Mixing and Transportation of Hydrogen via the
Natural Gas Network in Rozenburg
Anish Patil
Faculty of Technology, Policy and Management
Delft University of Technology, Jaffalaan 5
2628 BX, Delft. The Netherlands
Phone: +31 152788989
Email: a.patil@tudelft.nl
Abstract
The concept of a hydrogen economy is being touted as one of the hopes to reduce
greenhouse gas emissions and improve the energy security. The Netherlands has an
unusual starting position in this transition as one of the few countries with a fine meshed
natural gas infrastructure. The Greening of Gas project (VG2), which was sponsored by
the Dutch Economy, Ecology, and Technology (EET) program, studied the feasibility of
mixing and transporting hydrogen via the existing natural gas infrastructure. Within the
framework of the Greening of Gas project, this paper studies the conditions under which
mixing of hydrogen into the existing natural gas network is possible and might actually
occur. This paper addresses technical, institutional and economic aspects of the subject
matter to reveal the bottlenecks and (dis)advantages of introducing hydrogen into the
natural gas distribution network serving the Rozenburg community.
1. Introduction
The energy system is ill-prepared for the future: Experts predict severe shortage of oil
within the next few decades, to be followed by shortage of natural gas after another few
decades. Instead of waiting for these established sources of transportation fuels, power,
heat and petrochemicals to run out, there is a need to explore alternative energy sources
and energy carriers. The need to find alternatives is particularly urgent since experts
agreed that the carbon dioxide (CO2) emissions originating from fossil fuel usage are a
major contributor to the enhanced greenhouse effect – leading to climate change, and
politicians worldwide have agreed on ambitious CO2 emission reduction targets.
Hydrogen does offer a ray of hope – it has the potential to be a major energy carrier in the
energy system of the future in which we require a cleaner, more reliable, long-term
energy supply (Berry, Pasternak et al. 1996; Dunn 2002). Today, hydrogen is primarily
used as a chemical feedstock in the petrochemical, food, electronics, and metallurgical
processing industries. Its application for clean and sustainable energy systems is still
limited. Hydrogen can provide storage options for intermittent renewable technologies
such as solar and wind, and, when combined with emerging de-carbonization
technologies or sustainable energy sources, can reduce the climate impacts of continued
fossil fuel utilization (Conte, Iacobazzi et al. 2001; Barreto, Makihira et al. 2002). The
concept of the hydrogen economy centers on a closely connected action of two carriers –
hydrogen and electricity. Both can be used interchangeably to produce the other
(Hemmes, Patil et al. 2004; Hemmes, Patil et al. 2005). For example: fuel cell cars
consume hydrogen to produce electricity, and water electrolysis consumes electricity to
produce hydrogen. One important quality of hydrogen is that it can be stored more easily
than electricity, which does not imply that hydrogen storage is easy. Storage of hydrogen
derived from surplus sustainable electricity is an attractive prospect for the future, as it
would allow flexibility within the energy system, in which hydrogen can be used as a
buffer to convert the variable yield from renewable (solar, wind) power sources into a
controllable flow of energy (Quakernaat 1995; Hemmes, Zachariah-Wolf et al. 2007),
albeit accumulating losses at each conversion step.
The Greening of Gas (VG2) project studies whether the existing natural gas network can
act as a ‘buffer’ for hydrogen storage. More specifically, the project studies the feasibility
of mixing and transporting hydrogen via the existing natural gas network in the
Netherlands, and distributing the hydrogen/natural gas mixture to domestic and industrial
users that are connected to the gas grid, therewith contributing to a reduction of
distributed CO2 emissions.
1.1 Greening of Gas project (VG2)
The concept of a hydrogen economy is being touted as one of the hopes to reduce
greenhouse gas emissions and improve the energy security. As current hydrogen
production is mainly based on fossil resources and little hydrogen infrastructure is in
place, there is a long way to go before a hydrogen economy can become reality.
The Netherlands has an unusual starting position in this transition as one of the few
countries with a fine meshed natural gas infrastructure. The Greening of Gas project
(VG2), which was sponsored by the Dutch Economy, Ecology, and Technology (EET)
program, studied the feasibility of mixing and transporting hydrogen via the existing
natural gas infrastructure. Within the framework of the Greening of Gas project, this
paper studies the conditions under which the mixing of hydrogen into the existing natural
gas network is possible and might actually occur. This paper addresses the technical,
institutional and economic aspects of the subject matter to reveal (dis)advantages and
bottlenecks of introducing hydrogen into the natural gas distribution network serving the
Rozenburg community.
Firstly, this paper will introduce the Rozenburg case study. Secondly, technical analysis
will be carried out to determine the maximum volumetric percentage of hydrogen that
can be mixed into the natural gas – this maximum limit will be determined by the
analysis of the transportation pipes for leakage and condensation; analysis of the end user
appliances for safety and combustion. Once the maximum volumetric percentage of
hydrogen is determined the institutional and economic analysis for the case study will be
carried out.
2 Case background
Rozenburg is a small town (municipality) in the Rotterdam Port area. The municipality
covers an area of 6.50 km². With ± 7000 homes and more than 30 large chemical
industries, Rozenburg needs an annual supply of 20.106 Nm3 natural gas of G-gas quality.
In the Rotterdam port industrial complex hydrogen is produced as a co-product related to
the operation of the oil refineries and the production of chlorine (Wit, Hemmes et al.
2007). There is a well established hydrogen network connecting hydrogen producers and
users, the latter using hydrogen not as an energy carrier but as a chemical feedstock. For
the purpose of the case study surplus hydrogen is assumed to be available for mixing into
the Rozenburg natural gas grid. Figure 1 below shows the system diagram for the
Rozenburg case. On the left side is the production of hydrogen and natural gas and on the
right side is the demand. Hydrogen from nearby production plants (located in the Port of
Rotterdam industrial complex) is mixed with the natural gas. It is assumed that the
nearest mixing station at Pernis, in close proximity to Rozenburg, can be used for this
purpose. Once the hydrogen is mixed with the natural gas, the mixture is transported via
the natural gas network to the consumers, both industries and households.
Figure 1: System diagram for the Rozenburg Case Study
3 Mixing Hydrogen into the Natural Gas Network
The heating value of a mole of hydrogen is about 1/3 that of a mole of methane, thus the
energy density of natural gas decreases if hydrogen is injected. Because the energy
demand is independent of the mole fraction of hydrogen a higher pressure in the pipelines
must compensate the density decrease.
There are two choices for adding hydrogen to natural gas, to G-gas1 or to H-gas2. For the
past 40 years, most of the natural gas in the Netherlands came from the huge Groningen
gas (G-gas) field in the north of the Netherlands. This gas has a characteristic
composition, containing about 14% nitrogen. As a consequence both the calorific value
and the Wobbe-index are relatively low, compared to many of the gases used
internationally. As the Groningen gas field is depleting, other sources are needed to
supplement the dwindling G-gas supply. For this purpose G-gas from smaller fields, Hgas from (relatively small) onshore and offshore gas fields and imported natural gas are
either blended together (high calorific gases with low calorific gases) or ballasted with
nitrogen to yield “pseudo-G-gas” (Schouten, Janssen-van Rosmalen et al. 2006).
Most end-use equipment for natural gas in the Netherlands is installed and adjusted
taking into account the composition of the G-gas and the boundaries for the gas quality
(Wobbe-index, calorific value). For the G-gas segment, the Wobbe-index (W) must have
a value between 43.4 and 44.4 MJ/m3. Other values may lead to incomplete combustion
(CO, soot), will extinguish the flame, or overheat the equipment.
If H is the calorific value, and G the specific gravity of the Gas, then the Wobbe-Index
for the gas, W, can be defined as
W=
H
G
1
G-gas: Groningen gas contains more nitrogen than gas from most other fields, both onshore and offshore,
and therefore has lower calorific value and is termed G-gas, or L-gas (low calorific gas)
2
H-gas: High calorific gas
The Wobbe-index of the high calorific gases (H-gas) is far above the allowed values for
Dutch household appliances. At present, to satisfy the G-gas boundary conditions,
nitrogen is added to the H-gas, or high- and low-calorific value gases are blended.
Hydrogen addition lowers the Wobbe index and reduces the calorific value of the blend,
and a mixture with H-gas could comply with the Wobbe/calorific requirements of
household appliances. However, satisfying the requirements for Wobbe index and
calorific value, while necessary for supplying domestic appliances, are insufficient to
guarantee their safe performance: since the combustion characteristics of hydrogen differ
greatly from natural gas, the consequences for combustion behavior must be examined
too.
3.1 Hydrogen and End-user appliances
VG2 project partners at the Rijksuniversiteit Groningen and Gasunie have conducted
extensive research regarding the maximum amount of hydrogen that can be added to the
natural gas while guaranteeing the safety of the end-user appliances. In this research, they
have made a detailed comparison of the flash-back behavior of hydrogen-containing
natural gases with the variation in natural gases encountered in the Netherlands (Levinsky
2004), comparing burning velocities for hydrogen-containing natural gases (Hermanns
2007) and have made similar considerations for the rest of the EU for so-called H-gases
(Slim, Darmeveil et al. 2006; Pijpker 2007).
The results of the above mentioned research, as relevant to this paper, can be summarized
as below. (For detailed analysis we refer you to Levinsky 2004, Hermanns 2007, Slim,
Darmeveil et al. 2006, Pijpker 2007 and Patil, Levinsky et al. 2008).
Flash-back is caused by changes in the burning velocity of the fuel-air mixture, the
velocity with which the flame propagates against the flow of gas exiting the burner. As
can be seen in the figure 2 below, showing the burning velocity of various mixtures of
methane (major component of natural gas) and hydrogen as a function of the fuel-air ratio
(also known as the equivalence ratio), hydrogen addition significantly increases the
burning velocity of the mixture (Patil, Levinsky et al. 2008).
300
250
SL (cm/s)
200
CH4
CH4/H2 = 70/30
150
CH4/H2 = 20/80
H2
100
50
0
0.4 0.5 0.6 0.7 0.8 0.9 1.0 1.1 1.2 1.3 1.4 1.5 1.6
equivalence ratio F
Figure 2: Burning velocity of methane/H2 mixtures vs. equivalence ratio (figure source:
(Patil, Levinsky et al. 2008))
Since actual flash-back is most acute for cooking burners (although the same physical
phenomenon are responsible for overheating of the burner in other applications), we
considered the range of equivalence ratios (Φ, the ratio of fuel to air, divided by the
stoichiometric value of this ratio) valid for these systems, i.e. Φ>1 (the regime of Bunsentype flames). Since the gases with the highest burning velocities are those closest to the
stoichiometric ratio (Φ=1 in the figure), gases at the lowest end of the Dutch Wobbe
range were chosen for comparison with hydrogen-containing gases (there is a direct
relationship between equivalence ratio and Wobbe Index). Since the gas at Wobbe, W,
43.4 MJ/m3 is the distribution gas most sensitive for flash-back (the lowest W), and given
that hydrogen increases the burning velocity, no hydrogen is permitted at this Wobbe
Index; the burning velocity would then be automatically higher than the natural gas with
which it is compared. As the gases at the highest Wobbe Index in the Dutch band
(W=44.4 MJ/m3) are then the farthest removed from the stoichiometric ratio, they may
contain the highest amount of hydrogen. However, the experiments performed show that
at ~ 5% hydrogen at W = 44.4 MJ/m3, the tendency for flash-back was identical to that of
the most-sensitive natural gas. Thus, more hydrogen will yield burning velocities that are
higher than those encountered with the entire range of natural gases, and thus will
increase the risk of flashback outside the normal range. The results for the Dutch
domestic band (G-gas) are shown in Figure 3 (Note: the Wobbe index given here is the
resultant Wobbe after mixing with hydrogen). We remark here that this is necessarily a
conservative estimate. These results do not imply that all burners will automatically
flash-back at 6% H2, but rather that 5% is the fraction that guarantees that an appliance
that is adjusted to perform within the distribution band will suffer no deleterious effects
(Patil, Levinsky et al. 2008). Increasing the percentage above this value would require
local inspection (and possibly adjustment) of all appliances to receive hydrogen to
provide the necessary guarantee.
% H2 in natural gas
Maximum allowable H2 in NG
6
5
4
3
2
1
0
43.2 43.4 43.6 43.8 44
44.2 44.4 44.6
Wobbe index (MJ/m3)
Figure 3: Maximum percent of H2 permitted in natural gas as function of Wobbe index of
the gas-hydrogen mixture (figure source: (Patil, Levinsky et al. 2008)).
3.2 Transportation of the Hydrogen and Natural Gas mixture
As concluded above the maximum volumetric percentage of hydrogen that can be mixed
in the natural gas is 5%, further research for the transportation of hydrogen and natural
gas mixture will be carried out with this limit in mind. VG2 partners at the Delft
University of Technology has performed extensive research about the interaction of
hydrogen with the transport infrastructure, this research is published in (Neeft 2004;
Neeft, Schut et al. 2007). Below we summarize the results of this research as relevant to
this case study.
It can be concluded that for 5% hydrogen by volume in natural gas (Neeft, Schut et al.
2007; Patil, Levinsky et al. 2008):
1) Hydrogen diffuses through the walls of the pipelines, but the total flux (loss)
through the pipe is negligible.
2) Hydrogen leakage through rubber seals is negligible. In household/industrial
situations it is not easy to generalize at this point, but is not expected to be large at
such low concentrations of hydrogen.
3) Hydrogen diffuses through the walls of the pipeline, but even in the “worst” case
of transporting pure hydrogen, the release of hydrogen through the pipeline wall
is negligible.
4) Whereas the expected problems of condensate formation and hydrogen leakage
can be ruled out by our research, the mechanical integrity of the pipeline network
under exposure to hydrogen cannot be guaranteed. The phenomenon of enhanced
crack growth under exposure to hydrogen may eventually cause the demolishment
of the grid. VG2 research has generated some insight into the mechanism of
enhanced growth of (minute) cracks under hydrogen exposure, which appears to
be related to the trapping of (interstitially dissolved) hydrogen in defects that are
generated at the crack tip. The trapping of gas by defects reduces the mobility of
the defects and thus the possibility for their removal by diffusion of defects. On
the basis of VG2 research a method was proposed to reduce the dissociative
adsorption of hydrogen by iron in order to decrease the trapping probability, but
still the mechanism of enhanced crack growth is not fully understood and more
research is needed to obtain guarantees for the mechanical integrity of the gas
grid.
4 Institutional analysis
Over time within the socio-technical system, such as the Dutch natural gas system,
technical interrelationships and institutional rigidities have developed that may hinder
technological changes (Kemp, 1994). This can be explained by the concept of “path
dependence” – which refers to the phenomenon that the direction of future development
of a system depends, or is guided, by its past developments. Path dependency theory was
originally developed by economists to explain technology adoption processes and
industry evolution (Nelson and Winter 1977). Path dependence is an integral part of the
common knowledge that is developed within a certain area (Dosi 1982), technical
artefacts that are developed and adapted in relation to each other (Hughes 1987) and
institutional relationships developed over time (Kemp 1994; Rotmans, Kemp et al. 2001;
Geels 2002). Large technical systems, such as the energy system, encompass a capitalintensive infrastructure, a broad range of technical components and technologies and a
variety of actors and institutions (Markard and Truffer 2006; Bauer and Herder
Forthcoming). Path-dependence is further induced by the social and political
arrangements that determine the formation of the system: management and power
structures, technical disciplines and divisions, regulatory capture (Tsoutsos and
Stamboulis 2005). Such, institutional path dependence denotes a highly co-evolved, selfreferential system where the members of the system create rules and practices to
guarantee its self-perpetuation (Könnölä, Unruh et al. 2004). The techno-institutional
path dependence leads to huge sunk-costs – as the energy system evolved over time it has
lead to large investments for technologies, infrastructure, and market-setup. Institutional
analysis is performed for the hydrogen-natural gas supply chain.
4.1 Hydrogen Production
Shell, Linde Gas, Air Liquide and BP are the major hydrogen producers in the Rotterdam
area (Hoogma 2006). The Rotterdam area can be regarded as the centre of hydrogen
production in Europe (van den Bosch, Brezet et al. 2005; Smit, Weeda et al. 2007). The
participation of hydrogen producers is crucial for the success of project – as they control
the hydrogen production assets which are a conditio sine qua non for this case study. It is
assumed for the purpose of this research that sufficient hydrogen capacity is available in
the Rotterdam area and that part of the hydrogen produced could be diverted to service
the Rozenburg user community. Hydrogen producers may develop an active interest to
join such a project if they see new business opportunities (new markets), if sufficient
stimuli are in place (e.g. subsidies, tax incentives), if the project helps to acquire a
positive image (sustainable, responsible) or to maintain good relations with the local
community.
4.2 Mixing and transporting hydrogen and natural gas mixture
The transport and distribution of gas to the small consumers in the Rozenburg area is
managed by Eneco Energie. Eneco Energie is part of the larger Eneco holding, in which
the network operation function is managed independently, as required by law, from
energy service provision and trading functions. Eneco shares are owned by 61 Dutch
municipalities. As Eneco is known to pursue a “green energy” strategy, they may be
interested in “greening of gas” by hydrogen addition. However, as long as the hydrogen
available for this purpose is not generated from renewable sources, they are unlikely to
embark on this trajectory, as it would make them vulnerable to attacks from
environmental action groups. For the Eneco gas distribution network operator, which
interfaces with the Gasunie transmission network at the site of the Pernis mixing station,
reliability and safety of transport of the gas mixture are the predominant criteria.
Moreover, for a small-scale demonstration of hydrogen mixing into the gas grid restricted
to the municipality of Rozenburg, the mixing facility would need to be installed
downstream from the Pernis mixing station, tying into the pipeline serving only
Rozenburg. It is highly unlikely that Eneco Energie will be interested in making the
necessary investment, also considering the additional costs of testing all end-conversion
appliances, the limited environmental benefit (even if truly renewable hydrogen would be
supplied) to be gained from this effort and the lack of new business opportunity.
4.3 Usage – Industrial and Households
As discussed above, adequate performance of current domestic end-use equipment can
only be guaranteed with the 5% hydrogen limit. Besides the technical issues leading to
the 5% limit, there are also liability issues. For example, all domestic appliances have
been approved for use in accordance with EU approval rules (a CE safety and fitness-forpurpose regime, according to the Gas Appliance Directive, Directive 90/396/EEC). The
approval regime (residing under CEN), for which such safety aspects as flashback are
guaranteed, is intended for gases not containing hydrogen. Since hydrogen affects one of
the basic aspects (safety) specifically guaranteed by the Directive, addition of significant
quantities of hydrogen could be seen as an invalidation of the approval. The appliances
are being used outside their intended range, and this appears to raise liability issues.
These issues must be resolved prior to embarking on distribution of hydrogen containing
gases.
Furthermore, customers currently pay for gas based on volume. As the energy density of
hydrogen is lower than the energy density of natural gas, more gas (in case of a hydrogen
and natural gas mixture) by volume will be required to transfer the same energy content
as in the case of pure G-gas supply. Thus the billing procedure for considering the
calorific content of the gas must be adjusted to reflect the hydrogen-induced changes
correctly.
5 Economic analysis
Major contribution to the additional costs of hydrogen/natural gas mixtures instead of
natural gas as such is the cost of hydrogen, which is more expensive than natural gas. For
end users consuming gas mixtures with less than 5% of hydrogen by volume, the
additional hydrogen cost hardly affects their gas bill, assuming that hydrogen can be
mixed into the gas in an existing gas mixing station. In reality, this is not the case for the
community of Rozenburg. It is unclear; however, which party should bear the costs of
new mixing facilities, as end-users are free to purchase gas from any service provider
other than Eneco, dealing only with Eneco in its role of local gas distributor, as captive
users of the local distribution grid.
Consumers cannot be forced to pay for greener gas if they not specifically ordered
greener gas. In the current liberalized gas market, where customers can choose any
energy service provider, any scheme to stimulate “greening of gas” is likely to work in a
similar way as for “green” electricity: The purchase of green gas would then imply that
an equivalent portion of the gas distributed in the national gas system is derived from
green or renewable sources. For hydrogen produced from fossil resources, including
natural gas, such a scheme cannot work. However, in due course, as CCS is implemented,
customers may be offered the option of purchasing “carbon neutral” gas. Once hydrogen
is produced from renewable sources (with renewable electricity) it can be sold as truly
“green” gas. Green gas is, in fact, already on the market as biogas (methane rich gas
derived from landfills such as in Wijster, from drinking water sludge and sewage sludge
fermentation, etc.).
Under the present conditions no actor is likely to step into the project: the upfront costs
can simply not be justified. Currently, the Pernis mixing station is used for mixing gases
to be supplied throughout the Western Netherlands. If hydrogen is mixed into the gas at
the Pernis mixing station, it will be impossible to restrict the flow only for the Rozenburg
area. Another reason why Pernis is unsuitable for the case at hand is that it is not operated
year-around – implying that continuous distribution of the hydrogen/natural gas mixture
is not possible. In principle, to supply the mixture of hydrogen and natural gas only to the
Rozenburg area, a new gas mixing facility would have to be built downstream from the
Pernis station, with the concomitant exorbitant cost for such a small user community as
Rozenburg. It thus turns out that, if hydrogen mixing into the natural gas infrastructure is
to be implemented, a larger scale introduction would be more logical, either using an
existing Gasunie mixing station or investing in a new facility the cost of which is in line
with the benefit. In this exploratory case study, we will simply assume that the existing
mixing station can be used, and hence the economic analysis does not consider the capital
costs of a new mixing station.
As there are no major infrastructural investments needed (due to our assumption that an
existing mixing station, can be used for the purpose of this case study), the other links in
the hydrogen chain do not affect the economic analysis per se. Hence, in the economic
analysis only the hydrogen production and usage links are assessed for their contribution
to the additional costs. Wherever possible, costs are expressed in €/GJ. Even capital costs
are recalculated into €/GJ by assuming the yearly costs to be 10% of the capital costs
(covering depreciation & maintenance).
Calculations are based on the following assumptions:

A natural gas consumption of 4•107 Nm3/y (2•107 Nm3/y by the house holds of
Rozenburg and 2•107 Nm3/y by industries connected to the H2- enriched branch
of the NG-pipe-line).

An average H2 concentration of 5 %-v/v
o As a result a H2 demand of 2•106 Nm3/y

Net heating value: H2 = 10,8 MJ/Nm3, NG = 31,65 MJ/ Nm3

CO2-emission factor (Harmelen and Koch 2002):
o NG = CO2 56,8 kg/GJ,
o H2 = CO2 0 kg/GJ (Sustainable production),
o H2 = CO2 72 kg/GJ (Production from NG, 79% efficiency)

2007 €/$ rate =1,37
o Removal of the CO2-global warming effects 60 euro/ton CO2
(Underground CO2 storage by injection into old gas fields (35 - 85
euro/ton CO2)) (JC-Consultancy)
5.1 H2 production
The costs for H2 production are mainly determined by the feedstock and the various H2
production technologies. Figure 4 gives an overview of H2 production cost as a function
of production technology and primary energy prices for coal, gas, biomass and electricity.
Figure 4: H2 Production cost. Image source: (Simbolotti 2007)
In the Rozenburg case we assume that the hydrogen is available from the refinery, which
uses natural gas as a feedstock. The development of the prices for natural gas shows a
dramatic increase in the past decade (figure 5).
Figure 5: Prices (ex VAT) for natural gas on the Dutch market (image source: (EC 2007))
Assuming the 2008 natural gas price for the industry is 0,5 ct/m3, thus 7,5 €/GJ.
Extrapolating this feedstock price in Figure 5 results in H2 production cost of 33 $/GJ =
24,1 €/GJ, so the added value on basis of energy content is negative. The CO 2 emissions
of the hydrogen route as compared to the NG chain will increase with 72- 56,8 =15,2 kg
CO2/GJ. Mixing hydrogen, produced with natural gas as a feedstock, into the NG
network is unattractive because it results a negative added value of about 8 €/GJ and an
additional CO2 emission of 15,2 kg CO2/GJ. However, the central production of H2 as an
energy carrier is attractive as it opens up the route for CO2 separation and sequestration at
estimated costs of 4,3 €/GJH2 = 60 €/ton CO2. The overall conclusion is that, at current
price levels, fossil based H2 can be greened at costs of 12,2 €/GJ.
5.2 Usage – Industry and Households
From the previous technical analysis it is understood that the current domestic appliances
can handle gas mixtures with up to 5% hydrogen. But to address the liability aspect – few
domestic appliances in the region must be tested with the 5% H2 gas mixture to ensure
safety; if an appliance fails this test, then it must either be adjusted or replaced. It is
estimated that appliance testing and adjusting for a few hundred households will cost less
than € 100,000.
Further, many gas turbines (power generation) are not guaranteed for 5% hydrogen, and
this must be discussed with the owners and OEM providers. The current technical
analysis indicates that gas engines should be able to accept 5% hydrogen without engine
knock, but this is more dependent on the composition of the natural gas than on the
hydrogen, and must also be analyzed when setting possible limits.
A shortcoming of the above economic analysis is that it does not capture the real costs
involved during the implementation of this case study. This being an exploratory case
study, it assumes that the existing mixing station can be used for the purpose of this case
study – but in reality the existing mixing station, Pernis, is not suitable for a continuous
supply of hydrogen and natural gas to only the Rozenburg area. The cost of building a
new gas mixing facility for the sole purpose of the Rozenburg case runs into the millions
and would not be justified.
6 Discussion
Based on the Rozenburg case, this section will discuss the bottlenecks, disadvantages,
and advantages of introducing hydrogen in the existing natural gas network.
6.1 Bottlenecks
The biggest bottleneck in mixing hydrogen and natural gas in the Rozenburg area
originates from the fact that all end-conversion appliances of G-gas consumers in the
Netherlands are tailored to the properties of G-gas since the start of large scale
distribution of Groningen gas in the 1960’s. Since all CE certificates for safety and
fitness-for-purpose of gas using appliances in households and small industries are based
on G-gas specifications, a significant change in gas composition such as adding hydrogen
poses a liability problem that needs to be solved prior to embarking on hydrogen mixing
into the grid. In other words, the Dutch gas system is entrenched in the G-gas standard,
more precisely, the G-gas Wobbe Index and the G-gas calorific value.
However, as the combustion properties of a hydrogen/natural gas mixture are not the
same as those for natural gas, even at the same Wobbe and calorific value of the mixture,
the actual limits for hydrogen addition to natural gas are much more restrictive, since the
safety and fitness-for-purpose of the combustion systems in households must be
guaranteed. As discussed in the technical analysis, the dreaded phenomenon of burner
flashback restricts the volumetric percentage of hydrogen that can be present in the gas to
a maximum of 5%. For higher percentages, the safe performance of critical household
burners cannot be guaranteed. For the present situation, the 5% hydrogen limit is a
technical boundary condition.
Whereas the expected problems with hydrogen leakage from the transport and
distribution system turned out to be negligible, the problem that remains is the risk that
hydrogen poses to the mechanical integrity of the gas pipeline network. As exposure to
hydrogen may enhance the growth of minute cracks in the pipeline wall, pipeline rupture
is a risk that cannot be excluded. VG2 research generated valuable insight into the
mechanism at work, but more research is needed to further unravel the mechanism, test
proposed methods to inhibit crack growth and eventually guarantee pipeline integrity.
Introducing hydrogen “enriched” natural gas raises many questions on cost allocation.
Consumers cannot be forced to pay for greener gas if they not specifically ordered
greener gas. In the current liberalized gas market, where customers can choose any
energy service provider, any scheme to stimulate “greening of gas” is likely to work in a
similar way as for “green” electricity: The purchase of green gas would then imply that
an equivalent portion of the gas distributed in the national gas system is derived from
green or renewable sources. Whereas there is no physical difference between green and
brown or grey electricity, there is a physical difference between natural gas and a
hydrogen/natural gas blend. It is evident that, when locally introducing new gas
compositions or at the distribution network level, all users connected to the same network
receive the same gas, whether or not they have chosen to purchase the “new” gas. If
consumption of this gas raises additional costs (e.g. costs of testing and possibly
adjustment of appliances, or investment in new mixing facilities), then the additional cost
cannot be allocated to the users who have no interest in the “new” gas. For the gas system
this implies that any new gas introduced into the system should behave as the old gas (so
that all appliances can remain in place) or that new gas should be introduced at the level
of the national infrastructure network. Locally introducing new gas does therefore not
bring new business opportunities.
Another bottleneck is the (practical) inavailability of “green” hydrogen on the market. It
is obvious that the Rozenburg experiment is not easily implemented. Local actors, such
as Eneco and the partners in the Rotterdam Climate Initiative will not be motivated to
embark on the hydrogen mixing trajectory if the hydrogen is generated from fossil
sources. At the least they will require the hydrogen to be climate-neutral. The
implementation of the hydrogen mixing scenario will thus hinge on the technology
development, demonstration and regulation of full-scale Carbon Capture and
Sequestration (CCS).
The bottlenecks identified are not easily solved, implying that the scenario of hydrogen
mixing in the natural gas infrastructure is not likely to be brought into being in the
foreseeable future. If it would, hypothetically, be implemented, then some specific
advantages and disadvantages of hydrogen in natural gas are worth mentioning.
6.2 Disadvantages
Given the present restriction on hydrogen addition to 5% at maximum in the natural gas
network as is, the environmental benefit to be gained is very small: less than 2%
reduction in CO2 emissions - and only if the hydrogen is derived from sustainable
sources. However, this modest environmental benefit comes at the price of increased NOx
emissions. Especially NOx emissions in gas engines and industrial burners are expected
to increase significantly (~10%). Whereas the modest CO2 reduction is inherent to the
system, avoiding the increase in NOx emissions will require readjustment/replacement of
the equipment. For higher fractions of hydrogen than 5%, the tradeoff between
significantly increased NOx emissions and the reduction of CO2 (1/3 -1/2 of the volume
of the natural gas replaced by hydrogen) should be addressed.
6.3 Advantages
The case of supplying Rozenburg with hydrogen “enriched” natural gas brings little
advantage to any of the local actors. It can only bring true environmental benefit if the
hydrogen is supplied from renewable resources, and if the problem of increased NOx
emissions is effectively addressed. However, hydrogen also brings the advantage of
reducing condensate formation in the natural gas infrastructure: At all prevailing
pressures and temperatures the amount of condensate is less in the mixture of hydrogen
and natural gas than in pure natural gas (Schouten, Janssen-van Rosmalen et al. 2005).
7 Conclusion
Research into the combustion behaviour of hydrogen/natural gas mixtures revealed that
the volumetric percentage of hydrogen is restricted to a maximum of 5% - as a higher
hydrogen content of the gas may induce flame flashback in household appliances.
Without testing and possibly readjustment of all appliances the 5% hydrogen limit in
natural gas is the technical boundary condition for this case, and further analysis was
performed with this limit in mind.
Prior to any addition of hydrogen to the gas network a number of institutional issues must
be solved. These involve amongst others safety regulation and appliance certification, as
all domestic appliances carry a CE certificate that was issued for the use of natural gas
without hydrogen. Gas turbine operators need to renegotiate its fuel specification with the
original equipment manufacturer; without the manufacturer’s permission, the equipment
guarantee will be nullified.
Economically there is no case for mixing 5% hydrogen in natural gas. In reality the
supply of a hydrogen/natural gas blend to the community of Rozenburg requires new gas
mixing facilities to be installed and there is no business case for such an investment.
Since the end-users connected to the same network are by definition supplied with the
same gas, and consumers are free to choose their gas service provider, the additional cost
of hydrogen addition cannot be incurred on the users. There is no clear motivation for any
of the actors relevant to the Rozenburg case to pursue the option of hydrogen addition, at
least not on the short term.
For the longer term the option of hydrogen addition to natural gas should not be
discarded. In the framework of the VG2 project, new ceramic foam burners were
developed and tested. These were shown to be able to handle high percentages of
hydrogen, up to 70%, without the dreaded phenomenon of flame flashback and within
acceptable limits of NOx emissions (less than 25 ppm). By 2030, the current appliances
may gradually be discarded and replaced by a new generation of appliances equipped
with the new ceramic burner materials. Even domestic users may then be supplied with
hydrogen-rich gas obtained by mixing hydrogen with H-gas (high calorific gas from
small fields and imports). By that time, sustainable hydrogen may be produced and fed
into the natural gas network to store power surpluses from intermittent sources (wind,
solar). While a hydrogen network slowly co-evolves with the natural gas network, and
with other energy and energy-bound infrastructure networks (CO2, syngas), institutional
change must stay in sync.
Acknowledgement
This research was carried out within the framework of the Greening of Gas project,
which is financially supported by the Dutch Economy, Ecology, and Technology (EET)
programme (www.eet.nl). This paper is based on the Greening of Gas Case study report:
Case Study Rozenburg – Introducing Hydrogen in the Natural Gas Grid, submitted to the
Economy, Ecology, and Technology (EET), Netherlands.
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