h2 plant design discussion

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- 1 -

Middle East PETROTECH 2001

Conference and Exhibition

29-31October 2001

HYDROGEN PLANTS

FOR THE

NEW MILLENNIUM


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Hydrogen Plants for the New Millennium - 2 -

1 INTRODUCTION

Hydrogen is increasingly being considered as a utility gas within the refining and

petrochemical industry. From an end users perspective, investments in hydrogen plant

capacity tend to be judged by the cost of producing hydrogen molecules rather than by the

rate of return from the plant.

Hydrogen generation capacity is usually required to support major expansions or major

reconfigurations of core process units. Assuming that all other hydrogen sources in an

existing facility are fully utilised, there are two routes for the end user to obtain this additional

hydrogen:

! For the end user to own and operate its own hydrogen plant

! For the end user to buy hydrogen over the fence from a third party industrial gas supplier

End users of hydrogen, bought via either route, look for reliable supplies to the specified

hydrogen purity. In this context, there are limited opportunities for product differentiation.

Therefore, the competitive strategy of the hydrogen plant supplier has to be based around

being the lowest cost hydrogen provider.

The question to ask is what does lowest cost mean? Is it lowest initial capital investment,

lowest feedstock / fuel / utility / catalyst / chemical consumption or lowest operational

and maintenance costs? Foster Wheelers initiatives to develop its SMR hydrogen plant

technology are driven by minimising the lifecycle cost of producing hydrogen by

optimising the balance of these factors.


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Over a period of decades, SMR hydrogen plants have continued to be the leading technology

used for generation of source hydrogen on refining and petrochemical complexes. A typical

example and an SMR hydrogen plant is shown below:

50 MMscfd Steam Methane Reformer Hydrogen Plant at Lagoven, Amuay in Venezuala

SMR is a mature technology and is now unlikely to yield any large step changes in economic

benefit from technological developments. Marginal economic improvements are the order of

the day. These result from continued development and optimisation of the following:

! Main process design parameters

! Balance of capital and operating costs

! Synergistic design with existing plant facilities

! Project execution techniques

! Operation and maintenance techniques

!

Financial modelling techniques


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This paper focuses on the techno-economic choices available in selecting and developing

optimum SMR hydrogen plant configurations using the main process design parameters

and Discounted Cash Flow (DCF) financial modelling.

2 ECONOMIC FACTORS AFFECTING THE COST OF HYDROGEN

Economic theory on the benefits obtained through technology development is, at best, a

complex subject. Introductory notes covering economic theory are included in Appendix 1

for reference.

At a practical level, there are a large number of variable factors affecting the cost of

producing hydrogen. Many of these, including the unit costs of feedstock and utilities are

either given factors or pass through the economic evaluation calculations. The flexibility

available in establishing optimised economic results revolves around financial modelling,

charging structures and the main process design parameters.

2.1 Financial Modelling

Foster Wheeler uses DCF modelling methods to establish the lifecycle cost of producing

hydrogen, to quantify the driving factors for technology development and to assist in the

choice of optimum hydrogen plant configurations. In order to perform accurate DCF

modelling, all major costs elements need to be input covering each year in the lifecycle of the

hydrogen plant. Typical inputs to the DCF model include the following:

! Initial plant capital, typically spread over a two year project schedule

!

Residual capital value (if any) at the end of the plant lifecycle


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! Annual costs of feedstock and utility consumptions

! Annual costs of catalysts and chemicals

! Annual costs of operating staff and overhead costs

! Annual costs of maintenance

! Annual revenues from exporting the hydrogen product

! Annual revenues from exporting the steam products

! The cost of financing the resulting cashflows

! The required rate of return over the lifecycle

In pure costs terms, the cost of the capital elements of the plant can vary from as little as 10 %

of the overall cost, in cases where feedstock costs are high, to in excess of 40%, where the

scale of the plant is relatively small. This demonstrates the need to select plant configurations

suiting the economics of the project rather than offering the same standard plant configuration

to suit all cases.

2.2 Charging Structures

Revenue charges can be arranged to suit the end users cashflow requirements. Typical

examples of this include fixed and variable fee elements or combining charges as a totally

variable fee with a guaranteed minimum product take.

Charge

Demand

Fixed Fee

g:151a\prop_nos\36230-1404\g\10815_chart

Minimum Demand

Variable Fee

Total Fee

C h a r g i n g S t r u c t u re


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Plant capital charges are usually arranged such that the ownership of the plant resides with the

industrial gas supplier. Options can also be included allowing the end user to lease the plant

and take delayed ownership based on residual capital values at the time of purchase. These

types of option can be used to reduce the end users initial capital investments and in some

cases tip the balance of project sanction. Charging structures can be arranged to provide

considerable flexibility to suit the overall project economics and the end users cash position.

2.3 Hydrogen Plant Design Parameters

To establish the minimum life cycle cost of hydrogen, all the major fixed and variable cost

elements need to be established. The choices taken in shaping a hydrogen plant design need

to be economically driven. Some of the choices available are discussed in the following

section along with typical examples to demonstrate their economic effect on the cost of

producing hydrogen.

3 DESIGN PARAMETERS AFFECTING THE COST OF HYDROGEN

There are many design parameters ultimately affecting the cost of the product hydrogen. This

discussion is limited to five process parameters affecting the hydrogen yield and the energy

balance. Hydrogen plant variable operating costs are a substantial portion of the total cost of

the product hydrogen. The five parameters considered are:

! Reformer outlet temperature

! Steam to carbon ratio

! Unit operating pressure

! Shift reactor operating temperature

! H2 recovery in the PSA unit


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3.1 Reformer Outlet Temperature

The steam methane reforming reaction is strongly endothermic and therefore favoured by

higher temperature. Typical reformer outlet temperatures fall in the range 1500 F to 1650 F.

As the temperature is increased, the hydrogen yield increases which is observed by a

reduction of the methane concentration in the reformer effluent, known as the methane slip.

The higher yield means that less feedstock is consumed, for example, a 1.3% reduction in

feedstock can be achieved by increasing the outlet temperature by 10 F. Due to the lower

methane slip, the energy in the PSA tail-gas is reduced and since this stream is the base load

fuel for the reformer, the supplementary fuel imported to the unit increases. This effect is

enhanced because the higher reformer outlet temperature increases its radiant duty. The

supplementary fuel is a relatively small flow and is strongly influenced by small changes to

the reformer heat balance, so that in this case, there is a small increase in the total feed/fuel

consumption.

The export steam flow will increase by 1.3% for an increase in the reformer outlet

temperature of 10 F. This effect is due to the increase in radiant duty and reduction in the

steam requirement for the process feed giving the net increase in the steam available for

export.

Taken overall, the higher reformer outlet temperature shifts the heat balance to produce more

steam from more feed/fuel. DCF analysis is a useful tool to evaluate the economic benefit of

design optimisations. The effect can ultimately be expressed as a change in the life cycle cost

of hydrogen product, but in this discussion, the effect on the project internal rate of return

(IRR) is used as a general way of illustrating the impact.


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In this case study, typical monetary values are assigned to process streams as follows:

Natural gas feedstock 2.1 US$ / MM Btu

Supplementary fuel 2.1 US$ / MM Btu

Export steam (600#) 5 US$ / 1000 lb

Demineralized water 6 US$ / 1000 USgal

Cooling water 0.12 US$ / 1000 USgal

Electricity 0.05 US$ / kWh

The case study uses a natural gas feed/fuel design configuration with a nominal capacity of 10

MMscfd. The graph below shows IRR against the normally acceptable range of reformer

outlet temperature available to the designer. In this case study, the economic factors have

been chosen to give results with the IRR centred around a nominal 10%.

It should be noted that the nominal IRR figure chosen is for illustrative purposes only and

should not be read as an upper limit on hydrogen plant investment returns.

Reformer Outlet Temperature

9

9.5

10

10.5

11

11.5

1510 1530 1550 1570 1590 1610 1630

Temperature (deg F)

InternalRateof

Return(%)


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The graph demonstrates the significant impact on the project profitability, which would be

translated into life cycle cost of hydrogen in terms of $ per scf. The case study utilises a

design configuration based around Foster Wheelers proprietary Terrace Wall reformer. The

modern trend at Foster Wheeler is to use high reformer outlet temperatures in the region of

1620 F to take advantage of the economic benefits available with these typical feed and

utility costs.

3.2 Steam to Carbon Ratio

The feed gas to the reformer is a mixture of steam and hydrocarbon gas. The mixture is

characterised by the steam to carbon ratio, which is the molar ratio of steam to the reactive

carbon contained in the hydrocarbon gas. A higher steam to carbon ratio drives the reaction

closer to the equilibrium and increases the hydrogen yield. Reforming catalysts require steam

to be present in excess, increasing the volumetric throughput and cost of the plant and so there

is always interest in reducing the steam to carbon ratio. In doing so, there is an increase in

feedstock consumption, which is almost balanced by a decrease in demand for supplementary

fuel. A 1.8% increase in feedstock use will be the result of reducing the steam to carbon ratio

by 0.1. The mechanism of these effects is opposite to that for higher reformer outlet

temperature, in that the methane slip increases and the PSA tail-gas contains more energy.

The decrease in steam to carbon ratio gives rise to an increase in the reformer radiant duty,

which increases the steam generated in the convection section. Less steam is used in the

process and the steam exported from the plant is further increased. A 0.9% increase in steam

export will arise from a reduction in steam to carbon ratio of 0.1.


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In this case the significant benefit of lower steam to carbon ratio is clearly shown. Todays

hydrogen plants almost always minimise the steam to carbon ratio driven by these economic

benefits. On this subject the technology edge is with the catalyst performance and an

understanding of the tendency of the feedstock to form carbon at the reformer inlet. A typical

steam to carbon ratio in a configuration containing an HTS reactor is 2.8.

3.3 Unit Operating Pressure

Hydrogen plants comprising a steam methane reformer and a PSA purification section, can

comfortably produce hydrogen over a pressure range of 260 psig to 400 psig. Quite often,

these pressures are suitable for the facility hydrogen network and so the hydrogen plant

operating pressure will be set by the network without the need for product compression. In

this case, feedstock must be supplied at about 160 psi higher than the product hydrogen.

However, it is also common that there is a need to provide compression for both the feedstock

and the product hydrogen, in which case, the reformer operating pressure will be chosen by

consideration of appropriate stages of compression and also the effect on the plant

performance and cost.

Steam to Carbon Ratio

9

9.5

10

10.5

11

2.4 2.5 2.6 2.7 2.8 2.9 3 3.1 3.2 3.3 3.4 3.5 3.6

Molar Steam/Carbon Ratio

InternalRateofR

eturn(%)


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Typical reformer conditions give an increase in molar flow rate of approximately 50% across

the catalyst tubes, and therefore the reactions are favoured by lower pressure. The change in

pressure affects the reformer hydrogen yield and the energy contained in the PSA tail-gas in a

similar way to the previous discussion. For a reduction in the pressure of 15 psi, the

feedstock consumption reduces by 1.1%, while the supplementary fuel demand increases by a

lesser amount, such that the overall energy input is reduced.

For a change in the reformer operating pressure, the change in the export steam flow rate is

insignificant. This is essentially because the reduction in feedstock flow reduces the steam

generation by a similar amount to the reduction in the steam required by the process.

The graph demonstrates the value of lower operating pressure. Whenever there is a choice of

operating pressure, Foster Wheeler aims to select the lowest practical pressure when

optimised with other parameters.

3.4 Shift Reactor Operating Temperature

Unit Operating Pressure

9

9.5

10

10.5

11

260 280 300 320 340 360 380 400

Hydrogen Pressure (psig)

InternalRateofReturn(%)


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The water gas shift reaction is moderately exothermic and so is favoured by lower

temperature. A range of commercial catalysts is available covering operating temperatures of

390 F to 750 F providing plenty of flexibility in the design of the process configuration.

Changing the catalyst type from iron (HTS) to copper (LTS) together with associated

flowsheet changes, can have significant benefits, whereas optimising the operating

temperature of HTS catalyst has a more mild effect. When its operating temperature is

reduced, the carbon monoxide concentration in its effluent decreases, which improves the

hydrogen yield. For a reduction in temperature of 70 F, the feedstock consumption reduces

by 1%, however, due to the change in the energy in the PSA tail-gas, the supplementary fuel

increases by a similar amount. The effect on export steam flow is very mild. It is influenced

by the small change in feedstock consumption and the minor variation to the syngas cooling

train, which recovers heat into the steam system.

It can be seen that the effect of HTS operating pressure on the IRR are mild, and for this

reason Foster Wheeler prefers to standardise the design to optimise the performance of the

catalyst and employs a temperature ramping technique to this end.

3.5 Hydrogen Recovery in the PSA Unit

HT Shift Temperature

9

9.5

10

10.5

11

620 640 660 680 700 720

Inlet Temperature (deg F)

InternalRateofReturn(%

)


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The key design specification for the PSA unit is the hydrogen recovery, defined as the moles

of hydrogen in the product compared to the moles of hydrogen in the PSA feed gas. Modern

high performance designs can achieve up to 89% hydrogen recovery, while simpler designs

using fewer adsorber vessels can still achieve 84%. As the hydrogen recovery specification is

increased, the plant feedstock consumption reduces accordingly, but at the same time, the

flow rate of PSA tail-gas also reduces, so that more supplementary fuel is required with the

net result being a noticeable reduction in the total feed/fuel consumption. For a 5% points

increase in hydrogen recovery, the feedstock consumption will decrease by 5.7%.

Higher yield in the PSA means that all of the flows in the front end of the plant are reduced

including the export steam. For the 5% points increase in hydrogen recovery, the steam

export flow reduces by 4.3%. Taken overall, the higher hydrogen recovery shifts the heat

balance to produce less steam from less feed/fuel.

The graph illustrates the more moderate impact of hydrogen recovery on the IRR of the

project and therefore also on the cost of product hydrogen. Even so, when optimising a plant

design, this benefit is valuable in todays highly competitive market. Using the monetary

PSA Unit Hydrogen Recovery

9

9.5

10

10.5

11

83 84 85 86 87 88 89% Hydrogen Recovery

InternalRateofReturn(%)


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values in this case study, Foster Wheelers new plant designs typically utilise PSA recovery in

the region of 88%.

3.6 Comparison of Benefits of Design Parameters

The relative benefits of the design parameters on the feedstock consumption are presented

below:

The impact on feedstock consumption is given approximately for the whole of the practical

ranges available to the process designer, for each of the discussed parameters. Broadly, this

indicates that reformer temperature, steam to carbon ratio and unit operating pressure, are

significantly more powerful than PSA hydrogen recovery and shift reactor temperature. This

is most relevant when the feedstock is expensive and the supplementary fuel has only low

value.

However, some project sites have significantly different economic factors, such as very low

cost gas feedstock, which leads to variations in the optimum process parameters.

Additionally, there are other technical factors, which impact the way in which the individual

parameters may be combined into a design. For example, it is impractical to choose a steam

Impact of design parameters on Feedstock.

( expressed over practical range of design )

0 5 10 15

PSA Rec

Shift Temp

Pressure

S/C Ratio

Ref T.out

% Change in Feedstock


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to carbon ratio of 2.5 with an HTS reactor in the configuration and also impractical to choose

a PSA recovery of 89% with a product hydrogen pressure of 260 psig.

Therefore in the large scale hydrogen plant field, it is still most common to optimise the

design to the site conditions, rather than select a pre-engineered, off-the-shelf unit.

3.7 Variable SMR Designs for Specific Steam Export Requirements

HP steam is a natural by-product from the Steam Methane Reformer because of the large

quantity of waste heat generated at high temperature and because steam raising equipment is

always present to produce the process steam for the reformer feed gas. Of the fuel energy

fired in the reformer furnace, about 50% escapes into the convection section, while only about

15% is required to preheat the process feedstock. Not only this, but there is also a very large

amount of heat in the reformer process effluent and very few cold streams to preheat, leaving

a lot of surplus heat available to generate steam for export. The by-product steam can be

superheated or saturated, at pressures of 600 psig or higher. It is most suitable as a base load

steam generator since the export flow rate is linked to the hydrogen production flow rate, but

also because generation is at a very high thermal efficiency of greater than 90% LHV basis,

which is usually higher than steam boiler units.

In the most simple hydrogen plant designs, all the surplus energy is converted into steam

using coils in the convection section and process gas waste heat boilers. A graph of typical

steam export rate across the range of hydrogen production is shown below:

Typical Va riations in Stea m Export Rates

( no air preheat )

0

0.5

1

1.5

2

40 100

Plant Operating Capacity %

SteamR

ate

Factor


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The steam rate factor in the graph is expressed as US ton per hour per MMscfd of hydrogen.

An effective method of reducing the steam export flow rate, is to move heat into the

combustion air using air preheaters installed in the flue gas system. To handle the combustion

air, it is necessary to include a forced draft fan with ducting to the burners, in addition to the

usual induced draft fan for the flue gas. A diagram of an air preheat system is shown below:

The steam export flow rate can also be increased above that provided by the simple design, by

adding auxiliary burners in a combustion chamber integrated with the convection section.

The location of auxiliary burners in the reformer is shown below:


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Auxiliary burners provide the ability to vary the steam export semi-independently of the

hydrogen production rate and typically can produce up to an extra 50% steam export. In this

way, although the steam by-product should still be considered as a base load facility, some

degree of control is provided for its production.

The ability to vary the steam export using auxiliary burners can even be combined with an air

preheat system to achieve the variability at a lower level of export flow rate. Typical

variations in steam export rates with single and double air pre-heaters and auxiliary burners

are shown below:

The flow rate of export steam is one of the most variable specifications in the basis of design

of a hydrogen plant. It can often be dictated by the project site steam balance, and will always

be subject to the prevailing economic conditions. As an illustration, an example of the impact

of including a single air preheater in the design is given. The effect on the plant performance

is shown in the table below. Quite simply, there is a shift in the heat balance in that less

supplementary fuel is consumed to produce less export steam.

Typical Variations in Steam Export Rates

0

0.51

1.5

2

2.5

3

40 100

Plant Operating Capacity %

SteamR

ateFactor

Double Air Preheat

Single Air Preheat

No Air Preheat

Auxiliary Burners


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No airpreheat

Single airpreheat

Hydrogen production MM scfd 10 10

Natural gas feedstock MM Btu/h 141 141

Supplementary fuel MM Btu/h 48 34

Export steam (600#) US Ton/h 17 12

Using as before the typical feedstock and utility values and the DCF analysis, it becomes

apparent that with the air preheat system, the price of the export steam must increase by 1.3

US$ / 1000 lb when all other factors are kept constant. Therefore, in this case, the economics

favours producing more export steam using the simpler design without air preheat since the

marginal cost of the extra steam is low. The air preheat system is clearly suited to economic

conditions where the cost of the fuel is high relative to the price of the steam.

Consider the effect when the DCF analysis is repeated with the fuel cost at 5.0 US$ / MM

Btu. With the air preheat system, the price of the export steam can decrease by 0.50 US$ /

1000 lb when other factors are kept constant, except the price of hydrogen, which for any

design will rise in line with the cost of feedstock and fuel. In this case, the economics favours

the air preheat system and the marginal cost of more steam is high.

4 SUMMARY AND CONCLUSION

Foster Wheelers initiatives in developing its SMR hydrogen technology are driven by

minimising the lifecycle cost of producing hydrogen using discounted cash flow methods.

This has resulted in a variety of new plant configurations, based on the following changes to

the main design parameters:


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! Higher reformer outlet temperatures

! Lower steam to carbon ratios

! Lowest practical operating pressures

! Temperature ramping techniques for HTS catalysts

! Higher PSA recovery levels

The question posed in the introduction to this paper is What does lowest cost mean?

Foster Wheelers view is that all providers and end users of hydrogen benefit from using

lifecycle cost analysis. With this in mind, it is usually preferable to design with high

reformer outlet temperature, low steam to carbon ratio and high recovery in the PSA

unit for a given operating pressure. Use of DCF financial modelling clearly

demonstrates the advantages gained by this approach and is the driving factor behind

the development of Foster Wheelers Steam Methane Reforming Hydrogen Plant.

5 REFERENCES

Nellis, J.G. and Parker, D. (1997) The Essence of Business Economics, 2nd Edition, London:

Prentice Hall International.


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APPENDIX 1 ECONOMIC THEORY OF TECHNOLOGY DEVELOPMENT

There are a number of defined economic terms relating to the effects of technology

development on plant economics:

! Marginal costs of production, defined as the additional costs of producing one more

capacity unit of hydrogen, depends on the changes in variable costs in the short run

because fixed costs are constant as output changes.

! Short run average costs (SRAC) of production, defined as production cost over a

period where at least one of the main parameters of production is fixed, e.g., the installed

capacity of the hydrogen plant.

! Long run average costs (LRAC) of production, defined as the production costs over a

period where all factors of production can be varied in order to alter the scale of

production.

The aim of the plant designer is to select the plant configuration which produces the lowest

short run average cost of production at the design capacity of the plant, using the best

available current technology.

Unit

Production

Cost

Production

Capacity

Long Run Average Cost

g:151a\prop_nos\36230-1404\g\10815_chart

Short Run Average Cost

Average Cost Curve


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H d Pl f h N Mill i 21

If the plant is operated in turndown mode, the cost of production increases following the left

hand side of the SRAC curve. If the plant is operated above the design capacity, the cost of

production increases as the capacity becomes limited by the controlling plant design factors.

The effect of marginal technology improvements in the long term is a reduction in the short

run average costs of production. When a technology improvement is implemented, the LRAC

curve shifts down and to the right giving lower unit costs of production. The obvious

message here is that all hydrogen plant suppliers must continuously improve their current

technology to remain competitive in the long term.

As an existing technology matures, it becomes increasingly difficult to shift down the LRAC

curve any further. Introduction of a completely new technology for producing hydrogen

would have the effect of shifting the LRAC curve down and to the left. The immediate effect

of this would be a step change reduction in the unit costs of production, even for smaller

capacity plant. The longer term effect of this would be to negate the use of the existing

mature technology.

The obvious message here is that all hydrogen plant suppliers must keep their eyes open for

the development of completely new technologies which may supersede SMR hydrogen

technology, position themselves to implement this, or fall into terminal decline.

h2 plant design discussion

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