AckermannTh. (ed) Wind Power in Power Systems

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Fuel cells offer an alternative, as they convert hydrogen (and oxygen) into electrical

energy by means of an electrochemical process. In contrast to the case for thermal power

plants, the conversion in fuel cells is not limited by the Carnot process efficiency.

Basically, the process consists of the catalytic ionisation of hydrogen and oxygen. The

ions pass an electrolyte membrane, separating the fuel and the oxidant gas stream. The

recombination of hydrogen and oxygen ions then yields pure water and electricity.

Fuel cells are categorised by their operating temperature. Low-temperature cells are

operated at 80–100



C, high-temperature cells at 650–1000



C (see Table 23.2). The

higher the temperature the more efficient the electrochemical processes. A further

distinction is made according to the type of electrolyte. Low-temperature cells work

with liquid electrolytes [i.e. alkaline fuel cells (AFCs) or phosphoric acid fuel cells

(PAFCs)] or with polymer membranes [i.e. polymer electrolyte fuel cells (PEFCs)].

High-temperature cells use zirconium oxides [i.e. solid oxide fuel cells (SOFCs)] or

molten carbonates [i.e. molten carbonate fuel cells (MCFCs)].

Three aspects influence the choice of a fuel cell for reconversion to electricity:

high (electrical) efficiency in order to minimise overall conversion losses;

suitability for pure hydrogen obtained from electrolysis;

fast response to load variations required for load-following capability.

The first two criteria are self-explanatory, but the third provides potential for increasing

the controllability in connection with fluctuating electricity sources, such as wind energy.

Fuel cells can be used to reduce the demands of conventional voltage and frequency

control. MCFCs are not suitable for pure hydrogen feed gas, and the efficiency and cost

effectiveness of PAFCs and AFCs are insufficient. PEFCs show a high efficiency in

operation with pure oxygen, which means that PEFCs, and SOFCs, seem to be the most

suitable for being used in equipment for converting hydrogen to electricity.

Table 23.2 Comparison of fuel cell types: polymer electrolyte fuel cells (PEFCs), phosphoric

acid fuel cells (PAFCs), alkaline fuel cells (AFCs), solid oxide fuel cells (SOFCs) and molten

carbonate fuel cells (MCFCs)

Low-temperature fuel cells High-temperature fuel cells

PEFC PAFC AFC SOFC MCFC

Electrolyte Polymer Phosphoric acid Alkali Ceramic Molten

carbonate salt

Operating

temperature (



80 220 150 850 650

Fuel H

,CO

and CH

, CO, CO

and CH

Oxidant O

or air O

(!) O

or air O

or air

Efficiency

(%) 35–45 35–45 50–70 50–55 40–50

Higher heating value.

Source: Larminie and Dichs, 2000.

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SOFCs are difficult to cycle through low part load and cannot easily be shut down or

refired, but they have the highest electrical efficiency. SOFCs integrated into a gas-and-

steam cycle power plant can contribute to a total electrical efficiency of up to 70 %

(Palsson 2002). PEFCs, in contrast, are flexible in operation and fast in response to load

changes. They are suitable for customer site installations of CHP at various scales. Also,

these fuel cells will constitute the major part of fuel cells in vehicle applications. There-

fore, prices for PEFC are expected to fall drastically after market introduction of fuel

cell vehicles, maybe from 2010 onwards. A combination of the two types seems ideal for

covering both base and peak electricity loads.

23.5 Hydrogen and Wind Energy

Today, wind and solar electricity constitute only a small part of the European electricity

production. This situation may change in the future when the use of renewable elec-

tricity generation gradually approaches the technically exploitable potential. If renew-

able power reaches high penetration levels in the electricity distribution networks, the

fluctuating power output will at times even exceed the load requirements and thus cause

excess power and surplus energy production, which is equivalent to a temporary shut-

down of renewable power plants.

The continental European grids are interconnected in the network of the Union pour

la Coordination du Transport d’Electricite

(UCTE, 2003). This network maintains the

stability of the electricity grid through distributing control responsibilities among its

members. The network allows the aggregation of loads and generation over a very large

area. Therefore, the integration of high wind power penetration levels will be easier than

in isolated power systems (see also Chapter 3). Power trading between individual

regional grids, though, is limited to contingents agreed upon in advance (24 hours and

more) and is governed by business agreements, even though the physical electricity flow

itself cannot be easily controlled within the grid. The members may even risk penalties if

they do not comply with the prearranged power balance.

The amou nt of surplus energy caused by fluctuating sou rces in electricity networks

depends on the amount of renewable power capacity installed, the characteristics of the

renewable sources utilised and the characteristics of load and conventional power

generation (Stei nberger-Wilckens, 19 93). In rigid grids with a large contribution from

base load and /or with slow or limited response in the power generation to fast load

gradients, a surplus situation will occur more often than it will in flexible grids.

Depending on the type of the predominant renewable energy source, the ratio of peak

power to average power varies. This ratio is reasonably low for wind energy (i.e.

between 3:1 and 4:1, depending on the siting) and is even lower for offshore wind power.

Table 23.3 shows the percentage of surplus (wind) energy prod uction normalised to

the load as a function of wind power penetration. We define wind power penetration as

the ratio of wind energy production to total load requirement. The electricity grid

assumed corresponds to the German system in 1990, with a contribution of about

30 % nuclear energy and 4 % hydro energy, with the majority of contribution from

coal-fired generation. Surplus wind energy production starts at a penetration level of

about 25 % and reaches a value of 7 % percent at a penetration of about 50 %. Taking

512 Hydrogen

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into account the normalisation, that means that 14 % of the wind energy generation is

discarded. The calculations include the effect of the geographical distribution in a

nationwide grid.

Hydrogen as an intermediate storage vector can ‘absorb’ this surplus energy and

‘release’ it at times of low (or lower) renewable power production. The conversion of

electricity to hydrogen and the storage and reconversion to electricity were discussed in

Sections 23.3 and 23.4. Here, we will look at the influence of storage size on total system

performance.

Table 23.4 shows the percentage of conventional (fossil fuel) energy in a grid with high

wind and/or solar energy production in relation to penetration and storage size. The

storage system in this example is assumed to have an efficiency of 70 %. If there is no

storage (storage capacity ¼ 0 h), at a penetration rate of 100 %, about 50 % of the

renewable energy input has to be discarded, mostly because of the characteristics of the

solar power plants. The share of renewable energy that can be utilised increases with

storage size. Owing to storage losses, however, it does not reach a 100 % load match. It

should be noted that the increase in renewable contribution rises sharply with the first

increment in storage capacity but then approaches the limit of infinite storage very

slowly. This indicates that short-term and daily patterns govern the characteristics of

renewable (wind and solar) energies. Long-term temporal shifting of renewable power

requires very large storage sizes.

Table 23.5 illustrates the potential wind power production for 2010 in comparison

with the net electricity generation in 2000. The wind production was derived from the

total onshore potential estimated by van Wijk and Coelingh (1993) plus the rated power

of offshore projects in the planning phase around the year 1993. This will give an

estimate of the possible level of wind power production in the area between 2006 and

2015. Percentages vary, but many countries may be faced with a wind power generation

that substantially exceeds the surplus energy generation limits mentioned above. Data

are presented only for Europea n countries, since here the ratio be tween offshore wind

potential and load requirements is high. This is because of the ratio of length of coastline

Table 23.3 Model calculation for surplus wind energy (as a percentage of total consumption or

‘load’) that cannot be absorbed by the electricity grid as a function of renewable penetration in

the grid, where renewable penetration is defined as the ratio of total renewable energy production

and total electricity consumption (in the case depicted, wind energy is fed into the German grid at

the national scale (Steinberger-Wilckens, 1993)

Wind power penetration

(% of load)

Surplus energy

(% of load)

Surplus wind energy

(% of wind energy)

Surplus wind energy

(TWh/year)

25 0.0 0.00 0.0

30 0.5 0.15 0.8

35 1.2 0.42 2.3

40 2.8 1.12 6.2

45 4.7 2.12 11.7

50 6.8 3.40 18.8

55 9.2 5.06 28.0

60 12.0 7.20 39.8

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to mainland area. Coastal States in the USA may face similar problems in the future if

the electric power flow is restricted for any reason (see above).

Apart from control ling wind resources, the more immediate role of hydrogen in

offshore wind exploi tation appears to be the transport of energy from offshore wind

farms to the shore. The installation of a hydrogen pipeline is no more difficult than that

of a sea cable. A hydrogen pipeline is likely to take up less space, which may be an

important aspect given the massive wind capacity that may have to be transferred to the

shore. Transport losses are lower for hydrogen, and the required investment costs for

the production of hydrogen and its reconversion to electricity are similar to those for

high-voltage transmission. Still, losses in conversion to and from hydrogen are high.

Offshore hydrogen generation will be feasible only if the hydrogen is used for the

controlling purposes described above and for establishing hydrogen power production.

It does not make any sense to use the hydrogen only as a means of transport to the

shore.

23.6 Upgrading Surplus Wind Energy

Use of hydrogen as an intermediate storage medium results in a new controllability in

the wind power resource and in the possibility of optimising power supply. It may be

Table 23.4 Percentage of conventional electric energy necessary for load following (columns 2

through 5) as a function of renewable energy penetration (column 1; fixed mix of 90 % solar,

10 % wind energy; for a comparison with a 100 % wind system see Table 23.3) and storage size

Renewable power penetration

(% of load)

Conventional energy (% of load), by storage capacity

0 h 3 h 6 h infinite

0 100 100 100 100

10 90 90 90 90

20 81 81 81 81

30 73 72 72 72

40 67.5 63 62 62

50 63.5 58 55 54

60 60 52.5 49 46

70 57.5 50 44.5 37.5

80 55.5 47.5 40 30

90 54 45 37.5 22

100 53.5 42 35 16

Note: the storage capacity is normalised to the hourly average load (i.e. a storage capacity of 1 h

denotes a storage that can deliver the average load for 1 hour). Total storage system efficiency in

this example is set to 70 % (battery storage; Steinberger-Wilckens, 1993). Short-term storage

reduces the contribution of conventional (fossil fuel) generation considerably. Mid- and long-

term storage (above 12 hours) has an effect only at very high penetration rates, (of above 50%) as

indicated in the last column (‘infinite’) which also gives an indication of the maximum achievable

reduction in conventional energy use.

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attractive, for instance, to enter electricity spot markets for peak load. Although in the

past peak power was said to have a high value (Steinberger-Wilckens, 1993) this was not

necessarily reflected in the price indexes (E&M, 2002).

It is still under debate whether or not these indexes constitute ‘real’ market prices

since the effective price of control power supplied and peaking power station operation

are difficult to separat e from overall system operation. Theoretically, the electricity

delivered by a marginal peaking power station may be ‘infinite’ if this generating

capacity is not put into operation in a particular year, but this full-cost accounting is

not reflected in the actual spot pricing since this cost is attributed to safety-of-supply

risk management (and thus is included in the ‘overhead’ costs of electricity generation).

Suppliers of ‘green’ electricity, who might be required to certify load-following capabil-

ities, would be especially interested in ‘gree n’ peak load.

Hydrogen could offer an opportunity to store electricity over a considerable span of

time [e.g. on a daily basis, from weekend to week day and, less likely, over longer periods

(see Table 23.4)]. In the case of surplus electricity production, the energy cost of

generating the hydrogen would be reduced to zero.

Table 23.5 Net electricity production in the countries of the EU-15 in 2000

(Bassan, 2002) and extrapolated wind energy production in about 2010 (as the

sum of onshore potential plus offshore planning figures from 2003)

Country Total production

(TWh/year)

Wind production in 2010

TWh/year %

Belgium 80.1 6.20 7.74

Denmark 34.5 28.32 82.09

Germany 533.5 100.09 18.76

Greece 49.8 44.48 89.32

Spain 215.2 87.20 40.52

France 516.7 85.17 16.48

Ireland 22.7 45.56 200.70

Italy 263.6 69.00 26.18

Luxemburg 1.1 0.00 0.00

Netherlands 85.8 7.70 8.97

Austria 60.3 3.00 4.98

Portugal 42.2 15.00 35.55

Finland 67.3 7.00 10.40

Sweden 142.1 58.39 41.09

UK 358.6 118.04 32.92

Total EU-15 2473.5 675.15 27.30

Wind energy as a percentage of total electricity supply (net production).

Note: ‘2010’ denotes the period 2006–15; figures include all grid losses. (e.g.

electricity consumption in Germany amounts to approximately 490 TWh/year).

Sources: hypothetical onshore potential, van Wijk and Coelingh, 1993; offshore

operational and planning figures, IWR, 2003; Paul, 2002; Paul and Lehmann,

2003; NEA, 2001; WSH, 2003.

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A cost analysis, though, would need to show that the extra cost of hydrogen produc-

tion and of re-electrification installations can be compensated by extra revenue. Natural

gas reforming could be used for the production of hydrogen as a backup in situations of

a low supply of wind-derived hydrogen. This could enhance the flexibility of this system

and help to guarantee power production under all circumstances.

23.6.1 Hydrogen products

Apart from being used in electricity production, hydrogen can also be marketed as an

independent product. On the one hand, hydrogen has various industrial applications. In

various places there is already a regional hydrogen infrastructure that connects the

industry with a hydrogen surplus (derived from various chemical processes, such as

the chlorine chemistry) with facilities that use hydrogen in their production processes

(e.g. as a reducing agent). On the other hand, hydrogen is expected to be one of the most

important future energy vectors in the trans port market. Until now, it has commonly

been believed that the first hydrogen vehicles will run on fuel that is derived decentrally

(i.e. at the filling station) from natural gas by steam reforming. This process produces

carbon dioxide emissions, though. Hydrogen produced from wind energy can constitute

a more ecological alternative, since vehicles running on this fuel are practi cally emission-

free even when analysed on a global scale (i.e. taking into account the balance of all well-

to-wheel contributions; Feck, 2001).

If surplus wind-derived electricity is converted to hydrogen it is also branched out of

the electricity market and the price pressure exerted by surplus production will be

reduced. The spot market would react to an excess of electricity supply by an erosion

of revenues which, in turn, would drastically cut the return on investment for offshore

wind farms.

In addition to pure hydrogen, there are several ways of producing chemicals from

hydrogen. Today, the possible synthesis of methanol from atmospheric carbon

dioxide and wind-derived hydrogen is of major interest. Methanol can be transported

by tankers more easily than can hydrogen, and just as easily by pipeline. Whether

methanol or hydrogen will be first to be used as vehicle fuel is still under discussion.

An analysis of the efficiencies definitely points towards the direct use of hydrogen

(Feck, 2001).

Other possible hydrogen-derived products include ammonia, synthesised from atmos-

pheric nitrogen and hydrogen. This technology has been discussed in the past as a

vector for hydrogen fixation, storage and transport. However, there are no immediate

advantages to an application in the context of offshore wind farms.

23.7 A Blueprint for a Hydrogen Distribution System

Wind-derived hydrogen can constitute the basis for an environmentally safe, emission-

free energy supply. Figure 23.1 integrates the elements of hydrogen production, trans-

port, storage and distribution into a complete system. Here, electricity and heating,

transport fuel and industrial gas de mands are all supplied by wind energy sources.

516 Hydrogen

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The HyWindFarm system is the result of a joint development by engineering com-

panies, industrial gas suppliers, energy traders, control equipment manufacturers, and

control and system management software engineers. It is expected to be built in North-

ern Germany next to an onshore wind farm. The EUHYFIS (European Hydrogen

Filling Station; EUHYFIS, 2000) forms the ‘core’ of the system, thus simplifying the

installation. The filling station is a compact, preassembled module that comprises

electrolyser, compressor and storage. In this case, it would also be the interface with

the distribution system.

The system shown uses low-temperature fuel cells (PEFCs) to supply heat and

electricity to residential, administrative or industrial buildings and high-efficiency cells

for the reconversion to electricity. These could either be high-temperature cells (SOFCs)

or oxygen-driven PEFCs. The ox ygen would have to be supplied by molecular sieves

(used for separating air into oxygen and nitrogen) or by installing a separate supply of

Hydrogen

storage (500 bar)

Onshore and

offshore

wind power

Electrical grid

Electrolysis

Compression

(from 30 to 450 bar)

Fuel cell power

plant, 5 kW

Filling station

Pipeline

(approx.1 km)

Industry

(e.g. chemical)

Fuel cell

CHP 2 kW

End-user 1

as industrial gas

Vehicles

Compression of

(250 bar)

storage

(250 bar)

for peak

power production

Fuel cell

CHP 2 kW

End-user 2

Overall

management and

control system

Electricity

End-user 3

as fuel

Fuel cell

CHP 2 kW

Figure 23.1 Flow diagram of the wind–hydrogen production and distribution system HyWind-

Farm, which consists of electrolytic production of hydrogen from wind energy, diffusion of

hydrogen by pipeline and use for small-scale combined heat and power (CHP) in residential

applications, a small-scale fuel cell power plant (without heat recovery) and hydrogen fuel

delivery; hydrogen can also be supplied to industrial customers. Note: an electrolyser, compressor,

storage and filling station setup are included in the EUHYFIS module; the system is intended for a

medium-sized prototype installation in Northern Germany (see EUHYFIS, 2000)

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oxygen that is derived as a byproduct from the electrolytic production of hydrogen. The

engineering of an autonomous supply system for an island or isolated community has

resulted in a similar system layout (see Sørensen and Bugge, 2002).

23.7.1 Initial cost estimates

At this point, cost estimates are still rough and are likely to contain large error margins.

Many of the technologies involved (e.g. offshore platforms, gas pipelines, and electro-

lysers) are widely used. Their application in the context of bulk hydrogen production,

though, still poses substantial technical problems that need to be solved. The extrapola-

tion of costs to large systems is thus rather speculative.

In addition, fuel cell technology is quickly developing an d it is still difficult to come up

with realistic cost estimates of electricity production. Projections offered by the industry

are basically guidelines that need to be verified in practice. We therefore do not include

costs for the production of electricity from hydrogen. Tabl e 23.6 gives an overview of

component costs for a 1000 MW (1 GW) hydrogen production plant.

It must be pointed out that the equipment costs also have to reflect the marine

environment of the installations and the respective additional corrosion of the compon-

ents. Also, cost statements that are available today often refer to components in an early

stage of development. Projections for equipment at a mature stage of technical develop-

ment manufactured in large quantities are thus neither linear nor very reliable. The figures

in Table 23.6, however, correspond roughly to qualitative data published by Altmann and

Richert (2001) for offshore applications and to an analysis of long-distance onshore

transport of wind energy via hydrogen in the USA by Keith and Leighty (2002).

Table 23.7 shows estimates of the total cost of hydrogen (i.e. energy) including for

production, distribution and storage systems. Providing that wind energy sells at approxi-

mately 60.06 per kilowatt-hour at the time in question (i.e. after 2010, when hydrogen

systems of the size presented here can be actually built) the total cost of hydrogen

produced by the HyWindFarm system will be 60.568 per norm cubic metre (Nm

), or

Table 23.6 Cost estimate for a 1 GW hydrogen production plant on an offshore

platform; the hydrogen is transported by pipeline to the shore and the transport is

driven by the pressurised electrolyser

Component Qualification Specific costs

(6/kW)

Total costs

(6 millions)

Electrolyser, pressurised,

70 % efficiency

1 GW 800 800

Pipeline length 120 km — 36

Ancillaries, platform,

landing station, contingencies

N.A. — 173

Total 1009

N.A. Not applicable.

— Not calculated.

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60.189 per kilowatt-hour. Considering that the reconversion to electricity is not yet

included in these figures, delivery of stored energy to the electricity grid will be necessarily

restricted to peak load hours and high-quality, fail-safe electricity production because of

the associated costs. However, industrial hydrogen is sold at prices that are similar to

those mentioned above. Taking vehicle fuels as a standard, the figures quoted are in the

order of magnitude of taxed petrol and even diesel, taking into account that a fuel cell

vehicle would be of superior efficiency (roughly factor 2 above a diesel engine). Even

though the figures stated here are of limited reliability, this result is encouraging.

23.8 Conclusions

Hydrogen production from offshore wind energy is techni cally feasible and builds

mainly on technology that is already available today. Further technological develop-

ment will be necessary in order to scale up the components, improve efficiencies and

provide equipment that endures marine environments.

The role of hydrogen will be to transport wind energy to shore and to supply a means of

controlling wind energy output. The reconversion to electricity will be very sensitive to

cost factors and will probably be restricted to high-quality power applications.

The use of hydrogen as fuel or industrial gas and its distribution to stationary fuel

cells appear to offer a promising revenue stream for electricity generation.

References

[1] Alcock, J. L. (2001) ‘Compilation of Existing Safety Data on Hydrogen and Comparative Fuels’, EIHP2

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[2] Altmann, M., Richert, F. (2001) ‘Hydrogen Production at Offshore Wind Farms’, presented at Offshore

Wind Energy Special Topic Conference, Brussels, December 2001.

Table 23.7 Estimated production costs of hydrogen of 1 GW (including pressurisation and

storage)

Contribution Specifics Total costs

(6 millions)

Specific costs

(6/Nm

)

Hours of full operation 4000 h p.a. — —

Hydrogen production 933 million Nm

p.a. — —

Annual capital costs N.A. 185

Annual operation and management N.A. 62

Cost of hydrogen production plant

and storage

N.A. — 0.266

Cost of energy for hydrogen production,

including wind electricity costs

N.A. — 0.302

Total cost N.A. — 0.568

N.A. Not applicable.

— Not Calculated.

Note:Nm

¼ norm cubic metres.

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