1         Introduction

 

All governments have pledged to improve energy efficiency and reduce carbon emissions; this effectively means that the world must move to:

 

• Electricity  from nuclear, renewable or decarbonised sources
• Hydrogen from renewable or decarbonised sources
• biomass derived methane gas or hydrocarbon liquids or
• heat as a by-product, or from biomass, solar or geothermal sources.  

 

Of these electricity and hydrogen are purely manufactured energy vectors competing as intermediaries between energy sources and final consumers. In recent years the tide seems to have moved to electricity as the ultimate solution, but this article will take issue with this.  This is principally because of the severe cost implications associated with either electricity storage or its corollary – demand side management.

 

2         Background

 

The following chart[1] shows UK average monthly delivered electrical and gas (without gas for power generation) demand (kWh/day/person) since 1996.

 

 

 

It can be seen that annual natural gas consumption (excluding gas to power stations) is typically more than twice electricity consumption, and as expected has a much larger seasonal swing. The installed capacity of UK power generation is about 81,000MW, which is equivalent to about 30kWh/person/day; it should be noted that at least 20% of this is not available at any one time. Because of emissions from the transport sector (about 22kWh/person/day), to achieve the 80% reduction in emissions pledged in the UK would effectively require the energy consumption currently fulfilled by gas to be either eliminated by energy efficiency or replaced by green electricity.  It is true that energy efficiency is expected to play its part, but household numbers are expected to grow and actually reversing the annual growth in energy demand has been found extremely challenging.

 

Information on peak daily gas consumption is not readily available but based upon data for the SW of England[2] is about twice daily winter averages and thus about 100kWh/day person. This is a vast amount of daily energy and to meet it using electricity would require a quadrupling of installed power capacity, both generation and production, even more if a proportion of this is to come from erratic renewables.

 

Heat pumps (by increasing the efficiency of electrical use) may help, but for thermodynamic reasons Coefficients of Performance (ie electrical energy in to heat energy out) for heat pump systems are unlikely to exceed 3.5, maybe less in commercial buildings.  Widespread use of heat pumps would also require much of the UK business and domestic sector to be fully converted to 3-phase supply.

 

As an alterative to the all electric route it would thus seem sensible to consider de-carbonising the UK gas supply which effectively means distributing hydrogen. Let us consider a scenario where the existing natural gas system is replaced by a hydrogen network operating at 80bar (ie within current technology) and with sufficient storage to completely uncouple supply and demand. The author estimates this to be about 3600kWh/UK person. This is about 2.5 months’ winter demand, but due to the high CV of hydrogen is only about 95kg of H₂ per person. At 80bar this would be about 12m³/person, or for the whole of the UK a single underground cavern of cube side 850m. This uncoupling of supply and demand has great advantages:

 

• Solar PV (via electrolysis) can generate hydrogen for use when it is most wanted. This is on cold winter nights not at noon in the summer.
• Wind power (via electrolysis) can overcome all of the issues of support fuels during periods of low wind. It is possible that by avoiding synchronisation issues wind power via electrolysis could be more efficient at capturing wind energy than direct connection to the grid.
• Tidal stream plant (via electrolysis) can store energy over a few hours and
• Fossil fuel plants (plus carbon capture and storage (CCS)) can be built  knowing there is a continuous demand for their production.
• Hydrogen can be produced using photovoltaic cells in the Sahara and imported to Europe. 

 

The hydrogen so produced and stored can then be used to heat homes or businesses, fire chemical processes, fuel vehicles or produce electricity at any appropriate scale and location. The use of hydrogen for power generation opens up a number of options ranging from its combustion in large Combined Cycle Gas Turbines (CCGT) or use in localised hydrogen fuel cells.  The latter could incorporate combined heat and power and could in turn raise the overall efficiency of energy conversion.

 

This paper has a financial reference in its title as a currency allows for the separation of producers and purchasers; the generic characteristics of a currency are that it must be of provable quality, readily convertible, stable, and storable; electricity fulfils only the first two criteria, fortunately hydrogen fulfils them all.

 

It will consider both the generic advantages of the hydrogen approach and then consider how the technology might be introduced with specific reference to the South West of England.

 

3         Implications

 

With such a hydrogen based system, a range of extremely difficult problems become tractable.  

 

1. 1.      Cost of low carbon energy. Future hydrogen or electricity prices are notoriously difficult to predict but from a consideration of a hydrocarbon feedstock (as might be provided by a fossil fuel or biomass), hydrogen production is always much more thermodynamically efficient and the capital costs of production plant are lower than electricity production. The source of the hydrogen is clearly the major determinant of price, with hydrogen from renewables such as wind or wave likely to be more expensive than from biomass or fossil fuels such as coal, pet-coke or natural gas.  However, the uncoupling of supply and demand will enable production facilities to be optimised. One of the great unknowns of future energy planning is the operability and costs of Carbon Capture and Storage (CCS) other than in base load mode. 

 

Base load hydrogen (plant operating 8000hrs/y) from natural gas by reform and shift  is usually predicted to be about twice the price of natural gas feedstock ie about 3-5 p/kWh from 1.5-2.5p/kWh gas, and operate at a thermal efficiency of 70 to 80% (HHV to HHV) (plant costs from reference 3[3]). Thermal efficiency from coal is likely to lie at about 60 to 65%.  Whilst in some circumstances hydrogen is a less flexible fuel than electricity there are many instances where this flexibility is not required and low cost is a greater virtue.  The ability to store hydrogen and thus operate production plant in accord with the weather, tides, or continuously from a fossil fuel plant (with CCS) is another clear advantage.  As will be explained below, increased electricity from renewables markedly decreases the operating hours of fossil fuel plant; this then disproportionately increases the cost of the latter as a source of electricity. Unlike post combustion CCS, the production of hydrogen by the gasification, reform and shift routes generally results in a concentrated CO₂ stream whose sequestration costs are likely to be dominated by more modest transportation and burial costs rather than high costs of removal from dilute flue gases. 

 

 

 

1. 2.      Cost of energy distribution. It is much cheaper to transport energy using gas compared with electricity.  Gas distribution is less capital intensive and has lower energy losses.  Electricity distribution is also associated with the losses of plant on standby.  In the UK typical small user gas costs about 1p/kWh to move from beach to consumer, compared to electricity at about 7p/kWh for power station to consumer.  This means that transporting energy using natural gas as the vector is 7 times cheaper than using electricity.  This ratio has been similar for 30years or more.  Hydrogen will be more expensive to pipe than natural gas, but still considerably less than electricity.  It now seems universally accepted that at low pressures (<20bar) there is no problem with hydrogen embrittlement of gas distribution networks; this has been proven with reference to Towns Gas (still used in parts of Germany) which is ~50% hydrogen for 60years. There may be problems with some welds in some existing 80bar systems but generally the transportation of high pressure hydrogen should not present major engineering difficulties.

 

Bulk underground storage of hydrogen is well developed around the world[4].

• In England, at Teesside, Yorkshire, the British company ICI has stored 1 million Nm³ of nearly pure hydrogen (95% of H₂ and 3-4% of CO₂) in three salt caverns at about 400 m in depth for a number of years.
• In France, at Beynes, Ile de France, the gas company Gaz de France stored a synthetic “town gas” (50-60% hydrogen) in an aquifer of 330 million Nm³ capacity between 1956 and 1974 . No gas losses or safety problems have been reported
• In Russia, pure hydrogen was stored underground at 90 bar for the needs of the aerospace industry
• In Germany, at Kiel, a 62% H₂ towns gas was stored in a salt cavern of 32000m³ at 80-100 bar
• In Germany at Ketzin towns gas was stored in a shallow aquifer in the 1960’s
• In Czechoslovakia, at Lobodice a 50% H₂ towns gas was stored in an aquifer.

Costs are difficult to estimate but the Praxair company has recently built a commercial hydrogen storage facility in Texas. Costs are likely to be very site specific.

 

1. 3.      Difficulty in raising capital for power plant. Entrepreneurs wishing to invest in future power plant are currently faced with four unknowns:

 

1. the price of fuel,
2. the value of the electricity,
3. the number of hours per year the plant will operate,
4. in the case of fossil fuel plant, the robustness of CCS in the face of cyclic operation. 

 

This is too much uncertainty for most sources of finance, especially if fossil fuel and nuclear generating plant are forced to routinely cycle between high, low and off load on a daily, monthly and seasonal basis due to the intermittency of renewable electricity generation.  Short annual operating hours have fearsome effects on financially geared plant.  If the fossil and nuclear plants could at least be assured of always selling their steady state output and a price independent of time of day or year it would greatly simplify the risk equations.  A modest gas fired plant making hydrogen from ‘Reform and Shift’ followed by CCS could be assured of a continuous market into the hydrogen network.  A nuclear plant could make hydrogen via electrolysis (at 80 to 85% efficiency, gross) when it could not sell its electricity directly.  Alternatively, excess renewable electricity could be stored using hydrogen.  Suddenly all generating plant becomes much more attractive as it can be sized for average not peak load. Costs fall substantially, not only because the plant is smaller and works harder, but because the cost of capital falls in line with reducing risk.

 

1. 4.      Avoiding practical and cultural changes associated with changing to an all electric society.  Gas (hydrogen or natural gas) is a very convenient instantaneous fuel.  It can be used for peak heating of premises when occupied unlike heat pumps which are really limited to continuous background operation (operating a heating system continuously uses around 20% more energy compared with heating morning and evening ie when required).  Conversion to hydrogen would not require a change of anything other than the individual domestic boiler and an appropriate up-rating of the gas supply network.  Conversion of the UK to all electrical use would require enormous grid strengthening, very substantial investment by individual householders (especially ground source), and a significant culture change.

 

1. 5.      Simplification of a move to hydrogen transportation.  The existence of a hydrogen pipeline network would speed up the introduction of H₂ powered vehicles.  Average UK transport consumption is about 22kWh/day/person.  Hydrogen has a modest “source to wheels” conversion efficiency compared with batteries, but hydrogen has an energy density of 39.0kWh/kg as against a lithium-ion-polymer battery of up to 0.13kWh/kg.  This difference is so huge that in many rural areas the author believes that compressed gaseous hydrogen will have a role.  A low cost hydrogen network shared with static consumption using any source of hydrogen from renewable to coal gasification, reform and shift with CCS suddenly becomes very competitive, and would allow a conventional market to develop.  Honda’s new car (the FCX Clarity) has range of 270miles with a tank pressure of 350bar which they believe will outperform batteries. Despite this, the author has view that this demand for such a large range may be inappropriate and that in many urban situations 80bar storage and reasonably large tank could be an attractive alternative, but this is probably a detail at this time.

 

1. 6.      Introduction of microCHP distributed generation.  There would be substantial opportunities for well proven and simple hydrogen fuel cells which would make point of use mCHP a real winner.  When considering the advantages of a hydrogen network, the cost savings in not having to reinforce or replace the existing electricity grid should also be considered.

 

1. 7.      Continued use of existing assets.  The continued ability to re-use most of the UK’s natural gas infrastructure without which it could become a stranded asset.  Clearly, anaerobic methane could be used within the existing system but it is suggested that much of the potential feedstock associated with the very large scale production of this are associated with waste streams (especially food) that will probably be unacceptable/unavailable by 2050.

 

1. 8.      Minimising the risks of major disruption to supply. Unlike gas, electricity has very little natural resilience to plant outages.  A fully integrated grid (with no gas) would need to be built even more robustly.  Surely there are large security advantages to having an energy supply distribution with significant storage capacity as back-up.  Demand side management is often heralded as the solution to managing electrical peak loads, but particularly if used in extremely cold or hot periods, this is likely to build up unsatisfied loads relatively quickly (eg after 3 hours most fridge freezers would probably want to come back on) and managing mass restarts in a fuzzy fashion will be particularly challenging.

 

1. 9.      Addresses seasonal variations in energy use. As shown by the first graph, there is a very considerable variation in UK peak winter/summer demand.  Variation in true daily flows are probably nearer 7 to 1 in many areas than the 2.5 to one for monthly flow.  The author has seen little explanation by proponents of the all electric approach to this conundrum.  Even with load shifting, which will be difficult for periods of more than about 6hours, the capital cost of generation and distribution to meet energy demand during those coldest snaps will be very considerable.  It is interesting that even ‘Without the Hot Air’[5] regarded this problem as within the territory of unproven technology.

 

10.  Further use of renewable energy sources.  Hydrogen is a convenient candidate for long distance energy transport from (for example) solar electricity in the Sahara.  Although the electrolysis step is only 80 to 85% efficient, this is probably no worse (and may even be better) than high voltage ac to high voltage dc and back again.  It also inherently solves the diurnal problem.  Fifty percent of the UK’s hydrogen needs could be conveyed via four 48inch, 100bar pipelines with minimal energy loss for pumping.

 

11.  Safety.  It must be acknowledged that hydrogen has an unfortunate reputation, but the designers of the hydrogen air ship were trying to contain huge quantities of hydrogen in cotton fabric bags where inevitably there were sources of ignition (the principle one being static electrical discharge).  In a subterranean pipework situation, the risks are well known and can be readily controlled.  In the event of a leak, hydrogen quickly disperses, is non-poisonous, totally clean and environmentally benign.

 

4         Introduction of hydrogen to the South West of England

 

One of the great problems of energy policy is how to actually make the substantive changes required.  Clearly the transition to hydrogen will be challenging but could be legislatively relatively straightforward.  Taking the example of the SW of England, the following data is for the Natural Gas SW feeder circa 2001.  It is unlikely to have changed substantially:

 

	Winter	Spring	Summer	Autumn	Peak	Average
MW	6,958	3,875	2,375	5,542	12,500	4,688
GWh/d	167	93	57	133	300	112.5
Equivalent H2 tonne/d	4264	2374	1455	3396	7660	2872
m3/day	46,246,154	25,753,846	15,784,615	36,830,769	83,076,923	31,153,846
m3/day at 80bar	578,077	321,923	197,308	460,385	1,038,462	389,423

 

The very peaky nature of the load can be seen, although the ratios of the seasonal averages are (as expected) similar to the national figures shown in the graph in section 2 above.  This is equivalent to about 2.3million homes at 18,000kWh/year/home.

 

The concept proposed here would be to construct about five 1000MW (600tonne/day) hydrogen production plants at the rural locations where gas is depressurised from the National Transmission System (NTS) to sub-Local Distribution Zones (sub-LDZ).  The gas is generally depressurised from about 80 to <4bar.  The hydrogen production plant would be expected to cost about £500/kW from gas and would be fuelled with gas from the NTS.  This would lead to a total plant investment of the order of £2.5billion or about £1100/equivalent home. Separate plant operating on coal (as might be built at Avonmouth) might be expected to cost twice this per kW. These would be connected to about 500km of new 80bar hydrogen transmission system, running from Bristol to Land’s End with spurs down to Bournemouth and Plymouth, and including the hydrogen storage cavern of about 2,500,000m³ at 80bar.  This would be needed to smooth annual production. Although large this is a cube of edge only 135m, and about the equivalent of the great pyramid in Egypt. Each hydrogen production plant would need a pipeline for CO₂ sequestration; ideally this would be into local saline aquifers as may exist under Swindon, or S Wales.

 

At the completion of a hydrogen plant supplying each sub-LDZ, the area would be converted to hydrogen. This would be managed in a similar fashion to the Towns Gas to Natural Gas programme carried out in the 1970s.  At least one major UK gas boiler manufacturer has a proven design for a hydrogen boiler.  It is frequently argued that such a conversion is impossible due to the low CV of hydrogen (about 13000kJ/m³) compared to gas (about 39,000kJ/m³) thereby requiring much larger pipes.  However, energy efficiency is supposed to be brought about by reducing total energy demand and the use of fuel cells instead of combination boilers may reduce the very highest morning and evening flows.

 

Such a system could in future act (via electrolysis) as an excellent buffer for the wide variations in power expected to come from the proposed Severn Barrage.  This is expected to peak at about 8,600MW but only yield an average of 2,000MW. Such a level of variation twice per day could be expected to substantially complicate the design of biomass or fossil fuel generation plant required during the quiet periods.  Hydrogen could also be produced from hot rocks projects In Cornwall.

 

With suitable sub-LDZ gas grid reinforcement and load shedding, it is possible to envisage the system coping with the peak day requirement – a concept extremely expensive with electricity. 

 

5         Funding the conversion

 

The key to this conversion lies in two areas:

 

1.  The ability to sell the hydrogen for transportation. As indicated above, this is 22kWh/day/person.  Currently petrol is about 10p/kWh (at the pump) and is consumed with an efficiency which is unlikely to be greater than 25%, and often much less.  Simple hydrogen fuels offer the ability to reach 40% efficiency.  This difference in efficiency offers the potential to charge a significant premium for the hydrogen, and possibly a sale price of 15 to 20p/kWh. This is suddenly very attractive.

2.  The ability for householders to pay a premium for hydrogen for use within fuel cell mCHP.  The author believes that, in the future, electricity prices must rise, possibly to 15p/kWh or more.  A fuel cell consuming hydrogen at an estimated 7 to 10p/kWh but still releasing 40% of its energy content as electricity could be financially attractive.

 

This paper does not attempt to quantify these incentives but a simple comparison with hydrogen ex-works of 3 to 5p/kWh make the relative costs very attractive.  The cost of laying new and upgrading existing gas distribution infrastructure can be modest hence the decision of the Canadians to gasify even large parts of rural Canada in the mid-west.  A large UK gas utility has an asset value of about £160/connection.

 

Another useful exercise is to compare the capital cost of radically upgrading the energy efficiency of the existing UK building stock with the costs of the above approach.  Unfortunately, data on the latter (especially its real effectiveness) is limited, but in the opinion of the author a typical whole house make-over is unlikely to cost less than £20,000 and is unlikely to save more than 6,000kWh/y of gas ie about a third of average current consumption.  Added to this would need to be the costs to build the new electricity infrastructure (both production and distribution) to supply the heat pumps required for hard to treat homes and buildings. In contrast the hydrogen route might cost:

 

• Central plant £1100/home
• Upgrade LDZ distribution £1000/home (first estimate)
• Installation of new hydrogen boiler £2500.

 

This total of £4600 clearly scores well against the whole house make-over figure, especially as it guarantees conformance with the 80% reduction target; continuing to burn natural gas leaves carbon emissions in the hands of the householder (see appendix A)

 

6         Possible legislative approach

 

It is suggested that the legislative approach could mirror the 1956 Clean Air Act. This enabled local authorities to declare clean air zones where householders and industry had to move over from low cost bituminous coal to much more expensive smokeless fuel and/or smoke reducing appliances.  Grants were available but the details of the changeover were managed by the private sector.  It is envisaged that the ‘Gas Safety (Management) Regulations GS(M)R 1996’ would be modified to allow local authorities and/or regional governments to stipulate that the gaseous fuel supplies within a chosen area would be converted from natural gas to hydrogen, and that this would occur from a certain date.  Users would have to convert to hydrogen boilers or fuel cells. The local gas network company could cooperate (or sell the network) and gas suppliers would have to manage the transition (ie arrange for the necessary changes in appliances, metering, and billing). It would obviously be sensible if this area was large enough to justify the construction of a reasonably sized hydrogen production facility; this might be a city the size of Bristol. Appropriate storage would also be necessary.  On the ground a co-coordinating committee could manage the conversion process.  The concentration of resources in a small area such as this would give considerable economies of scale.

 

7         Conclusions

 

The above (which the author can support with more statistical data) surely demonstrates that hydrogen should be considered the keystone of the low carbon future. If we are to meet our 2050 timelines now is the moment to undertake the practical research necessary to take this concept to reality.

 

Mark Crowther MA MIChemE CEng

GASTEC at CRE Ltd

 

The author is indebted to Prof DJC MacKay for the concept of kWh/day/person.

 

 

Appendix A

 

Indicative economics of a property purchasing hydrogen at 8.5p/kWh, and using a fuel cell microCHP or a condensing boiler.  Fuel cell heat efficiency is apparently low due to the use of a boost burner.

 

mCHP
House annual heat demand	12000	kWh
Fuel cell heat efficiency	50.00%
Hydrogen use	24000	kWh
Cost of hydrogen	£0.085	£/kWh
Annual cost of hydrogen	£2,040
Fuel cell electricity efficiency	30.00%
Electricity production	7200	kWh
Cost of electricity	£0.15	£/kWh
Annual electricity used	4500	kWh
Electricity imported	2500	kWh
Cost of elec imports	£375
Electricity exported	5200
FIT for export electricity	£0.13	£/kWh
Annual income from FIT	£676
Net Cost of heat	£1,364
Net cost of heat to home	£0.11	£/kWh
Total energy expenditure	£1,739
Conventional
Annual cost of electricity	£675
Efficiency of boiler	85.00%
Annual cost of Hydrogen	£1,200
Total energy expenditure	£1,875
Annual saving  from mCHP	£136

 

 

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[1] DUKES  at www.bis.gov.uk

[2] Submission from Transco to OFGEM for future investment early 2000

[3] F. David Doty, PhD, Doty Scientific, Inc. Columbia, SC Mar. 11, 2004 (updated Sept 21, 2004)

[4] www.ika.rwth-aachen.de/r2h/index.php

[5] Sustainable Energy – Without the Hot Air.  DJC MacKay www.withouthotair.com