Hydrogen Production from Fossile Sources

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Contents 1 Introduction 2 State of the Art 2.1 Hydrogen Production - Coal 2.2 Hydrogen Production - Crude Oil 2.3 Hydrogen Production - Natural Gas 2.4 Main Metrics 3 Market Diffusion and Main Industrial Players 3.1 Market Share in EU 3.2 Oil Market Share 3.3 Coal Market Share 3.4 Gas Market Share 3.5 Commercial Companies R&D (US & EU) 4 Hydrogen Cost 5 Summary 6 Notes

Introduction

The production of hydrogen from fossil fuels is a mature technology. Of the two main fossils fuels used, natural gas offers the best economics and efficiencies and is the main pathway used to generate hydrogen today, mainly for the production of ammonia and methanol. The other, coal, can also be used to produce hydrogen but the initial investment is much greater and the efficiency is lower than when natural gas is used. So to be competitive, the ex-coal hydrogen will be developed only where cheap coal is available in large quantities. Coal is also to be seen as a mean s to enhance the energy security of supply in certain regions, in particular China, the United States of America, or in Europe in Germany or Poland. So, even if coal is not the cheapest way to produce hydrogen, this pathway will play a part in the future, if the hydrogen economy is to become a reality at least for energy security of supply reasons.

The main advantage of using fossils fuels for the production of hydrogen is the economics: those pathways offer clearly the cheapest way to generate hydrogen. Typically the cost range of hydrogen using either coal or natural gas should be between 7 to 15EUR/GJ to be compare to 25EUR/GJ for electrolysis hydrogen.

The main challenges for fossils fuels hydrogen will be first to stay as cheap as possible even with the anticipated mid term rise of coal price and mainly natural gas price and second to keep the CO₂ emissions as low as possible. The challenge to lower the CO₂ emissions of such process could be met if the ability to capture and store the CO₂ underground can be demonstrated in an economic way.

There are two types of CO₂ that are emitted in the production of hydrogen from fossil fuels : the CO₂ that is coming from the chemicals reactions that are taking place in the reactor and the CO₂ that is coming from the fossils fuels combustion that is needed to feed the process with heat. The chemical CO₂ which can represent as high as 90% of the total CO₂ emissions of the plant can be easily captured using classical already industrialized process as the CO₂ is concentrated. Typically the cost of the capture could be around 20$/t of CO₂. The CO₂ that is coming from the fossil fuel combustion is much more difficult to capture because it is diluted in high proportion with nitrogen coming from the air. A classical cost associated with the CO₂ coming from the air combustion of fossils fuels is around 50$/t of CO₂.

Once the CO₂ is captured the other challenge is to be able to store large quantity of CO₂ for a very long period of time with a reasonable degree of certainty. There are three types of reservoir that can be use for such storage :

• deep saline aquifers that can offers decades or hundreds of years’ worth of storage with between 1 000 and 10 000 Gt. of CO₂ storage capacity available.
• depleted oil and gas fields that can offers decades of CO₂ emissions
• un-mineable coal seems that can offers a third option with a less promising future

Deep saline aquifers represents the highest potential to store large amounts of CO₂, but it represents also the highest challenge since this type of underground structure can be huge and unknown, making the permanence of such storage uncertain. The monitoring of this type of structure would also be difficult due to the large area to be covered.

Depleted oil and gas fields offer a relatively secure option because those reservoirs have shown their ability to store hydrocarbons for million years because they have been very studied for the requirements of oil and gas production. Their limits are firstly the relatively low capacity of storage in comparison to the worldwide CO₂ emissions of today or tomorrow and secondly, a relatively inhomogeneous distribution over the planet earth.

Finally, the last challenge for this long term option should be the public acceptance of such solution where CO₂ could be stored very near large cities.

State of the Art

Hydrogen Production - Coal

Historically, the first industrial process of hydrogen production was coal gasification, which was invented in 18th century. Gasification technology has been in use for over 100 years from "town gas" operations in the late 19th and early 20th centuries. Technology was very simple and uncomplicated: air was passed through a coke layer, warming it up to 800-900^oC. In the next step air was replaced by steam and an endothermic reaction occurred:

H₂O + C → CO + H₂

In this way syngas was produced and coke's temperature dropped down. When temperature was too low, again air was used instead of steam.

The arrival of electricity displaced these first commercial gasification plants and the technology laid dormant until German scientists employed gasification to produce various chemical feed stocks. In the early 1970s, research was initiated on using solid fuel as the primary feedstock in the gasification process. By the late 1980s, gasification technology was then integrated with combined cycle power plant to produce a high efficiency low-emission coal fueled power plant.

Scheme of IGCC Process

As natural gas prices were rising in the 1970s, Shell and Texaco each initiated research projects to develop solid fuel gasification technology to replace natural gas. A gasification plant integrated with a combined cycle electricity power plant compromised an IGCC facility. The total plant consists of four operating components: an air separation unit ("ASU"), a gasification plant, a gas clean-up system, and a combined cycle power plant. The ASU separates air into its component parts and sends the gasifier a stream of pure oxygen. The high temperature in the gasifier melts the inert material and then flows to the bottom of the gasification vessel where it is cooled into a glass-like non-leachable inert slag. This slag is used primary as aggregate in road gravel or concrete applications. The gasification plant produces the syngas from variety of fuels. Unfortunately it contains small amounts of particulates, and various other elements that are not captured as slag including sulfur. These materials must be removed before the syngas is used, otherwise they can damage the gas turbine or the accompanying selective catalytic reduction system.

Syngas is then piped through environmental control processes and afterwards, it can be cleanly burned in a combined cycle gas turbine. Combined cycle technology is composed of gas turbines, steam turbines, and their supporting infrastructure. Coal is converted in 98% with 565 m³/t average oxygen consumption. Thermal efficiency reaches 94%. Figure presents IGCC infrastructure (gasification with oxygen).

Operating parameters:

• Gasification temperatures 1370-1540^oC
• Combustion gas 1100^oC
• Combustion gas leaving gas turbine 600^oC
• Power of gas turbine 155MW
• Power of steam turbine 128MW
• Operating pressure 2.8MPa

This technology is currently available and checked. Table 1 shows examples of commercialised IGCC applications.

Table 1: Examples of commercialized IGCC infrastructures ^[1]

Power station	Wabash River	Tampa Electric Co.	Demkolec (Buggenum)	Elcogas (Puertolano)
Gas generator (type)	Destec	Texaco	Shell	Prenflo
Gas turbine (type)	GE 7FA	GE 7F	V 94.2	V 94.3
Efficiency LHV [%] (reached)	261.6 (252)	250 (250)	252 (252)	300
SO2 emission [mg/Nm3]	125 (40)	210	21.5	25
NOxemission	185	120	21.5-43	150
Dust emission				7.5

Scheme of IGCC (air-blow) Technology

Also available is IGCC (air-blown) process, which is a demo installation (Nakoso Power Plant, Fukushima 1986-1996 - 200 t/d).The main elements of infrastructure (250 MW, 1700 t/d) are: 2-gradual gas generator with dry delivery of coal, gas turbine type 701 DA. Coal combustion takes place in the bottom part of the reactor and coke gasification occurs in the upper part where syngas is received. New IGCC (air-blow) installations ought to provide high efficiency, low emission, as well as the possibility of using different types of coal (inferior quality). The figure shows schematically IGCC (air-blow) technology. The next figure describes Nakoso Power Plant, Fukushima 1700 t/d (250MW). Table 2 below shows data concerning demo installation IGCC-250 MW.

JobanJoint Co.Ltd Nakoso Power Station, Japan[2]

Table 2: Guidelines concerning IGCC-250MW installation

Power	250 MW
Coal	Dry, 1700 t/d
Apparatus	Gas turbine	701 D, outlet temp. 1200oC
Efficiency (LHV) (goal)	net	42%
	gross	48%
Emissions (goal)	SOx	8ppm
	NOx	5ppm
	dust	4 mg/Nm3

Generally, the emission limits in an IGCC power plant versus a solid fueled facility are significantly lower than other technology. Sulfur scrubbing is in excess of 98%, with 99.9% scrubbing levels reached in certain circumstances. The primary particulate emissions are from the handling of bulk materials. NO_x emissions are also dramatically lower than those produced from a standard coal power plant.

Hydrogen is already produced from the gasification of coal at an industrial scale all over the world. Techno-economic studies show that there are good prospects for the large-scale production of hydrogen from coal. Coal is a relatively inexpensive resource, making it an attractive energy source when considering options to produce hydrogen. Additionally the coal industry is well developed. A concern regarding the utilisation of coal in hydrogen is that the resulting CO₂ emissions are greater than those from any other method of producing of hydrogen. With improvements in methods for carbon capturing and sequestration, hydrogen production from coal may prove to be a cost-effective pathway for establishing a hydrogen economy.

Hydrogen Production - Crude Oil

Another source of hydrogen is crude oil. The first oil wells were drilled in China in the 4th century or earlier. In the 8th century, the streets of newly constructed Baghdad were paved with tar, derived from easily accessible petroleum from natural fields in the region. The modern history of petroleum began in 1846, with the discovery of the process of refining kerosene from coal by Atlantic Canada's Abraham Pineo Gesner. Poland's Ignacy Lukasiewicz discovered a means of refining kerosene from the more readily available "rock oil" ("petr-oleum") in 1852. The industry grew slowly in the 1800's, driven by the demand for kerosene and oil lamps. Oil became a major national concern in the early part of the 20th century: the introduction of the internal combustion engine provided a demand that has largely sustained the industry to this day. Today, about 90% of vehicular fuel needs are met by oil. Petroleum's worth as a portable, dense energy source powering the vast majority of vehicles and as the base of many industrial chemicals makes it one of the world's most important commodities.

Typical compositions of crude oil are shown in the table 3. The composition of crude oil varies greatly from one source to another. Oil from the Middle East contains a greater proportion of straight chain hydrocarbons, while Nigerian crude oil is predominantly cyclic hydrocarbons and aromatics. Mexican crude can be up to 5% sulfur, while Pennsylvanian crude contains less than 0.1%.

Table 3: Compositions of Crude Oil

Fraction	No. carbons	Boiling point	% (*)
Gases	1-4	<0	2
Light Naphtha	5-7	27-93	34
Heavy Naphtha	6-10	93-177	34
Kerosene	10-15	177-293	11
Light Gas Oil	13-18	204-343	21
Heavy Gas Oil	16-40	315-565	31
Residuum	>40	>565	31

(*) percentage composition for Gippsland

Hydrogen production is connected with crude oil conversion. It is impossible to imagine refining without this process. Unfortunately hydrogen is only a by-product of petrol reforming and the scale of production is insufficient even for refinery demands. Presently nobody produces hydrogen from crude oil. Hydrogen in refineries is obtained as a by-product of different processes:

• Hydrofining,
• Petrol reforming,
• Methanol production,
• Ethylene production,
• Gas from other plants.

In this situation application of currently available methods of hydrogen production from crude oil concentrate on gas cleaning plant.

The most frequently used technology in industry is the PSA (Pressure Swing Adsorption). Gas passes through the stationary adsorber (zeolite) layer in conditions: P_max = 40 bar, T = 290-310K. All compounds besides hydrogen are captured. The PSA method can separate N₂, CO, CH₄, CO₂, H₂O, Ar, C₂-C₈, methanol, ammonia, hydrogen sulfide, organic sulfur compounds and many others. Increase of PSA work time, causes worsening hydrogen purity, due to lower efficiency of adsorbent. Process of adsorption should be cyclic and last at least 3-6 min. After this period gas ought to feed another adsorber, consisting of regenerated adsorbent. Meanwhile saturated adsorbent is regenerated. The process of regeneration conducts under lower pressure (atmospheric pressure). Conditions prompt desorption of impurities. The adsorber is blown through by hydrogen and filled till it reaches operating pressure. From that point the next cycle starts. Although usual number of adsorber vessels in PSA installations is 4, it can be extended to 16 vessels as well. The figure below presents scheme of PSA installation.

Pressure Swing Adsorption (PSA) installation

The degree of hydrogen recovery depends on compositions of raw material and product purity and can vary from 60% to 98%. The larger installation, the easier achieve high purity and considerable hydrogen recovery degree. 3-12 adsorbers, which operate in 5-50^oC, provide 100 000 Nm³/h production capacity.

A second method for hydrogen cleaning plant is cryogenic separation method. Unfortunately it costs a lot, especially in case of large installations. Gas is cooled down till it reaches temperature at which all compounds – impurities condense. Operating conditions, used in practice, are: (-173^oC) to (-153^oC), (100-120K) and P_max 6MPa. The figure below describes interdependence between hydrogen concentration in gaseous phase, temperature and pressure. Dependence between degree of hydrogen recovery and hydrogen concentration and pressure is shown in the next figure.

Dependence between hydrogen in gaseous phase and temperature, pressure

Dependence between degree of hydrogen recovery and hydrogen concentration pressure

The third method takes advantage of semi-permeable membrane, made from palladium. Main disadvantages are: high cost of palladium and high operating temperatures. Hydrogen purity is also lower in comparison with other methods. Moreover membrane is very sensitive to even low concentrations of impurities. Hydrogen sulfide or aromatic hydrocarbons can damage it.

Main properties of these three methods are presented in the table 4 below.

Table 4: Characteristic of different gas cleaning plants

	Process
	With membrane	Adsorption	Cryogenic separation
Hydrogen purity %	< 95	99.9	95-99
Hydrogen recovery degree %	< 90	75-90	90-98
Product (H2) pressure	<< raw material	≈ raw material	Various
By-products	-	-	+
Raw material pressure MPa	1.8-12.6	1-6	1.8-3.5

Hydrogen is a by-product of crude oil reforming. Scale of production is insufficient even for refinery demand. Crude oil is a relatively expensive resource. Reflecting increasing consumer demand for petroleum products, world crude oil demand has been growing at an annualised compound rate slightly in excess of 2 percent in recent years. In addition, world oil supply is running out. To sum up, techno-economic studies show that there are not good prospects for the large scale production of hydrogen from crude oil.

Hydrogen Production - Natural Gas

Hydrogen is used in a number of industrial applications, with today's largest consumers being ammonia production facilities (62.4%), oil refineries (24.3%), and methanol production plants (8.7%)^[3]. Because such large quantities of hydrogen are required in these applications, the hydrogen is generally produced at the use point, the most common method being steam reforming of natural gas.

Steam reforming processes, in which steam reacts with natural gas (methane) or petroleum naphtha over a nickel catalyst, are primary methods for producing synthesis gas, i.e. gas mixtures of carbon monoxides and hydrogen.

While natural gas is generally thought of as methane, about 5.25% of the volume is comprised of ethane, propane, butane, hydrogen sulfide, and inerts (nitrogen, CO, and helium). The relative amounts of these components can vary greatly depending on the location of the wellhead. Table 5 below gives the composition of the natural gas feedstock, as well as typical pipeline and wellhead compositions.

Table 5: Natural gas compositions ^[4],^[5],^[6]

Component	Natural gas feedstock used in analysis (a)	Typical pipeline composition (b)	Typical range of wellhead components (mol%)( c )
	Mol % (dry)	Mol % (dry)	Low value	High value
Methane (CH4)	94.5	94.4	75	99
Ethane (C2H6)	2.7	3.1	1	15
Propane (C3H8)	1.5	0.5	1	10
Nitrogen (N2)	0.8	1.1	0	15
Carbone dioxide (CO2)	0.5	0.5	0	10
Iso butane (C4H10)	0	0.1	0	1
N-butane (C4H10)	0	0.1	0	2
Pentanes + (C5+)	0	0.2	0	1
Hydrogen sulfide (H2S)	0	0.0001	0	30
Helium (He)	0	0	0	5
Heat of combustion, HHV	53,680 J/g (23,079 Btu/1b)	53,463 J/g (22,985 Btu/1b)	_	_

Steam reforming of natural gas, sometimes referred to as steam methane reforming (SMR) is the most common method (over 90%) of producing commercial bulk hydrogen. It is also the least expensive method^[7]. At high temperatures (700-1100 ^oC) and in presence of a metal-based catalyst, steam reacts with methane to yield carbon monoxide and hydrogen. Main reactions which occur during methane reforming are shown in the table 6 below.

Table 6: Reactions during conversion methane with steam or/and oxygen

No.	Reaction
1		206
2		-41
3		247
4		75
5		-173
6		-36
7		-803
8		-284
9		-242

Reacting methane with steam is highly endothermic whereas reactions with oxygen are medium- or highly exothermic. Depending on production system, processes may or may not require external heat source (only with steam or tiny amount of oxygen). In second case steam reforming is known as autothermal reforming, which is a combination of partial oxidation near the reactor inlet with conventional steam reforming further along the reactor, improves the overall reactor efficiency and increases the flexibility of the process.

In industrial installations, catalytic conversion of methane is conducted under 30-40 bar . The process requires excess steam (usually 4:1) in order to compensate for increase in pressure. High pressure negatively influences the equilibrium point. Simultaneously is preferred due to economical point of view:

• lower costs of syngas compression,
• smaller dimensions of pressurised apparatus,
• higher effectiveness of heat utilisation.

In the Table 7 are presented typical methane reforming conditions depending on future application. It is profitably to realize pre-reforming of natural gas, consisting of huge amount hydrocarbons (petrol, paraffin). Process is conducted in adiabatic bed reactor where all hydrocarbons are converted to methane and carbon dioxide:

In such situation proper reformer works at lower steam/carbon ratio therefore decrease tendency to carbonic deposit creation on catalyst.

Table 7: Typical methane reforming conditions depending on future application

							Gas composition %vol. (H2O genitive)
Process	H2O/C	Tout [K]	Pout [bar]	H2	CO	CO2	CH4
Hydrogen	2.5	1123	27	48.6	9.2	5.2	5.9
Hydrogen (from petrol)	4.5	1073	27	34.6	5.3	8.0	2.4
Ammonia	3.7	1073	33	39.1	5.0	6.0	5.5
Methanol	3.0	1123	17	50.3	9.5	5.4	2.6
Aldehyde/alcohols	1.8	1138	17	28.0	25.9	19.7	1.1

Steam methane reforming (SMR) is usually realized as catalytic process. Catalyst consist of 5-30% Ni which is deposit on aluminum oxide, aluminum-magnesium spinel or on silicon and magnesium oxides. Catalyst deactivation can proceed in consequence of steam oxidation or creation of nickel-aluminum spinel. Catalyst operates on average 2 years.

As a first step of the SMR process (purification), sulphur must be removed from the natural gas in order to prevent poisoning of the catalyst.

Methane Steam Reforming (SMR) technology (Foster Wheeler)

(1)compressors; (2) furnace; (3) HDS reactor; (4) H2S adsorber; (5) pre-converter; (6) converter; (7) heat exchangers; (8)STK reactor CO; (9) NTK reactor CO; (10) CO2 adsorber; (11) CO2 desorber; (12) reactor of methanization; (13) boilers; (14) water cooler; (15) air cooler; (16) pumps; (17) turbine; (18) separators; (19) diffusers; (20) PSA adsorbers

Natural gas, free from sulphur and chloride is mixed with steam, warmed up by combustion gas from furnace and is fed into the steam reformer. The reformer consists of vertical pipes filled with catalyst. In the second step which is known as gas shift reaction (WGS), the carbon monoxide (CO) produced in the first reaction is reacted with steam over a catalyst to form hydrogen and carbon dioxide (CO₂). This process occurs in two stages, consisting of a high temperature shift (HTS) at 350^oC and a low temperature shift (LTS) at 190-210^oC. SMR technology produces, after carbon dioxide washing 99% pure hydrogen. General SMR process scheme is shown in the figure above. In technology infrastructure Pressure Swing Adsorption (PSA) installation was added as an option for gas purification. Additional steps could also be needed if carbon capture and sequestration technologies are developed and utilized as part of this method of hydrogen production.

The table 8 gives the major performance and design data for the hydrogen plant. The hydrogen plant efficiency changes if the excess steam can not be utilized by nearby source. However, this does not change the amount of hydrogen produced by the plant. The hydrogen plant efficiency is defined as the total energy produced by the hydrogen plant divided by the total energy into the plant, determined by the following formula:

If the steam were not included in the above equation, the conversion efficiency would decrease to 79.2% (i.e., the 2.6MPa steam is produced internally and the 4.8MPa stream could not be used by another source).

Table 8: Steam methane reforming hydrogen plant data ^[8]

Design Parameter	Data
Plant size (hydrogen production capacity)	1.5 million Nm3/day (57 million scfd)
Hydrogen purity	Industrial grade (>99.95 mol% H2)
Average operating capacity factor	90%
Natural gas consumed @ 100% operating capacity	392 Mg/day (feed) 43 Mg/day (fuel)
Steam requirement (2.6 Mpa or 380 psi) @ 100% operating capacity	1,293 Mg/day
Steam production (4.8 Mpa or 700 psi) @ 100% operating capacity	1,858 Mg/day
Electricity requirement @ 100% operating capacity	153,311 MJ/day
Hydrogen plant energy efficiency (higher heating value (HHV) basis)	89% (defined in text below)

Because hydrogen production by steam reforming of natural gas is highly exothermic process more steam is produced by the hydrogen plant than is consumed. The excess steam generated by the plant is assumed to be used by another source.

In terms of total air emissions, CO₂ is emitted in the greatest quantity, accounting for 99 wt% of the total air emissions. The vast majority of the CO₂ (84%) is released at the hydrogen plant. In the table 9 below is a list of the major air emissions as well as a breakdown of the percentage of each emission from the following subsystems: construction and decommissioning, natural gas production and transport, electricity generation, hydrogen plant operation, and avoided operation. After CO₂, methane is emitted in the next greatest quantity followed by non-methane hydrocarbons (NMHCs), NO_x, SO_x, CO, particulates, benzene, and N₂O. Overall, other than CO₂, most of the air emissions are a result of natural gas production and distribution. Very few emissions, other than CO₂, come from the hydrogen plant operation itself. The CH₄ is primarily a result of natural gas fugitive emissions which are 1.4% of the gross natural gas production for the base case. Although not shown in Table 9, the CH₄ emitted during production and distribution of natural gas is 76% of the total system methane emissions.

Table 9: Range of air emissions ^[8]

Air Emission	System total (g/kg of H2)	% of total in this table	% of total excluding CO2	% of total from construction & decommissioning	% of total from natural gas production & transport	% of total from electricity generation	% of total from H2 plant operation	% of total from avoided operations
Benzene (C6H6)	1.4	<0.0%	1.3%	0.0%	110.9%	0.0%	0.0%	-10.9%
Carbon Dioxide (CO2)	10,620.6	99.0%		0.4%	14.8%	2.5%	83.7%	-1.5%
Carbon monoxide (CO)	5.7	0.1%	5.3%	2.0%	106.3%	0.7%	1.4%	-10.4%
Methane (CH4)	59.8	0.6%	55.7%	<0.0%	110.8%	<0.0%	0.0%	-10.9%
Nitrogen oxides (Nox as NO2)	12.3	0.1%	11.0%	1.8%	90.3%	9.5%	7.3%	-8.9%
Nitrous oxide (N2O)	0.04	<0.0%	<0.0%	7.3%	37.6%	58.7%	0.0%	-3.7%
Non-methane hydrocarbons (NMHCs)	16.8*	0.2%	15.6%	1.7%	89.8%	14.5%	0.0%	-6.0%
Particulates	2.0	<0.0%	1.8%	64.5%	25.2%	11.6%	1.1%	-2.5%
Sulfur Oxides (Sox as SO2)	9.5	0.1%	8.8%	13.5%	68.3%	24.9%	0.0%	-6.7%

Note: Construction and decommissioning include plant construction and decommissioning as well as construction of the natural gas pipeline.

Main Metrics

With partner cooperation involved in Task 1.3 of Work Package 1, Roads2HyCOM Project, a series of metrics was compiled in order to enable simplified evaluation and comparison of each currently available technology for hydrogen production.

The next step involoved, the main industrial players compiling the actual data against each metric (e.g. gas, coal or crude oil as a primary source of hydrogen). The information received related to technology accessibility, local and global environmental impact, energy efficiency, capacity and availability, safety of technology, provided data about state of the art and its future potential, relative to creation of hydrogen communities.

The aim of this task is to assess the key steps in a hydrogen pathway, from production of hydrogen to the final distribution to users for energy conversion applications. The main metrics and results, associated with the fossil fuels hydrogen production are given below in the table 10.

Table 10: Main metrics associated with fossils fuels hydrogen production

METRIC	SUB METRIC	DATA / RATING	UNITS	Natural gas		Coal
				With CO2 seq.	Without CO2 seq.	With CO2 seq.	Without CO2 seq.
Technology Accessibility	Compatibility with existing technologies	Rating	0-4	2	4	2	3
	Number of producers (1)	Data	no.	0	30	0	4
	Posibility of extending existing raffineries	Rating	0-4	n/a	n/a	n/a	n/a
Global Environmental Impact	GHG emissions associated with fuel production	Data	gCO2 eq/kg fuel	n/a	n/a	n/a	n/a
	CO2 emissions associated with fuel production	Data	gCO2/kg fuel	1.53	9.22	3	18.76
Local Environmental Impact	Air quality impact (consider Nox, PM, CO, NMHC) (2)	Rating	0-4	n/a	2	n/a	3
	Noise or perception of noise from fuel production facilities	Data/Rating	dB(A), sone	n/a	n/a	n/a	n/a
	Land use/damage to nature	Rating	0-4	n/a	n/a	n/a	n/a
Efficiency	Part load energy efficiency of technology	Data	%	n/a	n/a	n/a	n/a
	Full load energy oefficiency of technology	Data	%	67	74	59	62
	Energy efficiency of auxiliary facilities	Data	%	n/a	n/a	n/a	n/a
Capacity & Availability	Measured fuel production/supply	Data	kg fuel / year	n/a	n/a	n/a	n/a
	Maximun fuel production/supply (capacity)	Data	kg fuel / year	n/a	n/a	n/a	n/a
	Number of hours per year energy is available (regular use - maintenance hours, expected repairs & or failure)	Data	hours / year	n/a	n/a	n/a	n/a
Cost (click here for more datails)	Capital investment for fuel production facilities	Data	€/capacity	166 €/kW (275 US$/kg/d, 150000 kg/d, Large Scale SMR)[9]		582 €/kW (967 US$/kg/d, 150000 kg/d, Large Scale Coal Gasification)[9]
	Operational / maintenance cost (labour, electric energy cost, service, cost of other materials etc.)	Data	€/year	34609635 €/yr (34931000 US$/yr, 150000 kg/d)[9]		33092720 €/yr (33400000 US$/yr, 150000 kg/d)[9]
	Decommisioning cost	Data	€/capacity	n/a	n/a	n/a	n/a
	Selling price of fuel produced	Data	€/kg	0.03-0.04 €/kWh[10]		n/a	n/a
Safety	No. Of incidents (shut-downs, full leakage, tech failure)	Data	no. / year	n/a	n/a	n/a	n/a
	No. Of accidents causing injury to people,damage to property/environment	Data	no. / year	n/a	n/a	n/a	n/a

For most of these metrics, information appears to be unavailable. In most situations hydrogen is a semi-manufactured product (source - gas) or by-product (source - crude-oil), integrated into another process, this is a key reason as to the difficulty in obtaining information. The industrial data available relates for example in an ammonia production plant, to overall plant emissions rather than specifically to hydrogen manufacture. The industrial data available relates for example in an ammonia production plant, to overall plant emissions rather than specifically to hydrogen manufacture. In addition some of this information is commercially sensitive and is difficult for individual industrial players to provide. Crude oil, as a primary source of hydrogen is even more demanding, as it is currently not commercially produced in this way.

Despite several problems it is clear that metrics could provide valuable insight albeit in a simple way for data and technology evaluation. Further contacts with industry will allow us to assess all potential sources of hydrogen information.

Market Diffusion and Main Industrial Players

Market Share in EU

Presently the European Union aims at covering the increasing demand for electricity and to ensure the security of its supply, with increasing diversification of the fuels for power plants. Prices of crude oil and natural gas depend on depleting resources which are controlled by several main players. A monopolistic market runs the danger of increasing prices and it is highly desirable to have a variety of sources of hydrogen. The figure below describes EU market share of primary energy resources, from which hydrogen can be produced. Diagram assesses actual scale of their consumption. Not forgetting about oil, as a primary source used in transport, it is clear, the EU dependency on the main producers of crude oil and gas.

Structure of inputs of electricity generation in European Union in 2004 ^[11]

Shown below in the figures below are the primary energy consumption figures for Poland, Czech Republic, Hungary and Slovakia. European Union consists of countries, possessing different natural resources, and each nation should develop technologies based on its own available resources. Such policy should result in better diversification of the fuels for power plants and transport. Technologies already developed enable the the production of hydrogen from a variety of sources and through a variety of methods. Its desirable that in the future hydrogen economy all of these technologies play a part, enabling both to increase the security of supply and to maximise an individual member states strengths. For example it is clearly seen that Central Europe has considerable coal resources, and in particular in Poland energy from coal plays a much bigger role in comparison with ither EU countries.

Primary Energy Consumption in Poland 2005 [12]	Primary Energy Consumption in Czech Republic 2005 [12]
Primary Energy Consumption in Hungary 2005 [12]	Primary Energy Consumption in Slovakia 2005 [12]

Oil Market Share

Although much attention has been focused on using coal as the primary feedstock, the large majority of gasification projects in Europe to date are also based upon the use of fuels other than coal, as shown in tables below. Heavy liquid fuels like petroleum coke and other refinery residues can be also used for producing hydrogen rich gas. Most of the fuels of interest for energy applications include:

• Atmospheric distillation residues,
• Vacuum distillation residue,
• Residual tar from solvent deasphalting / visbreaking process,
• Petroleum coke.

The main disadvantages of these technologies are price of energy source and depleting world resources of crude oil. Assessment of technology for hydrogen production from crude oil demonstrated this root to be inefficient and uneconomic. Further chapters of this report will focus on the gas and coal market characterization, as these fossil fuels offer the greatest potential as primary sources for production of hydrogen.

Table 11: Major operating electricity producing gasiefiers by country ^[13]

Country	Plant Name	Type	Feedstock	Products	Year
Germany	Leuna Methanol Anlage	Shell	Visbreaker residue	H2, Methanol, Electricity	1985
Germany	Slurry/Oil Gasification	Lurgi MPG	Oil & Slurry	Electricity & Methanol	1968
Italy	Project	Texaco	ROSE Asphalt	Electricity, H2 & Steam	2000
Italy	SARLUX GCC/H2 Plant	Texaco	Visbreaker Residue	Electricity, H2 & Steam	2000
Netherlands	Pernis Shell Gasif. Hydrogen Plant	Shell	Visbreaker Residue	H2 & Electricity	1997
Singapore	Chawan IGCC Plant	Texaco	Residual Oil	Electricity, H2 & Steam	2001
Spain	Puertollano GCC Plant	PRENFLO	Coal & petcoke	Electricity	1997
USA	Delaware Clean Energy Gogen.	Texaco	Fluid petcoke	Electricity & Steam	2001
USA	New Bern Gasification Plant	Chemrec	Black liquor	Electricity	1997
USA	Wabash River Energy Ltd	E-GAS	Petcoke	Electricity	1995
USA	El Dorado IGCC Plant	Texaco	Petcoke, Ref. Waste &	Electricity & HP Steam	1996

Source: Derived from the World Gasification Database, US DOE and Gasification Technology Council.

Table 12: Major planned electricity producing gasiefiers by country ^[13]

Country	Plant Name	Type	Feedstock	Products	Year
India	Bathinda IGCC	Texaco	Petcoke	Electricity	2005
Italy	Agip IGCC	Shell	Visbreaker residue	Electricity & H2	2003
Italy	Sannazzaro GCC Plant	Texaco	Visbreaker residue	Electricity	2005
Japan	Marifu IGCC Plant	Texaco	Petcoke	Electricity	2004
Japan	Yokohama Cogen/B	Texaco	Vac residue	Electricity	2003
Poland	Gdansk IGCC Plant	Texaco	Visbreaker residue	Electricity & H2 & Steam	2005
Spain	Bilbao IGCC Plant	Texaco	Vac residue	Electricity & H2	2005
USA	Port Arthur GCC Proj	E-GAS	Petcoke	Electricity	2005
USA	Lake Charles IGCC Proj.	Texaco	Petcoke	Electricity & H2 & Steam	2005
USA	Deer Park GCC Plant	Texaco	Petcoke	Electricity; Syngas & Steam	2006
USA	Polk Country Gasification Plant	Texaco	Petcoke	Electricity	2005

Source: Derived from the World Gasification Database, US DOE and Gasification Technology Council.

Table 13: Feedstocks used in gasification plants ^[13]

Feedstock	Operational plant	Planned plant
Coal	27	17
Coal / petcoke	3	1
Petcoke	5	7
Natural gas	22	0
Biomass	12	3
Fuel oil / heavy petroleum residues	29	2
Municipal waste	5	0
Naphta	5	0
Vacuum residue	12	2
Unknown	40	6
TOTAL	160	35

Source: Derived from the World Gasification Database, US DOE and Gasification Technology Council.

Coal Market Share

Coal is one of most promising sources for hydrogen production. However, in recent years the coal industry in Western Europe has suffered a decline, reducing the number of working coal mines due to perceived poor efficiency and low profitability. However, Poland has maintained a sustained level of coal production in the period 1973 - 2003, see figure below, and has developed a leadership position in Europe, with Germany 16%, UK 15%, Czech Republic 7% and Spain 7% following.

Hard coal production in the enlarged EU: 1973-2003 [14]

Indigenous hard coal production in 2003, share by Member State [14]

In general terms, there has not been any significant change in quantities traded in EU-25 between 2002 and 2003. At the end of 2003 and also in the beginning of 2004 impressive development of China's economy has drastically affected traditional market flows. China has also its own big resources of coal. Nevertheless, it is hard to predict how its quick tempo of evolution can affect the global market. To sum up, it is clear that coal and gas will continue to play an active role in covering the future energy needs, albeit with increasing efforts being made to reduce their negative environmental impact.

Origin of hard coal import into EU-25 ^[14]

Apart from its own resources the EU also imports coal. The list of importers is quite long and starting from the biggest, main of the importer list are: South Africa, Australia, Colombia, United States, and Russia. In 2003 the EU as a whole produced approximately 180 million tonnes (figure above) and used about 370 millions tonns of coal (figure). The difference is made up by imported product (figure). Figure below presents balance between EU own production and import. Since 2000, the ratio of imported coal to EU produced coal has been steady at 50/50.

Production, imports and gross inland consumption of hard coal: EU-25 ^[14]

Gross inland consumption of hard coal by sector in EU-25 ^[14]

The figure above represents structure of hard coal consumption in EU-25. Most coal consuming sectors are: power plants, coking plants and industry. Household form a negligible part.

Gas Market Share

Since 1^st July 2004, all industrial users have been able to choose their gas supplier. The idea was to boost the competitiveness of European energy undertakings against international competitors by allowing the market to operate freely. The main structural characteristic of European gas imports is the lack of competition on the supply side, dominated by State-owned (and subsidised) companies from outside the European Union, such as Statoil, Gazprom and Sonatrach. In 2004, they represented over 45% of the European market (figure). Moreover, this dependency is expected to show a strong increase in the years to come.

European gas supply in 2004 [15]

Supply capacity for Europe 2010-2020 [16]

Indigenous supplies will decline and by 2020 will be around 40% (figure) ^[16]. Europe, however, is surrounded by many commercial gas suppliers. As the market increases, supply diversity will increase and also interconnect delivery routes to Europe. Imports into Europe will rise from traditional producers, in Russia, Algeria, and Libya and also new volumes can be contracted from further sources, like the Gulf States, Nigeria, Egypt, and South America.

Natural gas sales by sector ^[16]

Natural gas is currently the second most important source of energy for Europe, meeting around 25% of primary energy needs, forecast to rise towards 30% by 2020 (figure). Although gas demand is growing in all sectors of the economy, it is particularly strong in power generation, because when it is used instead of other fossil fuels, CO₂ emissions are lowered significantly and other pollutants are much less. Natural gas is expected to almost double by 2020.

The North Sea contains Western Europe’s largest oil and natural gas reserves. According to Oil and Gas Journal (1/1/05), the five countries in the North Sea region (Norway, UK Denmark, the Netherlands and Germany) together had 2 billion tones of proven oil reserves in 2005 (Table 14). Norway owns the bulk of these reserves (57 percent), followed by the UK (30 percent). The five countries in the North Sea region together had proven natural gas reserves of 4.4 billion tones of oil equivalent in 2005. Italy had proven also natural gas reserves of 0.2 billion, the fourth-largest in the EU, in 2005.

Table 14: Production of oil and gas in the North Sea (EU + Norway) in millions tones of oil equivalent ^[17]

Year	Oil	Gas	Total
2000	288	174	462
2004	244	189	433
2010	204	189	393
2015	139	169	308

Commercial Companies R&D (US & EU)

Hydrogen as a future energy source is an important aspect of research and development activities of many, international firms. It is hard to present here all of companies and academic institutions involved in this topic. Bellow is presented list of key, international players in hydrogen R&D community:

• Air Liquide
• Air Products and Chemicals,
• Inc. Alchemix Corporation Anuvu,
• Inc. Arbin Instruments Avlence,
• LLC BOC Group Collier Technologies,
• British Petroleum (BP),
• Inc. Direct Technologies,
• Inc. Gas Technology Institute,
• GE Global Research Genesis Fueltech Inc. H2GEN Innovations,
• Inc. HERA Hydrogen Storage Systems Hydrogen Components,
• Inc. Hydrogen Power,
• Inc. HyRadix,
• Inc. Infinity Fuel Cell and Hydrogen,
• LLC InnovaTek,
• In. Intelligent Energy JadooPower Systems,
• Inc. Millennium Cell,
• Inc. NextEnergy, Ocenergy, Plug Power,
• Inc. Praxair,
• Inc. Proton Energy Systems,
• Inc. Protonex Technology Corporation Quantum Technologies,
• Inc. ReliOn,
• Inc. Safe Hydrogen,
• LLC Stuart Energy Systems Corporation Sud-Chemie,
• Inc. Teledyne Energy Systems,
• Inc. Texaco Ovonic Hydrogen Systems,
• LLC TIAX,
• LLC UTC Power Ztek Corporation,
• Hexion BV,
• Linde Gas,
• Norsk Hydro,
• Shell Hydrogen.

For more information it is recommended to directly contact the companies listed.

Hydrogen Cost

There are numerous examples in literature confirming SMR method for hydrogen production superiority ^[18],^[19]. Even after including the cost of CO₂ sequestration reforming of natural gas in a centralized plant is the most economical technology. This is the dominant source of hydrogen today in refining and other industrial applications. Most information from available documents (IEA and US National Academies reports) shows that thermochemical routes to produce hydrogen from gas or coal have substantially lower cost than electrolysis. The final report of HYPOGEN project, concerning future costs of technology concludes the following^[20] :

Various simulations indicate hydrogen from SMR method will cost in the region of $5.6/GJ. Capturing and storing the emitted CO₂ is estimated to add 20-25% to the cost of $21/GJ the lowest carbon free electrolysis route using nuclear electricity. The cost from coal gasification with or without capture is also approximately twice the cost from natural gas.

Presently hydrogen fuels exist as natural resources only as natural gas, but they may in a variety of ways be synthetically produced using other energy resources. Current annual world hydrogen production is about 50 Tg (500 GNm³) ^[21].

World do not forget that hydrogen has great potential as an energy carrier. The overall European hydrogen market is estimated to be about $368 million in 2005 and is expected to grow to 740$ million in 2010 ^[22]. The European Commission funds various projects concerning the needs of the future, potential, hydrogen community. In comparison with Europe the US market is two times bigger and is expected to rise to $1.605 million in 2010.

Summary

Today only three methods are used to produce hydrogen for the industrial marketplace:

• Methane steam reforming (SMR),
• Autothermal reforming (ATR),
• Noncatalytic partial oxidation (POX).

The figure includes results for modified SMR method: SMR/OR. This technology is an intermediate version between the first (SMR) and second (ATR) process. In the case of autothermal reforming, the heat necessary for endothermic reactions, is received from partial raw material combustion.

Syngas composition depending on method of hydrogen production

This figure shows gas composition, obtained from each one of the above methods. Composition is described by H₂/CO ratio. It is obvious that the more significant participation of oxidation reaction in process and lower H/C ratio in raw material, the smaller value of H₂/CO ratio.

Comparison between costs and scale of production.

The other figure represents economical efficiency of syngas production from different raw materials. Results show that efficiency is heavily dependent on production scale and substrate's H/C ratio. The best results were achieved using natural gas. H/C ratio, costs, and technology is the most promising way of hydrogen production.

In summary, autothermal reforming is usually applied as single installation (a individual infrastructure) due to high capital cost (temperature about 1900^oC). Partial oxidation of fossil fuels in large gasifiers is another method of thermal hydrogen production. It involves the reaction of fuel with a limited supply of oxygen to produce a hydrogen mixture, which is then purified. Partial oxidation can be applied to a wide range of hydrocarbon feedstocks, including natural gas, heavy oils, solid biomass, and coal. Its primary by-product is carbon dioxide.

The SMR method is the most energy-efficient commercialized technology currently available, and is most cost-effective when applied to large, constant loads. Hydrogen is produced by the SMR process in large centralized industrial plants for use in numerous applications, including chemical manufacturing and petroleum refining. Steam reforming of natural gas offers an efficient, economical, and widely used process for hydrogen production, and provides near- and mid-term energy security. The efficiency of the methane steam reforming process is about 65% to 75%, among the highest current commercially available production methods. Natural gas is a convenient, easy to handle, hydrogen feedstock with a high hydrogen-to-carbon ratio. It is worth remembering that cost of this technology depends on natural gas prices. Only IGCC, gasification of coal rivals with SMR method. Price of coal and a well developed industry make this technology very attractive.

Multiple challenges must be overcome to achieve the vision of secure, abundant, inexpensive, and clean hydrogen production with low carbon emissions. Unfortunately current technologies produce large quantities of carbon dioxide and are not optimized for making hydrogen as an energy carrier. Existing commercial production methods (such as methane reformation, IGCC, gasification of coal) require also technical improvements to reduce costs, improve efficiencies, and produce inexpensive, high-purity hydrogen with little or no carbon emissions. A cost-effective way to capture and sequester carbon dioxide would facilitate this method of production of vast quantities of hydrogen with low carbon emissions. Captured system would need to be engineered into plant designs for steam methane reformers and multifuel gasifiers to lower the overall system costs and emissions.

Notes

1. ↑ [1]
2. ↑ Mitsubishi Heavy Industries, Ltd, Technical Review Vol.42, 2005
3. ↑ Today’s international consumption of hydrogen.
4. ↑ SRI 1994
5. ↑ ChemicalEconomics Handbook (Lacson, 1999)
6. ↑ Ullmann’s Encyclopedia of Industrial Chemistry, 1986
7. ↑ George W.Crabtree, Mildred S.Dresselhaus and Michelle V.Buchanan, ``The Hydrogen Economy”, Physics Today, December, 2004
8. ↑ ^{8.0 8.1} Pamel L.Spath, Margaret K.Mann ”Life cycle assessment of hydrogen production via natural gas steam reforming”, February 2001
9. ↑ ^{9.0 9.1 9.2 9.3} D. Simbeck, E. Chang, Hydrogen Supply: Cost Estimate for Hydrogen Pathways - Scoping Analysis NREL/SR-540-32525, November 2002
10. ↑ Deutscher Wasserstoff- und Brennstoffzellen-Verband e.V., 2005
11. ↑ Określenie optymalnego zakresu i tempa rozwoju energetyki atomowej w Polsce, Agencja Rynku Energii S.A., 2006r
12. ↑ ^{12.0 12.1 12.2 12.3} [2], New Challenges in the Central European Gas Market
13. ↑ ^{13.0 13.1 13.2} “Hypogen Pre-feasibility study”, final Report January 2005, European Science and Technology Observatory
14. ↑ ^{14.0 14.1 14.2 14.3 14.4} Commission of the European Communities, Commission Staff Working Document, "The market for solid fuels in the Community in 2003 and 2004.
15. ↑ [3]
16. ↑ ^{16.0 16.1 16.2} Natural gas - the energy for a sustainable future, EUROGAS
17. ↑ Facto, figures and expectations for the Greek Paper on a European Maritime Policy, International Association of Oil and Gas Producers, November 2005.
18. ↑ Simbeck et al., 2002
19. ↑ Gray et al.,2002
20. ↑ ^{20.0 20.1} Hypogen pre-feasibility study, Final Report, January 2005
21. ↑ Di Mario et al., 2003
22. ↑ [4]