!gases it can be added to the hydrogen makeup streamfrom the hydrogen plant[ However a hydrogen com!pressor will be required to bring the product hydrogen


Fig[ 6[ Syncrude hydrotreater low pressure hydrogen recovery scheme[

Fig[ 7[ Syncrude hydrotreater low pressure hydrogen recoveryeconomics[

up to 1[96 MPa\ the pressure of the makeup hydrogenfrom the hydrogen plant[

8[0[ Project size and feed purity

Petro!Canada|s low pressure o}!gas was chosen as thefeed basis for this sensitivity[ The results of the economicstudy 05 for this case indicated that it is not economicalto recover hydrogen from only 9[264 std Mm2:d of lowpressure o}!gas using either a PSA or membrane[

Figure 8 compares the cost per ton of recovered hydro!

Fig[ 8[ Sensitivity analysis of project size and feed purity[

gen for 9[172\ 9[455\ 9[749 and 0[022 std Mm2:d of lowpressure o}!gas containing 79) hydrogen and 74)hydrogen in the feed[ The price of new hydrogen wasassumed to be Cdn ,699:t and therefore the economiccut!o} "hurdle cost# is Cdn ,699 per ton of recoveredhydrogen[ It can be seen that project sizes more than9[455 std Mm2:d are required to make the 74) feedeconomic[ At 79) hydrogen purity\ the hurdle cost canbe met by a ~ow rate of at least 9[697 std Mm2:d\ therebyallowing an extra 9[031 std Mm2:d of lower purity feedto be added[ In summary\ the larger the hydrogen recov!


Table 2Petro!Canada hydrocracker purge gas material balance

Units PSA!LP PSA!HP MEMB CC!ABS NO!HRU

Feed basisVolumetric rate Std Mm2:d 9[011 9[022 9[011 9[206 9[005Temperature >C 26[67 26[67 26[67 26[67 26[67Pressure MPa 5[30 5[30 6[58 06[47 06[47H1 purity ) 83[3 83[3 83\3 83[3 83[3

HRUH1 recovery ) 77[40 65[36 78[89 78[78 9[9Product rate std Mm2:d 9[091 9[985 9[094 9[179 9[9Product pressure MPa 5[16 5[16 1[03 06[06 9[9Product H1 purity ) 88[7 88[7 88[6 85[9 9[9Tail gas rate std Mm2:d 9[919 9[926 9[907 9[926 9[005Tail gas pressure MPa 9[03 9[41 5[78 0[27 06[47Tail gas H1 purity ) 55[5 79[2 46[8 71[10 83[3Liquid circulation rate m2:h 9[9 9[9 9[9 31 9[9Pump power kW 9[9 9[9 9[9 13[12 9[9


2:d 9[091 9[985 9[092 9[158 9[9SMR H1 rate std Mm

2:d 9[742 9[769 9[741 9[769 9[838Bypass H1 std Mm

2:d 4[347 4[337 4[347 4[163 4[353Total recycle H1 rate std Mm

2:d 5[303 5[303 5[303 5[303 5[303Recycle H1 stream purity ) 84[06 84[07 84[06 84[06 84[05

Electric powerHRU kW 4[9 4[9 1[9 9[9 9[9HRU tail gas compressor kW 56 9[9 9[9 9[9 9[9H1 compressor stage 0 kW 0774 0812 1974 0787 1987H1 compressor stage 1 kW 1092 1017 1015 0833 1980H1 compressor stage 2 kW 628 628 628 628 628

Cooling waterProduct aftercooler m2:h 0[6 0[5 0[7 9[9 9[9Intercooler stage 01 m2:h 38 49 43 38 43Intercooler stage 12 m2:h 43 43 43 49 42

SteamHRU kg:h 9 9 0269 9 9

ery unit\ the better the economics will be\ due to economyof scale[

8[1[ Fuel as price

The study cases assumed that fuel gas would have thesame energy value as natural gas at Cdn ,1[9:GJ[ Thelost fuel gas from feed is a signi_cant component of theannual cost[ The higher the fuel gas price\ the higher theloss[ It may be optimistic to assume that fuel gas has thesame value as natural gas[ If there is a high percentageof hydrogen in the fuel gas\ the ~ow rates per GJ will behigher than natural gas[ Also\ if there are signi_cantvolumes of heavier hydrocarbons\ the fuel gas may notburn as clean unless modi_cations are made to theburners[

Petro!Canada|s low pressure feed to PSA with lowpressure tail gas was chosen as a basis to show the impacton the cost of recovery for a range of fuel gas prices[Figure 09 shows that the hurdle cost of Cdn ,699:t couldbe met if the assumed value of fuel gas was reduced toCdn ,0[3:GJ[ A lower fuel gas price will improve theeconomics of all study cases[

8[2[ Improved recovery

The economic e}ect of having very high recovery hasbeen identi_ed in each case study for a theoretical PSAunit having 099) recovery 05[ However\ this option isnot economic because the capital cost of such a unit isprobably higher than a conventional unit\ which is also


Fig[ 09[ Sensitivity analysis of fuel gas price[

true for a theoretical membrane unit having 099)recovery[

Petro!Canada|s low pressure o}!gas was chosen as thefeed basis for the sensitivity analysis of improved recov!ery[ Figure 00 shows the economic impact of havingimproved recoveries for a PSA and membrane units hav!ing the same capital cost as the base recovery case[ It isassumed that improvements in recovery would comefrom future process improvements and optimization to

Fig[ 00[ Sensitivity analysis of improved recovery[

the unit[ For PSA with low pressure tail gas\ improvingrecovery from 7484) reduces the capital cost of recov!ery by only about 4)[ The cost to develop these necessaryimprovements to the conventional PSA process may notbe justi_ed[ Again for the membrane\ improvements inrecovery result in only a small reduction in recovery costs[Unlike a PSA unit\ a polymeric membrane will havea _nite maximum possible recovery[ When the partialpressure on both sides of the membrane are equal themembrane has reached its maximum recovery[ Therefore\for a low pressure o}!gas feed at 1[96 MPa and a tail gasof 9[923 MPa\ the maximum recovery is 82)\ comparedwith the base case of 89) recovery[

8[3[ Ideal recovery

The ideal hydrogen recovery process\ if it could bedeveloped through continued research and development\would feature 84) hydrogen recovery\ 88[8) producthydrogen purity\ a pressure near the feed pressure and atleast 9[3 MPa tail gas pressure[ This sensitivity studyattempted to examine the economic impact if an idealPSA\ membrane or absorption process were developed\with capital costs kept the same as the previous case withthe same recovery but lower purity[

Petro!Canada|s high pressure purge gas was used asthe feed basis[ This stream is 06[37 MPa at 9[005 stdMm2:d containing 83[3) hydrogen[ If the operatingobjective is to replace new hydrogen from a hydrogenplant with recovered hydrogen from a hydrogen recoveryunit\ the economic objective is to recover hydrogen forless than the operating cost to make new hydrogen\ whichis Cdn ,275:t\ based on a 0[305 std Mm2:d size hydrogenplant[

Recovery cases at 74\ 89 and 84) were run for eachof the three recovery processes\ each assuming thathydrogen could be recovered at 88[8) purity[ This targetis easier achieved with a PSA than a membrane or acolumn absorber[ A membrane recovering 88[8) purehydrogen in its permeate stream would reach its partialpressure driving force limit at 84) recovery[ Achievinghigh purity and recovery in an absorber system is moredi.cult and would require a highly selective and e.cientsolvent[ In all cases\ the capital cost was kept the sameas the base recovery case[ These conventional tech!nologies will need to be optimized without increasingtheir capital or operating cost[

Figure 01 shows that none of the processes make thehurdle cost of Cdn ,275:t when the feed rate is only 9[005std Mm2:d[ Even if the PSA and membrane systems couldbe operated at higher product pressure to eliminate theneed for their makeup compression\ these technologiesdon|t make it[ The biggest lever to improving any of theseprocesses is to reduce their capital cost[ This may bepossible in the future with further improvements in tech!nology but likely only marginal[ Increasing the feed rate


Table 3Petro!Canada hydrocracker purge gas cost sheet

Basis PSA!LP PSA!HP MEMB CC!ABS NO!HRU

Capital costs "Cdn M,#H1 plant 38[17 38[80 38[11 38[80 41[71HRU 3[68 3[53 1[40 0[65 9[9COMP:HX

HRU tail gas compressor 9[83 9[9 9[9 9[9 9[9Makeup H1 compressors 14[02 14[41 15[42 13[10 15[28

Sub!total 79[03 79[96 67[14 64[77 68[19


Natural gas ,1[9:GJ 7[509 7[670 7[481 7[670 8[468Electricity ,9[93:kWh 9[073 9[077 9[073 9[077 9[194Other "per std Mm2:d# ,9[355M:y 9[271 9[289 9[270 9[289 9[314Fixed "per std Mm2:d# ,9[585M:y 9[457 9[468 9[456 9[468 9[521

HRUSteam ,3[28:t 9[9 9[9 9[94 9[9 9[9Power ,9[93:kWh 9[991 9[991 9[990 9[997 9[9Replacement capital 09) of Cap 9[9 9[9 9[140 9[9 9[9

COMP:HXHRU tail gas compressor ,9[93:kWh 9[911 9[9 9[9 9[9 9[9Makeup compressor ,9[93:kWh 0[463 0[483 0[537 0[414 0[539Cooling water ,9[93:kWh 9[915 9[915 9[916 9[914 9[916Sub!total 00[24 00[45 00[69 00[38 01[40

Lost fuel gas costs "Cdn M,:y#Fuel gas value credit ,1[9:GJ 9[15 9[39 9[13 9[21 0[93

Lost fuel gas 9[67 9[53 9[79 9[61 9[9

Economics "Cdn M,:y#Capital charge 19[68 19[66 19[29 08[57 19[43Operating costs 00[24 00[45 00[69 00[38 01[40Lost fuel gas 9[67 9[53 9[79 9[61 9[9

Total 21[81 21[86 21[79 20[78 22[91

to 9[172 std Mm2:d improves the economies of scaleshown in Fig[ 02[ Now both the membrane and theabsorber system meet the hurdle rate of hydrogen plantoperating cost[

If the capacity of an existing hydrogen plant is limited\a new plant would need to be built that would add aboutCdn ,203:t for capital depreciation[ The capitaldepreciation of Cdn ,203:t and the operating cost ofCdn ,275:t add up to Cdn ,699:t[ However\ purchasedhydrogen from an outside source would probably exceedCdn ,699:t[ It is evident from the sensitivity studies thathigher hydrogen costs always favor installation of hydro!gen recovery units[

09[ Conclusions

It was found that CANMET|s hydrocracker wouldsave Cdn ,00M:y with implementation of a counter!

current absorber using solvent properties similar to iso!octane[ This is a reduction of Cdn ,2M:y over the currentmixer!separator design using an aromatic solvent simu!lated by toluene[ A countercurrent absorption system isshown to have a small cost advantage over other optionsfor recovery from Petro!Canada hydrocracker high pres!sure purge gas[ There is no advantage to recover hydro!gen if this purge stream continues to be used as hydrogenfeed to their distillate hydrotreater[ Imperial Oil|supgrader could save Cdn ,1M:y if either a PSA with highpressure tail gas or a membrane recovery system wasimplemented[ Syncrude|s hydrotreater would realizeannual savings of Cdn ,02 million relative to new hydro!gen at Cdn ,699:t if a PSA\ operated at high tail gaspressure\ was installed[

PSA systems recover hydrogen at 88[8) purity whichminimizes the purge rate in a recycle system[ Thehighest recovery occurs when the tail gas pressure isthe lowest "usually 9[923 MPa#[ Compression of the tail


Fig[ 01[ Sensitivity analysis of ideal recovery for small size project[

Fig[ 02[ Sensitivity analysis of ideal recovery for large size project[


Table 4Imperial Oil upgrader o}!gas material balance

Units PSA!LP PSA!HP MEMB NO!HRU

Feed basisVolumetric rate std Mm2:d 0[234 0[234 0[234 0[234Temperature >C 25[67 25[67 25[67 25[67Pressure MPa 1[85 1[85 8[06 1[85H1Purity ) 56[9 56[9 56[9 56[9

HRUH1Recovery ) 74[9 55[9 89[9 9[9Product rate std Mm2:d 9[663 9[590 9[751 9[9Product pressure MPa 1[72 1[72 1[72 1[72Product H1 purity ) 88[9 88[9 83[9 88[9Tail gas rate std Mm2:d 9[460 9[633 9[372 0[234Tail gas pressure MPa 9[03 9[41 7[85 1[85Tail gas H1 purity ) 12[6 30[1 07[7 56[9


2:d 9[655 9[483 9[709 9[9SMR H1 rate std Mm

2:d 4[283 4[456 4[294 5[056Total recycle H1rate std Mm

2:d 5[062 5[062 5[062 5[062Recycle H1 purity ) 88[68 88[70 88[97 88[89

Electric powerHRU feed compressor kW 9[9 9[9 0443 9[9HRU tail gas compressor kW 0544 9[9 9[9 9[9H1 compressor stage 0 kW 8414 8414 8405 8414H1 compressor stage 1 kW 8202 8202 8294 8202H1 compressor stage 2 kW 3985 3985 3983 3985

Cooling waterFeed compressor cooler m2:h 9[9 9[9 32 9[9Product cooler m2:h 02 09 04 9[9Intercooler stage 01 m2:h 579 579 573 579Intercooler stage 12 m2:h 237 237 249 237

SteamFeed preheater kg:h 0489 0489 0489 9[9

gas to 9[3 MPa\ for use as fuel gas\ is expensive andtips the scale in favor of low recovery with high tailgas pressure[ Membranes are interesting because of thesimplicity of the process\ with no moving parts andgood turnaround capability[ However the membranemust have a positive hydrogen partial pressure drivingforce\ which limits recovery\ and the pressure of therecovered hydrogen is low which adds compressioncosts[ Countercurrent absorption has shown renewedpotential as an economic hydrogen recovery processwhen the feed pressure is high[ This system also featuresremoval of hydrogen sulphide[ Conventional PSA andmembrane systems have probably been optimized totheir greatest extent[ Further stepwise improvementswill likely require newer technology such as vacuum

swing adsorption\ advanced pressure swing adsorptionand selective surface ~ow membranes[

The sensitivity analysis showed that the higher the pro!ject size and the purity of the feed gas the more is theadvantage of using hydrogen recovery processes[ Since lostfuel gas is a major component of operating costs\ there iseven more incentive to recover hydrogen if fuel gas cost islow[ Conventional PSA and membrane systems wouldrealize very little economic bene_t if process recovery onlyis improved through research[ An analysis of the idealrecovery process\ where maximum product purity and tailgas pressure is obtained at no increase in capital cost\showed that recovery from high pressure purge gas willstill require an economy of scale to be competitive withincremental hydrogen from a hydrogen plant[


Table 5Imperial Oil upgrader o}!gas cost sheet

Basis PSA!LP PSA!HP MEMB NO!HRU

Capital costs "Cdn M,#H1 plant 084[93 087[65 082[00 100[24HRU 8[99 6[63 4[03 9[9COMP:HX

Feed compressor 9[9 9[9 6[07 9[9HRU tail gas compressor 7[87 9[9 9[9 9[9Makeup H1 compressors 55[19 55[19 55[04 55[19HRU product cooler 9[1 9[1 9[1 9[9

Sub!total 168[32 161[89 160[66 166[44


Natural gas ,1[9:GJ 45[70 47[52 44[77 53[84Electricity ,9[93:kWh 0[10 0[14 0[08 0[28Other "per std Mm2:d# ,9[355M:y 1[41 1[59 1[37 1[77Fixed "per std Mm2:d# ,9[585M:y 2[64 2[76 2[58 3[17

HRUSteam ,3[28:t 9[947 9[947 9[947 9[9Cooling water ,9[92:m2 9[992 9[992 9[993 9[9Power ,9[93:kWh 9[991 9[991 9[990 9[9Other capital related 4) of cap 9[349 9[276 9[146 9[9

COMP:HXFeed compressor ,9[93:kWh 9[9 9[9 9[406 9[9HRU tail gas compressor ,9[93:kWh 9[440 9[9 9[9 9[9Makeup compressor ,9[93:kWh 6[523 6[523 6[517 6[523Cooling water ,9[93:kWh 9[146 9[146 9[158 9[146

Sub!total 62[13 63[58 60[85 70[28

Lost fuel gas costs "Cdn M,:y#Fuel gas value credit ,1[9:GJ 05[18 06[69 03[04 11[48

Lost fuel gas 5[29 3[78 7[33 9[9

Economics "Cdn M,:y#Capital charge 61[37 69[67 69[38 60[88Operating costs 62[13 63[58 60[85 70[28Lost fuel gas 5[29 3[78 7[33 9[9

Total 041[91 049[25 049[78 042[27


Table 6Syncrude hydrotreater purge gas material balance

Units PSA!LP PSA!HP MEMB NO!HRU

Feed basisVolumetric rate std Mm2:d 0[313 0[329 0[588 0[305Temperature >C 26[67 26[67 26[67 26[67Pressure MPa 1[47 1[47 1[47 1[47H1 purity ) 72[0 72[0 72[0 72[0

HRUH1 recovery ) 73[49 64[90 78[58 9[9Product rate std Mm2:d 0[991 9[782 0[219 9[9Product pressure MPa 1[92 1[92 9[41 1[92Product H1 purity ) 88[8 88[8 85[9 88[4Tail gas rate std Mm2:d 9[312 9[426 9[268 0[305Tail gas pressure MPa 9[03 9[41 9[41 9[41Tail gas H1 purity ) 32[3 44[2 27[3 72[0


2:d 0[999 9[781 0[156 9[9SMR H1 rate std Mm

2:d 9[9 9[9 9[9 0[066Total recycle H1 rate std Mm

2 0[999 9[781 0[156 0[066Recycle H1 stream purity ) 88[8 88[8 85[9 88[8

Electric powerHRU kW 4[9 4[9 1[9 9[9HRU product compressor kW 9[9 9[9 3932 9[9HRU tail gas compressor kW 0274 9[9 9[9 9[9H1 compressor stage 0 kW 0773 0568 3932 1105H1 compressor stage 1 kW 0784 0578 4803 1117H1 compressor stage 2 kW 2845 2414 4050 3543

Cooling waterProduct aftercooler m2:h 06 04 12 9[9Intercooler stage 01 m2:h 38 32 093 46Intercooler stage 12 m2:h 38 32 041 46

SteamHRU kg:h 9[9 9[9 0269 9[9


Table 7Syncrude hydrotreater o}!gas cost sheet

Basis PSA!LP PSA!HP MEMB NO!HRU

Capital costs "Cdn M,#H1 plant 9[9 9[9 9[9 59[69HRU 02[13 01[25 6[28 9[9COMP:HX

HRU product compressor 9[9 9[9 05[88 9[9HRU Tail gas compressor 7[51 9[9 9[9 9[9Makeup H1 compressors 12[79 10[10 14[02 16[88

Sub!total 34[55 22[46 38[40 77[58


Natural gas ,1[9:GJ 9\9 9[9 9[9 00[75Electricity ,9[93:kWh 9[9 9[9 9[9 9[14Other "per Mm2:d# ,9[355M:y 9[9 9[9 9[9 9[42Fixed "per Mm2:d# ,9[585MM:y 9[9 9[9 9[9 9[67

HRUSteam ,3[28:t 9[9 9[9 9[94 9[9Cooling water ,9[92:m2 9[993 9[993 9[995 9[9Power ,9[93:kWh 9[991 9[991 9[990 9[9Replacement capital 09) of Cap 9[9 9[9 9[628 9[9

COMP:HXHRU product compressor ,9[93:kWh 9[9 9[9 0[235 9[9HRU tail gas compressor ,9[93:kWh 9[350 9[9 9[9 9[9Makeup compressor ,9[93:kWh 0[142 0[010 2[203 0[368Cooling water ,9[93:kWh 9[993 9[993 9[995 9[9

Sub!total 0[62 0[02 4[35 03[80

Lost fuel gas costs "Cdn M,:y#Fuel gas value credit ,1[9:GJ 7[22 8[18 6[52 05[34

Lost fuel gas 7[01 6[05 7[71 9[9

Economics "Cdn M,:y#Capital charge 00[73 7[60 01[73 12[99Operating costs 0[62 0[02 4[35 03[80Lost fuel gas 7[01 6[05 7[71 9[9

Total 10[58 06[99 16[01 26[80

References

0 Schendel RL\ Mariz CL\ Mak JY[ Is Permeation Com!petitive


tion\ 33th Canadian Chem[ Eng[ Conference\ 14 October\0883[

02 Parrillo DJ\ Thaeron C\ Sircar S[ Separation of BulkHydrogen Sul_de*Hydrogen Mixtures by Selective Sur!face Flow Membrane[ AIChE J[ 0886^32]1128[

03 Paranjape M\ Clarke PF\ Pruden BB\ Parrillo DJ\ ThaeronC[ Sircar S[ Separation of bulk Carbon!dioxide!HydrogenMixtures by Selective Surface Flow Membranes[ Acceptedin ADSORPTION\ 0886[

04 Cox BG\ Pruden BB[ The Cost of Hydrogen Compression\Industrial Hydrogen Chair Program\ University ofCalgary\ Canada\ Report No[ 86!90\ 0886[

05 Cox BG\ Peramanu S\ Pruden BB[ Puri_cation of Hydrogenfrom Hydroprocessor Purge and O}!gases\ IndustrialHydrogen Chair Program\ University of Calgary\ Canada\Report No[ 85!90\ 0885[

hydrogen production with psa

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