1.3 The hydrogen cycle - Treccani

1.3.1 Introduction

Hydrogen gas plays a central role in refining and inthe petrochemical industry. In the latter theprincipal applications are in the production ofammonia, methanol and other chemical products,while in refining hydrogen is used above all in theprocesses of hydrotreating and hydrocracking(conversion with hydrogen).

In recent decades environmental policies and thenew organization of the fuel and light-distillatesmarket have led to significant growth in the demandfor hydrogen and the introduction of considerablemodifications to the production and technologyaspects of refineries. The main factors increasingthe demand for hydrogen have been: • The need to process increasingly heavy feeds,

with a consequent increase in the level ofsulphur conversion and removal.

• The greater restrictions imposed byenvironmental regulations on the sulphurcontent in gasolines and diesel.

• The increasing market reduction in the demandfor high sulphur content fuel, which has made itnecessary to convert the residues, which are nolonger used as fuel oils, into lighter products.Therefore, against this background, hydrogen

represents (and will continue to represent in thefuture) a decisive element in maintaining andimproving productivity and operating margins.

As mentioned previously, the main use ofhydrogen in refining is in the processes ofhydrotreating and hydrocracking. In particular, inhydrotreating units (see Chapter 3.1), hydrogen ismainly used to remove the unwanted elements(sulphur, nitrogen, metals) from petroleumproducts, in order to meet market specifications for finished goods (gasolines, diesel and fuel oil).

In hydrocracking units, on the other hand, hydrogenis used to convert heavy distillates and atmosphericand/or vacuum residues into products with a highadded value (lighter fractions and middledistillates).

Table 1 outlines the main hydrotreating andhydrocracking processes, the main aim of thetreatments and the typical range for hydrogenconsumption. In all cases, the latter is closely linkedto the quality and composition of the feed: feedswith a high contaminant content, such as those witha higher concentration of unsaturated composites(for example, fractions from thermal processes,which have a significant level of olefiniccompounds) lead to greater hydrogen consumption.

1.3.2 Hydrogen productionin refineries

The indirect production of hydrogen, resultingfrom the catalytic reforming process, is no longersufficient to meet the growing demand forhydrogen in refineries. For this reason it hasbecome necessary to use dedicated auxiliaryplants. Additional hydrogen can be obtained from avariety of processes, starting with different types offeed (Fig. 1). In all cases syngas (H2, CO, CO2,CH4) is obtained as an intermediate product.

Depending on the technology used and the feedprocessed, the hydrogen yields vary widely, as shownin Table 2. Catalytic reforming has lower yields thanthe others, but it should be emphasized that its mainpurpose is the production of high-octane gasoline andthat hydrogen is merely a by-product.

The choice of the additional hydrogenproduction process is generally governed byeconomic considerations linked to various factors,

59VOLUME II / REFINING AND PETROCHEMICALS

1.3

The hydrogen cycle

such as capital and operating costs, the markettrend in raw material costs, etc. Generally, inrefineries the process of steam reforming ispreferred to the gasification of residues, since ithas markedly lower capital and operating costs,and thus enables greater specific hydrogen yieldsto be achieved.

To meet the growing demand for hydrogen,refineries can also use the followingstrategies: • Optimization of the management of the

hydrogen available in the refinery throughcareful analysis of the distribution network(hydrogen management).

60 ENCYCLOPAEDIA OF HYDROCARBONS

OIL REFINING INDUSTRY: GENERAL ASPECTS

Table 1. Main hydrotreating and hydrocracking processes

Process Main aim of treatmentConsumption (kg of H2 per t of feed)

Hydrotreating

Hydrotreating of gasoline

Elimination of poisons (mainly sulphur and nitrogen) for the reformingcatalyst and isomerization.Compliance with the specifications related to sulphur content in gasolines

0.5-10.0

Hydrodesulphurization of kerosene

Compliance with specifications related to sulphur content in middledistillates

1.0-3.0

Hydrodesulphurization of diesel

Compliance with specifications related to sulphur content in middle distillates

3.0-12.0

Hydrotreating of middle distillates

Pre-treatment of feedstock for the upgrading processes, such as FCC (Fluid Catalytic Cracking) and hydrocracking

5.0-15.0

DearomatizationCompliance with the specifications related to aromatic content in variousfractions (for example in middle distillates)

3.0-15.0

Hydrocracking

Conversion of middle distillates

Conversion of heavy vacuum fractions into lighter products such as LPG,virgin naphtha, kerosene, diesel (upgrading of the feed) 15.0-25.0

Hydrotreating and conversion of fuel oils

Reduction of content of undesired elements (metals, sulphur, nitrogen,etc.) to improve the quality of fuel oil.Partial upgrading of the residue to be fed

10.0-25.0

H2

synthesisgas

Fig. 1. Summary chart of the various processes used in the refinery for the production of hydrogen.

• Revamping of the existing plant based on thereforming process (modernization).

• External acquisition of hydrogen from industrialgas suppliers (hydrogen over-the-fence).

Catalytic reforming of gasolinesHydrogen is traditionally obtained as a

by-product from the catalytic reforming ofgasoline.

As mentioned, this process is mainly used forthe production of gasoline with a high octanenumber (RON, Research Octane Number, higherthan 96) by increasing the content of aromatics andisomerized products, starting with naphthenic andparaffin feedstocks.

In reforming, the main reactions which lead tothe formation of hydrogen are thedehydrocyclization of paraffins and thedehydrogenation of naphthenes:

[1]

[2]

There are also other competing reactions involvedin the process that cause part of the hydrogenproduced to be consumed (see Chapter 4.1).

The process of catalytic reforming is mainly basedon two types of catalytic reactors, a fixed-bed catalyticreactor and a mobile-bed (circulating) catalytic reactor.Depending on the type of reactor used, the processmay follow different configurations: fixed-bed semi-regenerative reforming (traditional plant), cyclicreforming and reforming with continuous regenerationof the catalyst.

The continuous development of the reformingprocess has over the years enabled a very extensivereduction in the severity of operating conditions andthe formation of coke (with a consequent increase inthe length of the catalyst’s life cycle), thus allowinggasoline with a higher octane number and greaterhydrogen yields to be obtained.

An important feature of the continuousregeneration processes is the higher hydrogen yield,ensured by the lower reaction pressure, which leadsto more complete aromatization; in this wayhydrocracking reactions, which consume hydrogen,are limited. On the other hand, the lower pressure (5-14 bar) leads to faster deactivation of the catalyst,due to the increase in the formation of coke; in anycase, since the process involves continuousregeneration of the catalyst, this phenomenon is oflittle importance.


THE HYDROGEN CYCLE

pre-treatment

steam reformer

airfuel tail gas

feedstock

export steam

PSA

H2

steamgenerator

CO shiftconverter

Fig. 2. General scheme of the steam reforming process. Export steam is the amount of steam formed in the steam reforming plant, conveyed to the refinery steam distribution network. PSA: Pressure Swing Adsorption.

Table 2. Yields from the various processes for hydrogen production

ProcessYield of H2

(% of the feed )

Semi-regenerative catalytic reforming 1.2-1.7%

Continuous catalytic reforming 2.3-2.6%

Steam reforming 30-40%

Partial oxidation of methane around 30%

Gasification of the residue (in the case of complete conversion of the hydrogencontained in the syngas and in the presenceof the conversion section for CO)

15-20%

+ H2

+ 3H2

R C C C CR'

R R

Steam reformingSteam reforming (Fig. 2) is the most commonly

process used in refineries to produce additionalhydrogen.

The most widespread application involves the useof natural gas or methane as feedstock (steam methanereforming); moreover, the gradual technologicalimprovements that have been made, such as thedevelopment of more selective catalysts, the design ofnew furnaces and the use of different flow schemes,have contributed to the development of more efficientand flexible steam reforming that can process evenheavier hydrocarbon feedstock and manage continualchanges in hydrogen demand.

Steam reforming of hydrocarbons is based on acatalytic reaction that is described by the followinggeneral equation:

[3] CnH2n�2�nH2O��nCO�(2n�1)H2

This reaction is endothermic and, therefore,favoured by high temperatures (750-850°C), as wellas being assisted by low pressure. Nonetheless, forreasons linked to the need to reduce plant size and tohave high pressure in the sections both up and downstream from the steam reforming furnaces, the processoperates at an average pressure (15-30 bar), raising thetemperature to the maximum levels allowed andforegoing complete conversion. Operating under theseconditions and with light feeds that are rich inmethane, ethane and propane, the percentage ofunconverted methane is quite low.

In the case of methane, the above reactionbecomes:

[4] CH4�H2O��CO�3H2

�H °298K�206 kJ/mol

Since the nickel catalyst, loaded in the tubes presentin the radial section of the reforming furnace (Fig. 3), isvery sensitive to minimal quantities of contaminants(such as sulphur, arsenic, phosphorous and lead), whichpoison it permanently, the feed used for steam reformingmust be pre-treated (with a catalyst based onmolybdenum and cobalt sulphides) in order to reduce thequantity of these unwanted elements.

The quantity of unconverted methane, and,therefore, the composition of the gaseous mix(known as syngas) at the exit from the steamreforming furnace depend not only on the type offeed used, but above all on the operating conditions(pressure and temperature), on the quantity of steamused (ratio of H2O/C) and on the performance of thecatalyst. The graph in Fig. 4 shows how, for a givenfeed and given values of pressure and temperature atexit from the steam reforming furnace, on increasingthe ratio of H2O/C (i.e. the quantity of steam used)

the unconverted quantity of methane contained inthe syngas falls, with the consequent increase inhydrogen yield (the balance of reaction [4] shiftstowards the right). Clearly, to obtain the same levelof conversion to methane with heavier hydrocarbonfeedstock, under the same temperature and pressureconditions, it is necessary to increase the quantity ofsteam.



steam �hydrocarbons

(LPG, naphtha, etc.)

H2, CO, etc.

steam �hydrocarbons

H2, CO, etc.

burner

heat heat

burnerreaction

tubes

catalyst

Fig. 3. Radiant section of the steam reforming furnace.

6

7

8

5

4

780 800 820 840

Tout reformer

860 8801436

°C°F 1472 1508 1544

feedstock: natural gas

2% CH4 in the syngas

3.5% CH4

5.0% CH4

feedstock: naphtha

1580 1616

3

H2O

/C r

atio

Pout reformer 20 bar

Fig. 4. Effect of the operating conditions on hydrogenproduction from steam reforming.

In parallel to the reactions described above, secondaryreactions may be noted which can lead to a lowering ofhydrogen yields and to the formation of coke:

[5] CH4��C�2H2 methane pyrolysis

[6] CO�H2��C�H2O reduction of carbon

monoxide

[7] 2CO��C�CO2 Boudouard reaction

The pyrolysis reaction is of minor importance underthe operating conditions of steam reforming, unlessheavier hydrocarbons are used as feedstock. It isimportant to stress that, in the various portions of thetubes in the reforming furnace, the composition of theprocess gas, the temperature and the catalyst activityinfluence the rate and the direction to which thesesecondary reactions proceed, and therefore thepossibility that coke formation takes place (Fig. 5). Inorder to avoid the deposit of coke on the active sites ofthe catalyst, it is necessary for the steam reforming totake place in the area where carbon does not form,where the operating conditions favour the flow fromright to left (with consequent removal of the coke) ofthe reactions [6] and [7] mentioned above, with respectto the pyrolysis reaction of the methane. The rate ofcarbon removal, therefore, becomes greater than the rateof its formation. In the case shown in Fig. 5, theposition of the composition-temperature profile alongthe tubes of the steam reforming furnace indicates that,in the given operative conditions, carbon depositionoccurs on the catalyst active sites within the portion ofthe tube (from the inlet) corresponding to about 30% ofits total length. One operating method which favours thecoke removal reaction consists of increasing the steamto carbon ratio so as to shift the equilibrium of thereaction [6] towards the formation of CO (with theconsequent reduction of the area for carbon formation;its border shifts, for istance, from line A to line B). Incases in which (for example, owing to plant restrictions)this type of operating solution cannot be adopted, analternative solution can be employed involving catalystsbased on alkyl compounds which act as promoters ofthe reactions to form CO and therefore lead to areduction in the area for the formation of carbon.

The gaseous mix outlet from the steam reformerfurnace is sent to the heat recovery section (composedessentially of the convection section of the steamreforming furnace and steam generator). There thegenerated steam is partially used for internalconsumption in the steam reforming process andpartially conveyed (export steam) to the refinery steamdistribution network.

The subsequent stage of the process consists of theconversion of the carbon monoxide into carbondioxide by further use of steam:

[8] CO�H2O��CO2�H2

�H °298K��41 kJ/mol

This stage, also known by the name of shiftconversion, occurs under different conditions from theprevious stage, in the presence of a catalyst based oniron oxide, Fe2O3, containing Cr2O3 as a promoter.

This type of unit allows a 2-5% increase inhydrogen yield after the conversion phase whichoccurs in the steam reforming furnace.

There are three types of shift conversion employedwhich differ according to their working temperatures:High Temperature (HT), 330-360°C; MediumTemperature (MT), 220-270°C; Low Temperature(LT), 190-220°C. Since the shift conversion reaction isexothermic (and thus favoured by low temperatures),the heat recovery section is also necessary to reducethe temperature of the outlet synthesis gas toacceptable levels for the shift conversion reactor.

The more commonly used configuration is a hightemperature shift conversion reactor. Economicconsiderations influence the choice to insert, beneaththe HT shift conversion reactor, a second LT reactor.This type of configuration guarantees an increase infeed conversion, with a reduction of the heat requiredin the steam reforming furnace.

On exiting the conversion section, the syngas issent to the purification and recovery section, within


THE HYDROGEN CYCLE

10

100

1

550 600 650temperature (°C)

LTUBE � steam reforming tubes length

0.3 LTUBE

0.4 LTUBE

0.5 LTUBE

no carbondeposition

zone

carbondeposition

zone

0.6 LTUBE

ndep �nremndep�nrem

ndep� carbon deposition rate

nrem � carbon removal rate

700 750 8000,1

pyrolysis

equilibrium curve (CH4 C

+2H2)

P2 H

2/P

CH

4

profile of the composition-temperature along the tubes of the steam reforming furnace

Fig. 5. Coke formation in the tubes of the steam reforming furnace as a function of the operating conditions. A and B lines identify the border between thearea where carbon does not form and the area where it does(the latter is smaller in B).

A B

which the carbon monoxide and dioxide present in thegas flow are eliminated. This section involves varyinglevels of complexity depending on the level of purityof the hydrogen flow desired.

In traditional schemes, the purification sectionconsisted of a system for washing the CO2associated with a methanation reactor; thisconfiguration allowed hydrogen recovery with puritylevels of between 92% and 97% and implied acertain operating complexity. Currently the PSA(Pressure Swing Adsorption) process has replacedthat scheme. The reasons for this change may befound in the following features of the PSA process:a) production of very pure hydrogen (99.99%); b) reduced operating complexity due to the lowernumber of process units; c) lower capital andoperating costs; and d) easier optimization of theprocess under operating conditions for reforming.

In the cases in which it might be beneficial torecover the carbon dioxide, the hydrogen productionsystems can include a separate section for therecovery of CO2 from the flow coming into the PSA.This configuration leads to a reduction of thefeedstock quantity brought to the purificationsection (lower load of CO2 to the PSA), thus alsoensuring better hydrogen recovery (an increase of 2-5%). However, its use is only justified if there is animprovement in the market prices for CO2, since thewashing unit has high operating costs, linked to theconsumption of amine (needed for the washing ofthe process flow in the adsorption column) and ofsteam (needed for the regeneration of the aminesolution in the regeneration column).

The gasification processAs discussed previously, the steam reforming of

methane is a common technique for the productionof hydrogen, since it guarantees a high conversionlevel (80-90%) at lower costs compared to otherprocesses. One of the other processes used for theproduction of hydrogen is gasification, whichenables the transformation of a variety of heavyhydrocarbon feeds into syngas for the production ofhydrogen, which may or may not be combined withthe production of electricity. Gasification plants maybe classified among those with a high productioncapacity (over 20,000 Nm3/h).

The gasification of coal could have anincreasingly important role in the future due to theeasy availability of the raw material on the market,the greater (long-term) price stability of coalcompared to natural gas and, above all, the lowerprice compared to other raw materials. In addition,the fall in demand for high sulphur content fuel oils,as a consequence of increasingly strict

environmental regulations, has made a large amountof processing residues available for convertinggasification processes.

The gasification process has a lower conversionefficiency (approximately 50-75%) than steamreforming, with an additional contribution to thetotal efficiency of around 5% in the case of energyrecovery, obtained by sending part of the cleansyngas to electricity production plants. For thisreason, gasification plants are usually found incombined cycle refineries for the production ofelectricity (see Chapter 7.3).

In general, the gasification process consists ofthe partial, non-catalytic oxidation of a solid, liquidor gaseous substance, with the production ofsyngas; the overall reaction of the process can bewritten as follows:

[9] CnHm�n/2O2��nCO�m/2H2

In the case of methane m�n�4, for an oilm�n�2 and for coke m�n�1. The composition ofthe gas produced depends not only on theoperating conditions, but also on the type offeedstock; the latter parameter also influences thechoice of gasification technology to be adopted.

Currently there are various gasificationtechnologies which use three different types ofreactors (see Chapter 7.3): the fixed-bed reactor, thefluidized-bed reactor, and the entrained-bed reactor.

Increase in the availability of hydrogenowing to the revamping of reforming processes

As mentioned previously, one of the methodswhich refineries can use to satisfy the growingdemand for hydrogen consists of revampingexisting units. The best solution depends on theconfiguration of the refinery and requiresassessments and comparisons of the variousalternatives both from a technical and economicpoint of view. In addition, in choosing the correctsolution it is also necessary to considerenvironmental aspects, since changes to hydrogenproduction plants, complex or otherwise, can leadto major variations in CO2 emissions.

In general, among the most economicinvestments is increasing the capacity for thecatalytic reforming of naphtha, which also leads toan increase in the production of hydrogen as a by-product. The main actions adopted in refining toachieve an increase in the hydrogen yield (DH2,expressed as the increase in the percentage yield asagainst the processed feed) from the catalyticreforming plants are as follows: • The choice of more selective and stable catalysts

(DH2�0.1-0.2%).



• An increase in the volume of the catalyst(DH2�0.1-0.2%).

• A change of the type of reactor, fromsemiregenerative fixed-bed to regenerativecontinuous (DH2�1.0%).The solution involving the revamping of the

existing units for catalytic reforming can prove to beuneconomic if there is a fall in the demand forreformed gasoline (with an increase in the demandfor diesel), associated with greater regulatoryrestrictions on the specifications relating to thecontent of aromatic compounds.

In the case that the increase in the demand forhydrogen is limited, the revamping of the existingsteam reforming plant can be considered; sometechnological solutions can lead to an increase inproductivity and, therefore, in capacity, up to amaximum of 25-30%. Table 3 summarizes, alongwith their related costs, some technologicalinitiatives relating to the conversion and purificationsections, which may be used to increase theproduction of hydrogen from steam reforming. As

shown in the table, different solutions implyvariations also as far as the feed and the exportsteam production are concerned. In analysing thecosts of the various solutions, it is necessary to bearin mind that the flexibility and costs of inserting thepre-reformer depend on the type of feed used andthat the cost of inserting the oxygen-blownsecondary reformer is heavily dependent on theavailability of oxygen and the possible need to builda new plant to produce it. As for the substitution ofthe heater tubes, the cost indicated in the tableincludes that relating to the catalyst. Finally, the costof the increase in the speed of CO2 removal dependson the type of system used; that indicated in thetable refers to a CO2 washing system, together witha methanation reactor.

To increase the production of hydrogen from theexisting units, in some cases it is possible to use themethanol to shift process:

[10] CH3OH�H2O��CO2�3H2

�H °298K�49,4 kJ/mol


THE HYDROGEN CYCLE

Table 3. Actions aimed at increasing the production of hydrogen in steam reforming plants

IncreaseIncrease in

incapital costs

Technologyhydrogen

Steam rate Feedrate per capacity

productionincrease

(dollars per scf/d)

Insertion of pre-reformer 10-12% 10-15% decrease Increase proportional 0.1-0.2to the hydrogen

production increase

Insertion of GHPR 15-30% 10-30% decrease Increase slightly 0.3-0.5(Gas Heated Post Reformer) more than proportional or EHTR (Enhanced Heat to the hydrogenTransfer Reformer): post- production increasereformer fed with partially converted gas

Insertion of oxygen-blown 20-50% 10-30% decrease Increase slightly 0.1-0.5secondary reformer more than proportional

to the hydrogenproduction increase

Replacement of reforming 20% Increase proportional Increase proportional 0.10-0.15heater tubes to the hydrogen to the hydrogen

production increase production increase(assuming adequate convection surface)

PSA modifications (substitution 15-30% Same Same 0.05-0.10of adsorbers or modificationsof adsorption cycles)

Increase of CO2 removal speed 20-25% 4-10% decrease Same 0.1-0.2

The conversion of methanol to hydrogen takesplace in the same reactor as the shift conversion,within which a dual-function catalyst is loaded,which simultaneously ensures the reactions toconvert carbon monoxide into hydrogen. This typeof solution does not require particular work onand/or changes to the existing steam reforming unit,even if in some cases it may be necessary to modifythe purification section (PSA) due to the increase inthe quantity of syngas to be treated. The option ofconverting the methanol has the advantage ofrequiring low capital costs, due to the limitednumber of new pieces of equipment to buy(methanol storage tank, methanol loading pumps,methanol evaporation system, etc.), the limitednumber of changes to be made to the existing plant,and the reduced realization times.

However, it should be emphasized that thismethod is only of real interest when the cost ofmethanol is equal to or lower than that of natural gasor, in any case, there is a ready supply of methanol.

Besides the construction works (revamping of theunit), to increase production it is possible to optimizesome operating variables in the process, which allowan increase in the conversion of the reformingreactions and therefore in the hydrogen yields. Forexample, the increase in the temperature on exit fromthe reforming heater (process gas side), for a givenvalue of the H2O/C ratio, leads to an increase of thepercentage of feed converted and, therefore, anincrease in the hydrogen yield (see again Fig. 4). Theincrease in temperature, however, leads to greater fuelconsumption. This process optimization is, therefore,heavily influenced by economic considerations linkedto the ratio of the price of the feed to that of the fueland is, therefore, only economically viable when thefeed is more expensive than the fuel.

Finally, a costly method to increase theavailability of hydrogen in the refinery is, of course,the construction of a new gas production plant(capital costs for a new plant are around 0.8-1.0dollars per scf/d); this choice is onerous in termsboth of capital and operating costs and leads also toan increase in carbon dioxide emissions.

1.3.3 Hydrogen distribution

The high number of hydrogen production andconsumption sources in the refinery makes itnecessary to implement a distribution network,which may be complex, at one or more gas pressureand purity levels.

In Fig. 6 there is an example of a complexdistribution network, in which there are four

hydrogen distribution lines, which guarantee greateroperative flexibility for the refinery. The varioustypes of gas rich in H2 produced/distributed by thenetwork are as follows:• Pure hydrogen, coming from PSA units, with

purity over 99% in terms of volume and absenceof H2S.

• Clean hydrogen, coming from the CR2 and CR3reforming units, with purity of 70-85% in termsof volume and absence of H2S.

• ‘Dirty’ hydrogen, coming from the CR2 unit andused in the desulphurization units forgasolines/kerosene/diesel, with purity of 70-80% in terms of volume and traces of H2S. The four distribution lines present in the network

in Fig. 6 are: • A line for H2S free hydrogen, at a working

pressure of around 30 bar. • An line for hydrogen containing H2S, at a

working pressure of around 20 bar. • Emergency lines, which distribute pure hydrogen

to all the plants concerned in an emergency.In the distribution network there are various

hydrogen producers present which generate loads,entering the network, with various levels of puritydepending on the type of process and purificationand recovery systems involved: a) semi-regenerativecatalytic reforming (CR2); b) continuousregeneration catalytic reforming (CR3); c) SteamHydrocarbon Reforming (SHR); and d) gasification.These processes can provide hydrogen with adegree of purity that varies between approximately75 and 85% in terms of volume. Part of thehydrogen produced is further purified in the PSA1,PSA2, PSA3 and PSA4 plants, bringing purity levelsclose to 99% in terms of volume. These loads aresent to the pure hydrogen distribution line. Theunpurified loads, coming straight from theproduction units, are sent directly to the distributionline for dirty hydrogen and/or clean hydrogen(depending on the purity and presence of H2S).

As for hydrogen consumption, the plantsconsidered are essentially those for the hydrotreatingof a range of fractions from topping (HDS1, HDS2,HDS3 and naphtha hydrotreater or NaHyd), thehydrocracking (HDC) plant and those for theisomerization of light gasoline (TIP, ISO). Theseplants require a different hydrogen purity, in relationto the type of process and the treatment to beapplied. HDS1, HDS2, HDS3 and NaHyd requirehydrogen with purity of around 75-85% in terms ofvolume, while HDC, TIP and ISO need very purehydrogen, approximately 99-99.5% in terms ofvolume, and therefore are fed with loads from thePSA plants.



1.3.4 Optimization of hydrogenmanagement in refineries

The management of hydrogen has become anessential priority in the day-to-day operation ofrefineries. As already seen, in order to meet thegrowing demand for hydrogen, refineries canemploy solutions of varying cost that guarantee anincrease in supply. Generally, before planningsignificant investment (such as that describedpreviously) studies are undertaken for more efficientrecovery of the hydrogen available in the various off-gas flows, combined with studies to optimize thehydrogen distribution network (HPA, HydrogenPinch Analysis).

The combination of these activities is theaforementioned hydrogen management, a methodwhich allows systematic analysis of the problem of

hydrogen balance in a refinery, by suggesting theactions to undertake in order to optimizeconsumption and, at the same time, offering possibletechnological solutions to be adopted. Hydrogenmanagement is, therefore, a low cost strategy tooptimize the hydrogen network, that can meetgrowing demand for hydrogen and also allow animprovement in profits.

Hydrogen management is based on the HPAmodel, which describes the hydrogen balance inrelation to its purity and the quantity of flowspresent in the distribution network. This modelprovides the criteria to optimize the management ofthe network, by establishing a varied and moreefficient cascade distribution of the varioushydrogen loads to the plants, without however takinginto account the technical and economic feasibilityof the solution found.


THE HYDROGEN CYCLE

permeate

syngas visbreaker residuenon permeate

H2S-free hydrogen

H2S-containinghydrogen

emergencypure hydrogen

emergencypure hydrogen

PSA: pressure swing adsorber

SHR: steam hydrocarbon reformerHDC: hydrocrackingHDS: hydrodesulphurization

de-ARO kero: de-aromatization of keroseneSCOT: tail gas treatment unit

TIP and ISO: isomerization of light gasoline

CR3: continuous regeneration catalytic reformingCR2: semi-regenerative catalytic reforming

NaHyd: naphtha hydrotreater

Fig. 6. Example of a hydrogen distribution network.

For example, in the HPA no assessments are madeof the capacity of the existing compressors and of theconsequent possibility of the plants reusing thehydrogen at the working pressure of the network.Often the critical factor in recovering hydrogen is notthe purity or the size of the gas flow, but the need touse, where possible, the compressors that are alreadypresent in the plant. Therefore, the goal to beachieved in studying the optimization of thehydrogen network is much more complex, since it isnot enough to consider the overall material balancewith respect to hydrogen, but it is also necessary toassess the potential of the compressors and theircompression ratios, so as to determine the bestsolution for the management of hydrogen in therefinery and to ensure the minimum impact oncapital costs.

As noted above, the method of hydrogenmanagement, besides providing indicators for theoptimization of the management of the hydrogendistribution network, also has the goal of recoveringhydrogen from off-gas flows. The adoption of thisrecovery strategy has contributed in recent years toan increase of around 30% in the availability ofhydrogen in refineries.

1.3.5 Hydrogen recovery systems

The choice of the recovery system for hydrogen isinfluenced not only by economic assessments, but alsoby project considerations linked to the feasibility ofrecovery, the flexibility of the process and the ease ofplanning future enlargements of the unit.

In choosing the system to adopt, recovery efficiencyshould also be taken into consideration, and this isinfluenced by a range of factors, the most important of

which are the pressure of the off-gas flows and their H2content (usually between 10 and 40%).

Currently there are three hydrogen recoverysystems available (Fig. 7), based on differentseparation principles, which give the three methodssignificantly different process features:• The PSA system, based on the principle of the

selective adsorption on molecular sieves (at a settemperature) of the various components of thegas flow.

• The membrane system, based on the principle ofselective permeability, i.e. the different rates ofpermeation, through a polymer layer, ofhydrogen and of the impurities present in the gasflow to be treated.

• The cryogenic separation system, based on theprinciple of the relative volatility (differentboiling points) of the components present in thegas flow to be treated; the simplest and mostcommon cryogenic separation process is that ofpartial condensation.Once a gas flow is judged to be potentially

useable for hydrogen recovery, it is necessary tochoose the most adequate technology to make therecovery economically viable. Table 4 shows asummarized comparison between the recovery andpurification systems mentioned above.

As shown in the table, the PSA allows therecovery of less hydrogen from the gas flow thanthe other two systems, but with purity of over99.999%. For this reason, this type of unit is usedabove all to purify hydrogen from catalyticreforming and to be sent to hydrodesulphurizationplants; the high level of purity of hydrogen fromthe PSA in fact allows the maintenance of a highpurity level in the gas recycled to thedesulphurization section.



Table 4. Comparison between various hydrogen recovery technologies

PSA Membrane system Cryogenic system

Capacity (kNm3/h) 1-225 1-50 10-75+

Pressure of the feed (bar) 10-40 20-160 5-75

Pressure of the H2 produced PH2 produced�PH2 feed PH2 producedPH2 feed PH2 produced�PH2 feed

Pre-treatment of feed no yes yes (removal of CO2/H2O)

Purity of H2 (%) 99,999� 90-98 90-96

Recovery H2 (%) 75-92 85-95 90-98

Expandability ��

Flexibility ��

Capital costs average low high

Unlike the PSA, the membrane system is moresuitable for the recovery of hydrogen from wastegasses from the high and low pressure separators inthe desulphurization units and, like the cryogenicsystems, for treating off-gas flows, which have ahydrogen content below 30-50%.

Although the cryogenic process isthermodynamically more efficient for the recovery ofhydrogen, the PSA process is the most commonlychosen technology, since it ensures the recovery ofvery pure hydrogen. In order to guarantee moreeffective recovery, it is preferable to apply a hybridsystem, consisting of the combination of the twosystems described; process engineering studies haveshown that the greatest technological advantagesderive from the three combinations: membrane-PSA;PSA-cryogenic; and cryogenic-membrane. Thechoice of the hybrid system depends on acombination of factors such as capital costs,compression costs, the purity of the hydrogen, therecovery percentage and the degree of flexibility inthe system.

Bibliography

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Abbott P.E.J. (2000) Get more production from your hydrogenplant, Synetix technical paper.

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Proceedings of the 5th European technical seminar on hydrogenplants (2004), Barcelona (Spain), 20-22 October.

Ratan S. (2003) Hydrogen technology. An overview, «PetroleumTechnology Quarterly», Autumn.

Ratan S., Wentink P. (2001) Cost effective hydrogen fromrefinery offgases, «Petroleum Technology Quarterly»,Summer.

Ricci G., Bottino S. (2004) Optimisation of hydrogenmanagement in refinery, in: H2 age. When, where why.Proceedings of the AIDIC international conference, Pisa(Italy), 16-19 May, 173-179.

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Michelangelo Di LuozzoEni - Divisione Refining & Marketing

Roma, Italy


THE HYDROGEN CYCLE

65-92%H2

90-99% H2

10-30% H2

99% H2

�40% H2

90-96%H2

90-96%H2

C2�

C3�

prismmembranes

cryogenicsystem52%

PSA14%

others1%

membranes33%

Fig. 7. Simplified schemeof the hydrogen recovery systems.

Documents

1.3 The hydrogen cycle - Treccani