DALCOR Consultants Ltd - Hydrogen Implementing Agreement

Transcription

DALCOR Consultants Ltd.
CANADIAN HYDROGEN
CURRENT STATUS & FUTURE PROSPECTS
A Study Conducted for Natural Resources Canada
August 2004
Dalcor Consultants Ltd. & Intuit Strategies Inc.
In conjunction with
George Deligiannis, Camford Information Services, Inc.
Matthew Fairlie, Consultant &
Ian Potter, Alberta Research Council
CANADIAN HYDROGEN
TABLE OF CONTENTS
Executive Summary
Page
i
Section 1:
1.1
1.2
1.3
1.4
1.5
1.6
Hydrogen: An Element of Challenge and Promise
The Challenges of Hydrogen
Hydrogen Today: The Big Picture
Hydrogen Production & Purification: Processes, Economics & GHG Prodn
Hydrogen Storage – Current State of Art
Hydrogen Transportation – Current State of Art
CO2 Management
1.1
1.6
1.8
1.26
1.33
1.35
Section 2:
2.1
2.2
2.3
2.4
2.5
Canadian Capacity, Supply & Demand – 2003
Introduction
Current Hydrogen Use
Canadian Hydrogen Surplus - 2003
Canada’s Hydrogen Storage and Transportation Infrastructure - 2003
Positioning for the Hydrogen Economy
2.1
2.2
2.9
2.11
2.11
Section 3:
3.1
3.2
3.3
Possible Hydrogen Futures in Canada
Influencing Factors
Hydrogen Uses in Canada
Scenarios to 2023: Descriptions & Rationale
3.1
3.7
3.8
Section 4:
4.1
4.2
4.3
Oil Refining in Canada: 2013 & 2023
Market evolution & demand
Oil Refinery Hydrogen Supply Capability
Implications for Oil Refinery Hydrogen
4.1
4.4
4.8
Section 5:
5.1
5.2
5.3
Heavy Oil in Canada: 2013 & 2023
2023 Hydrogen Supply Capability – Oil Sands Options
Implications for Production
5.1
5.7
5.9
Section 6:
6.1
6.2
6.3
Chemical Industries in Canada: 2013 & 2023
Chemical Sector: Hydrogen Supply Capability
6.1
6.4
6.7
Section 7:
7.1
7.2
Merchant & Fuel Use Hydrogen in Canada: 2013 & 2023
2023 Hydrogen Supply Capability
7.1
7.5
7.3
Section 8:
8.1
8.2
8.3
Appendices:
A.
B.
C.
D.
E.
F.
7.5
Opportunities & Challenges on the Hydrogen Road Ahead
The Canadian Picture
Opportunities for Canadian Technology Development
Summary of Technology Opportunities
8.1
8.2
8.11
2003 Canadian Hydrogen Production & Surplus by Sector & Region
(Dec 2003): Data tables
Scenario – Soldiering On: Projected Demand by Region & Sector (2013
& 2023): Data tables
Scenario – Carbon Conscious: Projected Demand by Region & Sector
(2013 & 2023): Data tables
Scenario – Hydrogen Priority Path: Projected Demand by Region &
Sector (2013 & 2023): Data tables
Canadian Companies & Organizations Active in Hydrogen Production,
Transport & Storage
Multi-National Large Scale Hydrogen Supply Companies
CANADIAN HYDROGEN
EXECUTIVE SUMMARY
This report has been prepared to provide a broad summary of hydrogen technology and a
comprehensive coverage of current production and use of hydrogen in Canada and also offers a
glimpse of future demand for hydrogen in Canada. The report should enable the reader to grasp
the significant size of the hydrogen industry in Canada. The report also addresses the
mechanical-chemical processes that create hydrogen now, the prospective technologies that are
emerging that can change the nature of hydrogen production, purification, transportation and
st
storage, and finally the areas of technical opportunities that arise with hydrogen in the 21
century.
The core of the report is a regionalized inventory of hydrogen production in Canada as of
December 2003. From this base, scenarios to meet Canada’s increasing need for energy are set
out for 10 and 20 years into the future as new markets may develop. This report develops
projected demands under each of the three scenarios:
1. Soldiering On (SO) – a business as usual perspective with no dramatic political
or climatic impacts
2. Carbon Conscious Agenda (CCA) – major disturbances considered due to
climate change and the resulting global concern results in a focus on greenhouse
gas (GHG) reduction and fuel efficiency
3. Hydrogen Priority Path (HPP) – a push for North American energy selfsufficiency and concerted actions by government and the populace to adopt the
many aspects of the hydrogen economy.
Canadian companies produce world-scale volumes of hydrogen, and the report describes the
range of current hydrogen production sources together with the respective cost/tonne and the
relative amount of GHG or CO2 per tonne. CO2 is considered as the principal greenhouse gas
produced during hydrogen production and is assumed to be a good proxy for the GHG output of
the various techniques when complete GHG data are otherwise not available.
The production consequences of the demands for hydrogen under each scenario shed light on
the potential size and location of Canadian’s hydrogen needs as the anticipated Hydrogen
Economy takes shape. Possible volumes and locations of Canadian projected hydrogen needs
in 2013 and 2023 are described as the consequences of choices that might be made by industry,
government, and consumers under the conditions set out in each scenario.
Canadian Hydrogen Study
By Dalcor Consultants Ltd
Intuit Strategies Inc.
August 2004
i
The final section addresses the opportunities and challenges ahead for Canadian industry,
technologies and governments as they address the range of possibilities that will convey us along
the pathway to the increased use of hydrogen in our economy
Particular attention was made to identify and set out opportunities for Canadian technology
development associated with production and the ancillary needs of hydrogen. Production,
purification, transport and storage technologies have been examined to identify situations where
“step-jump” improvements may be possible. While Canada’s significant needs in these areas are
not unique, Canadian companies and research facilities have established a strong technical and
commercial presence over the last 10 years. These strengths are a sound base for Canada to
deliver technology and expertise to meet the potential long-term demands for hydrogen in both at
home and abroad.
The report finds that:
1. Canada is the largest per capita producer and user of hydrogen in the OECD and likely in
the world. Present production is 3.09 million tonnes per year (t/y), while consumption is
2.89 million t/y.
2. There is a current surplus of hydrogen amounting to almost 200 thousand tonnes that is
used to either supplement furnace fuel requirements in the vicinity of production or is
vented to atmosphere.
Approximately 40% of the surplus is from Nova Chemical’s ethylene facility in Joffre AB,
20% from Dow Chemical in Fort Saskatchewan, AB and the remaining 40% is widely
scattered across Western and Central Canada in about 14 other process chemical and
chlor-alkali plants.
3. Canadian hydrogen capacity, at 3.17 million t/y, is slightly greater than current
production. The over-capacity reflects a combination of short-term reductions in demand
and excess capacity built in anticipation of growing demand.
4. Regional hydrogen production is as follows: Western 2.27million t/y, Eastern 0.6 million
t/y, and Atlantic 0.22 million t/y.
5. The distribution of hydrogen production and use was divided into industry sectors:
oil refining
670 thousand t/y,
heavy oil upgrading
770 thousand t/y,
chemical industry users
972 thousand t/y,
chemical industry by-product producers 451 thousand t/y
merchant gas production
17 thousand t/y.
6. Technologies for hydrogen production vary. Steam methane reforming of natural gas has
been the low-cost option by an order of three to six times. Over 75% of hydrogen
produced in Canada is from natural gas, either in dedicated facilities or as the by-product
August 2004
ii
of primary chemical extraction such as ethane. About 22% of the hydrogen production is
from refinery in-process gas that is re-used within the refinery. The remaining 3% of
Canada’s hydrogen is produced by chloralkali electrolysis.
7. Separation, transport and sequestration of more than 50% of the CO2 produced by
current hydrogen processes is can very likely be achieved at a quantifiable and
acceptable cost for process plants within the Western Sedimentary Basin. The nature
and cost of sequestration in other regions of Canada is less clear
8. Hydrogen production and demand under the SO scenario shows the largest growth in
Canadian hydrogen with a forecast Canadian production of 6.4 million t/y. Anticipated
hydrogen demands for upgrading of heavy oil represents will grow from the current 0.78
million t/y to 3.1 million t/y, or almost 50% of total Canadian production by 2023.
Chemical industries demand will increase but will grow much less rapidly and while
currently leading Canadian demand, this sector will be about one-half that of heavy oil
upgrading by 2023.
Full utilization of anticipated by-product hydrogen production could reduce the annual
demand by about 400 thousand t/y.
9. The CCP and HPP scenarios suggest a lower forecast growth in hydrogen production to
about 5.7 million t/y. Although the total hydrogen production is nearly identical under
each scenario the growth of chemical industries for plastics and lighter vehicle materials
grows in the HPP scenario while the demand for petroleum products, heavy oil
upgrading, drops.
Full utilization of anticipated by-product hydrogen production could reduce the annual
demand for the HPP and CCP scenarios by about 350 to 300 thousand t/y respectively.
This report was prepared for Natural Resource Canada, CANMET Energy Technology Centre,
Hydrogen and Fuel Cells Program.
The authors of this report have received very useful input from a wide variety of contributors, for
which they are particularly grateful. Amongst those who provided their time and knowledge are:
Fuel Cells Canada:
BC Hydro:
Enbridge:
Tom McCann & Assocs. :
Royal Military College:
Ron Britton
Allan Grant
Richard Luhning, Ho-Shu Wang and Jeff Jergens
Tom McCann
Brant Peppley
August 2004
iii
i
August 2004
iv
1.
HYDROGEN: AN ELEMENT OF CHALLENGE
1.1
The Challenges of Hydrogen
Industry, in the form of the refining and chemical industries, has used massive amounts of
hydrogen for years, and its use as a chemical intermediary is widespread. Usually, however,
hydrogen is produced very close to where it is used so bypassing the difficulties of transporting or
storing it – difficulties that come into play when considering hydrogen as a fuel.
Hydrogen’s use in industry is described and quantified elsewhere in this report. Its use as an
energy carrier has been much touted, but it is in this area where hydrogen’s challenges lie. The
commercial viability of any fuel or energy carrier is a function of cost and performance relative to
other contenders. Put another way, an attractive fuel is readily available where required,
efficiently converted into a useful form by available technology but, most importantly, has physical
properties that make the it easy to transport, store and transfer.
Those that are liquids under most environmental conditions meet these requirements; they have
an attractive volumetric energy density, and can be piped, pumped and tankered using relatively
simple, low cost and available technologies.
Gasoline and diesel have these attributes and are widely used not only because they are
relatively easily sourced and have a high energy density, but because they are easy to handle.
However, concerns about clean air and GHG emissions from conventional fuels are creating the
dilemma between ease of handling and cost.
Lower carbon fuels have emissions advantages but are typically more costly to handle.
Hydrogen in particular is desirable for its clean burning characteristics, but is also the necessary
energy source for fuel cells. In many respects hydrogen is a good fuel:
•
it has notable performance attributes over hydrocarbons in terms of efficiency and offers
measurable improvement in life cycle GHG emissions
•
it can be used as a fuel for both combustion and electrochemical energy conversion
• it is already produced in large volumes as a chemical intermediary
however, hydrogen’s major drawbacks lie in physical characteristics that make it hard to handle. It
does not travel well.
Hydrogen has three drawbacks, two of them tangible, significant and tough to overcome, and one
that is an issue of perception:
•
low volumetric energy density
•
inherently high energy cost of production & transport
• image
If hydrogen is to find a role as a common energy carrier, effective solutions to all three must be
found.
By Dalcor Consultants Ltd.
Intuit Strategies Inc
August 2004
Page 1.1
Hydrogen also has a straightforward business challenge: it must displace an existing entrenched
energy form (liquid hydrocarbons). This is perhaps its major challenge. The oil and gas industry
has trillions of dollars of capital invested in areas from exploration equipment to delivery pumps
and is the most powerful industry worldwide. It will fiercely protect its invested capital and allow
hydrogen in, in due course, on its own terms. Indeed, the industry - by and large - recognizes
that the world will change: hydrocarbons are becoming more difficult and more expensive to
discover and bring to market. The associated environmental issues will not disappear, and yet
the demand for energy will continue to increase worldwide. In the long run these companies will
embrace whatever energy form is appropriate, but will strive to control the transition.
Energy Density
A key requirement of an energy carrier is for compact and light energy storage. Hydrogen has a
high gravimetric energy density (i.e. it is light per unit of energy) that is of limited value when its
volumetric density is so low (it is bulky). This density can, and must be increased by compression
or liquefaction, but at significant economic and energy costs.
There is debate as to whether these costs become a hydrogen economy showstopper. The
answers vary with viewpoint, and each side of the debate can bring forth valid arguments. Much
hinges on the ultimate performance characteristics of fuel cell vehicles (FCV) versus internal
combustion hybrid powered vehicles using either gasoline or diesel. At present the most likely
FCV will be PEMFCs carrying onboard hydrogen as a fuel.
The magnitude of hydrogen’s energy density challenge relative to competing fuels is clear from
the table below:
Higher Heating Value per Litre for
Different Fuel Options
MJ/litre*
Hydrogen (200 bar)
2.2
Methane (200 bar)
7.5
Hydrogen (800 bar)
6.3
Methane (800 bar)
32
Liquid hydrogen (~20°° K)
10
Liquid methanol
17.5
Liquid propane
25.2
Liquid ethanol
23.5
Liquid octane
34
* Corrected for hydrogen compressibility factor and taken at 0° C
August 2004
Page 1.2
Hydrogen’s penalty is well demonstrated by considering the
needs of a typical busy fuel station, for which a daily delivery
of 25 tonnes of gasoline by 40 tonne gasoline tanker is
required. It would require 21 hydrogen trucks to deliver the
same amount of energy (400 kg per load, and 39.6 tonnes of
1
deadweight) .
In practice there are enormous
inefficiencies in the manner in which
the existing energy infrastructure is
operated, not through deliberate
design but because of the dynamic
nature of its operation and the
pragmatic way of managing load
peaks and valleys.
This is, however, an unrealistic argument as trucked delivery
of hydrogen is highly unlikely precisely for those reasons.
Today’s natural gas and power infrastructure will likely be the backbone of energy delivery for a
long time hence, threatening only the gasoline tanker in the long run. In a FCV world hydrogen
will be produced close to vehicle refuelling points.
Energy Costs of Production & Handling
Relative to conventional fuels, the energy invested to extract and handle hydrogen is high
compared to its energy content. Using high-grade energy to create a fuel runs counter to the
search for increased energy efficiency.
Taking into account hydrogen production efficiencies which vary by design, production process
and sizes, and considering the considerably higher energy costs of various H2 transportation
methods (compressed gas, pipelining, or liquefaction) it is a fair summary to state that the “wellto-tank” efficiency of hydrogen ranks very poorly alongside conventional fuels. The question is
whether this penalty is overcome when considering ultimate end-use efficiencies, i.e. extending
the analysis by factoring tank-to-wheel issues.
There are means of addressing some of the efficiency concerns. For example, with regard the
compression or liquefaction energy required to convert hydrogen in a transportable form, there
are opportunities to develop technologies to recovery and use some of the pressure or ‘exergy’ as
the fuel is used.
Perception
Hydrogen is unfamiliar as a fuel and many have valid concerns about its explosive properties. It
is, of course, easily ignited, very fast burning and has a wide flammability range. There may still
be a residual perception of fear amongst the general populace, which many hydrogen proponents
still refer to as the Hindenburg syndrome. Most people are, however, comfortable with gasoline
because it is familiar, but which is also very hazardous if mishandled.
•
1
Eliasson, Bossel, Taylor, The Future of the Hydrogen Economy: Bright or Bleak? Proc.: The Fuel Cell
World, Lucerne July 2002 (paper revised April 2003)
August 2004
Page 1.3
Like any other fuel, hydrogen represents ‘condensed energy’ which must be safely contained,
and in reality the negative perception issues are likely overstated and little different in degree than
other energy carriers. Hydrogen’s negatives must be weighed against its positives.
The ultimate questions for hydrogen as a fuel are simple:
•
Is hydrogen viable as a fuel?
•
Where will it come from?
•
How will it be delivered
As a key component of oil refining, heavy oil upgrading and numerous chemical and process
uses, hydrogen reigns supreme. A significant portion of Canada’s economic future hinges upon
the ability to generate and utilize hydrogen on a massive scale. For example, Canada exports
3
about 15,000 t/y of liguid and some gaseous hydrogen, over 15 million m /y of refined chemical
3
products, about 10 million m /y of upgraded crude oil and about 2 million t/y of ammonia as urea
or nitrates,
This report sets out the spectrum of challenges and opportunities for hydrogen in Canada. By
examining how developed and how diverse its role is today, a base is formed to establish
knowledge and familiarity with hydrogen that will put Canada on the leading edge of hydrogen
supply and distribution technology.
There are many myths surrounding hydrogen and the potential for a hydrogen economy, many of
which are non-issues. There will be some who agree and others that disagree with these on a
case-by-case basis, but the cases against most of these “myths” are quite plausible. Of course,
there are still areas of uncertainty and debate regarding the future of hydrogen, and while this
report does not aim to address these fully, it should provide a solid background of understanding.
August 2004
Page 1.4
The following list of negative perceptions, termed the “20 Hydrogen Myths”, has been developed and
addressed by the Rocky Mountain Institute
“20 HYDROGEN MYTHS”
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
18.
19.
20.
A whole hydrogen industry would have to be created from scratch
Hydrogen is too dangerous, explosive, or “volatile” for common use as a fuel.
Making hydrogen uses more energy than it yields, so it’s prohibitively inefficient.
Delivering hydrogen to users would consume most of the energy it contains.
Hydrogen can’t be distributed in existing pipelines, requiring costly new ones.
We don’t have practical ways to run cars on gaseous hydrogen, so cars must
continue to use liquid fuels.
We lack a safe and affordable way to store hydrogen in cars.
Compressing hydrogen for automotive storage tanks takes too much energy.
Hydrogen is too expensive to compete with gasoline.
We’d need to lace the country with ubiquitous hydrogen production, distribution, and
delivery infrastructure before we could sell the first hydrogen car, but that’s
impractical and far too costly — probably hundreds of billions of dollars.
Manufacturing enough hydrogen to run a car fleet is a gargantuan and hugely
expensive task.
Since renewables are currently too costly, hydrogen would have to be made from
fossil fuels or nuclear energy.
Incumbent industries (e.g., oil and car companies) actually oppose hydrogen as a
competitive threat, so their hydrogen development efforts are mere window-dressing.
A large-scale hydrogen economy would harm the Earth’s climate, water balance, or
atmospheric chemistry.
There are more attractive ways to provide sustainable mobility than adopting
hydrogen.
Because the U.S. car fleet takes roughly 14 years to turn over, little can be done to
change car technology in the short term.
A viable hydrogen transition would take 30–50 years or more to complete, and hardly
anything worthwhile could be done sooner than 20 years.
The hydrogen transition requires a big (say, $100–300 billion) Federal crash program,
on the lines of the Apollo Program or the Manhattan Project.
A crash program to switch to hydrogen is the only realistic way to get off oil.
The Bush Administration’s hydrogen program is just a smokescreen to stall adoption
of the hybrid-electric and other efficient car designs available now, and wraps fossil
and nuclear energy in a green disguise.
Rocky Mountain Institute
August 2004
Page 1.5
1.2
Hydrogen Today: The Big Picture
The global hydrogen production market continues to grow at a rate of about 5% per year as it has
for the last 10 years. This growth rate is attributed to the increased global demand for crude oil
refinery products, primarily gasoline and diesel, for ammonia based fertilizers to meet increased
grains and vegetable production, and to a lesser extent, methanol as a base for a host of
industrial chemicals and fuel additives.
Hydrogen is produced as a dedicated product, as a by-product of other industrial processes, and
as an off-gas from a range of industrial processes. Not surprising, this growth rate does not reflect
any impact from the “new hydrogen economy” as the amounts destined for hydrogen energy
applications are miniscule compared to the current volumes produced. In North America and
Europe the amount of hydrogen produced for the principal end uses is about 42.5 million tonnes
(Mt/y). Canada’s current production of 3.1 million tonnes is about 6% of the world total. This
global picture is presented in Table 1-1 World Consumption of Intentionally Produced and
Merchant Hydrogen – Revised to 2003, set out an approximate picture of the global production
and use of hydrogen. The global data are approximate and will be updated later in 2004 as part of
SRI International’s periodic publication of the Chemical Economics Handbook (CEH) on
hydrogen. These macro volumes enable the reader to appreciate the relative size of present
hydrogen production and use in the world. It is important to recognize that hydrogen is far from
being “a new kid on street”.
Table 1.2 – 1: Global Dedicated Hydrogen Production (thousand tonnes)– revised to 2003
b
(based on SRI International CEH HYDROGEN – 1999 and 2003 data)
United
States
Western
Europe
Canada
Japan
Rest of World
Total
Captive Users
Ammonia Producers
3,031
591
2,322
334
18,306
24,568
Refineries
3,472
1,627
2,297
1,214
2,598
11,021
715
200
432
2,359
3,707
Methanol Producers
Other
Subtotal
-
321
534
798
162
7,539
2,952
5,849
1,710
-
1,016
0
459
7
-
68
17
61
16
-
170
1,084
17
520
23
-
1,677
8,623
2,970
6,369
1,733
23,263
1,802
41,099
Merchant Users
Pipeline or On-Site
Cylinder or Bulk
Sub total
Global Total
Canadian Surplus
Total Canadian
23,263
1,507
42,776
200
3,170
Notes:
a.
b.
Excludes Turkey
Canadian data from Dalcor survey, other totals are 1999 figures with annual growth adjusted to
2003 at rate of 3% for ammonia, 6% for refineries, 0% for methanol in North America and 3% in
ROW, 5% for pipelines, and 3% for cylinder and bulk.
August 2004
Page 1.6
c.
Data for refineries includes heavy oil upgraders in Canada, and does not include by-product
hydrogen consumed on site except in Canada
d.
Data does not include Chemical process based hydrogen from electrolytic, olefins or other
chemicals production. This amount is estimated by CEH to be in the order of 1,000,000 tonnes.
Of the North American and European volume, ammonia production represents 37%, refineries
39% and methanol 10%. The remaining 14% is used in a wide range of chemical products, and
as an industrial blanketing gas that is essential to a number of metals and glass making
processes. Hydrogen production for the rest of the world is presently in the order of 12 million
tonnes per year (Mt/y) of which nearly 75% is for production of ammonia. Industrial fertilizer is
now used widely in agriculture throughout the world and is expected to remain the dominant
consumer of hydrogen in developing countries for the next 20 years.
Those more acquainted with hydrogen as a prospective fuel for automobiles and local electric
power generation may find relating to these data difficult. It is useful to note that that one tonne of
hydrogen will fuel 4 FCVs (PEM type systems that require pure hydrogen fuel) for a year or one
urban transit bus for about 45 days. Similarly, 1 percent of the current Canadian hydrogen
production will fuel the equivalent about 1,000,000 FCVs, or roughly 45% of the total light
vehicles currently registered in Canada. On a larger scale example, complete conversion of 100%
of all passenger cars and fleet vehicles in Canada to PEMFCVs would consume about 20% of
Canada’s current hydrogen production.
Global Trends in Hydrogen Use
Over the next five years global hydrogen production is expected to increase at an annual rate of
about 4.5 - 5%. This rate is projected to meet the demand for plastics, fertilizers and automotive
fuel throughout the world. Especially rapid is the increased demand in developing economies
such as China and India where reformulated gasoline and low sulfur diesel and future FCV’s will
keep annual growth rates near 10 percent. The combination of a low starting point in vehicle
ownership and robust economies has led to very rapid growth in the vehicle fleets in China and
India in recent years. The number of vehicles in China has been growing at an annual rate of
almost 13 percent for 30 years, nearly doubling every 5 years. India's fleet has been expanding at
more than 7 percent per year. While together these two countries now account for only a small
percentage of the vehicles on the road, that percentage will grow rapidly as these countries
2
continue to industrialize .
Reformed natural gas will almost certainly remain the world’s principal source of hydrogen in the
following decade and more barring a step jump technology innovation in hydrogen technology.
The leadership of SMR hydrogen production will remain primarily because natural gas or liquid
natural gas (LNG) is expected to remain the most cost-competitive feedstock. Beyond the next
10 years it is fair to speculate that the availability of natural gas will reduce and global priorities
•
2
China & India Vehicle Estimates from: http://www.wri.org/wri/trends/autos2.html
August 2004
Page 1.7
will see a significant focus upon limiting emissions of greenhouse gases (GHGs). However,
exhaust streams from SMR processes comprised primarily of CO2 and H2. The CO2 is relatively
economic to concentrate and inject into the earth (compared to dilute thermal power plant flue
gas streams).
In many geographic areas CO2 sequestration will have economies of scale that may enable costeffective subterranean injection. Limitations on GHG intensive processes without sequestration
could severely limit small SMR plant.
Electrolysis has an opportunity to command a larger portion of hydrogen generation but only if
there are positive process economics through access to dramatically lower priced electricity. As
the efficiency of electrolysis is relatively high, in the order of 85%, there is limited room for big
process cost reductions. Nuclear-based electric power, fission and perhaps the distant hope of
fusion by 2050, might be the Holy Grail of power cost reduction.
1.3
Hydrogen Production & Purification:
Processes, Economics, and GHG Production
Dedicated Hydrogen Production
There are various processes used for the dedicated production of hydrogen. Virtually all of these
use a commonly available feed-stock such as natural gas, coal, or water and produce a hydrogen
rich product that requires some degree of clean-up or purification before use. The degree of
product gas clean-up ranges from modest drying to remove water and some trace gases from
electrolytic sourced hydrogen, to complex purification in the case of fossil fuel-based processes.
Figure 1.3.1 Hydrogen Pathways summarizes the range of current and future pathways from a
range of energy sources to hydrogen. Note that only nuclear offers a potential for hydrogen
production directly. The technology known as high temperature dissociation of water is in the
early stages of research but does offer the potential for direct hydrogen production in the long
term.
August 2004
Page 1.8
Figure 1.3.1 Hydrogen Pathways, (http://www.ch2bc.org/index2a.htm)
The principal commercial processes specific for the manufacture of hydrogen are steam
reforming, partial oxidation, coal gasification, and water electrolysis. However, these are not of
equal economic importance. Relatively small quantities of hydrogen are produced by steam
reforming of naphtha, partial oxidation of oil, coal gasification, or water electrolysis. Worldwide,
hydrogen as a raw material for the chemical industry is derived as follows: 77% from natural
gas/petroleum, 18% from coal, 4% by water electrolysis and 1% by other means.
The most common fossil fuel processes are steam reforming, partial oxidation typically of natural
gas or light liquids.
Gasifiers are the second most common technology for hydrogen production and typically use
heavy refinery residuals or coal. Within a refinery, catalytic in-process reforming is used to
generate hydrogen for subsequent steps in the refining process. This in-process hydrogen
production uses specific, less common, feed-stocks and is essentially unique to the crude oil
refinery sector.
Dedicated electrolysis systems are common and the process is relatively simple to operate. At
this time the process has limited ability to achieve economies of scale, i.e. the largest commercial
th
electrolytic cell produces about 1000 Nm3/hr or about 2.2 t/d. This rate is about 1/100 the size of
a large commercial SMR system. As there is no further economies-of-scale, electrolysis of water
remains an expensive source of hydrogen.
These various current dedicated production methods are summarized below, following which the
actual workings of each of the processes are described.
The basic, theoretical level processes are simplistically summarized below:
steam reforming
CH4 + 2H2O
August 2004
CO2 + 4H2
Page 1.9
naphtha reforming
CnH2n + 2 nH2O
nCO2 + 1.88 H2
residual partial oxidation
CH1.8 + 0.98 H2O + 0.52 O2
coal gasification
CH0.8 + 0.6 H2O + 0.7 O2
water electrolysis
2H2O
CO2 + 1.88 H2
CO2 + H2
2H2 + O2
Actually process efficiency is less than that suggested above. For example the basic SMR
process does not achieve 4 hydrogen molecules per molecule of methane because some
methane is used to heat the reaction and some passes through the process without reforming.
Actual production of useable hydrogen is a ration between 2.5 and 3.0, considerably less than the
theoretical 4.
Process selection criteria focuses on a number of factors: hydrogen content of feedstock;
hydrogen yield from the process; economics; including cost of feedstock; capital and operating
costs; energy requirements; environmental considerations; and intended use of the hydrogen.
The processing difficulty and manufacturing costs increase as feedstocks change from natural
gas to liquid hydrocarbons and then to solid feedstock. Note also that as the fossil fuel feedstock
increases in molecular complexity, the relative amount of CO2 increases rapidly. If roughly 2.5 to
3 volumes of hydrogen are produced for each CO2 volume in methane reforming, while the ratio
is reduced to less than 1 for coal.
The partial oxidation and coal gasification processes require more capital investment than the
steam reforming plants because an air-separation plant, larger water gas shift and CO2 removal
facilities, and gas cleanup are needed. The capital cost of water electrolysis plants is comparable
to those of steam reforming in small-capacity plants, but high power demand tends to make
electrolysis relatively expensive. As the cost of electric power represents about 80% of the final
production cost, electricity cost and pricing “make or break” the cost of production. In largecapacity plants, the capital cost of the electrolysis process significantly exceeds that of other
processes.
The relative characteristics of the principal hydrogen production processes have been tabulated
to display the process efficiency, economic, and GHG output. Table 1.3 – 1 Summary of Process
Characteristics - Efficiencies, Costs and Greenhouse Gas Production for the Principal Hydrogen
Processes sets out the general range of characteristics that define the principal methods of
hydrogen production.
Various approaches have been developed that can make conventional electrolysis more cost
competitive, these include exclusive or principal power used as off-peak and therefore valued at
about half the normal day rates and perhaps a third or more less than peak power. The other
proposed compensating factor is to charge a carbon disposal cost on fossil fuel systems. Where
power is produced from hydro or solar sources this approach has validity, however about 80% of
the world’s electric power is thermally sourced from coal, oil and more recently natural gas.
Sequestering CO2 from combustion sources is much more costly, as flue gas from thermal plants
is about 12% CO2, the remainder nitrogen with some trace gases. Effective sequestration is
August 2004
Page 1.10
generally approached by effective gas separation processes first, which will concentrate the CO2
for cost effective compression and sequestration. SMR units produce two exhaust streams, one
that represents about 75% of the exhaust is about 45% CO2 and 50% H2. The remaining portion
is flue gas containing ~12% CO2. In large-capacity thermal power plants, the capital cost of the
separation process equipment significantly exceeds that of other processes as all gaseous
emissions are about 12% CO2.
Some consider the “hydrogen economy” as the widespread use of hydrogen for transportation
and storage of energy, which will be converted at the point of use into electricity and/or heat.
Fossil fuels and biomass, and nuclear or renewable generated electricity, would be converted into
hydrogen as a preferred energy carrier. However, this vision faces significant challenges
associated with the low energy density of hydrogen, and the economic and efficiency burdens of
energy carrier conversion and storage.
The ultimate objectives of the “hydrogen economy” are to improve overall energy system
efficiency, minimize obnoxious emissions, and alleviate global warming. These objectives may
be served by hydrogen in many ways, with hydrogen often serving a key internal role “within
battery limits” rather than being an external energy carrier for transportation and storage.
Hydrogen is generated and consumed within an energy conversion facility, fulfilling the
objectives. In its main industrial uses today, the role of hydrogen is captive within refineries,
heavy oil upgraders, ammonia and methanol synthesis plants. Likewise, hydrogen or hydrogenrich syngas are converted from fossil feedstocks in IGCC coal fuelled power plants, and in natural
gas fuelled MCFC and SOFC high temperature fuel cell power plants. The conversion to
hydrogen or syngas enables capture of sulphur and other pollutants, optional capture of
concentrated CO2, and efficient clean power generation conversion in combined cycle turbines or
high temperature fuel cells.
This decarbonization strategy is an available and potentially indispensable option with combined
cycle power plants. Note that with IGCC coal plants, air separation is required to generate
oxygen; but natural gas fuelled combined cycle plants may recover gas turbine waste heat use as
the heat source for their SMR sub-system, thus avoiding the carbon dioxide flue gas load of an
air-blown furnace. In more advanced plants, higher efficiency and process simplification benefits
will be achieved with SOFC technology and enriched hydrogen recycle coupled to
hydrogasification of raw fuel.
Figure 1.3 - 2 overleaf displays two decarbonization systems. Each system incorporates
gasification, separation, and conversion to electricity and heat. The Option A system reflects “best
available-technology” by combining oxygen gasification of fossil fuel or biomass with PSA or
membrane separation of the syngas into CO2 and hydrogen. The CO2 is destined for
sequestration and the hydrogen is burned in a gas turbine to generate heat and electricity. The
Option B concept uses hydrogasification by recirculation of some of the hydrogen and CO from a
SOFC; the gasifier product is cleaned and goes directly to the SOFC which internally completes
August 2004
Page 1.11
reformation of the syngas. The SOFC produce electricity directly, heat and returns some unused
hydrogen and CO to the gasifier. CO2 is expelled from the SOFC and sequestered.
The SOFC and enriched hydrogen recycle technology also offers some potential for very high
efficiency transportation power plants (e.g. for hybrid highway vehicles, as well as for rail and
marine propulsion) fuelled by conventional hydrocarbons or methanol.
In the much longer term, say 40 years, the most optimistic light that shines on production of the
large quantities of low CO2 hydrogen is from high temperature thermal decomposition of water
using nuclear power. Although still in the laboratory stage this hydrogen production technology
o
combined with the high (~1100 C process heat requirements) offers large scale hydrogen
supplies with low CO2 production. The heat generation and process is of course completely CO2
free, thought there is some CO2 associated with mining of the uranium fuel over the facility’s lifecycle. The risks of operating accidents, sabotage, and the disposal of fuel and radioactive waste
from decommissioning, have to be weighed by society alongside other risks.
August 2004
Page 1.12
D e c a rbo n iz a tio n S yste m s - C o m b in e d C yc le
G a s T u rb in es & S o lid O xid e F u e l C e lls -
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+
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Figure 1.3 – 2 Decarbonization System Schematics – Oxygen Gasifier c/w Combined Cycle and Hydrogasifier c/w Solid Oxide Fuel Cell
Canadian Hydrogen
August 2004
Page 1.13
1.3.1
Current Hydrogen Production & Purification Technologies
The relative characteristics of the principal hydrogen production processes have been tabulated
to display the process efficiency, economic, and GHG output. The table below sets out the
general range of characteristics that define the principal methods of hydrogen production.
Parameter
Capacity Range (NB: data
for larger versions)
Steam
Reforming (SR)
Partial Oxidation
(POX)
Texaco
Gasification (TG)
Water
Electrolysis
(Coal Thermal)
1 – 1000 t/y
1 – 1000 t/y
100 – 500 t/y
Minute – 2.5 t/y
natural gas
residual oil
bituminous coal
Water/ electricity
2320 t
507 MW
6
1.1 x 10 m
Feedstock
(requirement per day)
3
1020 m
3
78.5
76.8
63.2
27.2
steam
sulphur
sulphur
oxygen
1.7
30
70
695
83.2
205
316
132
4,46
3.86
3.93
19.21
feedstock
2.14
5.39
5.39
3.32
Capital
0.75
1.93
1.93
0.93
O&m
7.35
11.18
15.54
23.46
-0,16
-0.03
-0.08
-0.83
7.19
11.15
15.46
22.63
672
1,092
1,510
2,029
1
2
3
4
11,000
17,000
21.250
52,300
Thermal efficiency, %
By-product
By-product capacity, t/d
Capital cost, $ x 10
6
3
Production costs, $/(100m )
Total
By-product credit
Net H2 production cost
3
in $/(100 m )
$/t
Net production cost ranking
Average GHG production
(gm of GHG/kg of H2)
3
Table 1.3 – 1 Summary of Process Characteristics - Efficiencies, Costs and Greenhouse
4
Gas Production the Principal Large-scale Hydrogen Processes
Hydrogen supply at a local or on-site scale demands considerable complexity to package the
various process components into a size that can reasonably fit onto an existing service station
site. In addition, design features and “fail-safe” mechanisms must ensure the entire production,
purification, compression, storage, and dispensing, can be accomplished by relatively unskilled
people. The capital and operating costs of a range of on-site technology options is summarized in
Table 1.3 – 2 Cost Comparison- On-site Hydrogen Production for Alternate Technologies, set out
•
3
4
D. O’Connor, GHGenius calculations, May, 2004
“Methods of Producing Hydrogen”, I. Potter, Alberta Research Council. Nov 2001.
Canadian Hydrogen
August 2004
Page 1.14
below.
Appendix F lists some of the principal global suppliers of these and other principal
technologies associated with production of large scale hydrogen.
5
Table 1.3 – 2 Cost Comparison - On-site Hydrogen Production for Alternate Technologies
Technology/Size
(H2 kg/d)
SMR (natural gas)
900
40
48**
1,600
260
SR (methanol)
1600
260
Specific TCI
($/t)
Hydrogen Cost*
($/t)
9,053
2,672
2,667
n/a
n/a
3,692
1,738
3,110
2,720
4,760
n/a
n/a
2,960
4,360
6,616
10,288
10,446
4,383
4,975
5,024
n/a
n/a
7,800
9,300
Berry et al. 1996
4,115
3,959
Thomas 1995
4,683
5,311
Berry et al. 1996
Reference
Berry et al. 1996
Thomas et al 1998
NAS&E 2004
(S&T)
2
2003
2
2003
“
“
(S&T)
“
“
**future optimized design
Alkaline Electrolysis
1,170
234
39
1,600
260
PEM ELECTROLYSIS
1,170
850
234
39
32
250*
* optimized design
Steam Electrolysis
1,170
234
Berry et al 1996
“
“
“
“
(S&T)
2
“
2003
“
6,173
4,288
“
8,072
4,637
Thomas
1995
7,850
6,020
NAS&E
2004
n/a
“
2,880
6,965
Berry et al. 1996
“
“
5,300 (est.)
2,805
3,422
•
5
Kirk-Othmer. 1991a. “Hydrogen” in Encyclopaedia of Chemical Technology, 4 edition, Vol. 13: Helium
Group to Hypnotics, John Wiley & Sons, New York.
Canadian Hydrogen
August 2004
Page 1.15
RESIDENTIAL
0.80 (Electrolysis)
7.5 (SMR)
1.3 (Electrolysis)
Berry et al. 1996
Thomas et al 1998
“
“
16,203
6,427
12,742
6,787
4,381
7,808
Note: Costs have been adjusted by Dalcor, where necessary, to normalize for natural gas at $6.5/GJ & power at 7.5¢/kWh
The total cost of production, as well as the capital intensity of each process, is shown as cost per
tonne of relatively pure hydrogen, i.e. not less than 99.9% purity. Note, adequate purity for most
industrial uses of hydrogen is less stringent than that required for PEMFCs. Although it is still an
area of debate, purity specifications usually require less that 10 - 20 ppm CO (sometimes below 1
ppm) resulting in hydrogen purity that is in the order of 99.999% pure. The specific total capital
investment (TCI) is in $/tonne. The unit production cost incorporates the amortized capital plus
operating cost components divided by the annual output, while the TCI is the total capital cost
divided by the annual hydrogen production capacity. Note that a range of production costs is
shown. These ranges reflect the fact that scale has considerable effect on the capital cost and
efficiencies of most processes, authors vary in there data collected and in their analysis.
Life cycle GHG values were not attempted as the assumptions associated with this approach vary
widely, making comparison difficult. Water electrolysis, by itself does not create any GHG,
however the power source of electric generation ranges from essentially zero GHG’s for hydro
and nuclear power, through intermediate amounts for high efficiency gas turbine systems, to
relatively large amounts in the case of coal fired thermal plants. The LHV is used for the
hydrogen calculations.
With the exception of the Thomas et al cost estimates for the 40 kg/day SMR system, the
6
numbers generally fit current estimates . The Thomas calculations are based on pre-commercial
test results of a small SMR design. Again, the LHV is used for the hydrogen calculations.
The following section covers more detailed description of the principal hydrogen production and
purification technologies.
Steam methane reforming, usually referred to as “SMR”, is currently the principal method of
dedicated hydrogen production. The name suggests only methane (natural gas) but the process
will also accommodate a limited range of related gaseous or light liquid hydrocarbons such as
propane, butane, and naphtha’s. At present, about 30% of refinery hydrogen and about 48% of
dedicated hydrogen production is based upon SMR technology.
O
The SMR process typically includes heating of the feedstock to temperatures of 700-900 C with
the assistance of catalysts and in the absence of air, then injecting steam. The temperature and
water reaction not only splits the hydrocarbon feedstock into carbon and hydrogen but also splits
the water molecule (which itself provides hydrogen) to produce hydrogen and carbon dioxide.
•
6
Ian Potter; Methods of Producing Hydrogen; Alberta Research Council, November, 2001
Canadian Hydrogen
August 2004
Page 1.16
Allowing for process inefficiencies, up to 3.0 volumes of hydrogen and one volume of CO2 are
generated from one volume of natural gas.
The SMR process has been successfully demonstrated from a size suitable for fueling a single
home back-up FC unit of 5 kW to installations with capacity in excess of 100 million t/year. The
latter would be located in the largest of oil refineries, heavy oil upgraders, methanol, and fertilizer
facilities.
There are a number of proprietary SMR processes available through firms all of which offer their
technology on a global basis; see Appendix F. There are also a number of firms developing small
SMR designs suitable for use in an automobile service station capacity. Canada’s significant oil
and gas industry has made ample use of the SMR technology over the years and virtually all
major suppliers have representatives in either Calgary or Toronto. Smaller SMR suppliers are
typically not represented. A list of some of the principal suppliers is located in Appendix A. Typical
of most mature technologies, the specifics of each design are different, but the capital and
operating costs tend to be similar, resulting in closely guarded production costs that are
competitive within the technology. Choice is usually made on the basis of the particular capacity
and quality needs of each hydrogen application, the type of fuel available, established reliability,
and finally bid price.
The literature was surveyed regarding the economics of SMR and four detailed estimates were
7
8
9
obtained (Leiby 1994; Kirk-Othmer 1991; Foster-Wheeler 1996 ; Blok et al 1997 ). The standard
methodology was applied to the data and the results of the analysis are summarized in Table 1
with results in Canadian $ and a natural gas price of $6.50/GJ.
Table 1.3- 4 Summary of Large and Small SMR Hydrogen Product Costs
Facility Size
(H2 tonnes/d)
Large Facilities
120
190
250
600
2,280
Small Facilities
0.27
Specific TCI
($/t)
Hydrogen Price*
($/t)
Leiby 1994
Leiby 1994
Kirk-Othmer 1991
Foster-Wheeler 1996
Blok et al 1997
2,360
2,000
1,440
1,600
1,730
1,650
1,500
1,380
1,200
1,316
Leiby 1994
4,400
2,290
Reference
•
7
Kirk-Othmer. 1991a. “Hydrogen” in encyclopaedia of Chemical Technology, 4 edition, Vol. 13: Helium
Group to Hypnotics, John Wiley & Sons, New York.
8
Foster-Wheeler. 1996. IEA Greenhouse Gas R&D Programme, “Decarbonisation of Fossil Fuels”, Report
No. PH2/2, March.
9
Blok, K., Williams, R., Katofsky, R., Hendriks, C. 1997. “Hydrogen Production from Natural Gas,
Sequestration of Recovered CO2 in Depleted Gas Wells and Enhanced Natural Gas Recovery”, International
Journal of Hydrogen Energy, Vol. 22, No. 2/3, pp. 161-168.
Canadian Hydrogen
August 2004
Page 1.17
0.48
0.48*
NAS 2004
NAS 2004
5,130
2,667
4,680
3,110
* costs adjusted for
$6.50/GJ gas price
* optimized design
In each detailed analysis, the price of the natural gas feedstock significantly affects the final price
of the hydrogen. In fact, for these analyses, feedstock costs were 52%-68% of the total cost for
large plants and approximately 40% for small plants. Capital charges comprised most of the
remaining costs. In most systems, a small (i.e., < 1% of hydrogen price) credit for steam
produced was taken. Overall, the hydrogen prices in Table 1.3-4 agree well with other published
values for fuel costs in the range US$5 or C$6.50/GJ.
Partial Oxidation is a hydrocarbon-based syngas production process in which the fuel feed,
steam, and oxygen are preheated and injected into a reactor. Partial oxidation accounts for about
3% of the worldwide refinery hydrogen production. Here partial combustion of the fuel, controlled
by the amount of oxygen available, heats the associated gases to temperatures in the 1300 –
O
1500 C range resulting in break down of the hydrocarbon molecule and the reaction with water
to achieve a high hydrogen content syngas. The high temperature associated with this process
precludes the use of catalysts to assist the chemical reactions.
There is a significant economy of scale for these systems. The actual savings realized, however,
10
depends on the source document. Other authors (Thomas et al. 1998 ) have proposed that SMR
may be cost effective for small-scale distributed fuel cell applications when combined with vehicle
refuelling.
Smaller partial oxidation designs use air to achieve the internal combustion thus eliminating the
need for a dedicated oxygen supply. The resulting syngas is a low hydrogen content mix as the
80% nitrogen content of the air considerably dilutes the product gas. These air systems operate
O
at lower temperatures around 770 – 900 C and require catalysts to ensure sufficient chemical
reaction. The hydrogen content of product gas is lowered to less than 35% by the presence of
large amounts of nitrogen associated with the oxygen necessary for partial combustion.
The partial oxidation process has the ability to use a wider range of fuels than SMR. The resulting
syngas will range from a high to medium hydrogen content gas as depending upon the quality of
the fuel and the extent to which enriched oxygen is used. As part of the fuel is consumed to heat
the reaction the net efficiency of partial oxidation is usually a few percents points lower that SMR.
The choice of partial oxidation is usually based upon access to feed fuel and the occasionally on
convenient access to combustion oxygen from a nearby source.
There are a few suppliers of large industrial partial oxidation systems and several companies
offering small systems suitable for use in service station sized applications.
•
10
Thomas, C.E., James, B., Lomax, Jr., F., Kuhn, Jr., I. 1998. “Integrated Analysis of Hydrogen Passenger
Vehicle Transportation Pathways”, Draft Final Report, National Renewable Energy Laboratory, Subcontract
AXE-6-16685-01, March.
Canadian Hydrogen
August 2004
Page 1.18
Catalytic Reforming of naphthas has been the most widely used source of hydrogen for oil
refining. About 55% of refinery hydrogen is produced in this manner. As the feedstock is derived
from the initial refining stages, the process is seldom used outside the refinery sector. As the
feedstock are some of the lower octane hydrocarbons in the oil refining process the amount of
feedstock is limited by a refinery’s crude oil feed capacity. Until the 1990’s most refineries had
sufficient naphtha type hydrocarbon streams to provide sufficient process hydrogen. The
additional demands for hydrogen produced by the 2005 gasoline and the 2007 diesel vehicle fuel
specification have strapped most refineries for further internal hydrogen production.
Catalytic reforming consists of four distinct reaction steps that reform various of the naphthas
produced during the initial stages of the oil refining process. Hydrogen is a by-product of the
catalytic reforming process, an is produced at widely ranging rate based upon the quality of the
crude feed stock and the degree of catalytic reforming chosen to balance the refinery processes
at the design stage and in operation.
Catalytic reforming processes can generate a hydrogen stream of 70 – 90% purity, and volumes
3
from 30 – 60 m per barrel of crude.
Purge and Off-gas Hydrogen from petrochemical sources are widely used sources of
hydrogen. Hydrogen is also produced from the off-gases from various processes, as outlined in
the Table below:
Table 1.3-5
Hydrogen Containing Streams from Petrochemical Sources
Process
% H2 Concentration Range
Petrochemical Processes
Ammonia Purge
Ethylene by-product
Cyclohexane Purge
Formaldehyde by-product
Methanol Purge
55 – 65
65 – 90
~45
15 – 20
70 – 80
Refinery Processes
Fluid Catalytic Cracker
Hydroprocessor Purge
Naphtha Catalytic Reforming
15 – 50
50 – 90
6 - 90
The richest petrochemical hydrogen streams are those from methanol and ethylene plants. It is
not surprising that the inventory found that these facilities in Sarnia, Edmonton and Joffre Alberta
and Kitimat BC have complementary industries adjacent to them; ammonia synthesis is one of
the largest consumers of this hydrogen in Canada. Similarly hydroprocessor and naphtha
reformers in oil refineries can generate large quantities of hydrogen rich gases that may be
purified for further use in the refinery process. In the case of the very rich stream of 80 – 90%
hydrogen, the gas stream may receive minimal treatment before it is compressed and reinjected
into the process line.
Canadian Hydrogen
August 2004
Page 1.19
Hydrocarbon Gasification is the general name for a range of processes that use heavy
hydrocarbons, even coal, to generate medium quality syngas. This gas may be used as a fuel for
gas turbines, or purified similar to SMR syngas. Gasification techniques were started in the
1930’s by Germany and improved in South Africa in the 1960’s and 70’s during the time that each
of those countries were cut off from easy access to natural gas and crude oil. Modern gasifier
technology continues to be improved in an attempt to offset the increasing cost of natural gas as
the principal source of hydrogen.
Worldwide the development of gasifier technology is vigorous driven by natural gas forecasts that
continue to indicate increased price and the potential for reduced availability. Large hydrogen
users such as Alberta’s heavy oil upgraders are likely to be early adopters of reliable and costeffective gasifier technology. The first major Canadian application of heavy residuals gasification
will be for the Long Lake Heavy Oil project presently being built in Alberta and due on-stream in
2007. By-products from the heavy oil separation process provide the feedstock for hydrogen
production unit, unlike natural gas that is used in all the existing heavy oil upgrader plants in
Alberta.
The costs associated with gasification vary widely depending upon the process details and
especially the hydrogen content of the feedstock. Cost information is also very closely guarded.
Large multi-national energy companies that need to maintain cost competitiveness for survival
are developing many of the new processes. Cost of production is of course a function of the
hydrogen content of the feed. The “lightest” (generally the most liquid) feedstock contains the
highest amount of hydrogen per volume. On the opposite end of the spectrum is coal, which has
several well-established gasification technologies; the most widely used is known as FischerTropsch.
Estimated hydrogen production costs for large coal gasifiers, based upon analysis of a Texaco
entrained flow gasifier, were obtained from in literature that is dated (1991, 1996) but generally
relevant. For a 230 t/d facility the cost of hydrogen was about $1,900 per tonne and for a 550 t/d
facility the cost was $1,600 per tonne. Feedstock costs represents ~25% of the operating cost,
with coal price not given. These production costs are about twice that of a large SMR plant.
However, gasifier designs have improved considerably and industry supplier of large gasifiers
suggest that their equipment becomes competitive with natural gas prices between $7-10 per GJ.
Electrolysis is the oldest of the hydrogen, and oxygen, generating processes. It is achieved by
putting sufficient electrical energy into water to enable the water molecule to dissociate. The
process generates two volumes of hydrogen for one volume of oxygen. An electrolyzer is a
device that facilitates the electrolysis of water to produce large volumes of hydrogen gas.
Electrolyzers most commonly used today generate hydrogen at relatively low pressures (from
nearly atmospheric pressure up to 200 pounds per square inch) and use a liquid alkaline
electrolyte (KOH or NaOH) to facilitate transfer of electrons within the water solution. For the vast
majority of applications the hydrogen must be compressed for either process use or storage.
There is a significant energy penalty to compress the gas to say 200 bar for use in vehicles
(equivalent to about 8% of the hydrogen’s energy). The operation of alkaline electrolyzers
Canadian Hydrogen
August 2004
Page 1.20
requires regular, but relatively low-skill level maintenance. Disposal and replacement of the
caustic electrolyte is a part of the maintenance function.
A proton exchange membrane (PEM) electrolyzer can be designed to electrochemically generate
hydrogen at pressures of 150 bar or greater. This feature significantly reduces the amount of
compression required for hydrogen storage as the process takes advantage of electrochemical
compression, which is more efficient than mechanical compression. The process does not use a
caustic alkaline or acidic electrolyte. This fact reduces some aspects of maintenance and more
importantly, results in a higher purity hydrogen produce. There is general optimism that, as PEM
fuel cell technology improves and reduces in cost, PEM electrolyzer’s competitiveness will
benefit. The National Academy of Science and Engineering report on hydrogen, Feb 2004
suggests that PEM electrolyzer cost reductions could achieve hydrogen production costs of about
$5.33/kg from grid supplied electricity within the next 15 to 20 years.
The electrochemical efficiency of electrolysis is fairly high. PEM electrolyzer stacks, like PEMFCs
exhibit an inverse relationship between efficiency and current density (or amps per unit area).
When low levels of current are applied to the stack, resulting in lower output of hydrogen, the
efficiency of the process can exceed 85%. That is, more than 85% of the BTUs of electrical
energy are converted to BTUs of hydrogen chemical energy. The PEM stack gets less efficient
the harder it is pushed consequently systems today face the trade-off between efficiency and
capital cost.
The cost and GHG impact of hydrogen production by electrolysis in Canada will vary considerably
according to the source of the electrical power. In Canada the sources of power are diverse but
hydro power dominates. Figure 1.3.1 “Electricity Generation by Fuel Type sets out the current
Canadian mix. Clean or cleaner power including nuclear, together with hydro, solar, wind and
geothermal represents about 72%. Natural gas, oil and coal represents the remaining 28%.
Figure 1.3.1 (Canadian) Electricity Generation by Fuel Type, from the Canadian Clean
Power Coalition, May 2004
Canadian Hydrogen
August 2004
Page 1.21
1.3.2
Current Hydrogen Purification Technologies
PEM fuel cells presently require relatively high purity hydrogen (typically 99.999%). Although
some types of trace gases are not harmful to the cell’s membrane catalyst, carbon monoxide
(CO) can rapidly dactivate the PEM cell’s catalysts. Current specifications for fuel cell hydrogen
set a maximum of 20 parts per million CO. CO is a by-product of the fossil fuel based hydrogen
generations processes and is present in all syngas mixes. The syngas will contain from about
75% hydrogen in the case of SMR generated syngas to about 35% hydrogen for atmospheric air
assisted partial oxidation reformers; CO removal to the required specification is an essential step
in making the hydrogen a useful fuel for PEM cells. It is not a problem for IC engines operating on
hydrogen as some of the CO can be consumed in the cylinder; hence it serves as a fuel.
Hydrogen from most electrolytic processes generates a hydrogen stream of about >99% purity
with moisture and some trace gas associated (but no CO). Note that in the case of hydrogen byproduct gas from processes such as chlor-alkali plants, some chlorine will also be found as a
trace gas. The relatively high purity allows more efficient purification of electrolysis based
hydrogen gas. The range of current technologies that perform the clean-up function are described
in the following paragraphs.
Separation equipment will represent about 20 to 30 percent of the total capital cost of a fossil
fuelled hydrogen production facility. The amount depends considerably upon the specific
hydrogen process and the quality of hydrogen required. In the case of electrolytic sourced
hydrogen, the separation equipment component is more in the range of 5%.
Separation and Purification of Hydrogen Gas Streams.
All fossil fuel based hydrogen generators produce a gas mix of H2, CO and CO2 (proportions
varying with the amount of oxygen in the reaction). The gas mix is usually referred to a “syngas”
and it typically ranges from almost 75% in the case of SMRs to as low as about 27% for an air
fired partial oxidation reformer. The amount of hydrogen varies with the process and the quality of
the hydrocarbon feed. For example rich hydrogen syngas may be used in that form for further
chemical processes without specific clean up such as methanol, or some oil refinery processes.
In most cases the syngas is purified to deliver hydrogen at an appropriate purity level. There are
a number of hydrogen separation options.
Pressure swing adsorption (PSA) is the most widely used separation technique. It is reliable,
relatively inexpensive and can achieve consistent high purity under varying feed gas
compositions. This process is capable of achieving a range of purities to meet a variety of
chemical, industrial, or electronics applications. PSA separates hydrogen from virtually all the
gases found within a typical syngas. Separation is achieved by the selective adsorption of the
syngas components in a chamber filled with engineered adsorbent. Under pressure phase all
gaseous molecules are adsorbed except H2. Under pressure the pure hydrogen is pushed from
the adsorbing chamber into the product line. When the pressure is dropped all the contaminating
gases are released, exhausted through another line, and the cycle is re-started. As all the
attached gas molecules are released, the process is 100 percent regenerative. For example, PSA
systems have been in operation for 20 years with no replacement of the adsorbent. Typical large
Canadian Hydrogen
August 2004
Page 1.22
PSA systems have a separating efficiency of about 85%, and routinely achieve 99.999% purity
H2 output. The process can meet all but the most stringent purification standards. The 15%
hydrogen waste gas from the PSA together with all the CO2 and other trace impurities in the
syngas are passed out in the exhaust ports of the PSA. As the output has a very high CO2
content direct sequestration is easily accommodated. The PSA process has a process feature
that makes it extremely popular in hydrogen purification systems design; that is the product H2
leaves the process at about 95% of the pressure that the syngas entered. This feature is
important, as recompression of H2 requires sophisticated compressors and additional energy to
reach pressures appropriate for the application.
Cryogenic separation is a well- established technology for hydrogen purification where very
large volumes of relatively high purity hydrogen are required. The hydrogen rich syngas stream is
compressed and through controlled expansion of the contaminant gases, the temperature is
reduced to the point where the hydrogen liquefies, separating from all the other contaminant
gases. From a thermodynamic perspective cryogenic separation is the most efficient method for
hydrogen purification. Unfortunately the capital cost is disproportionately high for all but the
largest applications. Cryogenic separation becomes competitive for extremely large process
applications where production volumes exceed 80,000 t/y, feed pressure from the hydrogen rich
source are over 25 bar and high purity is required. Cryogenic hydrogen has, like PSA, the virtue
of a product pressure essentially equal to the feed pressure.
Amine separation and other liquid solvent processes are another established syngas
separation technology. The application of each technology depends to a great extent upon the
nature of the trace components in the syngas being purified. Liquid solvent processes are often
selected when trace gases such as hydrogen sulfide and mercaptans that are not easily
accommodated in a PSA separation process.
In the case of amine treatment, a liquid amine takes the CO2 into solution leaving the hydrogen
gas. Amine treatment is relatively more expensive than PSA as the saturated amine needs to be
regenerated with heat to drive out the CO2. The efficiency of amine systems is in the order of
98% CO2 removal. The CO2 and virtually all moisture in the syngas are driven out when the
solvent is regenerated. Solvent treatments are usually used when purifying a hydrogen-based
gas that has impurities such as heavier hydrocarbons or sulphur compounds that can
contaminate standard PSA systems
Membrane separation technology currently relies upon a polymeric membrane’s unique ability to
achieve strength, durability and uniformity of aperture size to selectively pass molecules based
upon size. The permeating gas first dissolves into the membrane, then diffuses through the
membrane structure to the other side of the barrier. Membrane separation of hydrogen increases
with pressure so this technique is typically used when the feed gas is already at high pressure
(such as refinery off-gases at 0.25 bar or 500 psig). The purified hydrogen exits at low pressure
and must be re-compressed for most applications. Membranes’ separation efficiency is relatively
low, in the range of 80% for a purity of 96%. This purity can be achieved with gases such as and
carbon monoxide and carbon dioxide making up most of the difference. Trace hydrogen sulfide is
not easily removed. The membrane process purity levels are well below that required for many
Canadian Hydrogen
August 2004
Page 1.23
applications. For example hydrogen prepared for a PEM fuel cell application requires purity of
about 99.999% or greater with CO at less than 20 parts per million.
1.3.3
Prospective Hydrogen Production & Purification Technologies
Hydrogen Production
Membrane reactors are currently seen as a very promising direction for hydrogen production
from a range of fossil fuels. This process uses partial combustion of the fossil fuel or external
heating of the fuel to break down the hydrocarbon molecules of the feed fuel (form methane to
coal) and continuously draws off a portion of the hydrogen molecules as the hydrocarbons break
apart. The hydrogen is typically drawn off by pressure passage through a palladium membrane
that can withstand the high reaction temperature and will allow only passage of hydrogen
molecules. Sorption-enhanced reaction is in the early stages of research and development for
SMR and water gas shift reactions. The reforming reactions continue as CO2 is continuously
withdrawn from the reaction chamber.
At present the most difficult development aspect of the process is manufacture of palladium of
consistently uniform, about (about 12 microns?) in thickness. A number of companies in the
world, including some in Canada, are developing process technology and membrane materials
and configurations that will enable the sorption-enhanced process to become commercial sized
and cost-competitive.
At this time the developers are cautious about estimating costs for hydrogen production, though
2
there is some optimism that new techniques will achieve 1 or 2 m of crack-free palladium that will
enable the development of industrial-scale plants.
Another type of membrane reactor uses a high temperature ceramic membrane that is selectively
permeable to oxygen ions. This technology may be integrated with a solid oxide fuel cell (SOFC)
to provide electricity and hydrogen. Ceramic membranes are also the most likely candidates for
the high temperature separation of hydrogen and oxygen that follows high temperature
dissociation of water discussed earlier.
Thermal dissociation of Water is a process that, through heat and pressure, decouples or
disassociates the two hydrogen molecules from the single atom of oxygen. The temperatures
o
requires to achieve this separation are in the order of 1000 C making only a few known materials
suitable to enclose and extract the hydrogen and oxygen gases. Nuclear appears to be ideally
suited to this application. Not all commercial nuclear reactors process designs operate at this high
temperature. For example the Canadian CANDU heavy-water systems are ideally suited to the
application while the US light- water reactors are not. Figure 1.3.3.1 displays a schematic of a
typical configuration for high temperature dissociation of water.
Canadian Hydrogen
August 2004
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Figure 1.3.3.1 Very High Temperature Reactor for Dissociation of Water
France, Japan, USA are devoting a considerable amount of government and private R&D into
scaling up current laboratory demonstration models to larger commercial demonstrations. As
work requires both a development of the reactor as well as the reaction chamber and gas
extraction systems there are a number of parallel programs within the core process development
countries and others, such as Canada, that have some components of the appropriate
technologies
Current cost estimates for future large-scale hydrogen production by this method are similar to
hydrogen from large SMR facilities, provided that $50-100 per tonne is added for CO2 disposal
and that requirements for disposal of nuclear wastes do not become prohibitively expensive. The
estimate did include incorporation of current US standards for decommissioning and disposal of
the facility.
Some interesting work on hydrogen production is being undertaken at an experimental level at
the Boreskov Institute of Catalysis in Russia. Of note is a catalytic process for reforming methane
o
into hydrogen and elemental carbon at a temperature of <700 C.
New gas separation technologies using existing technologies such as pressure swing
adsorption and liquids stripping offer the prospect of both incremental and step-jump performance
improvements in separating efficiency (i.e. increase percentage of the desired gas removed from
the product stream). As well, each offer the potential for increased discrimination of the types of
gases removed. For example extraction of hydrogen from oil refinery processes that currently
have 20 to 35% hydrogen content but the volume of gas and the nature of the many hydrocarbon
compounds does not allow conventional systems to economically remove the hydrogen.
Canadian Hydrogen
August 2004
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1.4
Hydrogen Storage: State of the Art
The current high cost of hydrogen storage could be the single most important barrier to the
development of a Hydrogen Economy. However, hydrogen has been safely handled and stored
for many years, albeit that most of the hydrogen has been used near the production site.
The primary methods for hydrogen storage are:
•
Compressed gas – above ground, below ground, and onboard vehicles.
•
Liquefied hydrogen.
•
Metal hydrides.
•
Carbon based systems.
The optimal method of storage depends on the amount of storage required, duration of storage,
whether it is a transportable form, or static, and on local costs. A fully integrated hydrogen
economy will likely require a mix of solutions. For example:
•
Large centralized storage if hydrogen is produced in large plants for wider distribution;
•
Longer term or seasonal storage in systems linked with intermittent (renewable energy)
facilities.
•
Comparatively small-scale storage on board vehicles, possibly in homes and for portable
devices.
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August 2004
Page 1.26
Compressed - High Pressure Gas Storage
Many vendors supply hydrogen as a high-pressure gas in steel cylinders. Pressures are typically
11
15-40 MPa, requiring around 2.3 kWh/kg . Compressed hydrogen tanks for fuel cell vehicles
12
operating at 70 MPa have been certified in Europe and Japan . These tanks have demonstrated
a 2.35 safety factor (165 MPa burst pressure) as
required by the European Integrated Hydrogen
Project specifications.
Figure 1 shows an Air Products system known as
13
the hydrogen “bumpstop” , which consists of a
number of high-pressure cylinders manifolded
(connected) together. Tube trailers can also be used
as static storage at sites where the volumes and
pressures required are higher than can be provided
by a bumpstop.
Vendor storage facilities typically use low-pressure
Figure 1.4-1: Air Products “Bumpstop”
gasholders, high-pressure steel storage tanks or
cryogenic storage. Small amounts of hydrogen are
3
shipped in steel gas cylinders that hold up to 7.45 m of hydrogen at 16.6 MPa. High-pressure
3
tube trailers are sized at 798 - 5100 m .
Advanced lightweight composite pressure vessels made from glass or carbon fibre, with minimum
permeation losses, are now commercially available through companies such as Dynetek
Industries in Calgary, AB. These vessels use an inner aluminum shell or lightweight thermoplastic
bladder liner that act as inflatable mandrels for composite overwrap and as permeation barriers
for gas storage. Initial cylinders manufactured by EDO and Luxfur realized around 3.0 wt% H2 at
14
pressure of 20-30 MPa , other tank systems have demonstrated 12 wt% hydrogen storage at 70
MPa.
Future storage methods may involve existing underground formations that previously held natural
gas. This type of storage is most suitable for large quantities and/or long storage times. There are
15
several large-scale undergrounds hydrogen storage systems .
•
11
12
Wurster, R. & Zittel, W, http://www.hydrogen.org/knowledge/Ecn-h2a.html, section 9.7
http://www.eere.energy.gov/hydrogenandfuelcells/hydrogen/storage.html
13
http://www.airproducts.co.uk/bulkgases/hydrogen.htm
Dutton, D. Hydrogen Energy Technology, Tyndall Centre for Climate Change Research, Working Paper
17, April 2002.
15
Padro, C.E.G. & Putsche, V. Survey of the Economics of Hydrogen Technologies, National Renewable
Energy Laboratory, NREL/TP-570-27079, September 1999.
14
Canadian Hydrogen
August 2004
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•
Kiel, Germany – stores town gas, ~65% hydrogen
•
Beynes, France – Gaz de France (French National Gas Company) has stored hydrogen
rich refinery product gas in an aquifer.
•
Teeside, UK – Imperial Chemical Industries stores hydrogen in a salt mine.
Compressed gas storage technology is improving, notably in the areas of validation testing which
requires the demonstration of resistance to hydrostatic bursts, extreme temperature cycles,
gunfire, accelerated stress, resin shear, permeation and softening.
Liquid Hydrogen
Liquid hydrogen storage is a well-established
technology not least because of its use in the space
16
program, Figure 2 . Liquid hydrogen is however more
difficult to produce and maintain than liquid natural
gas.
Hydrogen liquefaction is expensive in energy terms
because of the low temperatures required: 8.5 kWh/kg
17
and 13 kWh/kg depending on the plant size .
Research continues on novel liquefaction methods
(e.g. magnetic liquefaction) aimed at reducing these
costs.
Liquid hydrogen can be transported by rail in specially
3
18
built tank cars of 36 and 107m capacity .
Large-scale use of hydrogen requires large insulated
3
storage tanks. The largest, some 3,800m capacity, is
at NASA’s launch facility in Florida (Fig 2). Liquid
tanks are being demonstrated in hydrogen-powered
vehicles and a hybrid tank concept combining both
high-pressure gaseous and cryogenic liquid storage is
being studied. These hybrid insulated pressure
vessels are lighter than hydrides, more compact than
ambient-temperature pressure vessels, require less
energy for liquefaction and have lower evaporative
Figure 1.4-2: NASA Liquid Hydrogen Storage
Figure 1.4-3: Linde Liquid Hydrogen Tank
•
16
http://www.fsec.ucf.edu/hydrogen/nasa.htm
Dutton, D. Hydrogen Energy Technology, Tyndall Centre for Climate Change Research, Working Paper
17, April 2002.
18
3
The 107m capacity jumbo cars are 23.7m in length
17
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August 2004
Page 1.28
losses than liquid hydrogen tanks. These losses can be reduced by using high efficiency tank
insulation.
Other special problems with liquid hydrogen include:
•
need to precool the gas to the inversion temperature before the hydrogen can cool on
expansion to liquefy
•
exothermic ortho-to-para conversion after liquefaction.
Spherical shaped storage vessels reduce the surface area to volume ratio and hence heat losses,
but are difficult to accommodate in a car envelope. Figure 3 shows the Linde Liquid Hydrogen
19
tank developed for vehicle applications .
Storage in Materials
There are presently three generic routes known for the storage of hydrogen in materials:
•
absorption, e.g. simple metal hydrides
•
adsorption, e.g. carbon and zeolite materials
•
chemical reaction, e.g. complex metal hydrides and chemical hydrides
In absorptive hydrogen storage, hydrogen is absorbed directly into the bulk of the material. In
simple crystalline metal hydrides, this absorption occurs by the incorporation of atomic hydrogen
into interstitial sites in the crystallographic lattice structure.
Adsorption may be subdivided into physisorption and chemisorption, based on the energetics of
the adsorption mechanism. Physisorbed hydrogen has weak energy bonds to the material than
chemisorbed hydrogen. Sorptive processes typically require highly porous materials to maximize
the surface area available for hydrogen sorption to occur, and to allow for easy uptake and
release of hydrogen from the material.
Chemical hydrogen storage involves displacive chemical reactions for both hydrogen generation
and hydrogen storage. For reversible hydrogen storage chemical reactions, hydrogen generation
and storage occur by means of a simple reversal of the chemical reaction as a result of modest
changes in the temperature and pressure. Sodium alanate-based complex metal hydrides are an
example.
For irreversible hydrogen storage chemical reactions, the hydrogen generation reaction is not
reversible under modest temperature/pressure changes, so that storage requires larger
temperature/pressure changes or alternative chemical reactions. Sodium borohydride is an
example.
Currently, the following classes of materials are being investigated:
•
Metal hydrides - reversible solid-state materials regenerated on-board,
•
Chemical hydrides - hydrogen is released via chemical reaction (usually with water),
•
19
http://www.eere.energy.gov/hydrogenandfuelcells/hydrogen/storage.html
Canadian Hydrogen
August 2004
Page 1.29
•
Carbon- based materials - reversible solid-state materials regenerated on-board,
•
Glass microcapsules.
Metal Hydrides (High and Low Temperature)
Metal compounds that reversibly absorb/desorb hydrogen were discovered in the 1970’s.
Conventional high capacity metal hydrides require high temperatures (300°-350°C) to liberate
hydrogen, which is problematic in FC transportation applications. Current low temperature
hydrides suffer from low gravimetric energy densities and either take up too much on-board
volume, or present a major weight penalty. Researchers are developing low-temperature metal
hydride systems that can store 3 - 5 wt% hydrogen. Alloying techniques have been developed
that result in high-capacity, multi-component alloys with excellent kinetics, albeit at high
temperatures. Additional research is required to identify alloys with appropriate kinetics at low
temperatures. DOE hydrogen storage objectives range from 4.5 wt% by 2005 to 9 wt% by 2015
at a maximum cost of $US 2/kwh.
Various pure or alloyed metals can combine with hydrogen, producing stable metal hydrides. The
hydrides decompose when heated, releasing the hydrogen. Hydrogen can be stored in the form
of a hydride at higher densities than by simple compression. Using this safe and efficient storage
system depends on identifying a metal with sufficient adsorption capacity operating under
appropriate temperature ranges.
Alanates are considered the most promising of the complex hydrides for on-board hydrogen
storage applications. They have been the focus of extensive research to increase the storage
capacity of the materials, extend the durability and cycle lifetime and uptake and release
reproducibility. A thorough thermodynamic and kinetic understanding of the alanate system is
needed in order to serve as the basis for systematically exploring other complex hydride systems.
Engineering studies must be initiated to understand the system level issues and to facilitate the
design of optimized packaging and interface systems for on-board transportation applications.
Low-temperature hydrides are being developed at several US and overseas laboratories in a few
large industrial labs. These are expected to operate <100° C and store 5.5wt % hydrogen.
Pros and Cons of Hydrides:
• Storage capacity is high. Hydrogen can be stored in the
alloys at a greater density than its liquid form without the
need for cryogenic technology.
• Expense
• Safer than other storage methods. Hydrogen remains at
low pressure, and tank rupture would not be as
dangerous as that of a high pressure gas cylinder or LH2
cylinder.
• Can be unstable and affected by poisons.
• Hydride containers require heat exchangers to remove
heat during charging.
• Heavy base material, allowing maximum 2-4%wt
hydrogen.
Chemical Hydrides
An approach for the production, transmission, and storage of hydrogen using a chemical hydride
slurry or solution as the hydrogen carrier and storage medium is being investigated. There are
two major embodiments of this approach. Both require some degree of thermal management and
Canadian Hydrogen
August 2004
Page 1.30
regeneration of the carrier to recharge the hydrogen content. Significant technical issues remain
regarding the regeneration of the spent material and whether regeneration can be accomplished
on-board. Life cycle cost analysis is needed to assess the costs of regeneration.
In the first embodiment, a slurry of an inert stabilizing liquid protects the hydride from contact with
moisture and makes the hydride pumpable. At the point of use, the slurry is mixed with water and
the consequent reaction produces high purity hydrogen.
2LiH + 2H2O
2LiOH + 2H2
An essential feature of the process is recovery and reuse of spent hydride at a centralized
processing plant. Research issues include the identification of safe, stable, and pumpable slurries
and the design of the reactor for regeneration of the spent slurry.
The second, and most advanced, embodiment is sodium borohydride. The sodium borohydride is
combined with water to create a non-toxic, non-flammable solution that produces hydrogen when
exposed to a catalyst.
NaBH4 + 2H2O + catalyst
4H2 + NaBO2
When the sodium borohydride solution and catalyst are separated, the solution stops producing
hydrogen. After being in contact with the catalyst, the fuel is spent and goes into a waste tank.
This waste is recyclable into new fuel, subject to process feasibility and economics.
The borohydride system has been successfully demonstrated on prototype passenger vehicles
such as the Chrysler Natrium.
Carbon
Adsorption of hydrogen molecules on activated carbon has been studied in the past. Although the
amount of hydrogen stored can approach the storage density of liquid hydrogen, these early
systems required low temperatures (i.e., liquid nitrogen). Subsequent work showed that hydrogen
gas might condense on carbon structures at conditions that do not induce adsorption within a
standard mesoporous activated carbon.
Carbon materials present a long-term potential for hydrogen storage and several carbon
nanostructures are being investigated with particular focus on single-wall nanotubes (SWNTs).
However, the amount of storage and the mechanism through which hydrogen is stored in these
materials are not well defined. Current methods can store more than 6%wt hydrogen (perhaps
more than 10%wt). Fundamental studies are directed at understanding the basic reversible
hydrogen storage mechanisms and optimizing them.
Therefore, a coordinated experimental and theoretical effort is needed to characterize the
materials, to understand the mechanism and extent of hydrogen absorption/adsorption, and to
improve the reproducibility of the measured performance. These efforts are required to obtain a
realistic estimation of the potential of these materials to store and release adequate amounts of
hydrogen under practical operating conditions.
Canadian Hydrogen
August 2004
Page 1.31
Microcapsules
This concept is an innovative process where small class spheres of about 0.1mm diameter are
heated to about 300-400° C and subjected to pressures of ~80 MPa. At this temperature,
hydrogen passes through the glass walls. Upon cooling the glass spheres contain about 5-10%wt
hydrogen, which can be released with heating.
Cost of Storage Options
The two main factors affecting the cost of hydrogen storage system are production rate and
storage time. The required production rate determines the size of the compressors and
liquefaction plants and their operating costs; the production rate multiplied by the number of
storage days gives the overall capacity, which in term determines the unit size and capital cost.
The table below provides storage costs for stationary applications:
Storage System
Compressed
Gas
Liquefied
Hydrogen
Metal Hydride
Period of Storage
Facility Size
(GJ)
Specific TCI
($/GJ)
Hydrogen Storage
Unit Cost ($/GJ)
Short term (1-3 days)
131
13,100
20,300
130,600
9,008
2,992
2,285
1,726
4.21
1.99
1.84
1.53
Long term (30 days)
3,900
391,900
3,919,000
3,235
1,028
580
36.93
12.34
7.35
131
13,100
20,300
130,600
35,649
7,200
1,827
3,235
17.12
6.68
5.13
5.26
Long term (30 days)
3,900
108,000
391,900
3,919,000
1,687
1,055
363
169
22.81
25.34
8.09
5.93
131 - 130,600
4,191-18,372
2.89-7.46
Long term (30 days)
3,900 – 3.9 million
18,372
205.31
Cryogenic
Carbon
1 day
4,270
26.63
Underground
1 day
7-1,679
1.00-5.00
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August 2004
Page 1.32
Major Challenges in Hydrogen Storage
•
Capacities: Energy efficiency is a challenge for all hydrogen storage approaches. The
energy required to get hydrogen in and out is an issue for reversible solid-state materials.
Life-cycle energy efficiency is a challenge for chemical hydride storage in which the byproduct is regenerated off-board. In addition, the energy associated with compression and
liquefaction must be considered for compressed and liquid hydrogen technologies.
•
Costs: Cost reduction in the absence of high volume demand. The cost of on-board
hydrogen storage systems is too high, particularly in comparison with conventional storage
systems for petroleum fuels. Low-cost materials and components for hydrogen storage
systems are needed, as well as low-cost, high-volume manufacturing methods.
•
Manufacturing: Processes for developing tanks for mass production. Durability of hydrogen
storage systems is inadequate. Materials and components are needed that allow hydrogen
storage systems with a lifetime of 1500 cycles.
•
Materials: The weight and volume of hydrogen storage systems are presently too high,
resulting in inadequate vehicle range compared to conventional petroleum fuelled vehicles.
Materials and components are needed that allow compact, lightweight, hydrogen storage
systems while enabling greater than 300-mile range in all light-duty vehicle platforms.
•
Performance: The reliability and durability of materials used to handle hydrogen – in both
static and dynamic applications. Refueling times are too long. There is a need to develop
hydrogen storage systems with refueling times of less than three minutes, over the lifetime of
the system.
•
Codes & Standards: Inconsistent or non-existent codes and standards. Applicable codes
and standards for hydrogen storage systems and interface technologies, which will facilitate
implementation/commercialization and assure safety and public acceptance, have not been
established. Standardized hardware and operating procedures, and applicable codes and
standards, are required.
•
Demonstrations: Lack of safety demonstrations and acceptance. Life Cycle and Efficiency
Analyses. Lack of analyses of the full life-cycle cost and efficiency for hydrogen storage
systems.
1.5
Hydrogen Transportation – Current State of Art
Hydrogen can be transported using several methods:
•
Pipeline
•
Truck.
•
Rail
• Ship
The optimal method varies by distance transported, production method and/or use.
Canadian Hydrogen
August 2004
Page 1.33
Pipelines
Although there are several short-distance hydrogen pipelines in Canada and the United States,
the pipelining cost is very high. As such a large-scale hydrogen pipeline distribution infrastructure
is conceivable, but would be expensive. There are significant technical problems related to the
use of the existing natural gas pipeline network, such as embrittlement, diffusion losses, seal
materials, incompatibility of compressor lubrication with hydrogen and the use of plastic pipe.
Truck Transport
Hydrogen may be transported on trucks as a compressed gas, liquefied, metal hydride or other
20
media. Figure 4 shows a Linde Liquid Hydrogen truck . Liquid
hydrogen trailers carry from 1.5 to 3 tonnes and in North
America will deliver hydrogen as far as 1500 km. Compressed
hydrogen trailers, or “tube trailers“, are much more common
and service customers within a few hundred km of the storage
area. Compressed hydrogen trailers vary in size and carry an
average of 150 kg of product. Newer designs proposed by
Dynetek Industries uses advanced carbon fibre containers in
modules and achieves 500 kg of storage in a single tractortrailer unit.
Rail and Ship
The shipping of hydrogen has been evaluated for rail and ship,
but with reference in general to the storage mechanism, e.g.
Figure 1.5-1: Hydrogen Transport
Truck
21
Amos reviewed rail shipment for compressed gas, liquefied
hydrogen and metal hydride, and ship transport for liquefied hydrogen.
1.5.1
22
Cost of Transport Options
Transportation costs have been researched over the last decade, but it is clear from the
assumptions made that the economic evaluation must be continuously updated to reflect
technology development and transportation infrastructure.
Transport Type
Transmission Rate
Transmission/
Transport
Distance (kms)
Specific TCI
($/GJ)
Hydrogen
Transport Cost
($/GJ)
Pipeline
0.15 GW
161
805
1,609
14.14-21.22
67.53-106.24
134.18-210.32
2.03-2.83
8.87-13.84
17.41-27.23
Pipeline
1.5 GW
161
805
2.13-2.83
7.47-11.59
0.49-0.83
1.17-2.09
•
20
http://www.linde-gas.com/International/Web/LG/COM/likelgcomn.nsf/DocByAlias/nav_hydrogen
21
Amos, W. 1998. “Cost of Storing and Transporting Hydrogen”, National Renewable Energy Laboratory,
NREL/TP-570-25106, May.
22
Padro, C.E.G. & Putsche, V. Survey of the Economics of Hydrogen Technologies, National Renewable
Energy Laboratory, NREL/TP-570-27079, September 1999.
Canadian Hydrogen
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Page 1.34
1,609
14.13-22.3
2.03-3.53
Liquefied in
Truck
45,418 – 45.6 million GJ/year
16
161
805
1,609
0.44-11.0
0.77-11.0
2.70-11.0
5.10-11.0
0.24-1.60
0.52-1.84
2.00-3.10
3.90-4.70
Compressed Gas
by Truck
458,000-45 million GJ/year
“
“
16
161
805
1,609
4.10
8.20
30.20
57.60
4.70
10.60
41.10
79.40
Truck using
Metal Hydrides
“
“
16
161
805
1,609
7.54
15.08
55.28
105.54
2.63
5.75
21.92
42.11
322 km
805 km
1,609 km
8.22
16.43
24.58
13.34
14.39
15.44
(Hydride
@$18,375/GJ)
Ship
The above table provides a convenient volume, mode and distance cost comparison that
is relatively current ( 2002 basis).
1.6
Carbon Dioxide Management
The topic of CO2 generation, collection, and sequestration is a complex issue. CO2 is the
dominant GHG associated with fossil fuel based hydrogen energy production. It represents from
12 to 50% of the exhaust gas out put of current hydrogen production processes and is the
principal GHG in all exhaust gas mixes. It is important to address those aspects of CO2
management that bear on hydrogen from a fossil fuel source. This section on CO2 management
is included to ensure that the issue is neither considered trivial nor inordinately difficult.
CO2 is already being captured in the oil and gas and chemical industries from concentrated
streams. Merchant gas companies in the US and EU have several plants that capture CO2 from
power station flue gases for use in the food and beverage industry. However, only a fraction of
the CO2 in the flue gas stream is captured for commercial use. To reduce emissions from a
typical power plant by 75% the associated equipment would need to be 10 times larger than the
largest CO2 systems currently installed. (Ref: IEA Green Project – CO2 Sequestration).
There are four aspects of the CO2 issue that are briefly addressed in this report to provide some
context with which to view the issue. The first aspect is the amount of CO2 generated by the
various hydrogen production options. The second aspect is technology for collection and/or
separation from other non-GHG gases. Transporting and sequestering CO2 are the third and
fourth aspects addressed in the following pages.
CO2 generation sources have been well researched and documented by scientists and
engineers around the world. CO2 outputs from the basic reactions that generate hydrogen are
relatively straightforward to calculate on a theoretical basis. In-the-field sampling then establishes
the actual output reflecting the impact of process and operating in-efficiencies. Life cycle CO2
estimates are much more complete perspectives and should be core to policy planning. This
approach has developing methodologies and which makes it less easy to compare results from
Canadian Hydrogen
August 2004
Page 1.35
various authors. Field sampling is also less straightforward as all components of the life-cycle
may be widely scattered and individual sources may utilize alternate technology to produce a
component of the final product.
This report discusses only the in-process CO2 management. As the operating phase is generally
the period during which the vast majority of CO2 is generated management at this level is the
principal control step. There is much data developed on life cycle CO2 production. In Canada,
23
GHGenius and models by The Pembina Institute offer generally well accepted methodology and
results.
Fig 1.6.1 CO2 Production from Principal North American Sources
This figure sets out the contribution of
different sources of CO2 for a typical
industrialized nation. The vast majority of
the hydrogen technologies in this report are
found within the “Industry, Households, etc”
segment of 39%. Electrolytic hydrogen,
either dedicated to hydrogen production or
in chemical processes such as chlorine and
caustic soda production, contributes within
the “Electricity” section. Each section is a
significant contributor, and each has
fundamentally
distinct
waste-gas
composition.
Fossil fuel hydrogen production is primarily steam methane reformed (SMR) or Partial Oxidation
(POX) reformed. Each process produces CO2 and a range of usually trace levels of GHGs. In the
SMR, one component is produced from the furnace heating of the gases and represents about
25% of the total CO2 attributed to that process. After passing the syngas through a hydrogen
purifier with the exhaust gas from a PSA purifier contains about 40 - 50% CO2, 30 – 40% H2 and
the remainder methane. The high percentage of hydrogen makes it not readily suited for
sequestration and does offer some reasonable fuel value for process heating. As the value of
hydrogen increases, this exhaust gas may be passed through a secondary PSA and the CO2
concentrated to a level of about 70% CO2, and 8% CO and 8% methane, giving about a 95%
•
The GHGenius model is as lifecycle emissions model for 12 different greenhouse gases that could arise.
The model was developed to establish a thorough and sound representation of Canada’s own transportation
sectors. It can also be used to forecast the impact of alternate of alternate strategies and polices to control
and reduce GHG production. The model is based upon original work by Mark Delucchi and developed by
2
Don O’Connor of (S&T) Consultants. The model is expected to be available to interested users in the first
half of 2004.
Canadian Hydrogen
August 2004
Page 1.36
hydrogen recovery and a gas mix that could be suitable for sequestration. The remaining 25% of
the CO2 is exhausted as a component of the flue-gas from the associated heating cycle. This
flue-gas is typical of most emissions from electricity generation, and industrial and household
heating. The typical CO2 /GHG component of flue-gas is about 12 – 15%.
Separation of CO2
Most power plants and other large point sources use air-fired combustors, a process that
exhausts CO2 diluted with nitrogen. Flue gas from coal-fired power plants contains 10-12 percent
CO2 by volume, while flue gas from natural gas combined cycle plants contains only 3-6 percent
CO2. For effective carbon sequestration, the CO2 in these exhaust gases must be separated and
concentrated, and is an extremely expensive process because of the large volume of gas that
must be processed to extract the 12 – 15% GHGs. Separation of the CO2 and most of the GHG
components from flue gases is essential prior to transporting and sequestrating the CO2.
In summary, there is good evidence that the majority of CO2 from fossil fuel based large hydrogen
production can be separated for sequestering at reasonable cost.
It remains a considerable technical challenge to concentrate the CO2 from flue-gas and engine
exhaust sources to a level that makes transportation and sequestration relatively economic.
There are a number of well-established and effective techniques for separation of CO2 from other
gases; but at this time there are none that can accommodate the enormous volumes associated
with lean CO2 flue gases.
There are a number of processes that will capture the CO2 and bond it permanently to other
materials or liquids. The disposal or regeneration of the material then presents a disposal
problem. Separation techniques, of the type described in Section 1.3 can do the job but the size
of facility necessary to accommodate the volume of gas makes the capital and operating costs
high. As an example, several studies have estimated the cost to be in the order of 1.5 to 1.8 cents
per kW, equivalent to about a 20% to 25% increase in electric power costs.
The use of pure oxygen to replace ambient air potentially solves the lean CO2 problem.
Concentrated oxygen (in lieu of ambient air with 80% nitrogen and 1% argon), is used in some
large-scale or specialized industrial applications such as oil and coal gasifiers. The use of pure, or
enriched oxygen concentrates the CO2 in the exhaust stream by eliminating all or most of the
inert gases in ambient air. The resulting exhaust gas has a high CO2 content and generally be
directly transported and sequestered without further treatment.
Pure or enriched oxygen for gasifiers requires large scale, cost effective production. At this time
gasifier oxygen production is confined to liquefaction and pressure swing adsorption. Each
process significantly increases the operating cost of the combustion process. Oxygen enriched
combustion is presently used almost exclusively where high heat generation is essential to a
process; the heat adsorbing capacity of nitrogen is sufficient to reduce combustion temperatures
below desirable levels making oxygen enrichment an economically attractive option in some
cases. Both liquefaction and PSA technologies offer industrial sized capacities. However, present
Canadian Hydrogen
August 2004
Page 1.37
technology development is such that only air liquefaction is economic for large petrochemical and
power facilities.
Although outside the scope of this report on hydrogen, the potential impact of lower-cost
production technologies for pure or enriched oxygen is a key element of systems seeking to have
a major impact upon the reduction of GHGs.
CO2 Pipeline Transport is the only practical method at this time of transporting the large
volumes of CO2 associated with large industrial combustion or process facility sites to suitable
sequestration locations. Pipeline transport of CO2 is a well-developed technology.
Large-scale transportation of CO2 is common in the United States, and the gas has been used in
several US states for enhanced oil recovery (EOR) for some 40 years. As detailed in the CO2
Sequestration section of this report, about 50% of the EOR is based upon CO2 injection. There is
a network of 2,500 km of CO2 pipeline transporting over 1.2 billion scf/d of CO2. The bulk of the
CO2 is produced from naturally occurring underground CO2 reservoirs and does not represent
CO2 sequestration from energy or chemical process facilities.
The largest US operator of CO2 EOR systems is Kinder Morgan Inc. This company operates
24
over 1600 kms of CO2 pipelines and transports 400 million scf/d of the gas to several fields . The
largest CO2 EOR project in Canada is also a true CO2 sequestration project, and is located near
Weyburn Saskatchewan. CO2 is pipelined 325 kms from the exhaust output of a coal gasification
plant in North Dakota. The project has been underway since 2000.
Since CO2 has been successfully transported by pipeline for many years, the design parameters
25
are reasonably well understood . In some industrial circumstances CO2 is compressed to its
critical pressure (about 7000 Kpa for pure CO2) and then pumped as a liquid, though unless there
are extenuating circumstance for a high-pressure end-use, liquid pipeline transport is not costeffective, and for the most part CO2 is shipped as a gas. Key design parameters are volume,
distance, pre-treatment of potential contaminants, and assessing the amount of compression
required. Compressors generally represent the largest cost component of a CO2 pipeline as the
gas is frequently received from exhaust or clean-up processes at atmospheric pressure and
therefore requires maximum energy to reach a desires line pressure.
CO2 Sequestration is the final step in the process of CO2 management. CO2, if sufficiently pure,
can be sequestered directly from the process stream of most of the typical hydrogen production
26
processes. There are three basic options . These are:
•
24
http://www.kindermorgan.com/about_us/about_us_kmp_co2.cfm
Richard Luhning, Ho-Shu Wang, Jeff Jergens, Enbridge Inc. 2004
26
Blok, K., Williams, R., Katofsky, R., Hendriks, C. 1997. “Hydrogen Production from Natural Gas,
Sequestration of Recovered CO2 in Depleted Gas Wells and Enhanced Natural Gas Recovery”, International
Journal of Hydrogen Energy, Vol. 22, No. 2/3, pp. 161-168.
25
Canadian Hydrogen
August 2004
Page 1.38
1. underground storage in gas-tight natural reservoirs,
2. chemical reduction to solid carbon and carbon compounds
3. deep sea injection
Of the various types of geologic formations, depleting oil reservoirs and unmineable coal beds
have the highest near-term potential for storing CO2. There are four principal reasons:
•
large and geologically diverse storage capacity;
•
many regions offer the presence of existing surface and downhole infrastructure; and,
•
the strong base of industrial experience with injecting CO2 into depleting oil reservoirs to
enhance recovery, or enhanced oil recovery (EOR),
•
economic benefits arise from enhanced oil and potentially coal bed methane recovery.
However, using depleted oil reservoirs and unmineable coal seams for carbon sequestration has
goals and requirements that are fundamentally different from using CO2 for additional oil and gas
recovery.
Fig: 1.6.2
Canada’s Sedimentary Basin Most Suitable for CO2 Sequestration-
Source: Alberta Research Council - 2003
The figure above shows the numerous basin regions under and adjacent to the Canadian land
mass. There are adequate storage opportunities in most parts of Canada. The suitability and
quality of storage offered by the various locations differ considerably, but convenient options exist
within 200 km of most major urban areas and industrial centres. Potential deep basin
sequestration is available within Canadian territory for most regions with exception of Southern
Ontario. Here some accommodation in US basins would be most easily accessed provided that
Canadian Hydrogen
August 2004
Page 1.39
they are not fully used by US requirements. The alternative will be pipeline transport to the
Canadian East Coast, a distance of about 1800 km.
Enhanced oil recovery (EOR) and Enhanced Coalbed Methane Recovery (ECBM) are both
potential economically attractive method of CO2 sequestration. Work to verify the economics of
coalbed methane is at an early stage in Canada, building on pilot studies underway in Alberta.
More is understood about the economics of enhanced oil recovery. For example in 2001,
American industry injected 30 million tonnes of CO2 for EOR, providing 180,000 barrels per day
of additional domestic oil production. There are thousands of kms of CO2 collection, arterial and
re-injection pipelines in the US. Industry experts estimate that about 12% of the total current oil
production in the Lower 48 states of the US can be attributed to the use of CO2
Historically the oil and gas industry goals were to maximize oil and gas recovery using as little
CO2 as possible; geologic sequestration goals are to maximize CO2 injection. Current practices
are to keep the injected CO2 in the reservoir for only a handful of years; sequestration seeks to
store the CO2 for thousands of years. Beyond these and other differences in objectives, there are
areas where CO2 sequestration and production of "value added" hydrocarbons are
complementary and mutually beneficial.
First, the additional production of the reservoirs oil and natural gas can help defray some of the
costs of CO2 injection and long-term storage. Also, advances in technology can expand the types
and number of reservoirs amenable to CO2 sequestration. In turn, research of capture of the CO2
will help lower the costs and expand the volumes of CO2 available for injection. The two
overriding R&D areas for geological storage of CO2 are:
•
developing reliable monitoring, verification and mitigation technology; where considerable
emphasis is currently being focused on modifying existing technology to reduce its costs
and improve its use for monitoring geologic storage of CO2.
•
sponsoring appropriate health, safety and environmental (HSE) risk assessment data
collection and methodology.
A significant effort is also underway to understand the interaction of injected CO2 on the integrity
of the reservoirs cap rock as well as the flow and storage properties of CO2 in the reservoir.
In the case of ECBM the opportunities for long-term storage of CO2 may be greater as the carbon
crystal lattice bonds CO2 in preference to methane. The result is that not only is methane
production enhanced but also the CO2 is held permanently provided that there are no significant
reductions in pressure.
A critical goal in both Enhanced Oil Recovery and Enhanced Coal bed methane is to improve
understanding of these storage processes so that the process is cost-effective or appropriate
incentives can make long-term CO2 storage in oil reservoirs and coal seams common industrial
practice.
.
Deep saline reservoirs offer sequestration opportunities in many different areas of Canada.
Canadian Hydrogen
August 2004
Page 1.40
These deep reservoirs are saline aquifers at depths of more than 800m, enabling the storage of
CO2 in a dense supercritical form. They are distinct from the aquifers that provide fresh water for
human populations, though they are equally widely distributed. The worldwide potential for CO2
storage in such aquifers is thought to be thousands of gigatonnes of CO2 – enough for the
sequestration of several hundred years of CO2 from fossil fuel combustion. Many of these
aquifers are ‘closed’ - i.e. bounded spaces - which may accept only limited amounts of CO2
(Holloway et al, 1996) but other aquifers are extensive horizontal formations in which the injected
CO2 would gradually dissolve in the water in the formation. These would accept very large
amounts of CO2.
Considerable research was undertaken in Alberta in the 1990s that showed that aquifer storage
of carbon dioxide was possible. The largest project is in operation in the North Sea off the coast
of Norway. Since 1997, Statoil has been capturing roughly 1 million tons of CO2 per year from a
natural gas processing platform and injecting this into a saline formation below the ocean bottom.
Current research is aimed at developing field practices to maximize CO2 storage capacity and
understanding the dissolution reactions involving the CO2 and other chemical species and
minerals in the saline formation.
Other such sequestration projects have been proposed. This includes the deep ocean because it
may well be the ultimate destination for much of the carbon in the atmosphere today. This
solution is not widely supported primarily because the impacts are speculative. The principal
concerns are that 1. the local ecological impact is undetermined because so little is known of life
and life-cycles at great depths; second, the CO2 forced would be liquid at that depth and may
resurface as the result of currents or gradual disbursement.
Costs for CO2 Sequestration will vary widely and there is very little industry-accepted
information to date. Those regions that were, or remain, active petroleum production areas will
most likely have infrastructure, and drill holes accessing the reservoir, and relatively short pipeline
distances. These factors will assist in reducing the capital and operating costs of sequestration in
such areas. Other areas, such as Southern Ontario perhaps, will have higher capital and
operating costs and may not have the economic up-side of sequestration in coal or oil basin
areas where increased oil or gas production will help to off-set the costs of sequestration.
Injecting CO2 into reservoirs in which it displaces and mobilizes oil or gas could create economic
gains that partly offset sequestration costs. In Texas, this approach already consumes ~20 million
tons/year of CO2 at a price of $10 to $15 per ton of CO2. However, this is not sequestration,
because most of the CO2 is extracted from underground wells sometimes recovered at deep well
pressures and is generally ready for use after some useful liquids are separated. Nonetheless the
similarities are close and the economics are not obscure, despite the need for additional testing
and evaluation related to safety and long-term retention issues.
Canadian Hydrogen
August 2004
Page 1.41
Some numbers have been extracted from operating data, for example the current cost of pipeline
27
transport is about $1.25 per tonne/100 km of CO2 .
Theoretically based estimates abound. For example various articles and website information sites
suggest that if CO2 capture is added to the flue-gas of a typical fossil fuel thermal electric power
plant the collection, separation, transport and injection cost will add at least 2.5 US cents/kWh to
the cost of electricity generation. These estimates may, or may not take into consideration that
the generating efficiency would be reduced by 10 to 15 percentage points (e.g. from 55% to 45%
for a current technology fossil fuel facility). Again, this information based on current technology
further increasing the calculated cost impact. CO2 is currently recovered from combustion
exhaust by using amine absorbers and cryogenic coolers. The cost of CO2 capture using current
technology is calculated to be in the order of $ 50 – 80 per tonne of CO2 - much too high for
carbon emissions reduction applications based upon current technology. Analysis performed by
ENL - SFA Pacific, Inc. indicates that adding existing technologies for CO2 capture to an
electricity generation process could increase the cost of electricity by 2.5 cents to 4 cents/kWh
depending on the type of process.
The costs cited in the previous paragraph would nearly double the cost of hydrogen produced by
current electrolytic processes. The indirect impact would be that production would move to lower
cost electric power regions, provided that such alternatives existed. It is expected that widespread
application of this technology would result in developments leading to a considerable
improvement in its performance in the long term. The estimated cost of avoiding CO2 flue gas
emissions is 40-60 US$/tonne of CO2 (depending on the type of plant and where the CO2 is
28
stored) .
Existing capture technologies are not cost-effective when considered in the context of
sequestering CO2 flue gas from power plants.
Existing technologies could offer a cost-acceptable solution for 75% of the CO2 stream from SMR
based hydrogen production. The costs for secondary CO2 concentration of the SMR exhaust gas
would require compression and another PSA unit that would be about 25% the size of the primary
unit. The feed gas of roughly 55% CO2, 40% hydrogen and the remainder is methane and CO
would recover additional high-purity hydrogen from the SMR syngas stream and deliver a CO2
stream that would meet criteria for subterranean injection. A rough estimate of separation cost it
that it would create about a 20% cost increase in production of large-scale hydrogen production.
An alternate technology offers a less complex CO2, purification approach for lighter fuels such as
syngas and methane. Such fuels consumed in high temperature fuel cells such as SOFC or
molten carbonate fuel cells (MCFC) would create an exhaust stream from the cell of almost pure
CO2. The concentrated CO2, as the exhaust stream from such devices has already had some
testing by Shell Oil at a site in Norway.
•
27
28
Pipeline costs are estimated by Hans-Joachim, Los Alamos Labs. NM, Nov 2002
Ref: IEA Greenhouse Gas Project
Canadian Hydrogen
August 2004
Page 1.42
The potential EOR benefits arising form the CO2 sequestration in depleted oil fields is still not well
understood for the Western Canadian Sedimentary Basin. There is no field data on the
recoverability of value through enhanced coal bed methane. Nonetheless laboratory tests
suggest that the approach will increase the methane production is coal beds. In an effort to
improve the accuracy of potential EOR benefits, Alberta, Saskatchewan and the US are
undertaking projects. Starting in 2003 DOE's Rocky Mountain Oilfield Testing Center (RMOTC)
will manage a large-scale, multiple-partner CO2 sequestration/enhanced oil recovery project in
the Teapot Dome Field. The CO2 is recovered from a natural gas CO2 extracting plant about 200
kms distant. The carbon sequestration potential from the project is projected to be at least 2.6
million tons of CO2 annually. The expected concurrent rise in associated oil production is
expected to be about 30,000 Bpd, a six-fold increase over current production level.
For injection into depleted natural gas fields at a depth of 2 km, storage costs range from US$2.6
3
3 29
for an injection rate of 20 Nm /s to US$13.3/tC for an injection rate of 2 Nm /s .
In summary, industry estimates in Alberta allow for a minimum of $30 per tonne for CO2
sequestering. This would approach $80 for 12% CO2 flue gas streams.
•
29
Ref: Hendriks, C. (1994) Carbon dioxide removal from coal-fired power plants. Ph.D. thesis, Department
of Science, Technology, and Society, Utrecht University, Utrecht, the Netherlands
Canadian Hydrogen
August 2004
Page 1.43
2.
CANADIAN DEMAND, CAPACITY, SUPPLY & SURPLUS – 2003
2.1
Introduction
The data presented in this section is focused upon presenting the actual size and nature of the
hydrogen industry in Canada today. The report presents background and information on the
principal producers, users and surplus based upon volume data collected from documents,
interviews and calculations. Many of the companies have been in the hydrogen business for
decades and may, or may not view themselves as having anything to do with the future hydrogen
economy. Hydrogen is a key feedstock for a range of products. In other industries it is a byproduct to be sold if possible, but all too often, ends up as furnace fuel or simply discharged to
the atmosphere.
A total of 68 facilities, pus three hydrogen pipelines, were included in the project survey. Of these
38 facilities, plus one pipeline, were located in the Western Region, 25 facilities, plus two
pipelines, in the Eastern Region and 5 facilities in the Atlantic Region. Among this group 17 were
oil refineries, 4 are heavy oil upgraders, 17 are chemical dedicated production, and 30 are
chemical by-product production. Included in the Eastern Group are the coke ovens at the
principal steel smelters in Ontario. There are also 3 merchant gas production facilities in the
Eastern Region and two gas purification facilities in the West. Merchant gas companies also
operate the two major hydrogen pipelines in Canada, one in Strathcona (east of Edmonton) and
the other in Becancour, Quebec.
The following notes describe some general aspects of the data presented in detail in Appendix D,
and summarized in this section.
1. the data are as of December 31, 2004, to the extent possible.
2. the hydrogen producers and users have been identified and data collected based in part
by previous work by
a. Camford Information Services, Toronto, Ontario
b. CEH Review (Chemical Economics Handbook), SRI International, Palo Alto, CA
3. Camford contributed its database to the project and one Camford staff person assisted in
the data collection and documentation.
4. telephone and/or email contact was attempted, and in the majority of cases, responded
to, by the identified companies.
5. numbers were independently developed or cross-checked from contacts with
knowledgeable industry people associated with the merchant gas companies and
specialist chemical consultants.
6. in this report product volumes are expressed in metric format, typically in tonnes per year
(t/y) of hydrogen. The majority of industry expresses volume as standard cubic feet/day,
(Within the accuracy of the estimates made by industry data in this report, hydrogen
volumes were considered as: 1 million scf/d if hydrogen approximately equals 1,000 t/y of
hydrogen).
Canadian Hydrogen
August 2004
Page 2.1
7. while capacity of systems is often documented in facility permits, actual production is
treated by most companies as much more confidential. Dalcor did not offer confidentiality
of the data.
8. production volumes quoted are annual averages.
9. “Surplus” hydrogen (tonnes per year of hydrogen) is the amount of medium to rich (50 –
100% pure) hydrogen outputs that are otherwise used as furnace fuel or is vented to
atmosphere.
10. sources of hydrogen production in quantities less than about 50 t/y were not measured,
11. bulk hydrogen suppliers, typically merchant gas companies, of bottled or trucked
hydrogen were not measured except where dedicated hydrogen generation facilities were
operated by the suppler.
12. The regions selected relate to the conventional national description, i.e. Western Region
includes British Columbia, Alberta, Saskatchewan, and Manitoba. Yukon and Northwest
Territories, The Eastern Region includes Ontario, Quebec and Nunavut, and the Atlantic
region includes Nova Scotia, New Brunswick, Prince Edward Island, Newfoundland and
Labrador.
2.2
Current Hydrogen Use – 2003
2.2.1
Summary Inventory – Hydrogen in Canada - 2003
The results of the hydrogen industry survey are presented below. The quantity of hydrogen is
expressed in tonnes per year and reflects an approximate “average” production for the various
facilities. Table 2.1 – 1 displays the data from the inventory of Canadian hydrogen capacity,
production and surplus data. The information is divided into regions and the nature of the users
and producers, divided into up to five categories.
For detailed information on each source, and associated companies that use excess hydrogen,
please refer to Appendix A. The data in Appendix A presents the facility-by-facility information
used to develop Table 2.2 – 1 for industry sectors in each of the three Canadian Regions.
Canadian Hydrogen Production & Surplus by Sector & Region (tonnes/year)
Western Region
Oil Refining
Heavy Oil Upgrading
Chemical Industry
Chemical Industry By-product
Merchant Gas
Sub-total
Central Region
Oil Refining
Chemical Industry
Canadian Hydrogen
2003 - Capacity
2003 - Production
(t/yr)
(t/yr)
2003 - Surplus
(t/yr)
198,270
185,355
770,000
770,000
0
0
912,900
912,900
26,100
463,000
398,609
147,653
0
0
0
2,344,170
2,266,864
173,753
437,362
437,362
0
74,075
73,591
0
August 2004
Page 2.2
Merchant Gas
Sub-total
Atlantic Region
Oil Refining
Chemical Industry
Merchant Gas
Sub-total
Total Canadian Production/Surplus
72,000
70,712
22,154
16,700
16,700
0
600,137
598,365
22,154
222,000
222,000
0
0
0
0
2,000
2,000
0
0
0
0
224,000
224,000
0
3,168,307
3,089,229
195,907
Table 2.2-1 Canadian Hydrogen Capacity, Production and Surplus – December 2003
The capacity and actual production tend to be closely linked as industrial markets are generally
good. While summer periods may see reduced operations for all but the oil refineries, the late fall
and winter are periods of generally steady demand to fill inventories. Refineries will have shifted
slightly from gasoline to somewhat heavier fuels but the effect on hydrogen production is not
significant enough to result in reporting any change. The particulars of each sector are discussed
in the following sub-sections of this report.
2003 H2 Capacity by Region
2,500,000
2,344,170
T/year
2,000,000
1,500,000
Tonnes / year
1,000,000
600,137
500,000
224,000
0
1
2
3
Figure 2.2 – 1 Canadian Hydrogen Production Capacity – 2003 by Region
At a macro scale, Canadian production of hydrogen is just over 3 million tonnes per year, an
amount that puts Canada as the leading per capita producer in the OECD. Data from the Middle
East could confirm that Canada leads the world in per capita hydrogen production. The huge
amounts of hydrogen produced are driven by the petrochemical sector and will likely remain
dominated by that sector and increased oil sands upgrading for the next 20 years.
The Western Region dominates Canadian hydrogen production as a result of being now, as in the
past, the fossil fuel bread-basket of Canada. As a result, the oil refineries located, primarily in
Edmonton area, serve not only Western Canada’s needs but also export a range of refined
petroleum products. Closely tied to the large fossil fuel resource is a range of chemical industries
Canadian Hydrogen
August 2004
Page 2.3
that use natural gas as a feedstock. The upgrading of heavy oil from the unique oil sands in
Alberta is the fastest growing hydrogen demand sector and will likely remain the fastest growing
sector for the next 30-50 years. As shown in Table 2.1 – 1, four heavy oil upgrading facilities use
almost four times as much hydrogen as the six Western refineries.
Hydrogen consumption in the East is a function of refinery and chemical industry development
that is strategically located to use Western crude, as available, but equally available to use
Newfoundland and offshore crude. These refineries serve primarily the needs of Eastern
petroleum needs. The Eastern-based chemical industries are primary, secondary and tertiary
chemical producers and consume ethylene and polyethylene as the primary chemical produced in
for example Alberta and transported by rail as pellets or if ethane by pipeline to locations such as
Sarnia.
The Atlantic Region consumption of hydrogen is almost entirely related to oil refining. There are
three refineries, with the Irving Oil refinery being the largest in Canada. The Region produces
refined oil products primarily for export. Crude is exclusively from abroad and from offshore
Newfoundland. There are two hydrochloric acid facilities that consume all the by-product
hydrogen produced by the Region’s electrolytic based chlor-alkali plants.
Merchant gas companies sell hydrogen across Canada and into the US in liquid form and tubetrailer form for local service. The total volume is relatively low on the scale that this report’s data
has been collected. Total merchant hydrogen sold is about 18,000 t/y. Of this, most is purchased
from some of the many hydrogen producers with surplus gas available.
There are many opportunities associated with the prospect of the hydrogen economy, and fuel
cell vehicles. It is interesting to observe that in 20 years Canada is expected to have
approximately 22.6 million passenger vehicles. If all were fuel cell vehicles (a unlikely conversion
30
rate in only 20 years) and each uses the anticipated average of about 0.230 t/y of hydrogen,
then annual hydrogen production would need to increase by 5.2 million tonnes per year; or
slightly less than a doubling of the country’s present hydrogen capacity. The US, on the other
hand, would require a 12-fold increase in production to meet a complete fuel cell conversion of all
light vehicles.
The final note at the macro scale is to point out the Canadian surplus hydrogen volume of nearly
200,000 tonnes annually. There is an additional amount of almost 100 t/y of hydrogen produced
from the Algoma, Dofasco and Stelco coke ovens. The 55% hydrogen off-gas is used as fuel.
Algoma unsuccessfully attempted to extract hydrogen for annealing during the early 1990’s but
abandoned the process facility. Dalcor in not aware of any coke facilities in North America that
have been successful making hydrogen extraction successful. In general, the large hydrogen
surplus is a reflection of the fact that hydrogen is still relatively “cheap” and does not travel well.
The effort to utilize or sell the excess hydrogen from by-product production is limited because the
economic value of the excess hydrogen has not reached the level where new production is more
•
30
National Academy of Engineering and Board of Energy & Environmental Systems; “The Hydrogen
Economy: Opportunities, Costs, Barriers and R&D Needs 2004”; National Academy Press, March 2004.
Canadian Hydrogen
August 2004
Page 2.4
costly. Despite the fact that hydrogen pipeline design and operation is relatively straight forward,
there remains a surplus awaiting links with appropriate demand requirements.
2.2.2
Hydrogen Use and Supply in Canada – 2003
The actual consumption of hydrogen in Canada equals the production of 3,089 thousand tonnes
less the surplus of 196 thousand tonnes, for a total use of 2,893 thousands tonnes. The 100
thousand t/y of hydrogen generated from coke ovens has not been included in the inventory as
recovery in not practical at this time.
Each sector of the hydrogen industries makes greater or less efficient use of the hydrogen
produced or available. The sector differences are shown in Table 2.1 – 1. For example, the oil
refinery sector uses virtually all the hydrogen made within the facilities and consequently shows
no surplus. The same is true of the chemical industry that uses hydrogen as a feedstock; it makes
only what it needs unless markets have changed significantly leaving the facility with surplus
hydrogen production capacity that can be contracted out. On the other hand, the chemical
industry by-product sector generates hydrogen that is not of direct use to the facility. The byproduct hydrogen may or may not be developed as part of an integrated chemical complex
maximizing the use of hydrogen. In most cases some complementary chemical industries have
been constructed nearby, and/or pipelines constructed to move the surplus hydrogen to other
independent but nearby users. Compatible products include ammonia, hydrochloric acid and
hydrogen peroxide. Alberta, Ontario, Quebec and New Brunswick chemical by-product producers
have made these links in some cases. Nonetheless, the surplus hydrogen volumes in Western
and Eastern Regions exceed, by a wide margin, the demand by such complimentary industries.
Hydrogen production as either on-purpose for direct use by the producer, or as by-product of the
producers process appears to have been an easy technological and economic choice in Canada
over the past 20 years. This choice has been primarily due to the fact that both fossil fuels and
electric power have been competitively priced compared to the world market. Consequently
Canada abounds in hydrogen. Unfortunately for maximum economic use, some of the resulting
excess hydrogen produced is not near enough to potential users and is used as fuel or vented.
The Canadian production of hydrogen by Region is displayed in the Figures 2.2 – 1. The figure
shows that hydrogen capacity in Canada is dominated by Western Region production. The large
investment in capacity in the West is a reflection of:
•
relatively low cost and abundant natural gas which has been the cheapest in Canada,
and remains competitive in North America,
•
crude oil has been abundant in the Western Canadian Sedimentary Basin (WCSB); all of
which is within the Region. The WCSB happens to contain the oil sands; a heavy
bituminous oil deposit that rivals the reserves of Saudi Arabia
Nature and geology have provided a range of complementary feedstocks for refined oil products,
petrochemicals, and synthetic crude oil (SCO) that have been the core of industrial growth for
primarily Alberta, and to a lesser extent British Columbia and Saskatchewan.
Canadian Hydrogen
August 2004
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th
For perspective, the relative capacity in the Eastern Region is about 1/5 of the Western capacity,
and the Atlantic Region is about ¼ of the Eastern Region. Capacity to supply has not been an
issue, as feedstock costs have remained competitive for many years.
Capacity by Region and Sector
The sector information is displayed in Figures 2.2.2 – 1, 2 and 3. The figures show the relative
capacity of the principal production sectors of oil refining, heavy oil upgrading, chemical Industry,
chemical industry by-product, and merchant and fuel in each Region. The details are set out in
Appendix A.
Western Canadian production by sector is dominated by the heavy oil upgrading and chemical
industries infrastructure of natural gas reformers and those primary petrochemical process plants
that produce hydrogen as a by-product.
Western Region-Capacity - 2003
Oil Refining
463,000
0 198,270
Heavy Oil Upgrading
Chemical Industry
770,000
Chemical Industry Byproduct
912,900
Merchant Gas
Table 2.2.2 – 1 Canadian Western Region Hydrogen Capacity - 2003
The total capacity is 2.3 millions t/y and the current production is 2.2 million tonnes. The slightly
lower production reflects a combination of new equipment not fully on stream, and some
reduction in agricultural and forest product production. The latter industries are respectively the
principal users of the fertilizer and chlor-alkali products. As detailed in Appendix A, the Western
Canadian Region is made up of:
•
6 oil refineries; 4 - Alberta, 1 - British Columbia, 1 – Saskatchewan
•
4 heavy oil upgrading plants; 2 – Ft McMurray, I – Lloydminster, 1 Ft. Saskatchewan
•
14 chemical process use; 7 ammonia and fertilizer related, 6 chemical products
•
14 chemical process by-product; 2 ethylene, 11 chlor-alkali products
The region currently generates about 174 thousands t/y of surplus hydrogen.
The largest and longest hydrogen pipeline in Canada is located east of Edmonton and is
sometimes referred to as the Praxair Hydrogen Pipeline. The line was built and is operated by
the merchant gas company Praxair Canada Inc., and has been in operation since 1996. The
original pipeline is approx. 52 km long and is predominantly 20 cm (8 inch) diameter. It operates
at a nominal pressure of 55 bar (800 psig) with a design capacity of ~200 t/d. The line is currently
Canadian Hydrogen
August 2004
Page 2.6
carrying about 80 t/d of purified hydrogen from Praxair’s PSA plant at the Celanese methanol
facility in east Edmonton. The pipeline runs from Edmonton through the county of Strathcona to
Fort Saskatchewan and on to the Redwater area. The line is used by Dow Chemicals and Shell
Canada for chemical production and oil refining. Praxair has recently extended this line approx.
3.5 km southward towards the main refinery area in east Edmonton. Long term petrochemical
development along the pipeline corridor is expected to increase to have the line at capacity in the
next 10 years.
Eastern Canadian production by sector is dominated by the oil-refining sector that represents
about 60% of the hydrogen capacity and production.
Eastern Region Capacity - 2003
16,700
Oil Refining
72,000
Chemical Industry
74,075
437,362
Merchant Gas
Table 2.2.2 – 2 Canadian Eastern Region Hydrogen Capacity – 2003
Hydrogen production in the Eastern Region is dominated by the requirements of the crude oil
refining. The petrochemical process plants that generate on-purpose hydrogen and by-product
hydrogen together form about 25 % of the total. The total capacity is 600 thousand t/y and the
current production is 598 thousand t/y. The small difference between capacities is a result of
slight reductions in the demand for chemicals and may also result from operator reported
production estimates as opposed to the nameplate capacity data that is usually public
information. As detailed in Appendix A, the Eastern Canadian Region is made up of:
•
8 oil refineries; 5 - Ontario, 3 Quebec (Ultramar/Valero at Levis is the second largest in
Canada)
•
3 chemical process use; 1 chemical products, 1 vegetable oil hydrogenation, 1 ammonia
fertilizer plant
•
14 chemical process by-product; 4 ethylene/styrene/xylene, 7 chlor-alkali products, and
the 3 steel company coke ovens in the Hamilton and Sault St. Marie ON
•
1 facility for for steel annealing in Hamilton, ON operated by Air Liquide
The region currently generates about 22 thousand t/y of surplus hydrogen, not including the
future potential of hydrogen recovery from coke ovens which offers an additional 100 thousand
t/y.
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August 2004
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There is one 2 km long hydrogen pipeline located in Becancour, Quebec that connects the PCI
Chemicals chlor-alkali plant’s by-product hydrogen production with Atofina’s hydrogen-peroxide
plant and Air Liquide’s hydrogen liquefaction plant also in Becancour. A second hydrogen pipeline
exists at Varennes between the chemical complexes of Petromont, Shelll and others. This line
crosses the St. Lawrence River. The network is estimated to be about 10 kms in total.
Atlantic Region production by sector is dominated by the oil refining sector that represents
about 99% of the hydrogen capacity and production in the region.
Altlantic Region Capaccity - 2003
2,690
0
0
Oil Refining
Chemical Industry
Merchant Gas
222,000
Table 2.2.2 - 3 Canadian Atlantic Region Hydrogen Capacity – 2003
The region’s hydrogen production capacity is 225 thousand t/y and the actual production is the
same. The fact that the two numbers are the same primarily reflects that fact that the dominant
refinery section produces only what it needs. Optimum refinery operation is often based upon
steady full operation, keeping operating costs low and steady and selling product at the level that
the market will bear. A steady export market assures regular demand. Only market gluts, where
there is no ability to sell at any reasonable price, will cause a reduction in plant production. The
region’s hydrogen producers are listed in Appendix D and are summarized as:
•
3 oil refineries; I Nova Scotia, 1 New Brunswick, and 1 Newfoundland
•
Chemical by-product; 2 chlor-alkali, both in New Brunswick
The two chlor-alkali plants are unique in Canada in that each is fully integrated with an attached
hydrochloride acid plant that consumes all the by-product hydrogen. The Atlantic Region has no
surplus hydrogen.
Canadian Hydrogen
August 2004
Page 2.8
2.3
Canadian Hydrogen Surplus – 2003
The term surplus has been given to that volume of hydrogen production that could be purified as
industrial, commercial or in the future consumer hydrogen. It is presently either used for furnace
fuel or vented to the atmosphere. As mentioned earlier in this section the current Canadian
surplus is about 200 thousand tonnes per year.
The use of hydrogen as a furnace fuel does have the environmental advantage; in most cases it
of replaces natural gas with a carbon-free fuel. Substitution of the hydrogen used as fuel in any
specific facility will result in the increasing the user facility’s carbon output and could in some
cases possibly put the facility out side its permitted limit. With that caveat only, higher economic
use could be made of the surplus hydrogen in virtually every case, if there is an appropriate enduser.
At this time, all the surplus hydrogen in Canada is either a by-product from the ethylene extraction
process or from the chlor-alkali electrolyzer process. The potential of hydrogen recovery from
coking operations was unsuccessfully attempted by Dofasco and was abandoned after several
year because of the extremely complex particulate clean-up necessary and the wide variability of
the off-gas content due to coal varition and process demand. The hydrogen by-product gas are
characterized at follows:
Typical gas compositions for the major hydrogen by-product sources
Ethylene typical ethane cracker off-gas:
Hydrogen 85 - 90%
Methane 10 to 15%
Ethylene - ppm trace
Ethane - ppm trace
Carbon Monoxide - <1 %
Typical exhaust pressure - ~80 psia
Chlor-Alkali typical off-gas composition as percent dry-weight:
Hydrogen 99%
Inert gases - <1 %
CO - ppm trace
CO2 - ppm trace
SO2 - ppm trace
N2 or perhaps NH3 - ppm trace
O2 - ppm trace but can be up to 5%
Cl or HCL - ppm trace or perhaps up to 1%
Typical exhaust pressure – atmospheric
Note: Moisture content of the by-product gas is up to 29.9% wet-weight
Typical coking off-gas as a percent of dry weight is:
Hydrogen 55%
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August 2004
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Methane 25%
Nitrogen 10%
CO/CO2 9%
Other hydrocarbons 2%
Note: Moisture content is about 50% wet-weight, and a range of contaminants such as tar
vapour, ammonia, hydrogen sulfide, naphthas.
Existing separation and purification technology can readily clean up the fist two by-product
streams to high purity or with cryogenic cooling to very high purity suitable for electronic chip
manufacture. Clean up of coke oven off-gas has not been successfully done. The chlor-alkali by
product hydrogen typically requires only drying and minor purification. Although it is has the
advantage of being relatively pure, the need to compress the chlor-alkali by-product hydrogen
from atmospheric to a working pressure is a significant cost factor especially as most user
processes require compression to at least 10 atmospheres.
Given the above description, it is important to note that all “surplus” hydrogen is not the same.
The actual value of the hydrogen to an end-user will depend upon some of all of the following
factors.
•
The gas pressure is low or at ambient levels. Compression, especially from atmospheric
level is costly,
•
The gas mixture may contain contaminants that are adverse to existing purification
technologies, some refinery purge gases contain large quantities of sulphur. Coking offgas is the extreme version of the contaminant issue.
•
Transportation costs from source to end-user are excessive.
•
Reliability of supply from the source facility may not meet the demands for the same
degree of “up-time” as that of the prospective end-user,
•
The output volume from the source may vary considerably over daily or seasonal
intervals and be inconsistent with the requirements of the prospective end-user.
It may appear that there is substantial waste occurring in the limited use of the excess hydrogen,
yet there are various factors that come into play to determine if hydrogen available at a specific
location is a more cost-effective feed stock than production dedicated or on-purpose hydrogen.
Unquestionably the increasing value of hydrogen will begin the process of more complete
utilization. The numerous, semi-urban, locations of many chlor-alkali plants could offer an
economically attractive source for limited quantities of hydrogen, especially during the early
stages of FCV availability. The advantage of these sources is that, with the exception of the
Maritimes, chlor-alkali plants are conveniently scattered across Canada, near most major urban
areas.
Significant amounts of hydrogen are lost through process inefficiencies in collecting and
purifying syngas. The “surplus” amounts presented in this report do not include the hydrogen
lost in exhaust gas from purifiers; typically this will be in the order of 10 to a maximum of 15%.
Nor does it include lean hydrogen off-gases from such refinery processes as fluid catalytic
crackers that may generate off-gas with 10 to 20% hydrogen content. Other process off-gases
Canadian Hydrogen
August 2004
Page 2.10
may have as much as a 40% hydrogen content. The hydrogen wastes streams are typically
added to the “furnace fuel line” of a refinery or chemical process plant and mixed with other
vented gases to form a portion of the plant heating needs.
Dalcor estimates that this lost hydrogen across the entire hydrogen production sector in Canada
amounts to between 350 and 400 thousand t/y. Of this about 50% will be in stream containing
less than 30% hydrogen. The remainder, or 175 to 200 thousand t/y is of sufficient concentration
that current technology and increasing hydrogen value will combine to make recovery of the
feasible. . Hydrogen rich streams that were not considered to be cost-effective to recover in the
past will likely become new hydrogen sources, especially for refineries that are faced with
continually increasing demands for hydrogen. Work in the field of separations in general and
more specifically in adsorbents will push PSA purifiers and alternate technologies to improve
separation efficiency. Improved catalysts, adsorbents and process engineering have the
opportunity to find some big wins.
Process improvements continue to address the level of waste hydrogen in the petrochemical
sector. Improved separation technology is again one of the better opportunities for potential
economic CO2 reduction.
2.4
Canada’s Hydrogen Storage and Transportation Infrastructure – 2003
Storage and transportation of hydrogen in Canada is almost entirely confined to the four major
merchant gas companies, Air Liquide, Air Products and Chemicals, BOC Gases, and Praxair.
These companies’ storage and transportation facilities include equipment that serves Canada as
well as exports to the US.
There is liquid storage at Becancour and Magog, Quebec and at Sarnia, Ontario where
liquefaction plants are located. There are no liquid facilities in the Western or Atlantic Regions
however the economics of liquid transport allow competitive trucking to the east and west coasts.
The estimated total storage volume in the three liquid facilities is 50 tonnes/day. About 90% of
the merchant hydrogen produced in Canada is shipped to the US.
Compressed hydrogen storage facilities are located in 5 locations across Canada where
hydrogen is produced and/or purified by a merchant gas company. Excess hydrogen is often
purchased from adjacent chemical product plants. Compressed hydrogen is purified and
compressed for delivery by tube-trailer at Becancour, Magog, Sarnia and Hamilton in the Eastern
Region, as well as at Joffre and Edmonton, Alberta. There is no compressed hydrogen storage in
the Atlantic region.
Transportation of liquid hydrogen is by truck trailer units holding from 1.5 - 3 tonnes per trailer.
Industry experts indicate that there are about 6 liquid hydrogen trailer units operating in Canada
for Canadian use and about 45 more that are associated with significant export to the US.
Compressed hydrogen is transported in “tube-trailers”. As the economic cost of transporting
compressed hydrogen limits the distance traveled the total volume of compressed hydrogen is
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August 2004
Page 2.11
much less than the amount transported in the liquid form. Tube-trailers carry about 125 – 300 kg
of hydrogen each. There is an estimated 100 – 150 tube-trailers operating in Canada. Ontario
Hydro also operates a small fleet of tube-trailers to service the companies several large
generating stations.
2.5
Positioning for the Hydrogen Economy
Canada produces large amounts of hydrogen for the industrial sector but relatively little for the
commercial or light industries sector. This situation reflects the fact that Canada has a shallow
depth in secondary and tertiary manufacturing. In contrast with the US and Europe, Canada has
a very undeveloped hydrogen transportation infrastructure primarily for this reason. Consequently
this infrastructure will form as the country’s metals, electronics and plastics industries mature.
Canada continues to import a large percentage of products that arise from processes that use
hydrogen such as: float-glass (window glass), advanced metal products (stainless steel), and
electronic chips. Until population density increases it is unlikely that there will be a significant shift
in the nature of manufacturing, as the market base does not justify establishing facilities when
importation from the EU, US and Far East is more economic.
Growth and industrial diversification will continue to occur and the associated hydrogen
infrastructure will develop as needed. The technology for this is generally available and advanced
in aspects of hydrogen infrastructure are more likely to be acquired by Canada from abroad as
others will be challenged for new technology before Canada will be.
In the meantime, Canadian expertise will focus on hydrogen production, separation and
sequestration technologies. There will global demand for the country’s hydrogen-based products
as well as expertise in the technology areas mentioned above.
Canadian Hydrogen
August 2004
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3.
HYDROGEN IN CANADA’S FUTURE
3.1
Influencing factors
Dalcor has been asked to consider the nature of Canadian hydrogen demand over the next 10
and 20 years. Scenarios are the reasonable approach to assessing the nature of the hydrogen
sector in 2013 and 2023, conveying the nature of how national, international, resource availability
and climatic change may influence Canada’s hydrogen industry.
In the context of this study we must ask the question: “What are the factors that could impact the
hydrogen production and demand balance within the next twenty years, and how may they play
out?”
The coarse answer is that hydrogen’s future will be shaped by three factors:
1. the relative prices of various energy resources
2. government shaping of market forces (international or national regulations, treaties,
mandates, fiscal intervention in the market, etc.)
3. relative economic and environmental performance of different technology pathways
Supply
Demand
Biomass
Fossil fuels
Chemicals
Hydrogen
Fuel
Electricity
Solar, wind,
hydro,
geothermal
Manufacturing
Nuclear
Addressing these in turn:
Price of Energy
Firstly, it is important to point out that the emphasis is on price rather than cost. Price is what is
factored into economic decision-making, whereas economics does not yet means of accounting
for all components of cost.
Canadian Hydrogen
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Page 3.1
Oil, because of its global prominence and ubiquity, represents a benchmark for most other forms
of energy. Oil price directly impacts the cost of the world’s transportation fuels, and any
contender in this area must compete against oil.
Oil’s importance to the North American economy cannot be overstated, and its continued ready
availability at prices similar to today becomes a cornerstone of all US government official
projections based on a supposed significant expansion of world oil production in the future due to
the application of advanced oil production technology. In its 2004 Annual Energy outlook, the
Energy Information Agency projects average world oil price will decline to $23.30 per barrel (2002
dollars) in 2005. It then rises slowly to $27.00 per barrel by 2025, largely due to the impact of
higher projected world oil demand. This reflects effectively level pricing. Price as of mid-April
2004 are in the $37–38 range.
However, there has been a growing debate concerning the direction of future global oil
production.
Declining resource base
Prominent international petroleum geologists express the view that world oil production
31
will peak in the not too distant future, possibly before 2010 . The counter argument
favoured by the US DOE and American Petroleum Association is that improved finding
and extraction technologies will increase the reserve base, and that oil production will not
peak until 2035.
The arguments are extensive and detailed. It is not the task of this study to settle on any
particular position, but to highlight the uncertainties and demonstrate that there are
various plausible alternative energy futures.
US oil production in the lower 48 states peaked in 1972 and has been in decline ever
since. Similar declines are apparent in numerous other major basins. This is true in
Canada’s Western Sedimentary Basin, where a decline in conventional oil production is
now evident, although increased output of non-upgraded bitumen and synthetic crude
(crude oil which has been upgraded from raw bitumen) from oil sands has compensated
for this shortfall in conventional supplies.
The rapid decline of major fields appears to exist in many producing basins around the
world and must be considered in long-term supply forecasts. Yet a review of various price
forecasts indicates that there is a prevalent sentiment of business-as-usual. Substantial
new supply will emerge out of Russia (already now equalling Saudi oil production), but
•
31
L.F. Ivanhoe, "Updated Hubbert Curves analyze world oil supply," World Oil, November 1996, pp. 91-94.
C.J. Campbell and J.H. Laherrere, "The End of Cheap Oil," Scientific American, March 1998, pp. 78-83.
J.H. Laherrere, "World oil supply-what goes up must come down, but when will it peak?," Oil & Gas
Journal, February 1, 1999, pp. 57-64.
Canadian Hydrogen
August 2004
Page 3.2
will not replace the declining basins. The oil sands contain large amounts of reserves,
but are high cost and are low ‘net energy’ producers (i.e. high energy costs of extraction).
New frontiers will be explored, but these are by definition high cost producing areas.
Meanwhile world oil consumption continues to increase, and in the United States is
expected to rise from 19.7 million barrels per day in 2000 to 26.7 million barrels per day
in 2020, a 35% increase (EIA Annual Energy Outlook 2002). The US now imports ~59%
of its oil (2001) and the trend continues. China’s rapidly expanding economy is having a
powerful effect on oil demand worldwide. In 2003-4 China will likely account for onethird of the increase in global oil demand. It has now surpassed Japan as the second
largest user of petroleum in the world. The IEA projects that Chinese demand for oil will
double by 2010.
Geopolitical factors
A host of uncertainties surrounding global political stability, particularly in oil producing
regions, also places uncertainty as to continued ready access to supplies. Major western
oil importing countries are particularly vulnerable to disruptions. Access to secure and
reliable energy supplies is a core factor in maintaining economic growth – an issue that is
very well understood by the US Administration.
While a tightening oil supply is a key factor impacting price, global demand will increase
substantially, driven by the newly industrializing countries (notably China and India). Together,
these factors create a valid argument for a substantially higher oil price than today.
Natural gas, for economic reasons, has been and is the overwhelming choice of feedstock for
hydrogen. The economics of hydrogen production and its viability as a chemical feedstock - or as
a fuel - therefore hinges very closely on the price of natural gas.
Natural gas has replaced oil in many energy applications as supply, and the delivery
infrastructure have increased. It has been a favoured fuel because of its clean burning
characteristics replacing oil in many industrial and power generating facilities. To date, North
America has been self-sufficient in supply, and there are expectations of new supply from coal
bed methane, and also from conventional production in the Arctic, as well as offshore Canada
(east and west coasts). These ‘frontier regions’ call for higher cost exploration and development,
with higher costs involved in moving the gas to market.
North American demand continues to increase, and may well require imports in the form of LNG to
maintain adequate supply. The US Energy Information Agency projects that offshore imports will
increase from ~0.2 Tcf in 2001 to 2.5 Tcf in 2025 (~8% of US forecast US consumption). Arctic gas
could be a significant source of supply, competing on the delivered cost to market. An Alaska line
would provide 4 billion cubic feet per day by 2013, with about another 1 billion cubic feet coming from
Canadian Hydrogen
August 2004
Page 3.3
the Mackenzie Delta32. Benefits would include reduction of dependence on imports, security of
domestic supplies and reduction of price volatility.
The EIA’s 2004 Annual Energy Outlook states that it now believes that net imports of LNG will
exceed net gas imports from Canada by 2015. The "primary reason" for this change was the
"significant downward reassessment by the Canadian National Energy Board of expected natural
gas production in Canada,"
LNG has recently become a more viable source of future natural gas supply because of the vast
extent of world natural gas resources and the significant decline in LNG costs in all segments of
the supply chain. If sufficient North American LNG import capacity existed, LNG imports could
potentially play an important swing supply role in the gas market. LNG could moderate price
increases by increasing spot cargos of LNG during periods of high prices and conversely
moderate price declines by reducing spot cargos during periods of low prices. The US would
need to add a further 4 or 5 import terminals to the 4 already operating.
Concerns about the near-term decline of natural gas production are not nearly as strident as
those about oil. The reserve base is large and more widespread than oil, but it should be noted
that as North America’s demand exceeds its own supply, it becomes increasingly vulnerable to
geopolitical factors that could impact supply. Again this raises issues of security of supply in what
currently appears to be an increasingly risky world.
The natural gas industry will continue to have unpredictable price swings, caused by cycles on
investments in supply and random external events. Such swings impose major risks on large,
costly supply projects that require long lead times, such as LNG terminals or a pipeline from the
arctic and favours investments in conventional onshore natural gas supplies. Price swings can
also obscure the value of high-efficiency consumer appliances and alter the financial viability of
large industrial projects where fuel costs dominate operating costs. If supply costs increase
substantially, large chemical plants using natural gas feedstock have the option of relocating to
regions of the world where lower gas prices are found. In the longer term, however, and with
international trade in LNG, natural gas prices may be more consistent worldwide. The US Energy
Information Agency (EIA) projects average delivered LNG costs of about $3.80 per Mcf,
fluctuating with supply and demand pressures. The price of natural gas varies by location
(distance from source) and by customer type. Figure 3.1 below captures the range of various
“wellhead” gas price forecasts out to 2025. Delivered prices can be 1.5
>3 times the wellhead
price, depending on customer type and location due to transportation and distribution costs:
•
32
Testimony to the US Senate Committee by Testimony of Mary H. Novak, Managing Director, Energy
Services, Energy Insight. March 19, 2003
Canadian Hydrogen
August 2004
Page 3.4
Figure 3.1-1:
Gas Price Forecasts (Wellhead price in 2004 US$/GJ)
$6.5
$6.0
$5.0
US DOE
McDaniels
$4.5
PIRA
$4.0
CERA Turmoil
CERA Technology
$3.5
$3.0
$2.5
$2.0
20
01
20
02
20
03
20
04
20
05
20
06
20
07
20
08
20
09
20
10
20
11
20
12
20
13
20
14
20
15
20
16
20
17
20
18
20
19
20
20
20
21
20
22
20
23
20
24
20
25
US$/GJ Wellhead
$5.5
Time
Government actions
Government policy is perhaps the most important and influential of the factors impacting price,
and the importance of regulations, tax and other fiscal measures in influencing a so-called “free”
market, cannot be overemphasized. These policies will be shaped primarily by the economic
interests of the country (often reflecting lobbying from industry), but also by public opinion about
environmental issues and by international agreements (NAFTA, Kyoto, etc.).
While few doubt that there will indeed be a hydrogen economy in the long term, the routes to get
there are unclear. Debate about the ‘optimum pathway’ is only now beginning, and relying on
market forces alone may not steer us down that pathway. Government intervention, then, in the
form of shaping markets may be necessary to nudge the economy in the ‘preferred’ direction.
Governments may choose to intervene in the markets for a variety of reasons; for example,
stimulate or maintain local and regional production, protect local businesses, effect environmental
improvements, or to encourage the development of new technologies. Intervening to encourage
a hydrogen economy for environmental or other reasons is not a stretch.
The triggers to such major government intervention in the marketplace may well be environmental
concerns, whether centered on local air quality or on global issues. The Canadian and US
governments show less inclination to intervene in shaping markets (aspects of protectionism
aside) than European and, particularly, Asian governments. It is worthy of comment that new
markets for hydrogen could be shaped elsewhere before they occur in North America helped in
large part by firm government influence on the markets.
Canadian Hydrogen
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Technology
Technological progress continues mostly in incremental improvements, though occasionally some
unexpected breakthrough takes place that establishes a new paradigm. An example of such a
breakthrough would be the influence of information technology on today’s world which, twenty
years ago, would have been hard to envisage.
In the energy field, we can predict continuing efficiency improvements in the known energy
technologies (production, storage, transport, & conversion). The question we must ponder is: is
there potential for a major new energy technology (or technologies) becoming commercial in the
timeframe of this study, and what influence will it have on the existing physical and business
infrastructure.
Decarbonization technologies are arriving on the scene as scientists and engineers begin to
assemble a coherent view of combustion, energy efficiency and reduced GHG outputs.
Combustion of fossil fuel produces heat, incurs inefficiencies to delivery electricity, and diluted
CO2 must be collected and sequestered if climatic concerns are to be addressed. Internal
decarbonization processes generate and consume hydrogen produce some heat and electricity
directly and deliver a concentrated stream of sequesterable CO2. System efficiency is superior to
the conventional combustion approach. The basic process incorporates a combined cycle of
gasification to high temperature fuel cells (MCFC or SOFC) to generate electricity, pure hydrogen
if desired for possible transportation use, and CO2 as the system exhaust gas, The concept is
widely embraced by energy and combustion scientists around the world. Canadian companies in
the high temperature fuel cell business, QuestAir Technologies with process technology, coal
gasifier concepts such as Zeca in Calgary and advanced process engineering work at several
Canadian universities are currently developing practical approaches to decarbonization
technology.
Nuclear energy, which has been out of favour for many years, may be set to reemerge as an
answer to concerns about CO2 production from the burning of fossil fuels. The concerns about
long-term disposal of high-level radioactive waste, and about security issues, may be eclipsed by
its growing attraction as a solution to GHG production. The favoured base-loading of nuclear
power plants could work in favour of electrolytic hydrogen production and in the future possibly
high temperature dissociation of water. Because of lead time, nuclear energy is not expected to
figure prominently on the Canadian scene within the next decade, but could be a larger
contributor within twenty years.
One emerging area of enormous potential is nanotechnology. While the base science is only now
being explored, nanotechnology could have a significant impact on the energy business within a
twenty year time period. The technology deals with materials science and will impact the very
nature of materials behaviour, fabrication techniques, etc. In the energy sector its impact may be
felt in many areas, including energy storage, power transmission, and fuel cell design and
performance. While it is difficult to predict the nature and timing of such impact, they could be
very significant.
Canadian Hydrogen
August 2004
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The challenges of storing and transporting hydrogen are major obstacles to its wider market
acceptance. Higher pressure storage has mixed benefits: the energy density is higher, but
comes at the expense of considerable energy input. New storage technologies (e.g. nanoadsorbents, energy-recovery devices) could be a major enabler to hydrogen using technologies
and are plausible within both the ten and twenty year time frame.
It is quite plausible to believe that, within this study’s time frame, fuel cell technology will advance
to successfully compete with and begin to steadily displace combustion-based energy converters.
The degree to which this occurs depends upon the degree of economic advantage the new
technology possesses.
The next ponderable is what percentage of these fuel cells will use hydrogen, and if so, how is it
supplied. The likelihood is that the vast majority of mobile applications will use PEM cells
requiring hydrogen or, possibly, methanol. However, as introduction of PEMFCs is delayed there
is increased prospect for hybrid vehicles with SOFCs as the energy source. At this time it is most
likely that stationary devices (SOFC & MCFC) will likely be fuelled with natural gas and gasified
products from heavy oils and coal. The success of the fuel cells in displacing the internal
combustion (i/c) engine is key to any forecast, although the actually impact on hydrogen
production in Canada over the next 20 years will be comparatively minimal.
The energy delivery systems in North America – from raw resource to consumer - are the result
of trillions of dollars of capital investment with lifetimes of 25+ years being common. This
represents a massive inertia to change and presents a significant obstacle to new technologies or
systems that may be developed, even if they have economic advantages.
Discounting a major paradigm shift in our energy thinking caused, maybe, by a series of
environmental catastrophes it is unlikely that we will see a wholesale replacement of this
infrastructure within the twenty-year study horizon.
The “inertia” argument applies to a lesser extent with end-use fuel using technologies, notably the
vehicular sector where hydrogen may find application, where vehicle lifetimes may be 10 – 15
years.
3.2
Hydrogen Uses in Canada
As described elsewhere in this report, Canada is the world’s largest per capita producer of
hydrogen by a considerable margin. Hydrogen will continue to be used as a bulk chemical
feedstock in the production of such commodities as methanol and ammonia, and also in certain
manufacturing processes. However, the major new area of potential lies in its use as an energy
carrier. The question is how big a market may this be relative to today’s industrial markets?
With the exception of the more than 100,000 t/y of surplus hydrogen used as industrial furnace
fuel, hydrogen’s use as an advanced fuel is presently miniscule relative to its use as a bulk
Canadian Hydrogen
August 2004
Page 3.7
chemical. With aggressive expansion into the fuel market, the proportion of hydrogen used in this
manner would not be out of proportion to today’s industrial production of hydrogen. Although it is
an unrealistic scenario, if all the ~17 million passenger vehicles registered in Canada today were
FCVs running on hydrogen it would require an approximate doubling of Canada’s current
hydrogen production. For comparison, if all passenger vehicles on the US were fuelled with
hydrogen, the US would need a ten to twelve fold increase in hydrogen production capacity.
How this hydrogen fuel market may develop is of considerable interest to this study. As an
energy carrier, hydrogen will compete with oil and natural gas. Its success as a fuel depends on
whether it provides significant advantages of the systems in place.
One certainty is that fuel choice will continue to be an economic decision, based on total
operational costs. Energy cost is just one input. The primary factors influencing decision are
shown below:
Fuel price
Fuel
availability
Operational
logistics
FUEL CHOICE
Price
modifiers:
(taxes,
regulations,
incentives,
etc.)
Cost, availability & efficiency of
conversion technologies
Again, the issues of relative energy price, government actions and technology come into play.
Our scenarios must consider different futures with these factors in mind.
3.3
Scenario’s to 2023: Descriptions and Rationale:
There is no certain picture of the future, and forecasting is a risky business. This is especially so
today because the extent of the macro issues of geopolitics, climate change, resource depletion
and technology development combine to present a depth and complexity perhaps greater than
that we have ever faced before.
Canadian Hydrogen
August 2004
Page 3.8
33
Some well-reported scenarios on our energy future make interesting reading, and there is a
remarkable divergence of views reflecting their base assumptions. We have considered selecting
some scenarios from this existing work, but decided to separately generate three scenarios for
this study.
While these capture many of the dynamics that others factor into their pictures of the future, it has
been our intent to keep the story simple for the purposes of this work which are, inter alia, to
develop hydrogen demand forecasts to 2023.
We anticipate that within the time frame of this study, under each of the three scenarios
developed here:
a “free market” economy endures
worldwide economic growth continues
fossil fuels continue to dominate global energy supply
In summary the three developed scenarios are:
1.
Soldiering On
A ‘business as usual’ outlook with no major upheavals or surprises
Incremental improvements in existing technologies
No “breakthrough” technology emerges that displaces systems in place
North America continues to have unfettered access to global oil and gas gradually at an
increasing price.
US government maintains a supply-driven philosophy
2.
Carbon Conscious Agenda
Triggered by real or perceived catastrophic global impact from GHGs
Kyoto-focused environmental agenda
Nuclear positive environment, driving its re-acceptance
Legislation to encourage a “carbon neutral” economy
Significant government intervention in shaping energy markets
Widespread focus on energy efficiencies to reduce demand
Clean renewable energy sources such as solar, tide and wind are given priority
3.
Hydrogen Priority Path
Triggered by push for North American energy self-sufficiency
Re-emergence of nuclear power, accepted as ‘solution’ to hydrogen supply
Fuel cell centric
•
33
NRCan’s “Energy Technology Futures”; NEB’s “Canada’s Energy Future: Scenarios for supply & demand
to 2020”, 2003”; Shell International’s “Energy Needs, Choices & Possibilities to 2050”, 2001; ExxonMobil’s
“Report on Energy Trends, Greenhouse Gas Emissions & Alternative Energy”, Feb 2004
Canadian Hydrogen
August 2004
Page 3.9
Energy pricing reflecting all elements of cost (e.g. environmental costs, resource
depletion, etc.)
There is a further picture of the future that may be regarded as an “extreme” scenario of
abrupt climate change triggering massive population movement, changes in agriculture and
34
economy, and political upheaval . This possible picture of our future has been developed by
a leading international scenario development team and suggests that there would be major
geopolitical changes resulting in an epic paradigm shift. Dalcor has decided to omit this
scenario from this report, as its implications are too extreme to assess in this report.
Scenario 1: Soldiering On
Energy Resources:
North American energy reserves will be bolstered by frontier exploration and development
(offshore east and west coasts of Canada, Arctic, coalbed methane), though imports of both
oil and gas will increase. Energy costs will rise slowly, but steadily, reflecting increased E&P
expenses and the costs of bringing the products to market.
Global production will continue to adequately meet demand, despite increasing demand
pressures from China. No extreme changes in geopolitics to disrupt international oil and gas
market. Oil and gas prices will remain relatively steady in real terms.
Coal, because of its lower cost, could regain some of the share lost to gas especially in the
power generation sector. Nuclear remains out of favour.
Government policy:
Governments will not intervene overtly in the supply-demand balance, except potentially by
means of some “tweaking”. North America maintains its ‘supply side psyche’, and meanwhile
governments will continue to endorse demand management but do little of substance to
actively encourage it.
Concerns about ‘global warming’ are not widely embraced by government, except to maintain
the encouragement of voluntary efforts to reduce CO2 output.
Technology Factors:
•
Incremental improvements of existing technology will continue, but no significant new
breakthroughs seen that could fundamentally change the present pattern of supply and use
of energy. Transportation technology continues to focus on the i/c engine, with performance
34
“An Abrupt Climate Change and it’s implications for US National Security”, Peter Schwartz & Doug
Randall, Oct 2003
Canadian Hydrogen
August 2004
Page 3.10
improvements by means of hybrid systems, and perhaps a greater range of fuel including
35,36
bioethanol, etc. Modest presence of FC vehicles by ~2015
regional markets.
in slowly expanding niche and
Scenario 2: Carbon Conscious Agenda
Energy Resources:
North American natural gas and oil reserves will continue their already established decline,
and so drive exploration and production into frontier areas with consequently higher finding
and production costs. Technology will serve to facilitate in bringing this energy to market,
and ameliorate costs to some extent, but the inherently higher costs of geography and
climate will be hard to overcome.
International energy market operates with few interruptions, but tighter supply/demand
balance drives oil and gas prices well above historical levels. Increasing LNG supplies
contribute somewhat to meet North American demand, but there is public resistance and
consequent delay in constructing import terminals.
Higher costs and more volatility due to uncertainties about the timing and cost of new
supplies stimulate much greater focus on demand management.
Government policy:
Recognition that frequent and common catastrophes are the result of anthropogenic
climate change; impact becomes widespread through increased insurance costs and
calls for government to “do something” become strident. Governments respond to
growing public concerns with powerful market interventionist mandates and regulations
(such as carbon taxes), which drive consumers to use cleaner fuels.
Kyoto Protocol is embraced somewhat enthusiastically by government, and with qualified
support of business. Much emphasis on reducing CO2 production and sequestration
practiced with consequent higher energy delivery costs. Carbon taxes and carbon trading
change the economics of energy systems. Stimulation of nuclear generation.
Technology Factors:
Higher energy costs result in major developments in energy efficiency. Hybrid vehicle
technology become the norm, and i/c engine maintains market dominance not only because it
has least implications on fuelling infrastructure, but also lowest well wheel CO2 contributor.
•
35
Morgan Stanley. Equity research on Ballard (Oct 2003): FCVs introduced model year 2010-2011
36
National Academy of Engineering, The Hydrogen Economy: Opportunities,Costs, Barriers, and R&D
Needs (2004): FCVs introduced commercially at earliest by 2015
Canadian Hydrogen
August 2004
Page 3.11
Gradual emergence of gaseous fuelled (natural gas
transition of gaseous fuelling stations.
hythane
H2) i/c engines as
FCVs initially not able to compete effectively with improved i/c-hybrid engines, and not
appearing in showrooms until near 2020 when they finally compete successfully on cost and
performance. By this time SOFC hybrid vehicles may be a contender for the most efficient
and cost-effective motive power.
Much focus on CO2 sequestration. Growing public acceptance enables nuclear to make a
new appearance in Canada by mid 2010s, with greater impact by mid 2020s.
Hydrogen Priority Path
Energy Resources:
With global unrest continuing, world oil supplies are under threat. US in particular has
growing concern about security of supply, and levies greater taxes on gasoline to encourage
switch to more fuel efficient vehicles. This will accelerate the development of hybrid vehicles,
and may usher in selected market opportunities for alternatively fuelled vehicles. Much focus
on continental energy resources (Canada’s oil sands and natural gas).
New sources of conventional hydrocarbons continue to be found, but at steeply higher
development and transportation costs. These new economics now allow development of
certain higher cost energy hydrocarbon sources, such as methane hydrates (though perhaps
later in the century), but also improve the viability of renewable power sources (tidal, wave,
wind, biomass).
Changing public acceptance, due reality of energy supply tension, allows nuclear energy to
figure much more prominently in a low carbon future, though it cannot make much impact
until well into the second decade.
Government policy:
National security of supply concerns cause developed world governments to intervene more
forcefully in energy markets by way of fuel taxes or levies to stimulate demand management,
and to encourage the development of gaseous transportation fuels.
Natural gas and gasified fossil fuels and biomass serve as a bridge fuel towards hydrogen,
enabling a gaseous fueling infrastructure. Government will encourage CO2 sequestration and
the development of nuclear generation with concerted cooperation with US, EU and
Japanese for development of practical means for high temperature dissociation of water.
Technology Factors
Canadian Hydrogen
August 2004
Page 3.12
The economic viability of ‘clean energy’ technologies will be boosted as conventional energy
costs are driven higher by increasing supply costs and new taxes.
Fuel cell vehicles creep into early fleet use by 2010-12, where the economics of centralized
refueling is positive. Fuel cells show performance and cost advantages over i/c engines by
2015. FCVs taking early market share as passenger vehicles in 2015-18 period, and growing
presence as the refueling infrastructure grows. FC vehicles become mainstream by 2025.
PEM technology continues to dominate the mobile fuel cell market, requiring high purity
hydrogen to be widely available. SOFC hybrid engines become attractive options to power
heavy duty, long-haul transport trucks.
Hydrogen storage materials and fuel cell technology will advance (through positive impact of
nanotechnology) and become more economically effective.
Canadian Hydrogen
August 2004
Page 3.13
4.
OIL REFINING IN CANADA: 2013 & 2023
4.1
Market Evolution & Demand
4.1.1
General Trends
The 17 oil refineries presently operating in Canada are expected to remain and slowly expand
capacity over the next 20 years. The present total capacity is 270,000 m3/day or 1,700,000
barrels/day. Refined oil as an energy source in Canada is expected to increase by about 42%
37
over the next 25 years according to the NEB report Canada’s Energy Future “soldiering on”
case. In considerable contrast, the net demand increase will be only 3% for the 25 years under
the “Techno-Vert” scenario of conservation, significant improvements in technology, and reduced
GHG output. The latter scenario does indicate that there will a continued steady growth at about
1.5% per year for then next 10 to 15 years until fuel cell vehicles and other technology and capital
equipment investments come on-stream. After that period demand will drop to almost the current
level of refining capacity. The average rate of expansion under the two NEB scenarios does not
vary much until after 2013. In no case do scenarios by the NEB or Dalcor suggest that demand
will drop below current levels of refinery production.
The demand for refinery hydrogen will also increase. However, this increase will not be at the
same rates. The key factors that will influence hydrogen demand are:
•
Increased refinery capacity requires increase crude processing
•
Constraints on availability of light crude will result in greater use of heavy crude that
requires disproportionately more hydrogen to refine.
•
Likely improvements in catalysts and general process technology will enable refineries to
stretch hydrogen within the plant, i.e. make more and use less to achieve the desired
range of refined products,
•
Continued tightening of specifications for gasoline and automotive diesel, requiring
reduction of trace components notably sulphur but also toxics, volatile organic chemicals,
and oxygen content.
The two most significant factors creating increased hydrogen demand over the next 20 years are
use of heavier crude and progressively tighter specifications of fuel quality. The reduced
availability of the world and North American light crude supply will require the use of heavier and
sour crude oil feedstock. Heavier hydrocarbons and increased sulphur content each push up the
amount of process hydrogen required. Two factors dominate:
1
Light crude reserves are diminishing. In North America, this trend is especially
pronounced. New sources may be found but there is no evidence that a find is at hand.
North American energy security is closely tied to making more use of continental crude
oil. For example light crude supplied from the Middle East to Canadian eastern refineries
•
37
National Energy Board, Canada’s Energy Future – Scenarios for Supply and Demand to 2025,
July 2003, Ottawa
Canadian Hydrogen
August 2004
Page 4.1
and US eastern refineries could be cut off entirely. In such as case, the use of heavier
crude would increase dramatically.
2
The expectation is that gasoline and diesel fuels will be improved in steps to improve air
quality. Environmental legislation mandating cleaner gasoline and diesel fuels are to be
in-place for gasoline by 2005 and diesel by 2007. These changes are not expected to be
the last changes in specifications between now and 2023.
4.1.2 Hydrogen Demand 2013 and 2023: The estimated percentage increases in hydrogen
demand for the 2013 and 2023 period for Canadian refineries are set out in Table 4.1.2 – 1
below:
Projected Rates of Increase 2013 & 2023 in Canadian Oil Refinery Demand for
Hydrogen - (From base year of 2003)
2013
2023
(%)
(%)
- Capacity increase
13
21
- spec & quality related
15
25
- capacity increase
13
15
- spec. & quality related
15
25
Scenario/Source
Soldiering On (SO)
Carbon Conscious (CCA)
Hydrogen Priority (HPP)
- capacity increase
10
5
- spec. & quality related
15
25
Table 4.1-1
Projected Rates of Increase 2013 & 2023 in Canadian Oil Refinery
Demand for Hydrogen - (From base year of 2003)
It is important to note that the percentages shown above reflect change from 2003. The various
percentage changes are intended to reflect the range of factors discussed in earlier. The
capacity increase shown for the HPP scenario was set at 5% as opposed to the NEB estimate of
3% because the NEB’s “Techno-Vert” scenario estimate implied and earlier and more dramatic
increase in the use of FCV’s by 2023 than Dalcor’s projections indicate.
38
One US estimate , presented in 2002, suggests a steeper growth rate over the next number of
years. This report states that; “The U.S. for on-purpose hydrogen will continue to increase by 510% per year, depending on the extent of implementation of the 1990 U.S. Clean Air Act
Amendments (CAAA) and other proposed environmental legislation”. Dalcor has chosen to lower
this range to 3 – 4% based upon the situation here in Canada, as much because specifications
are national and the steep rate suggested by the authors appears to reflect the California regional
•
38
M. Khorram, T. Swaty , Oil and Gas Journal, Nov 25, 2002
Canadian Hydrogen
August 2004
Page 4.2
standards. These impose more stringent gasoline and diesel trace components levels than most
other states.
HYDROGEN (T/Y)
OIL REFINERY HYDROGEN DEMAND SCENARIOS 2013 & 2023
1,300,000
1,250,000
1,200,000
1,150,000
1,100,000
1,050,000
1,000,000
950,000
900,000
850,000
800,000
Soldiering
On
Carbon
Conscious
Agenda
Hydrogen
Priority
Pathway
2003
2013
YEARS
2023
Figure 4.1.2-1 Canadian Oil Refinery Hydrogen Demand Scenarios – 2013 & 2023
The combined results of the two change factors in the three scenarios are displayed in Figure
4.1.2 – 1 Canadian Oil Refinery Hydrogen Demand Scenarios – 2013 & 2023. The curves show
very little difference over the first ten years, but diverge by 250,000 to 400,000 t/y by 2023
reflecting the range of expected to increase by the end of the period.
In the US, demand for diesel desulphurization, residuals upgrading, high-sulfur crude processing,
and reformulated gasoline production is projected to result in a 11.5 million t/y increase in onpurpose hydrogen demand. This amount reflects a tripling of Dalcor’s projections when compared
to total Canada versus US refinery capacity. The total Canadian refinery capacity is about 1.7
million barrels/day versus a US total of 16.7 million barrels/day. The US estimate projects new
hydrogen demand over “a longer term” while this study horizon is 2023 or 20 years. If we assume
that the intervals are about the same, then US projection reflects 0.69-tonnes/ year of capacity for
every barrel of refinery capacity, whereas, the projection in this report for Canada is 0.25,
considerably lower.
There are some reasons to expect a difference in projected requirements. These include a higher
percentage of heavy crude processed in the US, a larger percentage demand in the US for light
refined products such as gasoline, and future estimates of more restrictive US specifications than
in Canada. The difference in the two estimates should be investigated in more detail.
Canadian Hydrogen
August 2004
Page 4.3
The relatively small differences among the three Dalcor scenarios over the first 10 year period to
2013 is primarily due to the fact that the technology-impact of improved processes and changes
in consumer demand take time to be in place. The oil refining business is a highly competitive,
commodity market. Capital investments are massive and new technology is less eagerly
accepted than in the more “frontier” sector of heavy oil upgrading.
The large sunk-capital base and relatively low profitability of the refinery business means that
capital improvements are very carefully considered. As long established facilities, refineries are
usually confined plant areas. The direct capital cost implications are high because of the higher
construction cost associated with the confined construction sites as well as the fact that rapid
adoption of new changes frequently results in equipment replacement before the end its
economic life. Unlike the heavy oil sector where most of the new demand for hydrogen will result
from facilities yet to be built, the oil refining sector is unlikely to see any entirely new plants
constructed over the next 20 years.
Western, Eastern and Atlantic Region refinery demand factors are each somewhat a different.
However, the majority of the factors appear to balance sufficiently that this study does not
attribute different loading factors to each region. The Western refineries will expand capacity to
meet regional demand and possibly increase market share of exported refined oil products due to
marginally more competitive feedstock and natural gas prices. These six refineries will also
convert more of their processes to accommodate bitumen blend, essentially heavy crude. Heavy
crude was not common when the refineries were built and process changes will be needed as oil
sands bitumen becomes widely available. There will be no surplus hydrogen generated at any of
the facilities.
Eastern Region refineries in Ontario will to increase capacity and will likely draw more light crude
from Newfoundland, as availability of Western Sedimentary Basin light crude will have dropped
considerably by 2023. Quebec based refineries will unlikely have a pipeline connection to the
West so will continue to rely upon Newfoundland light crude and a range of heavier and light
crude from South America and the Middle East. The Atlantic Region refineries will continue to rely
upon ocean tanker supplies from Newfoundland and abroad as pipeline supply is not practical.
The amount of increase in capacity will depend upon price competitiveness with other North
American east coast refineries. At this time there is no reason to believe that Irving Oil, in St.
John, NB and the Atlantic Refinery in Come-by-Chance, will not remain competitive and will
therefore expand to meet growing demands for the next 10 years. As with other refineries, by
2023 there could be a drop in demand as hydrogen based FCVs become used, especially on the
US east coast.
4.2
Oil Refinery Hydrogen Supply Capability
The need for additional hydrogen to meet Canadian refinery needs is well understood within the
industry. It does not have the high visibility of hydrogen needs for the heavy oil upgrading
associated with exploiting the reserves of the Alberta oil sands. This is likely due to the relatively
smaller amount of new hydrogen needed and partly because the crude oil refining process offers
the opportunity to obtain a significant amount of hydrogen from within the existing processes.
Canadian Hydrogen
August 2004
Page 4.4
Unfortunately, the percentage of internally generated hydrogen from process off-gas and purge
gas is reduced as the ratio of light crude and heavy crude feedstock reduces.
Refinery studies have shown that the option of extracting only internally generated hydrogen from
the process requires more costly low-sulfur crude feedstock than if external hydrogen is added. In
other words, if a refinery’s processes are optimized for only internal hydrogen production as the
source for achieving the spectrum of refined products, adding externally generated hydrogen will
significantly reduce the amount of lower-cost feedstock consumed. Table 4.2.1–1: Refinery
39
Products – Impact of Externally Generated Hydrogen, is from a recent US study of a refinery
upgrading to meet 2005 gasoline specifications. The table displays the amount of feedstock that
would be used to generate the equivalent volume of product mix, and meeting the 2005
specifications for refined gasoline products. One option uses a relatively small, dedicated
hydrogen facility with a capacity of 6 MMscf/day (about 5,600 tonnes/year) and the other relies
only upon the internally-generated hydrogen from purges and off-gas.
InternalProcess
Hydrogen
Dedicated
Hydrogen
Arabian Light - $22/bbl
90,275
41,016
Brent Sweet Crude - $25.3/bbl
4,725
53,984
Isobutane - $24.5/bbl
2,275
3,244
2,655
2,382
Total Cost of Materials ($US)
5,540
2,298,600
2,456,600
Pre-change (2003) material costs ($US)
2,281,600
MTBE - $47.0/bbl
!"#$%
&
LPG
3,929
5,939
Unleaded Premium
3,310
10,857
Unleaded Regular
26,250
21,714
RFG Regular
13,163
21,714
RFG Premium
6,543
0
18,840
20,865
No.2 Fuel Oil
4,460
5,216
1% Fuel Oil
9,759
1,894
3% Fuel Oil
9,627
7,898
Diesel
Coke
Total Product for Sale ($US)
Total Value of Product for Sale ($US)
'
($US)
-' .
.
3,584
2,165
99,465
2,708,000
(%)*(%%
98,262
2,837,000
+,%*(%%
!,#"+
Table 4.2.1 - 1 Refinery Products – Impact of Externally Generated Hydrogen
•
39
40
40
M. Khorram, T. Swaty , Oil and Gas Journal, Nov. 25, 2002
ibid
Canadian Hydrogen
August 2004
Page 4.5
The comparison shows the significant difference in the amount of expensive, low sulphur,
feedstock (Brent Crude) that would be required to maintain an equal product volume under each
option for hydrogen supply. The estimated cost of hydrogen from a dedicated facility is $US 2.50
per million standard cubic feet (MMscf), while the value of the hydrogen is $US 8.23 per MMscf. It
is interesting to note that the addition of sweet crude delivers more higher value products the
increased raw material costs more than offset the increased revenue.
In the short term, additional hydrogen will come from newer and established technology,
improved catalysts, and improved process optimization and control. Experience has shown that
process optimization through energy conservation measures, process optimization, and state-ofthe-art process control technologies and software in refineries often result in finding opportunities
for increasing the available hydrogen. Hydrogen that is otherwise flared, used in plant furnaces,
or lost in residual products can be recovered to some degree. Sub-optimal operation and
practices waste not only valuable hydrogen, but also some light hydrocarbons.
Fuel gas streams must be treated in a gas processing and separations unit in order to recover
hydrogen. A complex refinery can have as many as 50 sources of fuel gas, all supplied into the
refinery fuel header. These sources contain varying concentrations of hydrogen, methane,
ethane, propane, and higher hydrocarbons, including small concentrations of aromatics
Industry experts suggest that additional external hydrogen will be required in virtually all of
Canada’s refineries, if not to meet 2004 specification changes most certainly those for 2007.
There are several process engineering software companies such in Canada which have
development and field engineering groups to service the refinery sector. Together with
experienced process engineers, these state-of-the-art process optimization models and process
control systems can model an existing refinery and optimize hydrogen production and
consumption to achieve the desired refined product mix. The amount of external hydrogen
needed, if any, can then be calculated.
If, after internal refinery optimization, more hydrogen is required the options are limited to one of:
•
Purchase and pipeline from a compatible current producer with surplus hydrogen
•
Build and operate a dedicated SMR or similar, hydrogen generation and purification
system.
•
Contract the hydrogen supply to a separate entity (usually a merchant gas company)
Surplus hydrogen from convenient facilities is often not suitable for refineries due to incompatible
requirement for high levels of refinery “up time” and for other factors presented and discussed in
Section 2.1.2. There may be certain circumstance where sufficient lower value light liquid fuels
are available to make a partial–oxidation reformer cost-effective. There are few, if any, partial
oxidation reformers used in Canada.
A number of US, European, and now Japanese companies, offer turnkey, state–of-the-art SMR
and POX systems complete with purifiers. Multi-bed pressure swing adsorption units will recover
Canadian Hydrogen
August 2004
Page 4.6
between 80 and 85 % of the hydrogen generated. Natural gas is available, and can be expected
to be available and economic in the short term for Canadian refineries. SMR hydrogen will likely
be the preferred choice until long-term contracted natural gas prices reach beyond $6 -7 per GJ.
Technologies are underway to meet the needs for alternate, ‘big-hydrogen’ sources.
To meet the largest hydrogen demands in the longer-term, the technology needed can be
grouped into four main areas:
•
steam methane reforming improvements; at this time there is an urgent need for
incremental improvements to deliver more hydrogen per volume of natural gas; items for
attention are improved catalysts, more heat efficient mechanical design and improved
process control.
•
gasification of residuals must be demonstrated as cost-effective and reliable. There is a
considerable body of knowledge on gasifiers, especially coal, from South Africa’s
experience with oil embargos. Although gasifiers are not new technology, the
requirements of increased plant capacity and quality of hydrogen output will have to be
both demonstrated. Leading suppliers of gasifier technology are Chevron Texaco, Lurgi,
ConocoPhilips (now General Electric), and Shell; each has devoted considerable effort to
have alternate source of a suitable syngas from which hydrogen can be concentrated.
It is important to note that gasification of heavy or solid hydrocarbons carries with it the
burden of substantially increased CO2 per tonne of hydrogen produced.
•
Gas separation technology improvements are essential in the short and medium term.
Items of opportunity include:
o Increase the present 85 – 90% extraction efficiency from SMR syngas
o improve selectivity of trace components
o reduce capital costs for CO2 extraction technology
•
nuclear power related technology, may be a cost-effective, high capacity heat source in
the longer term. In the near term, low temperature electrolysis with off-peak power is
possible with scale-up of electrolytic cells. With the possible exception of high
temperature electrolysis these technologies are improbable prior to 2023.
o dedicated electric power for high temperature electrolysis, and
o dedicated high temperature thermal dissociation of water to produce hydrogen
and oxygen, in due course.
There is a growing trend for some specialized users of hydrogen to contract-out the supply to an
over-the-fence contractor that designs, constructs, owns and operates the hydrogen facility. A
suitable long-term contract gives extended assurance of a minimum rate of hydrogen supply at a
negotiated price. The oil refiner is free of the considerable capital investment, and the operation
of a relatively specialized facility. Recent announcements to this effect in Canada are:
Canadian Hydrogen
August 2004
Page 4.7
•
Air Products Canada Ltd. will construct a 70,000t/y (71 MMscfd) hydrogen production
plant adjacent Petro-Canada's 135,000 b/d refinery in Edmonton. This represents the first
arm’s length, dedicated facility, and hydrogen supply arrangement with a Canadian
refinery. The hydrogen and steam generating facility, to be owned and operated by Air
Products is expected to be on stream in April 2006. A second Air Products owned
hydrogen facility of similar size is anticipated to meet growing regional petrochemical
industry
demand.
•
Air Products Canada Ltd will construct a 75,000 t/y hydrogen facility in Sarnia, ON to
supply Suncor Energy and Shell Canada process plants in the city. The hydrogen plant is
expected to be onstream mid-2006.
Praxair, another merchant gas company, has provided large volumes of hydrogen for several
years with its Strathcona area pipeline. The hydrogen is purchased by Praxair, purified and piped
to the end users. At this time. no new hydrogen is generated by Praxair owned facilities
associated with the pipeline. The pipeline was built with capacity to meet anticipated
petrochemical industry growth in the region over the next 10 to 15 years and may link into the
planned new Air Products SMR’s in due course.
4.3
Implications for Oil Refinery Hydrogen
New external sources of hydrogen for Canadian refineries are key to meeting the needs for
present and future refined oil products. The planning and technology options are more or less
straightforward. For the next 5 – 10 years, there will be little choice but to rely upon natural gas
as the principal feedstock for any necessary external hydrogen requirements. If necessary the
costs of natural gas for the two Maritimes refineries may be stabilized by imported LNG within 5
to 8 years. If an LNG terminal were located on the St. Lawrence River, some gas price stability
would be available for Montreal refineries.
As described in the following section of this report, the urgency for cost-effective big hydrogen
production dominates the Alberta oil sands bitumen upgrading program. The successes and
benefits of the increased hydrogen production technology for heavy oil upgrading will flow over to
the refinery sector. As natural gas prices increase, so too will the economic viability of coal-based
gasifiers. Coal is readily available throughout Western Canada, the Maritimes and could be
shipped by rail or ocean vessel to refinery location in Central Canada. Coal gasifier technology,
provided by such companies as SASOL of South Africa, is now a relatively mature technology.
.
Canadian Hydrogen
August 2004
Page 4.8
5.
OIL SANDS UPGRADING IN CANADA: 2013 & 2023
Alberta’s oil sands are becoming ever more important as the North American demand for crude
oil starts to recognize the value of these enormous deposits. This report focuses on the various
development plans, the nature of the product process insofar as hydrogen is concerned, the
amount and possible sources of this hydrogen, and the scope of CO2 associated with the
41
hydrogen production .
5.1
Market Evolution and Demand
5.1.1
Current Oil Sands Development Projects
There are presently two operating mine/upgraders, 8 in-situ operations, and two upgrader plants
producing ~ 1 million barrels a day (bpd) of bitumen. About 6 projects are under construction,
and a further 15 projects in the Fort McMurray region, 3 in the Cold Lake region, 2 in the Peace
River region, and 1 new upgrader in the Edmonton area either approved or awaiting approval.
Table 5.1 – 1 below summarizes most of the projects that are in operation, under construction or
in the approval process as of December 2003, according to the Alberta Chamber of Resources.
The list changes frequently and updates are available from the Chamber.
Table 5.1 – 1 Major Current and Approved Oil Sands Projects
Fort McMurray Area
Organization
Project
Type
Status
Syncrude
Syncrude
260K bpd
In production
Suncor
Steepbank Mine and
Millennium
225K bpd
In production
Encana
Christina Lake
10K bpd
79K bpd
Completed
Shell Canada
Muskeg River
70 K bpd
Preliminary
Jackpine Mine
100K bpd
Preliminary
•
41
There are several reports that provide in-depth background on current oil sands development and many of
the technical issues associated with the development. These are “Oil Sands Technology Roadmap”;
Unlocking the Potential”, Alberta Chamber of Resources, January 2004; Canada’s Energy Future: Scenarios
for Supply and Demand to 2025, National Energy Board, July 2003, and “Overview of Canada’s Oil Sands”
TD Securities, January 2004. The last of these is included as a perspective on the funding of the billions
necessary to make the development vision happen. More recently, “Oil Sands Update”, Alberta Economic
Development, March 2004, has been issued. This document sets out the current status of producing and
approved projects, describes the economic, labour and permitting issues surrounding the development
program, and sends out warning that natural gas supplies may not sustain the vision set out only a few
months earlier.
Canadian Hydrogen
August 2004
Page 5.1
Petrobank Energy
Whitesands Pilot
Approval obtained
February 2004
JACOS
Hangingstone
10K bpd
Pilot project
ConocoPhillips
Surmont
100K bpd
Approval obtained May
2003
Petro-Canada
MacKay River
30K bpd
In production
Meadow Creek
80K bpd
Application filed
Devon Energy
Corporation
Jackfish
35K bpd
Approval submitted 2003
True North Energy
Fort Hills
190K+ bpd
EUB approval 2002 Project
deferred
Canadian Natural
Resources
Horizon
100K bpd
later phase 270K bpd
Approval obtained 2004
70 bpd
Approval obtained 2003
OPTI Canada and
Nexen
Synenco Energy
Northern Lights
100K bpd
Disclosed Sept 2002
Deer Creek Energy
Joslyn, Phase 1
600 bpd
Under construction
Imperial Oil
Kearl
100Kbpd to 200Kbpd
Announced Nov 2003
Husky Energy
Sunrise Thermal Project
50K bpd increasing to
200K bpd.
Application in 2004-2005
Cold Lake Area
Imperial Oil
BlackRock Ventures
Canadian Natural
Resources Ltd.
Encana
Husky Energy
Mahkeses
30K bpd
Completed 2003
Nabiye/Mahihkan
30K bpd
Application filed
Orion EOR
20K bpd
Application August 2001
Primrose/Wolf Lake
Expansion
40K bpd
Producing 35K bpd
Foster Creek
25-30K bpd
Foster Creek Expansion
50K bpd
Application filed
Tucker Project
30K bpd
Application filed 2003
Currently producing 30K
bpd
Peace River Area
Shell
BlackRock Ventures
Peace River
9K bpd
Company reviewing
options
Seal
16K bpd
Current production 8K bpd
Other
Shell
Scotford Upgrader
UPGRADER 155K bpd
Commenced June 2003
Petro-Canada
Strathcona refinery
conversion
UPGRADER 53K bpd
Increase total to 135K bpd
Husky Energy
Lloydminster upgrader
UPGRADER 82K bpd
Production to 77K bpd
Alberta Heartland
Upgrader
UPGRADER IN 150K bpd
Assessment filed 2003
BA Energy
Canadian Hydrogen
August 2004
Page 5.2
5.1.2
Background:
This section covers planning for development of the Alberta oil sands, and the associated
demand for hydrogen. There is now widespread recognition in Alberta and abroad that:
1) recovery and refining of the oil sands is practical at the current and expected future prices
of crude oil provided that natural gas prices in Western Canada roughly track those of oil.
3
2) there is about 50 billion m of recoverable crude oil in these deposits, more than in any
other country in the world, including Saudi Arabia. At an international level, the
International Energy Agency and the US Department of Energy each identify the oil
sands as a primary energy source for the next 30 years.
Current production of bitumen from the Alberta oil sands is now at about 1 million barrels or about
3
3
3
160,000 m (1 m = 6.3 barrels). This amount is a combination of about 100,000 m of synthetic
3
crude oil (SCO), and about 60,000 m of bitumen for blending. The two products are based upon
the same bitumen extracted from the deposit. The difference is that SCO is upgraded to a light
crude quality and can be used in many oil refineries. Bitumen blend is a mix of the natural
extracted material from the deposit, blended with 30 to 50% light liquid hydrocarbons. The liquids
used are often stripped from natural gas production and reduce the bitumen viscosity to make a
“pipelineable” heavy crude that is sold primarily to mid-West US refineries. These refineries have
traditionally processed heavy of crude oils such as those from Venezuela and can accommodate
some volume of bitumen blend. The large quantities of coke produced as a by-product of heavy
crude processing is used as fuel, primarily by thermal power and cement plants in the mid-West
and eastern US.
Hydrogen demand in the oil sands is created by production of the higher value SCO. At present
the four operating heavy oil upgraders in Alberta consume about 700,000 t/y of hydrogen.
Development plans for the oil sands currently vary considerably. The largest difference in
perspective is between the 2003 NEB view and the 2004 Alberta and TD Bank view. A summary
of the various views is shown in Fig. 5.1 – 1 below.
Canadian Hydrogen
August 2004
Page 5.3
SCO & BITUMEN BLEND
(M3/day)
OIL SANDS - ALTERNATE LONG-TERM
DEVELOPMENT SCENARIOS
1,000,000
800,000
NEB - "bau"
NEB - "TV"
ALBERTA
TD BANK
600,000
400,000
200,000
0
2003
2013
2023
2033
YEARS
Fig. 5.1–1 Oil Sands – Alternate Long-term Development Scenarios. (from reports 2003 and
2004 of the listed agencies)
3
The dominant vision is from Alberta and suggests about 800,000 m (5 million barrels) of SCO
and bitumen mix by 2030. This level of production is described in the Alberta Resources and TD
Bank scenarios. The National Energy Board is more conservative and projects about 460,000 m3
by 2025, a figure well below that of the Alberta vision. The NEB report considers two scenarios of
development. One is business as usual (BAU), and the other is termed "Techno-Vert" (TV) that
reflects a more carbon conscious society. The latter scenario considers greater emphasis on
GHG production and sequestration than the business as usual scenario. There is a relatively
small difference between the two NEB scenarios as is shown later in Table 5.2 – 1.
For perspective, the estimated hydrogen production required for the Alberta Chamber of
Resources plan is about 4.5 million t/y, while that of the NEB is about 2.6 million t/y. The TD Bank
scenario shows a much steeper rate of increase. This may be due partially to numerical
differences in conversion figures for diluting the bitumen to “bitumen-blend”, as the amount of
diluent used varies from 30 –50%.
The hydrogen requirements of the various scenarios depends to a great deal upon the amount of
upgrading that is done prior to selling the bitumen. The SCO captures a much higher value than
does bitumen mix that sells at a steep discount from light crude oil. In an effort to capture more
value from the resource, the oil sands developers, Alberta and Canada will attempt to upgrade
the maximum amount of bitumen that the market will take.
Canadian Hydrogen
August 2004
Page 5.4
To this end, the Alberta vision suggests that by 2012 of a total of 320,000 t/d, about 240,000 t/d
will be SCO and 25% will be shipped as bitumen mix. By 2030 the ratio is down to 20%.
The upgrading process can be achieved in two ways, or by a combination of both.
•
The “coking” processes heats and cracks (breaks down the longer hydrocarbon chains)
and then takes the existing hydrogen in the bitumen and re-allocates it to lighter fraction
to produce a lighter crude, a SCO. Solid coke and some minor asphaltic materials
remain and must be used or disposed of. In Alberta the Suncor plant primarily uses this
process and disposes of the coke in the previously mined oil sand pits.
•
The “hydrocracking” process heats and cracks the bitumen and then adds additional
hydrogen to make more SCO from the same amount of bitumen. The current hydrogen
requirements are about 1000 scf of hydrogen to 1 barrel of SCO. The Shell Canada –
Albion upgrader uses hydrocracking only. Syncrude and the Husky Oil upgraders
incorporate a combination of hydrocracking and coking and achieve a higher quality SCO
a than that from Albion.
The net effect is that the requirements for hydrogen are substantial, under even modest
expectations of oil sands development. It should be noted that from a global resource and GHG
perspective there is not much difference between the minimal hydrogen requirements of coking
and alternate SCO upgrading process. Ultimately the crude oil is refined and steel mills will use
coking coal rather than oil sands coke residuals.
5.1.3
Hydrogen Demand Scenarios
The projected demands for hydrogen production in the oil sands sector are a direct function of the
actual rate of development. As well, hydrogen demand will reflect the extent to which the
producer companies can command the market and retain a significant share of the potential value
from upgrading. Upgrading can be taken to several levels, each requiring more hydrogen. The Oil
Sands Technology Road Map states that hydrogen demand will increase from 1000 scf/barrel to
as much as 1800 scf/barrel. This prospect that will almost double the amount currently consumed
to make an entry-grade SCO.
The range of possible bitumen production rates is shown in Table 5.1–2 below. The rates
assumed in this study for upgrading volumes in 2013 and 2023 are based on the projections from
the various interest groups as indicated.
Canadian Hydrogen
August 2004
Page 5.5
ESTIMATED DAILY PRODUCTION OF SYNTHETIC CRUDE OIL
(Soldiering On Case)
SCO Production (t/d)
Current SCO production
100,000 (~ 630 thousand b/d)
SCO 2013 (TD Securities)
350,000
SCO 2013 (NEB est.)
200,000
SCO 2013 (Oil Sands Roadmap)
260,000
Assumed SCO production for 2013
250,000 (~ 1,5 million b/d)
SCO 2023 (TD Securities)
no projection
SCO 2023 (NEB est.)
315,000
SCO 2023 (Oil Sands Roadmap)
480,000
Assumed SCO production for 2023
410,000 (~ 2.6 million b/d)
Table 5.1-2 Estimated daily production of SCO (SO case)
The volumes of SCO indicated above form the basis for projections of hydrogen consumption
under the three scenarios of Soldiering On (SO), Carbon Conscious Agenda (CCA), and
Hydrogen Priority Pathway (HPP). In each scenario SCO production volumes vary, resulting in
different hydrogen demand scenarios. These are shown in Figure 5.1-2 below. The increased
demand for higher quality SCO is reflected by increasing the consumption of hydrogen from 1000
scf/b today, to 1200 scf/bbl by 2013 and to 1400 scf/bbl by 2023. Although there is a suggestion
that hydrogen consumption could reach 1800 scf/b it is most likely that older facilities will not be
able to accommodate the associated process requirements and/or cannot justify the additional
capital cost of SMR or gasifier generated hydrogen.
Canadian Hydrogen
August 2004
Page 5.6
OIL SANDS HYDROGEN DEMAND - SCENARIOS
2013 & 2023
HYDROGEN (T/Y)
4,000,000
Soldiering
On
3,500,000
3,000,000
2,500,000
Carbon
Conscious
Agenda
2,000,000
1,500,000
1,000,000
Hydrogen
Priority
Pathway
500,000
0
2003
2013
2023
YEARS
Fig 5.1-2 Oil Sands H2 – Scenarios 2003, 2013 and 2023
The hydrogen requirements in 2003 under the three scenarios range from about 3.6 million t/y for
the SO case and only 2.3 million t/y for the HPP case. Refined oil products are expected to
continue to increase at the estimated 1.5% per year, and the costs associated with CO2 reduction
and sequestration do not materially effect the present competitiveness of bitumen recovery and
upgrading to SCO. The production volumes used for the analysis in the report are midway
between the estimates of Alberta, the TD Bank and those of the NEB. Should these higher growth
rate development plans come to fruition, the total amount or hydrogen required for SCO
production will be increase from 3.6 million to 4.2 million t/y. To again put that number in
perspective, Canada would require 5.2 million t/y of hydrogen in 2023 if every passenger vehicle
in the country was a PEM FCV.
Both the CCA and HPP scenarios show lower oil sands production by 2023 compared to the SO
scenario. The CCA scenario is about 2.7 million t/y and the HPP at 2.3 million t/y of hydrogen.
These volumes reflect reductions of about 1.0 million and 1.2 million t/y of hydrogen respectively.
The causes for the projected reductions have some common aspects. The cost of increased
GHG abatement and containment will make the bitumen recovery and the upgrading more costly.
Further, general consumer consciousness of GHG impacts, and the urge to contribute to reducing
overall transportation fuel use, will reduce the size and the average annual distance traveled by
vehicles. The rate of demand for refined oil products will decease.
In the case of the HPP scenario, FCV use will reach the level where liquid fuel consumption will
drop reducing further the demand for refined oil products. The hydrogen for these FCVs is
expected to be generated by natural gas or electricity and not with onboard reformers requiring
gasoline or similar oil based products.
Canadian Hydrogen
August 2004
Page 5.7
5.2
Hydrogen Supply Capability – Oil Sands Options
The enormous quantities of hydrogen required for any of the oil sand scenarios is well recognized
by all those generally familiar with bitumen upgrading. The principal focus of the document “Oil
Sands Technology Road Map; Unlocking the Potential” is to address the range of technical issues
that will help to create “internally sufficient” recovery and upgrading of oil sands bitumen. This is a
significant technical task that scientists and engineers are addressing in Canada, the US and
Europe. The fact is that there are too many diverse technical issues to be investigated to give
good estimates about how long it will take to achieve “internal sufficiency”.
For
short-term
planning
purposes,
today’s
“..business as usual consumption (of
technology will need to fulfill the majority of supply
natural gas) for expanded oil sands
production,
will
lead
to
an
requirements. However, there is one important
unsustainable dependence on natural
caveat: if natural gas continues to be the prime
gas well before 2030, and perhaps as
syngas source there is growing evidence of
early as 2015. Even today’s operators
may need to retrofit for alternatives
hydrogen production costs that will be unacceptable.
beyond 2010”
At this time there is good evidence that there is
Oil Sands Technology Road Map Update
insufficient natural gas within the Western Canadian
March 2004
Sedimentary Basin to meet the continuing
requirements of the growing bitumen recovery and
upgrading without seriously impacting the price of natural gas in Western Canada. Natural gas
from the Alaska and NWT will very likely be required for both industry and governments
acknowledge the potential demand and the limited immediate solutions.
To meet future hydrogen demands with new options the contributing technologies needed can be
grouped into four main groups:
•
steam methane reforming improvements; at this time there is an urgent need for
incremental improvements to deliver more hydrogen per volume of natural gas; such
items as improved catalysts, more heat efficient mechanical design and improved
process control are items for attention
•
gasification of residuals must be demonstrated as cost-effective and reliable; this
prospect is a key component of Opti Canada/Nexen’s Long Lake oil sands production
and upgrader project due to start in 2007. For the first time upgrading hydrogen will be
supplied by a gasifier that uses the aphaltics residuals from initial treatment of the
bitumen. Although gasifiers are not new technology, the requirements of increased plant
capacity and quality of hydrogen output will have to be both demonstrated. The
Omni/Nexen project is relatively modest in size with as first phase of 11,000 m3/d
(70,000 b/d).
Closely associated with residuals gasification is coal gasifier development that could
enable another alternative to high value natural gas. There are no immediate plans for a
full-scale demonstration plant.
Canadian Hydrogen
August 2004
Page 5.8
•
gas separation technology improvements are essential in the medium term. Focus on:
o increasing the present 85 – 90% extraction efficiency from SMR syngas
o improving selectivity/reducing sensitivity to some trace components of gasifier
syngas;
o reducing capital costs for CO2 extraction technology to concentrate process
generated CO2
•
nuclear power related technology, may be a cost-effective, high capacity heat source in
the longer term. Studies by Alberta and AECL are underway for
o underground bitumen recovery (currently steam assisted gravity drainage
(SAGD) is mostly natural gas based),
o dedicated electric power for low temperature electrolysis, and in due course,
possibly heat for high temperature electrolysis and thermal dissociation of water
to produce hydrogen and oxygen.
In conclusion, hydrogen production, dedicated to large users such as bitumen upgrading, must
reflect the lowest costs of hydrogen production achievable by available technology. Hydrogen
supply by current technology may be impacted by lack of competitively priced natural gas. By
2008, gasifiers will begin to demonstrate hydrogen supply independence and the natural gas link
may be broken.
5.3
There is some prospect that large volume hydrogen production technology will not stay abreast of
demand for upgraded bitumen. The strategic challenge will then be to decide if bitumen
production should be withheld until technology is able to produce cost-effective hydrogen,
sufficient to enable upgrading at the targeted scale.
The challenge of producing large quantities of cost-competitive hydrogen with a substantially
lowered GHG footprint is great, yet successfully meeting this challenge will make Canada a preeminent player in hydrogen technology. The timing of the oil sands hydrogen needs could not be
better. Driven by an urgent need, Canada and indeed the world will have a full-scale opportunity
to meet the necessity of producing "big hydrogen". The production scale will match the needs
associated with the complete hydrogen conversion of passenger vehicles; that is to say, 5 million
t/y in Canada, 100 million t/y in the US and about 30 million t/y in Europe. No other country in the
world will be pressed into delivering 4 million tonnes of new hydrogen within the next 15 to 20
years.
The oil sands offer the opportunity to develop decarbonization technology as alternate sources of
hydrogen are explored. The co-generation of hydrogen and electricity could deliver two of the
large demand inputs to heavy oil upgrading. There is also the prospect for high temperature
steam delivery for process heat and in-situ thermal recovery of bitumen. Very large-scale high
temperature fuel cells would be required to meet the demands of oil sands applications. However,
Canadian Hydrogen
August 2004
Page 5.9
as the process facilities operate on a continuous base, with virtually no daily variation in demand,
high temperature fuels cells would be working in an ideal demand environment.
The Alberta oil sands offer an unparalleled opportunity for scientists and engineers throughout the
world to deliver incremental and step-jump improvements in technology for big hydrogen
production and CO2 capture and sequestration. The associated opportunities for innovative
transport of both gases also goes with the package of critical new technology needs.
The oil sands offer security of short and medium term energy supply to North America. Canada
has the opportunity to harness the world's best to meet the challenge.
Canadian Hydrogen
August 2004
Page 5.10
6.
CHEMICAL INDUSTRIES IN CANADA: 2013 & 2023
6.1
Market Evolution & Demand
The chemical industries that consume or generate hydrogen serve diverse markets.
Consequently, factors affecting future demand are complex. To address these differences, this
report divides the sector into three groups of chemicals with somewhat similar markets. The
groups are:
•
general petrochemical products (hydrogen consumers): is 90% ammonia, and
methanol, with a few other minor such as hydrogen peroxide and hydrochloric acid.
•
primary petrochemical products (hydrogen producers): ethylene and other related
•
chlor-alkali chemical products (hydrogen producers): chlorine, caustic soda and
sodium chlorate.
The first group, general petrochemical products, is discussed under the demand section of
section 6 as these chemicals consume hydrogen. The other two, primary petrochemicals and
electro-chemical products produce hydrogen. Projections of their possible market evolution are
discussed in the supply section.
Each group’s future growth was considered separately under the three scenarios of ‘Soldiering
On’, ‘Carbon Conscious Agenda’, and ‘Hydrogen Priority Path’. The study assigns specific rates
of growth for each group.
The hydrogen-related chemicals sector is further complicated by the wide range of relative scale
of operation, and the fact that smaller capacity process facilities are numerous and the larger
ones sparsely located.
Within the chemical sector there is a wide range of what is considered “normal scale of
operation”. That is to say that a normal world-class ammonia or methanol plant will consume
upwards of 80 – 100 thousand t/y of hydrogen. Whereas a competitive sized hydrogen peroxide
plant will use only 5 thousand t/y. Similarly a world-scale ethylene plant will generate 50 - 80
thousand t/y of 90% hydrogen gas, and a competitively sized chlor-alkali plant will generate from
2 - 10 thousand t/y. The effect of these differences in scale means the there are opportunities for
clustering hydrogen user industries around the large generator facilities. In contrast, the 20 small
chlor-alkali plants scattered across Canada offer opportunities for convenient local supply of
hydrogen to complimentary industries such as hydrogen peroxide or hydrochloric acid. These
relatively small sources of relatively high purity could also supply early needs for hydrogen fuel.
The markets for these industrial products are varied and scattered, and demand changes are
relatively predictable. An exception is in certain fertilizer markets where domestic supplies may be
trucked or railed directly to local farm supply centres.
Canadian Hydrogen
August 2004
Page 6.1
The markets for the general petrochemical group such as agricultural fertilizers and methanol for
resins and synthetics are moved great distances to Canadian and export customers. Customers
for primary petrochemicals such as ethylene are the downstream secondary and tertiary
synthetics manufacturing plants located in centres such as Sarnia, Ontario and in eastern US
synthetic materials centres. The electrolytic based products, chlorine and caustic soda, are
primarily used in the forest products industry and usually consumed on a local and regional basis.
Projections of long-term demand for this range of chemicals are based upon industry insight
through industry trade journals, web literature and interviews with sales and marketing staff.
The combined total demand for hydrogen to supply the Canadian chemical sector is displayed in
the figure below:
HYDROGEN (T/Y)
CHEMICAL INDUSTRY: TOTAL HYDROGEN DEMAND SCENARIOS 2013 & 2023
2,100,000
Soldiering
On
1,900,000
1,700,000
Carbon
Conscious
Agenda
1,500,000
1,300,000
Hydrogen
Priority
Pathway
1,100,000
900,000
2003
2013
YEARS
2023
Figure 6.1–1 Chemical Industry Sector – Hydrogen Demand: Scenarios to 2013 & 2023
The maximum total volume displayed in 2023 of over 1.7 million t/y does not rival the 3.6 million
t/y associated with the oil sands but is a significant amount. The chemical sector hydrogen
projection is 75% greater than that projected for oil refining sector.
The general petrochemical sector is expected to grow at rates in the order of 3% per year in
the short term under a “soldiering on” scenario, a relatively strong rate that reflects the experience
in Canada for the last decade or more. As upwards of 90% of this sector’s products are exported,
competitiveness in the North American market is essential and will likely remain strong. Canada’s
natural gas prices have always been a bit lower than that of the US. However, recent increases
which now appear to be established for the longer term, may cut into the competitiveness of
Canada’s petrochemical industry, but only if relative prices change against US gas prices.
Canadian Hydrogen
August 2004
Page 6.2
Natural gas prices are expected in the SO scenario to balance over North America as a whole,
consequently short and medium market share will not change much.
The impact of increasing and variable gas prices that may occur may have an impact upon short
term competitiveness within North America of Alberta-based primary chemicals. In the longer
term, certainly the 2013 to 2023 period should find a considerable amount of coal and residuals
fuelled gasifier hydrogen generated and used in Alberta. Hydrogen generated from coal and
heavy oil residuals would currently be a more expensive fuel base than natural gas for the
chemical industry in Western Canada. However, gasified coal and heavy residuals are currently
used as the base for chemicals in several parts of the world. Chemical industry planners believe
that fuels other than natural gas will be significant sources for their industry. The momentum
generated by the technology, operating experience and investment confidence associated with
the swing of heavy oil upgrading to gasifiers should enable Alberta based chemical industries to
maintain their traditional ability to be able to supply at a competitive price.
Recently Canadian methanol production has shown a sharp downturn against the broader
chemical industry sector trend. Much of Western Canada’s methanol production was exported
abroad and global competitiveness is essential. The cost of bulk transport of a liquid - once
loaded on a ship - is low. At present gas prices in geographically remote Patagonia where there
is otherwise no market for the gas, are markedly lower than those in Western Canada. Large
global producers like Methanex are taking advantage of lower feedstock prices to improve
strategic supply locations on geographically diverse global market.
Under the CCA and HPP scenarios there will be fuel cost increases above what is currently
anticipated, and GHG collection and sequestration will add to operating costs. Ammonia
production for fertilizers will continue to be in strong demand under all scenarios and this product
area alone tends to dominate demands for hydrogen. The CCA scenario will reflect even higher
fuel costs together with considerable mandated carbon clean-up measures.
The annual growth rate in the SO scenario is 3% per year to 2013 for both Western and Central
chemical sectors. Increasing natural gas prices and slower rates of increase in consumer
spending will reduce growth to 2 to 2.5% (Central and Western) for the 2013 – 2023 period. The
CCA scenario will have the most Impact on growth of this sector. Considerable increases in
natural gas prices and mandated carbon reduction regulations add additional costs for capital and
operating costs. Consumer demand can be expected to result in reduced demand. Both the CCA
and HPP scenarios will have a number of similarities but under CCA natural gas prices increase
faster than with HPP. As the product price is very sensitive to feedstock price, offshore supplies
gain a greater market share.
An annual rate of increase in demand of 1.5 to 2% (Central and Western) was set for CCA
scenario and 2.5% for the HPP for the 2003 – 2013 period. The rate of increase in demand is
expected to continue to drop in the second period with a 0 to 1% (Central and Western) rate for
the CCA scenario. In the case of HPP natural gas priority for FCVs and increased consumer
demand will result in a maintained 2.5% annual increase for the last period.
Canadian Hydrogen
August 2004
Page 6.3
6.2
Chemical Sector – By-product Hydrogen Supply Capability
Figure 6.1-1 shows that the hydrogen requirements for the general chemicals sector are
substantial; by 2023 they are in the order of 1.7 million t/y under the SO scenario and about 1.1
thousand t/y under the most constrained CCA scenario. Fortunately the primary petrochemical
and chlor-alkali groups are hydrogen providers. These sources could help mitigate the demand
for additional dedicated hydrogen generation.
Figure 6.2-2 below, displays the volume of hydrogen expected to be produced by the two
producer chemical groups. Upwards of 850 thousands t/y can be expected from this group by
2023. Some of this hydrogen is committed under long-term agreements to nearby petrochemical
process plants, or merchant gas companies that require hydrogen. The integration of
complimentary process industries will become much more common as the value of hydrogen
increases over the next 20 years.
CHEMICAL INDUSTRY BY-PRODUCT
HYDROGEN PRODUCTION- 2013 & 2023
Soldiering On
HYDROGEN (t/day)
900,000
800,000
Carbon
Conscious
Agenda
700,000
600,000
Hydrogen
Priority
Pathway
500,000
400,000
2003
2013
2023
YEARS
Figure 6.2 – 1 Chemical Industry By-Product Hydrogen Production - 2013 & 2023.
The amount of new hydrogen produced and available by 2023 will not meet the entire needs of
the user chemical industries but the available volume could make a contribution that amounts
about 50 % of the projected demand.
Anticipated growth in the primary petrochemical and chlor-alkali groups will be important to
reducing feedstock costs, reducing the demand for natural gas, and reducing GHGs from the
petroleum and petrochemicals sector. The anticipated growth of two groups to 2023 is outlined.
Canadian Hydrogen
August 2004
Page 6.4
The primary chemicals, such as ethylene, styrene and other primary petrochemicals, have
traditionally grown at a more conservative rate than some of the petrochemicals. Estimated
growth rates are 2 to 3% in the first period, slowing to 1.5 to 2% in the second in the SO case.
The CCA and HPP scenarios will result in only a slight reduction as primary chemicals as plastics
and synthetics will be in demand for lighter vehicles continues at an even more rapid pace than at
present. However, natural gas prices will remain high and the convenient access to primary
petrochemicals from the Western Region via the Cochin products pipeline to Sarnia and by rail
into the US Mid-west and California will ensure continuing demand. A key component of primary
chemicals production will be the proposed North-slope gas pipeline from Alaska and the Beaufort
reserves. There could be a priority use of natural gas for transport and the high efficiency
electrical energy from distributed power from HTFCs, thus incrementally increasing natural gas
prices. The rate increase for the primary chemicals sector will reduce to 2% annual increase to
2023.
Primary chemicals such as ethylene may, in the future, be produced from oil components such as
naphthas. Derivatives such as ethylene, butadiene and benzene continue to be produced from
crude oil.
Ongoing building and operation of primary petrochemical facilities will have an important role
helping to satisfy the growing demand for hydrogen from other chemical and oil refineries.
Primary petrochemical processes such as ethylene can provide enormous amounts of process
hydrogen to industry. At present the primary petrochemical facilities in the Eastern Region have
sales for most of the hydrogen output. In Alberta only 65% of the hydrogen output is used for
further processing.
The chlor-alkali sector will respond to the slowing changing growth pattern of the Canadian and
US forest products industry. Though a small producer of hydrogen and a frequently maligned
process sector, chlor-alkali facilities not only offer high purity hydrogen but are also conveniently
scattered across the country. About 20% of the existing Canadian facilities have a complimentary
process facility that uses the hydrogen by-product. Hydrochloric acid and hydrogen peroxide are
industrial chemicals that are used in relatively small quantities and fit markets similar to those of
chlor-alkali. In Canada only 5 of the 20 chlor-alkali plants pipeline hydrogen to nearby users; the
remainder vent or burn the hydrogen by-product.
Experts in the chlor-alkali sector consider long-term growth rates to be about two-thirds or three
quarters of the GNP, slow growth by some of the other sector standards. Based on Statistics
Canada projections of a long term GNP of 2.5%, the expected growth of this industry sector will
be about 1¾ % per year (0.01875 to 0.0165). The growth rate will lower to ~1.5 % under the CCA
scenario, as electric power supply will be restricted, more expensive and more unreliable. The
HPP scenario will improve the electric power situation as nuclear power will be generally
accepted and HTFCs will be providing power throughout the grid. Electric power costs in the
HPP scenario will be viewed as relatively low compared to those in the CCA world.
Canadian Hydrogen
August 2004
Page 6.5
Combined chemicals Sector Hydrogen Production
All the hydrogen currently made, in excess of the producer facility demands, fall within the
chemicals sector. Figures 6.2-3 displays the excess quantities for the chemical industry that has
its own dedicated or on-purpose hydrogen production. Figure 6.2-4 displays the amount of
excess and uncommitted hydrogen arising from the by-product chemical groups.
HYDROGEN (Y/Y)
CHEMICAL INDUSTRY: ON-PURPOSE HYDROGEN
DISPOSITION (SO Scenario)
2,000,000
1,800,000
1,600,000
1,400,000
1,200,000
1,000,000
800,000
600,000
400,000
200,000
0
2003
On-purpose
Production
Surplus
On-purpose
Production
2013
2023
YEARS
Figure 6.2-3
Chemical Industry: On-Purpose Hydrogen Disposition (SO Scenario)
This figure shows that in 2003 there was only 3% or 26,000 t/y of excess hydrogen spread among
four process plants in the West. The largest source is the Celanese plant that has about 45% of
the available total. If the same percentage of excess is continued the amount of hydrogen
available in Canada in 2023 will be about 70,000 t/y. This amount will likely be commercially
attractive at any specific sites where quantities are greater than 10,000 t/y.
The by-product hydrogen producers are and will continue to be major suppliers of industrial and
potential hydrogen fuel. Figure 6.2-4 shows the scope of actual and potential supply from this
group. In 2003 there is about 38% or 169,000 t/y surplus or "in-excess” hydrogen that was not
used for other than furnace fuel or vented. If the same percentage of excess is continued the
amount of hydrogen available in 2023 will be about 330,000 t/y. The majority of the present
amount is from process plants in the West. There is a modest supply in the Eastern Region that
can be expected meet a range of lower volume needs, especially the needs of merchant gas
companies. The largest single source is the Nova Chemicals ethylene plant at Joffre, AB where
about 80 – 120,000 t/y could be available depending upon current ethylene demand.
Canadian Hydrogen
August 2004
Page 6.6
HYDROGEN (t/y)
CHEMICAL INDUSTRY: BY-PRODUCT HYDROGEN
DISPOSITION (SO Scenario)
900,000
800,000
700,000
600,000
500,000
400,000
300,000
200,000
100,000
0
2003
By-product Surplus
(projected at same
% as 2003)
By-Product Sold
2013
2023
YEARS
Figure 6.2-4
Chemical Industry: By-Product Hydrogen Disposition (SO Scenario)
The various figures discussed above relate to the amounts of produced and surplus hydrogen for
the “Soldiering On” scenario, reference to Figure 6.2-2 shows that there will be very little
difference in the total available under any of the three scenarios.
6.3
The chemicals sector is the largest producer of hydrogen in Canada. Even if all the surplus
hydrogen available within the section were used to displace existing production, the sector would
remain the largest.
There are several chemical value-added sequences from primary products produced in Alberta to
secondary and tertiary products in Sarnia. Greater facility integration will make hydrogen
pipelines to existing and future facilities feasible, as hydrogen is a component to many chemical
processes.
This study’s forecast of ‘surplus’ volumes will of course not be reached because likely the future
value of hydrogen will ensure that there is a demand for the gas, and it is therefore removed from
the ‘surplus’ category.
Due to the chemical sector size and complexity, this group of producers and suppliers have
considerable experience to bring forward on hydrogen production and hydrogen futures.
Participation from this sector will be important to gaining a complete view of the Canadian
hydrogen sector.
.
Canadian Hydrogen
August 2004
Page 6.7
7.
MERCHANT & FUEL USE HYDROGEN IN CANADA: 2013 & 2023
7.1
“Merchant” hydrogen is that produced by industrial gas companies and sold to various industries,
usually for process use. The hydrogen is often produced in central plants and shipped to the
customer in cylinders or as a liquid; alternatively it can be produced on-site in small “on demand”
plants, or delivered “over the fence” through pipelines. The choice of delivery method is a
function of demand pattern, volume and distance.
Merchant gas companies will most likely produce some of the hydrogen required by the oil
refining, oil sands and chemical sectors. This report does not estimate the amount of merchant
gas market share, but it could easily be in the hundreds of thousands of tonnes per year. The
enormous demand for hydrogen in Canada over the next 20 years represents a significant
business opportunity for well capitalized specialist suppliers .
There is a range of industrial markets for hydrogen:
Specialty chemical manufacture (aldehydes; HCl; H2F; benzene; etc.)
Metallurgy (induction welding; activation & reduction of catalysts; refining; etc.)
Food and drinks (fat hydrogenation; drinking water denitrification)
Electronics (silicon chip manufacture)
Float glass manufacture
Power utilities (generator coolant)
Laboratories (cryogenic fluid; detectors; fuel cell research; etc.)
Transportation (rocket fuel; FCVs; etc.)
With the exception of the transportation category, most of these markets respond to the economic
cycle, and industry literature indicates that collective past and projected growth rate is somewhat
less than the general economic growth rate. Our projections for non-fuel merchant hydrogen
markets are identical under each scenario.
Fuel cells represent a new market for hydrogen, but not in all fuel cell applications. The early fuel
cell markets in stationary power will be likely filled by solid oxide or molten carbonate type cells
that operate on natural gas, hence not stimulating hydrogen demand. Solid polymer electrolyte
fuel cells are currently regarded as the best candidates for vehicular use and will, of course, call
for hydrogen.
Transportation, or fuel use hydrogen has different drivers, and fuel use of hydrogen could
significantly impact merchant gas demand. Unlike the US, where the space program has been a
major user of fuel hydrogen, (and has been impacted by the grounding of the shuttle fleet)
Canada’s aerospace use of hydrogen is minimal at best. However, the potential for a new market
for fuel cell vehicles in Canada must be considered in any view of the future.
The rate of introduction of FC passenger vehicles is different under the three scenarios. The
same is true also for fleet and transit FC vehicles, though there may be more market demand for
Canadian Hydrogen
August 2004
Page 7.1
these (ZEVs) due to the issue of local or regional air quality, irrespective of the somewhat greater
overall GHG implications.
7.1.1
Merchant & Fuel Use Hydrogen Demand Projections
2013
Under each scenario we project:
Merchant (non-fuel) hydrogen: 20,700 tonnes/year (~2% above 2003’s 16,700 tpy)
Transportation hydrogen:
still primarily for demonstration, and a few captive fleets
(i.e. not significant)
2023
Merchant, non-fuel hydrogen under each scenario = 25,000 tpy (~2% >2003’s demand)
Transportation hydrogen:
Soldiering On
FCVs may appear in a few fleets prior to 2013, but do not register significant numbers. Sales
pick up in the 2015 period and increase at the % of new vehicle rates as shown below.
2015
2016
2017
2018
2019
2020
2021
2022
2023
% new vehicles per year
Passenger
vehicles
0.25
0.25
0.5
0.5
0.75
0.75
1
1
2
Fleet vehicles
0.5
0.5
0.75
0.75
1
1
1.25
1.25
1.5
Transit buses
0.5
0.5
0.75
0.75
1
1
1.5
1.5
2
Total number of vehicles
Passenger
4158
8384
16970
25692
38976
52462
70714
89235
126818
Fleet
166
332
665
1000
1448
2010
2687
3366
4218
Transit
23
46
80
115
162
208
278
349
443
Hydrogen demand projected for 2023
Passenger vehicles
@ .25 Tpy
31,700
Fleet vehicles
@ 2.5 Tpy
10,545
Transit vehicles
@ 18.25 Tpy
8,085
Total projected hydrogen demand (tonnes per year)
Canadian Hydrogen
August 2004
50,330
Page 7.2
Low Carbon Agenda
Somewhat greater penetration of FCVs in both transit & urban fleets to reflect local air quality
concerns.
2015
2016
2017
2018
2019
2020
2021
2022
2023
Passenger
vehicles
0.2
0.2
0.2
0.2
0.2
0.4
0.4
0.4
0.4
Fleet vehicles
0.2
0.2
0.4
0.4
0.5
0.5
0.6
0.6
0.7
Transit buses
-
-
0.25
0.25
0.5
0.5
0.5
0.75
0.75
Passenger
3327
6707
10142
13630
17173
24365
31666
39075
46,591
Fleet
110
221
444
667
947
1228
1566
1906
2,303
Transit
-
-
12
23
46
70
93
128
164
Hydrogen demand project for 2023
Passenger vehicles
@ .25 Tpy
11,650
Fleet vehicles
@ 2.5 Tpy
5,760
Transit vehicles
@ 18.25 Tpy
2,990
20,400
Hydrogen Priority Pathway
More rapid introduction and acceptance rate of FCVs encouraged by various measures
to make them more attractive.
2015
2016
2017
2018
2019
2020
2021
2022
2023
Passenger
vehicles
1
1
1
1
1
1
1
5
5
Fleet vehicles
1
2
2
2
4
4
4
6
6
Transit buses
1
1
1
3
3
3
5
5
5
Passenger
16633
33536
50709
68151
85864
103845 122097 214704 308660
Fleet
552
1660
2772
3888
6128
8276
10632
14028
17436
Transit
46
92
138
277
416
556
790
1024
1260
Hydrogen demand projected for 2023
Pass vehicles
@ .25 Tpy
77,165
Fleet vehicles
@ 2.5 Tpy
43,590
Transit vehicles
@ 18.25 Tpy
22,995
Canadian Hydrogen
August 2004
143,750
Page 7.3
RATIONALE FOR TRANSPORTATION HYDROGEN DEMAND PROJECTIONS
Our projections for FCV penetration contain some major assumptions, but are founded on the
following logic:
1. Forecast numbers of passenger, fleet vehicles and transit buses 2013 & 2023 by region
a. Derived from StatCan historic data on population and transportation fleet numbers
Source: Canadian Vehicle Survey 2002, et al., Statistics Canada;
b. Rationalized by types of vehicle per head of population and regionalized on a
population pro rata basis
c.
Commercial fleet FC candidate types assumes 100% urban courier vehicles, 75%
private & gov’t trucks, & 40% other ‘owner-operator’ vehicles
Source: Transport Canada: www.tc.gc.ca/pol/EN/Report/Courier2001/C6.htm
2. Account for operating lifetime of different vehicle types, and turnover rate
sales
Source: Industry data
new vehicle
3. Assumed annual average hydrogen fuel consumption for vehicles types is:
a. Transit vehicles – 18.25 t/y
Consultants
Sourc; Industry information and Dalcor
b. Fleet vehicles – 2.5 t/y Source: Dalcor Consultants
c.
Passenger vehicles – 0.25 t/y Source: based on US National Academy report
March 2004, which assumes 0.23 t/y consumption.
4. Penetration rate for FCVs established as a percentage of new vehicles per year
5. Calculation of cumulative number of FCVs of different types, year by year, with
consequent demand hydrogen implications
Canadian Hydrogen
August 2004
Page 7.4
7.2
2023 Hydrogen Supply Capability
Canada has a deep hydrocarbon resource base, and its capability to make large amounts of
hydrogen is well established. However, moving away from today’s natural gas source of
hydrogen to heavier hydrocarbons has CO2 implications, and the viability of using these other
resources hinges on the economic consequences of the day (i.e. applicable carbon taxes, etc.)
Ultimately these can only be assessed when measures for practical sequestration or carbon
trading are developed. These topics are comprehensively addressed in the preceding sections.
Approaching 2023 it is possible that Canada’s energy supply may contain a much greater
proportion of nuclear generation. Using off-peak power in electrolyzers may well produce an
important amount of hydrogen for the merchant market – a technology that suits distributed
production very well.
Indeed it is the distributed nature of demand that characterizes the merchant market, and the
vehicular market in particular. The transportation fuel market will present interesting challenges
as supply must respond to expected demand growth. The capital cost of on-site hydrogen
production is not insignificant, yet may not be warranted until volumes reach a triggering point.
There will be logical sweet spots for vehicular hydrogen sales where either hydrogen is available
nearby, or where there is immediately sufficient demand to support an on-site production unit.
Such sweet spots may enlarge almost organically as demand increases.
A proportion of these merchant markets can be supplied from expected large-scale production
plants, but the majority will in time be served by smaller local production. Apart from economic
viability, there are no show-stopping barriers to developing such productive capacity.
42
Pipelining is an option both for local distribution or longer distance transmission , although it is
unlikely that hydrogen will be pipelined thousands of kilometers. To date the pipelining and
merchant gas business have had little interaction, but the opportunities presented particularly
under the hydrogen priority pathway provide a new business paradigm where these two business
sectors may either compete or collaborate.
The pipelining companies own the core
competencies of land acquisition and pipeline construction and operation, as well as owning
existing rights-of-way, whereas the distribution and sale of industrial gases is the current bailiwick
of the merchant gas companies. A leadership position is up for grabs.
7.3
The business potential of the transportation hydrogen fuel market presents an enormous
opportunity that will be pursued aggressively by the merchant gas companies. Their present role
in the hydrogen sector now is low key, but important. They are involved today as purifiers,
•
42
For example, Joffre, Alberta has 80,000 – 100,000 tonnes/day that could be pipelined to Edmonton using
existing pipeline corridors.
Canadian Hydrogen
August 2004
Page 7.5
packagers and transporters of gas rather than primary producers, but they will be lobbying for a
position in this sector.
The energy companies that currently retail vehicle fuels will also be pondering how they address
this market. They have the enormous advantage of real estate in the form of existing gas
stations, and the ‘gas’ station of the future is likely to be a multi-fuel facility. We can expect to see
different forms of alliances and JVs established between the energy companies and the merchant
43
gas companies .
MERCHANT AND FUEL HYDROGEN DEMAND
160,000
HYDROGEN (T/Y)
140,000
120,000
Soldiering On
100,000
Carbon Conscious
Agenda
Hydrogen Priority
Pathway
80,000
60,000
40,000
20,000
2003
2013
2023
•
43
Air Products has recently signed a deal with PetroCanada to supply 71,000 tpy hydrogen for a PetroCan
upgrader refinery.
Canadian Hydrogen
August 2004
Page 7.6
8.
OPPORTUNITIES & CHALLENGES ON THE ROAD AHEAD
8.1
The Canadian Picture
Canada has a rich hydrocarbon resource base, our abundant hydropower base provides the
potential for no-carbon hydrogen, and we have vast tracts of biomass and large land area that
together provide both sources of hydrogen and potential sinks for CO2. In addition, as this report
shows, Canada already produces and uses vast amounts of hydrogen, and we have gained an
international reputation as a leader in hydrogen
technologies.
“ Projections show that large industrial
Taken together these factors indicate that the nation is
well positioned to develop a leading hydrogen economy.
Yet, because of these same hydrocarbon resources
Canada is also a large per-capital emitted of CO2. This is
a significant potential liability that could impact Canada’s
international competitiveness if and when the Kyoto
protocol is ratified and comes into effect.
emitters could produce about half of
Canada’s total greenhouse gas
emissions by 2010. In accordance with
the Climate Change Plan for Canada,
large industrial emitters are to reduce
their emissions by 55 megatonnes (Mt)
of carbon dioxide equivalent. Through its
discussions with industry, provinces and
territories, and other stakeholders, the
Large Final Emitters Group will design
policies and measures that are effective
in encouraging reductions of this
magnitude, are administratively efficient
and clear, and help to maintain the
competitiveness of Canadian industry.
Natural Resources Canada, as a branch of the federal
government, has demonstrated both strong policy intent to
address CO2 emissions, and considerable technical
NRCAN WEBSITE
leadership (particularly through CANMET) in addressing
energy efficiency, renewable energy development and low-CO2 output issues. Collectively,
Canada has powerful industry and government expertise in energy systems development.
Collectively these factors represent powerful opportunities for Canada to take and maintain a lead
in the development of hydrogen systems engineering and deployment.
However, the incentives to do this are currently more virtual than real. Kyoto remains an
interesting thought, presenting no immediate threat to Canada’s economy. The US, at present
seemingly unlikely to support Kyoto, and being our major trading partner serves to benefit if
Canadian companies alone were subject to restrictions and additional costs. Canada’s
competitive position could well be eroded. Additionally, because of the intrinsic ‘popularity’ of
environmental issues and the plethora of different government initiatives addressing these, there
is a danger of fragmented and disjointed efforts that individually fail to achieve much.
In summary:
Opportunities:
•
Well developed industrial base
•
Deep resource base
•
Regarded as world leader in hydrogen technology
•
Many opportunities for potential demonstration projects
•
Canada regarded as a high CO2 emitter
Canadian Hydrogen
August 2004
Page 8.1
Challenges:
•
•
•
8.2
Competition for government capital
Competitive position vis-à-vis the US
Fragmented efforts
Opportunities for Canadian Technology Development
Canadian companies, research institutes and universities have developed a range of areas of
interest and expertise in the fields of hydrogen production, purification, transportation and
storage. At this time Canadian-based hydrogen technology organizations consist of about five
companies with established commercial products and continuing extensive R&D plus an
additional 9 companies or organizations that are engaged in research and development only. The
current Canadian hydrogen technology organizations are listed and briefly described in Appendix
E of this report. Within this group the areas of technical interest and expertise cover the range of
hydrogen production, purification, transport and storage. As might be expected, several
organizations have areas of interest that cover more than one topic.
The Canadian organizations that have been identified as having hydrogen specific areas of
research and development interests are listed in Table 8.2 - 1 “Canadian Hydrogen Technology
Organizations”. This list probably misses hydrogen related research at some Canadian
universities, especially in the field of adsorbent and catalysts. Dalcor was able to identify some
but likely not all university related work in the field. For example, there is widespread work in
various natural and synthetic crystalline structures at chemistry departments in most universities.
Some of these may have researchers working on hydrogen specific applications. Many will have
the potential for hydrogen applications, but as yet the hydrogen branch has not been explored.
1.
Alberta Research Council
2.
Centre of Automotive Materials & Mfg.
3.
Dynetek Industries
4.
CANMET Energy Technology Centre
5.
Enbridge Gas Distribution
6.
FuelMaker Corporation
/
7.
Hera Hydrogen Storage Systems Inc.
/
8.
Hydrogen Research Institute
Canadian Hydrogen
H2 storage
H2
transportation
H2 purification
H2 production
Organization
Products
Commercial
Table 8.2-1 Canadian Hydrogen Technology Organizations
/
/
/
/
/
/
/
/
/
/
August 2004
/
/
Page 8.2
9.
Institute of Integrated Energy Systems (UVic)
/
10. Membrane Reactor Technologies Ltd.
/
/
/
11. National Research Council
12. NexTerra Energy Corporation
/
13. Noram Engineering and Constructors
/
14. PowerNova Technologies Corporation
/
15. Precision H2 Inc.
/
/
16. Questair Technologies Inc.
/
/
/
17. Royal Military College
/
18. Saskatchewan Research Council
/
19. Stuart Energy Systems Corp.
/
/
20. University of Alberta
/
/
21. University of Calgary
/
/
22. University of Ottawa
/
/
/
23. University of Regina
Totals
5
14
11
3
4
Opportunities can be grouped both by specific component that make up the known means of
hydrogen production, purification, transportation and storage. The opportunities can also be
grouped into large-scale and small-scale capacity. While some technologies and integrated
processes can bridge large and small capacity ranges with ease, most do not. Either operating
conditions determine a size range that will ensure steady operating conditions, or costs do not
scale well and while the process works it is uneconomic.
The table below provides a list and summary of the principal opportunities. While the list may not
be comprehensive it includes the key technical development opportunity areas that arise from the
present and future size, growth rate and timing of hydrogen production and use in Canada’s over
the next 20 years.
Table 8.2-2 Principal Technology Opportunities in the Canadian Hydrogen Industry
Relative Size of Opportunity*
Technology Development
Large-scale
Production
Small-scale
Production
1.
Alternate fossil fuel-based processes
L
M
2.
Incremental mech. improvement – SMR/POX
L
M
3.
Incremental mech. improvement – gasifiers
L
S
4.
Incremental mech. improvement – PSA
L
M
5.
More selective CO2 adsorbents
L
L
Canadian Hydrogen
August 2004
Page 8.3
6.
More cost-effective and selective H2 catalysts
L
M
7.
More cost-effective and selective H2 adsorbents
L
M
8.
Larger capacity of electrolytic cells
L
S
9.
Improved H2 storage in materials
M
L
10. Hydrogen separation from hydrogen sulphide
M
M
11. Coal gasification & separation
L
S
12. Co-production of hydrogen & power
L
M
13. Portable reforming of lighter hydrocarbons
L
S
14. High temperature separation of hydrogen
L
S
15. CANDU applications in high temp H2 processes
L
S
16. Recovery and utilization of waste hydrogen
L
M
17. Steam cracking of heavy residuals
L
S
18. Bitumen upgrading for hydrocarbon fuel cells
L
S
19. Hydrogen storage cylinder technology
S
L
20. High octane fuels and hydrocracking
L
S
21. Modified air separation techniques
L
M
22. Process integration and improved efficiency
L
L
Note: * Relative size of the opportunity L - large, M – medium, S – small or nil
8.2.1
Canadian Technology in Large-scale Hydrogen Production
Opportunities and technology in large-scale hydrogen production and purification: The
consequence of the increasing demand for more hydrogen in the oil refinery, heavy oil upgrading,
and chemicals sectors offers a considerable market pull for large-scale hydrogen technology. The
above sectors require technology that has offers high capacity production with purification in the
order of over 100 t/d or 50 thousand Nm3/hr. Entry into this market is expensive, extended and
ruthlessly demanding. Few small companies make it into this league without appropriate industry
partners.
The demand for new hydrogen production technology in the industrial sector, primarily in Alberta,
is immediate. There is unlikely to be a need until 2030 to 2050 for large-scale hydrogen
production and distribution for PEMFCVs. The extent that Canadian organizations can participate
in supplying current needs should position these companies for the future large-scale hydrogen
production and distribution demands of FCVs.
In the early years of FCV introduction there will be considerable demand for smaller-scale, high
purity hydrogen production and purification. A number of Canadian companies are poised to
service this sector. Some technologies developed to meet the anticipated demand for small-scale
systems will likely show promise for scale-up. Any of the current 10 organizations currently
developing technology of this type may find profitable and immediate scale-up opportunities
within the industrial sectors.
Canadian Hydrogen
August 2004
Page 8.4
Dalcor estimates that some 350 – 400 thousand t/y of hydrogen is lost annually in Canada from
process inefficiencies associated with incomplete reformation of methane and separation losses
from pressure swing adsorption, to name two sources. At one percent improvement in process
efficiency of the nearly 2.3 million t/y currently produced by SMR, PSA and similar systems would
represent about 23,000 t/y. Incremental improvements in the existing process technology is
primarily in the domain of the major hydrogen gas production engineering companies. None-theless, Canadian scientists and engineers should be able to contribute by working with multinational hydrogen companies to improve the performance of catalysts, adsorbents and
processes.
At present there are no Canadian development organizations with established technology having
capacity in the range from 50,000 Nm3/hr and greater. Some companies do have technologies
that offer incremental or step-jump improvements in conversion of fossil fuels to hydrogen.
QuestAir Technologies has a number of commercial small-scale hydrogen purifier designs. The
company is currently developing designs for a packaged purifier system with a capacity that will
reach into the range of 50 thousand Nm3/hr of industrial grade hydrogen. Membrane Reactor
Technology (MRT), with technology in the design concepts, expects to have a module capacity of
hydrogen production and purification about 1/10 the large-scale size. Like QuestAir, MRT has an
expectation that the potential for lower unit costs will enable multiple units to be assembled and
deliver hydrogen that will meet industrial volume and cost requirements.
A common aspect of MRT’s and QuestAir’s technologies is that they reflect proprietary changes
to conventional processes and to achieve significant process intensification. Both companies'
processes can achieve upwards of 10 times the productivity of the conventional technology from
which they are based. The result is the both companies able to consider a wider range of catalyst
or adsorbents that may, at higher cost, offer improved performance. The relatively low catalyst or
adsorbent inventory enables the processes to deliver superior performance using materials that
conventional SMRs or PSA systems could not afford to use. Development opportunities exist for
dedicated materials for each of these companies.
The University of Regina’s entity HTC Hydrogen Thermochem is actively developing and
improving hydrogen production processes from natural gas and other fossil fuels. The company’s
focus is SMR processes, catalysts and associated gas clean up by membrane separation. In
addition to SMR technology the most promising step-jump technology will be in the field of
gasifiers that can generate syngas from a range of fossil fuels and even biomass. The University
of Calgary, Chemical Engineering has strong leadership in fossil fuel reforming processes and
catalysts. As well, some of MRT’s technology was developed as part of a program with U of C,
Chemical Engineering.
CANMET Energy Technology Centre and the University of Regina are addressing different
aspects of large-scale gasification. A start-up company, NexTerra Energy Corp of Vancouver, has
developed successfully a biomass gasification design that is being demonstrated in BC. The
company plans to direct some of its R&D efforts towards large-scale coal gasification for
production of syngas and heat. The Nexterra process, at this stage offers high efficiency
combustion of biomass materials. To achieve competitive syngas production primary stage
Canadian Hydrogen
August 2004
Page 8.5
temperature will need to be increased to ensure hydrocarbon-reforming temperatures are
achieved to achieve commercially competitive medium-rich syngas.
Current work at several Canadian universities in the field of catalysis and adsorbents have a
reasonable prospect of developing materials that will improve the performance of existing largescale SMR’s, gasifiers and pressure swing adsorption purifiers. Canadian expertise in this field is
well recognized and research work has and is being carried out for a number of multi-national
companies offering large hydrogen systems.
Canadian technology in catalysts and adsorbents development has traditionally resulted from
directly funded research with a select group of established scientists in a few universities. At
present the University of Ottawa, University of Regina and the University of Alberta have
internationally recognized scientists working in the catalysis and adsorbent fields. The results of
successful research are usually available to the funding company on the basis of a licence or
other contractual arrangement. Incorporation of the new catalysts or adsorbents are carefully
tested on a larger scale with field condition gases, demonstrated and finally introduced at a
customer-friendly site before becoming a commercial product.
The introduction of new hardware into industrial use is more complex than is the case with
catalysts and adsorbents. The requirements to be an equipment supplier to the large hydrogen
production sector are onerous. Due to the large capital investment, the demand for reliability to
achieve service time in the order of 99 percent for 18 to 24 month intervals makes performance
demands that are difficult to meet unless the company and the design is well proven. Proving of
new technology can be a slow and expensive task. Almost inevitably, the final product must be
delivered with accompanying performance guarantees that only large well-financed, usually multinational companies can deliver. Generally, partnerships with such large companies are an
important part of successful technology delivery. QuestAir Technologies for example has industry
partners that include BOC Gases and Shell. These established companies having gained insight
and confidence in the developer company’s technology acquired during the development or
demonstration stages and can give all-important credibility to new technology. Further, such
partners have the ability to back-up the essential performance guarantees.
The prospect of nuclear based heat and energy as a hydrogen source is becoming progressively
more attractive as GHG related and fossil-fuel scarcity issues become more evident. Significant
steps in high-temperature electrolysis and high temperature dissociation of water are each areas
of international research and development. Atomic Energy of Canada (AECL) is well poised to
participate in the high temperature electrolysis sector. High temperature disassociation demands
0
operating temperatures in the order of 800 and 1000 C, well above the temperature range if
conventional nuclear plants. The US and Japan are current leaders in the high temperature
disassociation. The most successful designs use helium as the coolant. The associated materials
challenges are significant.
The rapidly developing demand for large-scale hydrogen production and purification offers
Canadian-based companies and unusual opportunity to develop appropriate technology. Being
Canadian Hydrogen
August 2004
Page 8.6
located close to the final customers should enable Canadian organizations to be well positioned
know the end-users’ specific needs.
Opportunities and technology in large-scale hydrogen transportation: There is should an
increasing demand for large-scale hydrogen pipeline transportation arising from:
•
the increased value of hydrogen will result in pipelining surplus sources, such some
80,000 t/y at Joffre AB, to integrated petrochemical users in Edmonton 80 kms north.
•
the prospect of large-scale gasifier production as an alternate to natural gas SMR
systems may see hydrogen production sites clustered closer to a coal fuel sources with
hydrogen pipelined to several end-users.
•
the normal vertical integration of the petrochemical industry in centres such as
Edmonton AB and Sarnia ON will likely result in the need for hydrogen distribution nets
works such as those in the major US, EU and Japanese chemical centres. Each centre
has from 50 to 100 miles of hydrogen pipeline. Edmonton’s Praxair pipeline is 52 kms
and under capacity at this time, will not be nearly sufficient to handle location and
capacity as Alberta’s petrochemical industry matures over the next 50 years.
The technology associated with pipeline transport of hydrogen is relatively well established. The
potential for developing Canadian opportunities so likely confined to development and delivery of
engineering and construction services. The experience gained over the next 20 years of
development in Alberta where several long distance projects should arise, will enable the
companies awarded these contracts to be well positioned for contracts abroad where hydrogen
can be expected to become a major commodity in the next 50 years.
Opportunities and technology in large-scale hydrogen storage: As small-scale storage is still
struggling to get beyond liquefied hydrogen, storage is not a factor in current large-scale
hydrogen systems. To date the largest hydrogen storage requirements have been with NASA; the
costs associated with massive liquid storage are too great to have any prospect for industrial
applications. To a great extend the need for storage is minimal due the more-or-less continuous
operation of both the production and the consumption processes. Virtually all are round-the-clock
and year-round operations and most shutdowns are scheduled. Hence, supply and demand is
balanced to the extent possible and the balance is made up from dedicated hydrogen plants
There is little demand for storage applications in the industrial hydrogen sector as the costs with
present technology make massive storage relatively impractical.
With the pending arrival of PEMFCVs there remains a possible need for large-scale storage of
hydrogen in the event that distributed hydrogen production approaches do not succeed for
whatever reasons. At present, the technology for distributed hydrogen production offers good
promise of success as there are several technologies competing for this market. Technology
developments in electrolysis and small SMRs offer the potential for convenient hydrogen supplies
without excessive transportation and storage. There remains the prospect for a step-jump in
hydrogen storage technology, should this occur such technology could produce a paradigm shift
in where hydrogen is made, how it is stored and how it is distributed.
Canadian Hydrogen
August 2004
Page 8.7
8.2.2
Canadian Technology in Small-scale Hydrogen Production
Opportunities and technology in small-scale hydrogen production and purification:
Not surprisingly, the core of Canadian hydrogen technology efforts has been focussed upon
small-scale hydrogen delivery. Although there has existed for many years a modest demand for
small hydrogen systems, firms such as Electrolyzer (now Stuart Energy Systems) developed and
sold small systems throughout the world, the market pull has been from fuel cell and automobile
st
manufacturers that anticipate the need to fuel the vehicles of the 21 century.
Unfortunately the strong demand for many, cost-effective, small-scale hydrogen systems will
likely be some 20 years off based upon current US and EU estimates of FCV penetration.
Introduction of PEMFCVs is expected sometime between 2010 to 2015. Fortunately for many
organizations addressing the needs of the small-scale hydrogen production there is funding to
maintain development; unfortunately there is little in the way of significant sales. For the
organizations in this sector there are increasing markets for small systems and there is the
prospect of technology scale-up that will, in some cases, find a commercial opportunity.
An additional point of caution for the small-scale applications addressing the future needs for
distributed hydrogen fuel is the extent to which PEMFCs remain the most cost-effective and low
GHG fuel cell vehicle option. At present, PEM cells offer the most promising cost and energy
density both as existing custom products and as a high volume manufactured engine. In addition
to the current cost and energy advantage, the PEM cell’s need for high purity hydrogen offers the
advantage of zero exhaust emissions, a factor in reducing urban GHG production. Assuming that
PEMFVs become common, present estimates of demand in Canada will require about 5 million
t/y to service a potential 20 million vehicles. The volume pales compared to the anticipated needs
in the US where estimated needs are as large as 100 million t/y should all light vehicles be
PEMFCVs. The logistical aspects are extreme when its recognized that this amount of hydrogen
will be consumed at thousands of service stations scattered across the country. It remains to be
seen whether the hydrogen will be produced onsite from natural gas, or a similar fuel, or in large
base-load hydrogen facilities and distributed, much as gasoline is now.
The technology opportunities are large, but the significant demand is still distant. At this time
there is no clear path as to how hydrogen production, purification and transportation will play-out.
To further compound the difficulties of developing successful technology, Canadian technology
development will be meeting head-on with that of the US, EU and Japan. An option to offset this
same-time-out-of-the-starting block situation, Canada could choose a “go-it-alone” approach to
PEMFCVs. Such a move would need to be nearly correct in selecting future technology and
product development directions. Unlike the immediate demand for large quantities of industrial
hydrogen where Canada has clear demand and opportunity for a competitive need edge, the
potential for many small, distributed sources, together producing large quantities of PEMFCV
hydrogen is problematic.
Canadian Hydrogen
August 2004
Page 8.8
The possible pathways to cost-effective, distributed PEMFCV fuel hydrogen are several.
Electrolysis offers the easy convenient and low infrastructure cost of harnessing electricity to
produce on-site hydrogen. Although the absolute production costs of electrolytic hydrogen is high,
the ability to tap into a ready source of electricity offers at least a short –term source of PEM fuel
cell hydrogen. Electrolysis is a relatively mature and efficient process, but the technology has
resisted efforts to scale-up. Incremental improvements in the technology are likely, but limited.
For greater success, electrolysis needs methods of low-cost electricity production. Under current
cost and GHG concerns the electricity sources should be de-coupled from fossil fuels. Nuclear
power, off-peak can offer relatively attractive pricing and is generally looked upon as the nearterm pathway. Similarly, energy sources from solar, wind, wave and tidal power have
characteristics that make electrolytic hydrogen generation a preferred mode. Technology and
business development will likely see the energy source and electrolyzer organizations working
much closer together to develop well-packaged and cost-effective systems. Stuart Energy, AECL
and large multi-national players such as General Electric should be able to identify economies of
R&D scale that will result in productive joint activities.
Other electric powered technologies such as plasma based dissociation of methane offers the
prospect of hydrogen production from fossil fuel with hydrogen gas separated by high
temperature to leave carbon as the only by-product. The process offers tremendous
environmental value provided that the electric power energy source can be efficiently utilized.
Precision H2 and PowerNova are firms working in this field.
The prospect of distributed hydrogen needs and mobile hydrogen production on-board PEMFCVs
has resulted in work by a great many organizations around the world. In Canada this work is
centred at the Royal Military College associated with Hydrogenic Corporation’s need for FC fuel.
The college’s program is also associated with the Auto21 project involving several Ontario
universities and participation by Daimler-Chrysler, especially focussed on reforming of diesel fuel.
R&D is based on autothermal reforming technology, a variant of partial oxidation technology, with
natural gas and diesel as fuel. MRT’s technology is now in the scale range of small-scale
hydrogen production. The company anticipates the there will be a market of small, distributed
hydrogen systems. MRT’s technology includes high temperature membrane separation so that
“PEMFC ready” hydrogen is produced as a finished product.
Small-scale hydrogen separation technology from syngas streams has been the development
focus of QuestAir Technologies since its start in 1997. The company has succeeded in
commercializing several fast-cycle compact PSA based purifiers appropriate for stationary
distributed hydrogen service stations. As well, the company developed working models of much
more compact PSA systems appropriate for on-board syngas purification to match with on-board
liquid fuel reformers suited to automobile PEMFCs. The several QuestAir systems use
comparatively small volumes of conventional or proprietary adsorbent configurations and
adsorbents. There are good opportunities for performance improvement with development of
increasingly selective adsorbents.
Canadian Hydrogen
August 2004
Page 8.9
Work in high temperature, usually palladium or ceramic membranes, is a strong technology
opportunity area. Separation technology that can purify gases at or near processes temperatures
offer considerable energy efficiency as conventional PSA and polymeric membranes require the
treated gas to be close to ambient temperature. Heat exchange for cooling and re-heating drops
system efficiency.
High temperature separation will be key to technologies such as gasifier/high temperature fuel
cells systems, and for high temperature water dissociation. At present there is Canadian-based
work in this area using palladium at the Membrane Reactor Technologies and the associated staff
at the University of British Columbia and CANMET laboratories in Ottawa. CANMET has for
several years had work focussed on ceramic-based hydrogen membranes.
The University of Regina also continues work in range of low and high temperature membrane
separation technology some of which have small-scale applications. For the most part the focus
remains on larger scale processes.
Opportunities and technology in small-scale hydrogen transportation:
At present, Canada has modest requirements for transportation of small-scale hydrogen volumes.
As mentioned in earlier sections of this report there are some 45 traditional steel tube trailers and
about 6 liquid trailers servicing present Canadian needs. There will be growth in these numbers,
but it will be slow until there is a firm base of PEMFCVs in operation to accelerate distributed
demand.
Dynetek Industries has developed plans for high-pressure tube trailers at 350 and 700 bar (5 to
10 thousand psig) as part of the company’s plan to be in a position to cost-competitively deliver
hydrogen to distribution points from central production facilities. The trailers incorporate the
company’s proprietary carbon-fibre bound aluminium storage cylinders. These commercial trailers
will carry roughly three times more hydrogen in a single trailer that will cost about twice that of a
conventional metal tube trailer. DOT approvals are not yet in place awaiting changes to
regulations allowing very high pressure, flammable gas on public highways.
Pipeline transport of small volumes of hydrogen is relatively well established technology.
Opportunities and technology in small-scale hydrogen storage:
Small-scale, cost-effective storage of hydrogen for use in mobile applications, such as PEMFCVs,
forklifts, motorcycles/mopeds, portable power units and golf carts is a technology that will be
worth a fortune. To date there has been no break-through in scientists’ attempts to seek what is
probably the holy grail of the hydrogen economy. Canadian technology has a sound base in
materials storage with Hera Hydrogen Storage Systems Inc. the leading organization seeking
commercially viable material storage designs. There is a range of more fundamental research
being undertaken at several Canadian universities.
Canadian Hydrogen
August 2004
Page 8.10
As previously pointed out, hydrogen does not travel easily. R&D efforts in locations around the
world are working to achieve sufficient onboard storage of hydrogen to enable a 400 km travel
distance for a PEMFCV. The US and industry set targets for materials-based storage have been
set to put emphasis on finding a competitive alternative to compression of hydrogen to 700 bar.
The energy costs of compression are high and reversible metal hydrides are seen as one way of
achieving the storage density without the compression cost. To date the weight of metal hydride
has forced developers to improve the amount of hydrogen held per unit weight of material.
Hera’s staff and scientists within government and universities have a well-recognized world
expertise in metal hydride storage and should continue to deliver competitive technology.
The US DOE has set performance targets for material storage technology; see Section 2 of this
report. The targets include only hydrogen density but also uptake time to enable reasonably
efficient recharging of materials-base storage options. A break-through in the field of solid storage
technology would make a major leap forward in bringing PEMFCVs to market.
Until materials storage becomes a competitive option for mobile PEMFC applications such as
those listed in the introductory paragraph, high-pressure containers dominate storage options.
Dynetek Industries in Calgary is probably the world’s leading developers and manufacturer of
lightweight, high-pressure hydrogen containers. Most FCV’s demonstrated over the last few years
have used Dynetek high-pressure storage containers. Until alternative technology is developed
small-scale hydrogen storage, especially for mobile applications will be containers at 700 bar
(approximately 10,000 psig). The energy cost for compression to this level is somewhere in the
order of 12% of the energy value of the contained hydrogen; the efficiency cost is high but at
present there are no alternatives.
8.3
Summary of Technology Opportunities
The hydrogen sector in Canada has great possibilities. Probably the most important is to
recognize and understand the two distinct cultures of the large-scale and small-scale industries.
There are many components of hydrogen technology that have similar or in some cases identical
needs in both the large and small camps. Canadian hydrogen technology companies should find
out if there are common bonds to their technologies and find ways to develop in the direction that
offer the greatest market pull and technical compatibility. Some approaches to consider are:
•
Forums should be developed where large and small technical and business/marketing
interests can meet. One such forum is being considered as part of the BC and FCC
initiative of “Hydrogen West”. Other forums may develop from this.
•
Components of large hydrogen production have areas of common concern that can have
little to do with process size. Such areas are catalysis, adsorbents, separation
technologies of all kinds, especially high-temperature membranes and processes. Other
possible areas include mechanical devices such as fast-cycle valves and detection
instrumentation.
Canadian Hydrogen
August 2004
Page 8.11
•
Canadian end-users of large-scale hydrogen systems should be approached to see if
and how local specific knowledge and ingenuity might help to improve process cost or
efficiency of large proprietary production and purifying systems. Appropriate partnering
with the multi-national process engineering and design company could be facilitated by
the end-users to the benefit of all three parties.
•
While the demands for hydrogen supply, especially in Alberta, is substantial and
immediate, new technology will not be adopted without extended demonstration of
process stability, reliability and cost control both in construction and in operation.
Traditional venture capital financiers may not have the perspective to endorse such
development and capital might come from those firms already in the petrochemical and
oil & gas sectors.
•
Depending upon the rollout date of FC vehicles and the rate of market penetration these
vehicles, those companies with exclusive or partial focus on the small-scale sector
should examine the potential for small-scale applications that are independent of FC
vehicle development.
•
Through the deliberations of such groups as the Hydrogen Road Map Working Group,
strategic thinking can be focussed to identify and suggest action or direction to
government and industry to ensure that Canadian hydrogen priorities are established
and maintained.
Canadian Hydrogen
August 2004
Page 8.12
CONVERSIONS USED IN THIS REPORT
Energy
1 GJ
≅
1 million btu
≅
6.29 bbl
≅
1 mcf natural gas
Volume
1m
3
Hydrogen (specific)
1 million scf/day ≅
1 kg
≅
1000 tonnes/year
420 scf ≅
11.1 Nm
1 kg
≅
120 MJ (LHV)
1 million btu = 7.43 kgm of Hydrogen
Canadian Hydrogen
August 2004
3
Appendix: A
2003 Canadian Hydrogen Production & Surplus by Sector
& Region
(Dec 2003): Data tables
Canadian Hydrogen
August 2004
Page A 1
APPENDIX A: Canadian Hydrogen Production Inventory Data by
Sector and Region – December 2003
CANADIAN HYDROGEN PRODUCTION and SURPLUS BY SECTOR AND REGION (tonnes/year)
2003 - Capacity
2003 - Production
2003 - Surplus
(t/yr)
(t/yr)
(t/yr)
Western Region
Oil Refining
Heavy Oil Upgrading
Chemical Industry
Merchant Gas
Sub-total
198,270
185,355
770,000
770,000
0
912,900
912,900
26,100
463,000
398,609
147,653
0
0
0
2,344,170
2,266,864
173,753
437,362
437,362
0
74,075
73,591
0
72,000
70,712
22,154
Central Region
Oil Refining
Chemical Industry
Merchant Gas
Sub-total
16,700
16,700
0
600,137
598,365
22,154
222,000
222,000
0
0
0
0
2,000
2,000
0
0
0
0
224,000
224,000
0
3,168,307
3,089,229
195,907
Atlantic Region
Oil Refining
Chemical Industry
Merchant Gas
Sub-total
Sector Totals
2003 - Capacity
Oil Refining
Heavy Oil Upgrading
Chemical Industry
Merchant Gas
Canadian Hydrogen
0
August 2004
2003 - Production
2003 - Surplus
857,632
844,717
0
770,000
770,000
0
986,975
986,491
26,100
537,000
471,321
169,807
16,700
16,700
0
Page A 2
Western Region
Oil Refinery
Company
Plant
Location
Capacity
Principal
Product
Prod’n Sold to Surplus
Others
Remarks
tonne/year
Chevron
Burnaby,
BC
0 3,000 current surplus
8,700 petroleum
products
10,000
Consumers Co- Regina, SK
op Refinery
Husky
Prince
George, BC
95,000 petroleum
products
5,000 petroleum
products
85,000
Imperial Oil
Edmonton,
AB
16,570 petroleum
products
10,355
0
Petro-Canada
Edmonton,
AB
30,000 petroleum
products
32,000
0
Shell Canada
Scotford,
AB
43,000 petroleum
products
43,000
0 Additional H2 will be
Total
(fuel) destined for
gasoline and diesel
treatment over next 3
years
5,000
0
0 By-product H2 from
motor fuel reformer,
new SMR unit planned
for 2005, perhaps
15,000 t/yr
Ave daily volume 19.2
t/yr H2 processed - 12
t/yr increasing to 14.5
t/yr in 2006
NB: New 71 million t/yr
merchant H2 plant by
Air Product for April
2006
required for 2006
diesel hydrotreater
198,270
185,355
0 Surplus in all gases
temporary, short
term
Heavy Oil Upgrading
Company
Plant
Location
Capacity Principal Prod’n
Product
Sold to Surplus Remarks
Others
tonne/year
Husky Energy
Lloydminster, SK
Albion
Scotford,
Upgrader (Shell AB
and others)
Suncor
Fort
McMurray,
AB
Syncrude
Fort
McMurray,
AB
Total
Canadian Hydrogen
75,000
225,000
synthetic
crude oil
synthetic
crude oil
75,000
225,000
0
0 Includes 100 t/yr
from Dow
150,000
synthetic
crude oil
150,000
0
320,000
synthetic
crude oil
320,000
0
770,000
0
770,000
August 2004
Page A 3
Chemical Process Use
Company
Plant
Location
Product
Others
tonne/year
Agrium
Agrium
Agrium
Carseland,
AB
Fort
Saskatchewan, AB
Joffre
72,000 ammonia,
urea
88,000 ammonia,
urea
0
72,000
0
88,000
0
0
0 Purchases H2 at
100,000 t/y from
NovaChem
Agrium
Redwater,
AB
Alberta
Envirofuels
Edmonton,
AB
Canadian
Fertilizers
Celanese
Medicine
Hat, AB
Edmonton,
AB
92,000 ammonia,
ammoniu
m nitrate,
urea
6,700 iso-octane
92,000
1,200
0
4,500 Needs slight
purification when
customer found. Air
Liquide has short
pipeline and H2
storage for AE.
168,000 ammonia,
urea
cellulose
134,000
168,000
0
134,000
10,000 On Praxair pipeline,
3,000 hydrogen
peroxide
3,000
needs purification
when customer
found
0 43000 Nm3/hr from
Praxair pipeline,
3
3,300 Nm /hr from
own SMR
acetate,
formaldehdy
e, methanol
Degussa
Gibbons,
AB
FMC
Prince
George, BC
Kitimat, BC
3,000 hydrogen
peroxide
170,000 methanol
0
3,000
170,000
0
Medicine
Hat, AB
150,000 methanol
0
Methanex
Methanex
Saskferco
Simplot
*Sherritt
Gordon
up to 150,000 t/y
could be available
Belle
Plaine, SK
Brandon,
MB
86,000 ammonia,
urea
83,700 ammonia,
ammoniu
m nitrate,
urea
86,000
Fort
Saskatchewan, AB
15,000
15,000
1,071,400
912,900
Total
Canadian Hydrogen
0 Facility moth-balled -
August 2004
83,700
0
8,600 Could give small
surplus of hydrogen
~ 10mscf/day.
0 Also may purchase
from Praxair
26,100
Page A 4
Chemical Process ByProduct
Company
Plant
Location
Cancarb
Medicine
Hat
Chemtrade
Pulp
Chemicals
Product (t/y)
Others
Most H2 is presently
used for process heat,
some to steam ~ 30
MW power to city.
26,000
20,000
Prince
George, BC
4,000
sodium
chlorate
Dow Chemical Ft
Saskatchewan, AB
14,000
chlorine,
caustic
soda,
hydrogen
chloride
14,000
4,000 4,000 t/y
sold to
FMC for
hydrogen
peroxide
production
0
7,000
ERCO
Bruderheim,
AB
4,000
sodium
chlorate
3,100
3,100 By-product H2, about
ERCO
Grand
Praire, AB
4,000
sodium
chlorate
4,000
4,000
ERCO
Hargrave,
MB
2,000
sodium
chlorate
2,000
2,000
ERCO
Vancouver,
BC
Saskatoon,
SK
5,500
sodium
chlorate
5,500
5,500
5,000
sodium
chlorate,
chlorine,
caustic soda
5,000
10,000
sodium
chlorate
11,245
ERCO
0 Captive for hydrogen
chloride production
2,982 By-product H2 from
Nexen
Brandon,
MB
Nexen
Bruderheim,
AB
3,000
sodium
chlorate
4,069
1,802
Nexen
Nanaimo,
BC
Vancouver,
BC
1,500
sodium
chlorate
chlorine,
caustic
soda
1,500
1,269
Nexen
Dow LHC-1
Nova
Chemicals - E1,2,&3
Ft
Saskatchewan, AB
Joffre, AB
Total
Canadian Hydrogen
4,000
140,000 ethelyene
240,000
ethylene
463,000
August 2004
sodium chlorate
manufacture, 7,138 t/yr
used as fuel. 30-40%
expansion by end of
2004
By-product H2 from
sodium chlorate
manufacture, 1,860 t/yr
used as fuel, 407 t/yr
ventilation mgmt,
Remainder vented
Vented to air.
0 Most is fuel, 3,100 t/yr.
4,195
140,000 100,000
t/y sold
to Shell
180,000 100,00 t/y
sold to
Agrium, 0.2
t/y sold to
Air Liquide
398,609
75% for internal fuel
use; remainder vented
By-product H2 from
sodium chlorate
manufacture
By-product H2 from
sodium chlorate
manufacture
By-product H2 - vented
to air
40,000
Some sold for rerefining of oil or used
internally for HCL ~
1,154 t/yr.
Check this surplus may reflect Dow share
of Joffre
80,000 Facility below capacity
as market is down,
normal production will
have 100,000 t/y
surplus. Facilities E-1
and E-2 are Nova and
E-3 is jointly owned with
Dow
147,653
Page A 5
Hydrogen
Pipe Lines
Company
Plant
Location
Capacity Principal Producti Sold to Surplus Remarks
Product on
Others
tonne/year
Praxair
Strathcona,
AB, to Fort
Saskatchew
an
Western
Total
Canadian Hydrogen
80,000 hydrogen
80,000
18,000 From Celanese
28,000 t/y additional
methanol plant to Dow, capacity exists from
Shell, Degussa
Celanese if PSA is
expanded. 30 km. 8
inch pipeline @ 800
psig.
18,000
August 2004
0
Page A 6
Eastern
Region
Oil Refinery
Company
Plant
Location
Capacity Principal
Product
Prod’n
Sold
Surplus Remarks
tonne/year
Imperial Oil
Sarnia, ON
39,000 petroleum
prods
39,000
0 Reported volume
Imperial Oil
Nanticoke,
ON
Mississauga
ON
Montreal
East, PQ
Corunna,
ON
54,362 petroleum
prods
9,000 petroleum
prods
125,000 petroleum
prods
17,000 petroleum
prods
54,362
0
9,000
0
Petro-Canada
Petro-Canada
Shell Canada
appears low. Has H2
catalytic reformer.
125,000
0 Capacity was increased
17,000
0 Depending on feed H2
in 2003.
Shell Canada
Montreal
East, PQ
45,000 petroleum
products
45,000
0
Sunoco
Sarnia, ON
48,000 petroleum
products
48,000
0
Ultramar/Valero Levis, PQ
Total
Chemical
Process Use
Company
100,000
Petroleum
products
437,362
Plant
Location
100,000
437,362
Capacity Principal
Product
Prod’n Sold
capacity is about
15mstc/day from CR3
reformer
Depending on feed,
capacity is 3035mstc/day. Trying to
increase daily feed by
15%. Additional H2 is
purchased from Coastal
and Petromont.
H2 capacity also treats
some of Shell diesel fuel
production
Facility is 2nd largest
Canadian refinery
0
Surplus Remarks
tonne/year
ADM - Archer
Daniels Midland
Windsor, ON
Kemira
Chemicals
Terra
International
Maitland,
ON
Courtright,
ON
Total
Canadian Hydrogen
0 SMR unit on stream
1,075 Hydrogenated veg.
oil
591
3,000 hydrogen
peroxide
70,000 ammonia,
urea
3,000
0
70,000
0
73,591
0
74,075
August 2004
in 1996, production
as needed, operating
50-60% of capacity
Page A 7
Chemical Process ByProduct Production
Company
Plant
Location
Coastal
Petrochemicals
Eka Chemicals
Montreal
East, PQ
Magog, PQ
Eka Chemicals
Capacity Principal
Product
9,000 xylenes
Producti Sold
on
tonne/year
9,000
Surplus Remarks
0
6,000 sodium
chlorate
5,100 Sold to
6,000 sodium
chlorate
7,000 sodium
chlorate
3,000 sodium
chlorate
3,000 sodium
chlorate
6,000
6,000 By-product H2, burned
7,000
3,000
Nexen
Chemicals
Valleyfield,
PQ
Buckingham
PQ
Thunder
Bay, ON
Amherstburg
ON
3,060
2,754 By-product H2, 306 t/yr
Nexen
Chemicals
Beauharnois
PQ
3,000 sodium
chlorate
2,552
2,500
15,000 ethylene
15,000
0
ERCO
ERCO
Nova Chemicals Corunna,
ON
BOC for
liquid H2
productio
n (5.9
million
SCF/day
), burned
as fuel or
vented
900 By-product H2, burned
as fuel or vented
as fuel or vented
as fuel or vented
as fuel or vented
Nova Chemicals Sarnia, ON
7,000 styrene
7,000 Sales to
0
PCI Chemicals
Becancour,
PQ
8,000 caustic
soda,
chlorine
8,000
0
Petromont
Varennes,
PQ
5,000 ethylene
5,000
Allgoma, Dofasco,
Stelco
Ontario
Canadian Hydrogen
0 Coke oven
off-gas
August 2004
0
Air
Products
11,500
SCF/day
H2 is
pipelined
to
ATOFIN
A
Canada
Inc's
H2O2
plant or
liquified
by
Hydroge
nAl.
H2 is
sold to
adjacent
Petromo
nt Olifins
plant
internal requirements
(Vent mgmt control),
excess vented
By-product H2, burned
as fuel 1,250 t/yr,
remainder vented
Ethylene by-product, H2
is consumed captively
for reforming or fuel use
Styrene by-product, H2
for captive purposes
0 Ethylene by-product
Medium purity H2.
Estimated 100,000
t/y. Not
successfully
recovered to date.
Page A 8
Total
72,000
70,712
Merchant Gaseous Hydrogen
Production
Company
Plant
Capacity Principal
Location
Product
22,154
Producti Sold
on
Surplus Remarks
tonne/year
Air Liquide
Hamilton,
ON
Air Products
Sarnia, ON
11,000 hydrogen
HydrogenAL
Becancour,
PQ
3,500 hydrogen
Total
2,200 hydrogen
16,700
Hydrogen Pipe
Lines
Company
Plant
Location
2,200 80% sold
to steel
mills,
rest sold
as
merchan
t market
compressor
11,000
3,500 Up to
4000 t/y
sold to
Hydroge
n AL by
Atofina
16,700
Capacity Principal
Product
0 Also has 500 SCF/day
Producti Sold
on
0
Receives H2 as a byproduct from Nova
Chemicals styrene
manufacture.
H2 from PCI Canada’s
(7 metric t/d)
HydrogenAL’s has
3,500 t/y steam
reformer
0
Surplus Remarks
tonne/year
PCI Chemicals
Petromont Pipeline
Eastern Total
Canadian Hydrogen
Becancour,
PQ
Varnnes, PQ
8,000 hydrogen
10,000
hydrogen
18,000
8,000 .
8,000
16,000
August 2004
H2 is pipelined to
Kemira’s H2O2 plant or
liquified by HydrogenAl
0 H2 is piped across St.
Lawrence, serves
facilities of several
companies. Estimated
10 kms total.
8,000
8,000
Page A 9
Atlantic
Region
Oil Refinery
Company
Plant
Location
Capacity Production
Principal Sold to
Product Others
Surplus Remarks
tonne/year
Imperial Oil
Dartmouth,
NS
Irving Oil
North Atlantic Refining
0 H2 estimated by Dalcor.
12,000
12,000 petroleum products
St John,
NB
100,000
0
Come By
Chance,
NFLD
110,000
0
222,000
222,000
0
Total
H2 by-product from
refinery reformer
H2 estimated by Dalcor.
Facility is largest
Canadian refinery
H2 from platformer as
off-gas and from steam
reformer unit
Chemical Process
Production
Company
Plant
Location
Capacity Production
Principal
Product
Surplus Remarks
tonne/year
PCI Chemicals
St Anne Chemical
Dalhousie,
NB
Nackawic,
NB
Atlantic Total
Canadian Hydrogen
2,000
2,000 caustic soda, chlorine,
0 By-product H2, captive
690
690 caustic soda, chlorine,
0 By-product H2, captive
2,700
sodium chlorate
sodium chlorate
2,700
August 2004
use for HCl
use for HCl
0
Page A 10
Appendix B
Scenario – “Soldiering On”: Projected Demand by Region
& Sector (2013 & 2023):
Data tables
1Canadian Hydrogen
August 2004
Page B
APPENDIX B – “ Soldiering On” Scenario Projected Demand by Region & Sector (2013 and 2023)
CANADIAN HYDROGEN PRODUCTION and SURPLUS BY SECTOR AND REGION
(tonnes/year)
2003 - Capacity
Western Region
SCENARIO - "SOLDIERING ON"
2003 - Production 2003 - Surplus 2013 - Production 2013 - Est.Surplus
(t/yr)
(t/yr)
(t/yr)
2023 - Production
2023 - Est.Surplus
Oil Refining
198,270
185,355
0
237,254
0
270,618
Heavy Oil Upgrading
770,000
770,000
0
1,860,000
0
3,096,000
Chemical Industry
912,900
912,900
26,100
1,287,736
36,817
463,000
398,609
147,653
523,976
194,092
0
0
0
865
2,344,170
2,266,864
173,753
3,909,831
437,362
437,362
0
559,823
0
74,075
73,591
0
94,203
10,000
72,000
70,712
22,154
84,824
26,575
99,149
Merchant Gas
16,700
16,700
0
21,930
0
32416
0
600,137
598,365
22,154
760,781
36,575
884,946
43,253
222,000
222,000
0
284,160
0
324,120
0
0
0
0
0
0
0
0
2,690
2,690
0
2,408
1,000
2,836
1,178
Merchant Gas
Sub-total
1,648,410
0
0
47,128
661,127
244,895
17272
230,908
5,693,428
292,024
Central Region
Oil Refining
Chemical Industry
Sub-total
638,549
114,833
0
12,190
31,063
Atlantic Region
Oil Refining
Chemical Industry
Merchant Gas
Sub-total
Sector Totals
0
0
0
141
0
3715
0
224,690
224,690
0
286,710
1,000
330,671
1,178
3,168,997
3,089,919
195,907
4,957,321
268,484
6,909,045
336,455
2003 - Capacity
2003 - Production 2003 - Surplus 2013 - Production 2013 - Est.Surplus
2023 - Production
2023 - Est.Surplus
Oil Refining
857,632
844,717
0
1,081,238
0
1,233,287
0
Heavy Oil Upgrading
770,000
770,000
0
1,860,000
0
3,096,000
0
Chemical Industry
986,975
986,491
26,100
1,381,938
46,817
1,763,243
59,318
537,690
472,011
169,807
611,209
221,667
763,113
277,136
16,700
16,700
0
22,936
0
53,402
0
Merchant Gas
BCanadian Hydrogen
August 2004
Page B
Appendix C
Scenario – “Carbon Conscious Agenda”: Projected
Demand by Region & Sector (2013 & 2023): Data tables
Canadian Hydrogen
August 2004
Page C 1
APPENDIX C – “Carbon Conscious Agenda” scenario Projected Demand by Region & Sector
(2013 & 2023)
(tonnes/year)
SCENARIO - "LOW-CARBON"
2003 - Capacity 2003 - Production 2003 - Surplus
Western Region
2013 - Production 2013 - Est.Surplus 2023 - Production 2023 - Est.Surplus
(t/yr)
(t/yr)
(t/yr)
Oil Refining
Heavy Oil Upgrading
198,270
770,000
185,355
770,000
0
0
237,254
1,560,000
0
255,790
2,744,000
0
0
Chemical Industry
912,900
463,000
912,900
398,609
26,100
147,653
1,094,535
500,149
31,293
185,266
1,209,048
602,540
34,567
223,193
0
2,344,170
0
2,266,864
0
173,753
865
3,392,804
216,559
7557.914094
4,818,935
0
257,760
Oil Refining
Chemical Industry
437,362
74,075
437,362
73,591
0
0
559,823
85,967
0
10,000
603,560
127,252
0
14,802
Merchant Gas
Sub-total
72,000
16,700
600,137
70,712
16,700
598,365
22,154
0
22,154
81,238
18,613
745,641
25,452
0
35,452
93,474
14356.82982
838,643
29,285
0
44,088
222,000
222,000
0
284,160
0
306,360
0
0
2,690
0
2,690
0
0
0
2,321
0
1,000
0
2,646
0
224,690
0
224,690
0
0
141
286,622
0
1,000
1570.202095
310,577
0
1,140
0
1,140
3,168,997
3,089,919
195,907
4,425,067
253,010
5,968,154
302,988
Merchant Gas
Sub-total
0
Central Region
Atlantic Region
Oil Refining
Chemical Industry
Merchant Gas
Sub-total
Total Canadian
Production/Surplus
Sector Totals
2003 - Capacity 2003 - Production 2003 - Surplus
2013 - Production 2013 - Est.Surplus 2023 - Production 2023 - Est.Surplus
Oil Refining
Heavy Oil Upgrading
857,632
770,000
844,717
770,000
0
0
1,081,238
1,560,000
0
0
1,165,709
2,744,000
0
0
Chemical Industry
986,975
537,690
986,491
472,011
26,100
169,807
1,180,502
583,708
41,293
211,717
1,336,300
698,660
49,369
253,619
16,700
16,700
0
19,619
0
23,485
0
Merchant Gas
Canadian Hydrogen
August 2004
Page C 2
Appendix D
Scenario – Hydrogen Priority Path: Projected Demand by Region &
Sector (2013 & 2023):
Data tables
Canadian Hydrogen
August 2004
Page D 1
APPENDIX “D” – “Hydrogen Priority Path” Scenario Projected Demand by Region & Sector
(2013 & 2023)
(tonnes/year)
SCENARIO - "HYDROGEN PRIORITY PATH"
2003 - Capacity 2003 - Production 2003 - Surplus 2013 - Production
Western Region
2013 - Surplus
2023 - Production
2023 - Surplus
(t/yr)
(t/yr)
(t/yr)
Oil Refining
Heavy Oil Upgrading
198,270
770,000
185,355
770,000
0
0
231,694
1,506,000
0
240,962
2,332,400
0
0
Chemical Industry
912,900
463,000
912,900
398,609
26,100
147,653
1,149,388
523,976
32,861
194,092
1,471,314
634,855
42,065
235,164
0
2,344,170
0
2,266,864
0
173,753
1,869
3,412,926
226,953
47,197
4,726,727
277,229
Oil Refining
Chemical Industry
437,362
74,075
437,362
73,591
0
0
546,703
94,822
0
10,000
568,571
121,381
0
12,801
Merchant Gas
Sub-total
72,000
16,700
600,137
70,712
16,700
598,365
22,154
0
22,154
84,824
20,438
746,787
26,575
0
36,575
99,149
89,123
878,223
31,063
0
222,000
222,000
0
277,500
0
288,600
0
0
2,690
0
2,690
0
0
0
2,408
0
1,000
0
2,836
0
224,690
0
224,690
0
0
415
280,323
0
1,000
10,451
301,887
0
1,178
0
3,168,997
3,089,919
195,907
4,440,036
264,528
5,906,838
Merchant Gas
Sub-total
0
Central Region
43,864
Atlantic Region
Oil Refining
Chemical Industry
Merchant Gas
Sub-total
Sector Totals
1,178
322,271
2003 - Capacity 2003 - Production 2003 - Surplus 2013 - Production 2013 - Est.Surplus 2023 - Production 2023 - Est.Surplus
Oil Refining
Heavy Oil Upgrading
857,632
770,000
844,717
770,000
0
0
1,055,896
1,506,000
0
0
1,098,132
2,332,400
0
0
Chemical Industry
986,975
537,690
986,491
472,011
26,100
169,807
1,244,210
611,209
42,861
221,667
1,592,694
736,841
54,866
267,405
16,700
16,700
0
22,721
0
146,770
0
Merchant Gas
Canadian Hydrogen
August 2004
Page D2
Appendix C
Companies & Organizations Active in Hydrogen Production,
Transportation and Storage
Canadian Hydrogen
August 2004
Page E1
APPENDIX E:
CANADIAN COMPANIES & ORGANIZATIONS ACTIVE IN HYDROGEN PRODUCTION,
TRANSPORT & STORAGE
1. Alberta Research Council Inc.
250 Karl Clark Road
Edmonton AB T6N 1E4
Website:
www.arc.ab.ca
Products:
Power Generation, Transmission and Distribution
Description:
The Alberta Research Council (ARC) develops and commercializes technologies to give
customers a competitive advantage. A Canadian leader in innovation, ARC provides
solutions globally to the energy, life sciences, agriculture, environment, forestry and
manufacturing sectors. ARC works with more than 800 clients each year.
Applied expertise: ARC’s Advanced Materials business unit develops and
commercializes new materials, products, and processing technologies in ceramics,
metals, and polymers and composites. Our key technologies include polymer
nanocomposites, polymer membranes, thermoplastic pultrusion, ceramic and ceramic
composites for structural and functional application, hollow ceramic membranes,
composite ceramic coatings, micro-solid oxide fuel cells, and solar energy systems.
Hydrogen: Capabilities in coal/oil gasification, and purification, and hydrogen energy
economic models.
Carbon Dioxide Sequestration: Currently involved as scientific group for a major CO2
enhanced oil recovery project in Saskatchewan.
Staff, Facilities & Services: Twenty-five highly trained staff, including 13 scientists;
extensive lab and engineering space to conduct materials processing testing and
evaluation as well as thermal analysis; membrane characterization facilities, chemical
processes lab, a ceramics lab, a gas membrane lab, an ambient room, a metallography
room and environmental control chambers; access to venture management expertise
including patent and intellectual property administration; and market intelligence.
Contact:
Phone:
Fax:
Email:
Dr. Partho Sarkar
Dean Richardson
Group Leader, FC Research Venture Manager
(780) 450-5272
(780) 450-5334
(780) 450-5477
(780) 450-5334
[email protected]
[email protected]
Dr Ian Potter
Director
(780) 450-5401
(780) 450-5083
[email protected]
2. CANMET Energy Technology Centre
Natural Resources Canada
th
580 Booth Street, 13 Floor
Ottawa, Ontario K1A OE4
Website:
www.nrcan.gc.ca/es/technologies-e.htm
Description:
The CANMET Energy Technology Centre (CETC) is Canada’s leading federal S&T
organization that is developing and deploying energy efficient, alternative energy and
advanced technologies. CETC’s Transportation Energy Technologies program partners
with industry and other federal and provincial agencies to develop and deploy new
Canadian Hydrogen
August 2004
Page E2
transportation technologies, such as: alternative fuels and advanced propulsion systems;
advanced energy storage systems; emissions control technologies; vehicle transportation
system efficiency; and fuelling infrastructure technologies. The program supports R&D
through cost-sharing agreements, standards, development, and technology transfer, both
domestically and internationally.
In June 2001, Natural Resources Canada established the Canadian Transportation Fuel
Cell Alliance (CTFCA), a $23 million, 5-year, demonstration program for hydrogen
infrastructure. The CTFCA is partnering with the private sector and provinces to
demonstrate and evaluate different hydrogen fuelling systems for fuel cell vehicles,
establish safety standards and develop training and certification programs for the
personnel who will maintain these systems. The CTFCA will enable Canada to focus and
showcase its world-leading fuel cell and fuel supply technologies.
Contact:
Phone:
Fax:
Email:
Nick Beck
Chief, Transportation Energy Technologies
CANMET Energy Technology Centre – Ottawa
(613) 996-6022
(613) 996-9416
[email protected]
3. Centre for Automotive Materials and Manufacturing
945 Princess Street
Kingston, Ontario K7L 5L9
Website:
www.cammauto.com
Description:
The Centre for Automotive Materials and Manufacturing (CAMM) is Ontario's industry,
university, and government partnership dedicated to providing leadership and a
framework to transform university research and education into opportunities for the
automotive sector.
Fuel cells are a major area of CAMM's research and development program, with
applications including transportation, portable, and stationary systems. Our current
university partners for fuel cell projects are Queen's University, the Royal Military College,
and the University of Waterloo. The focus of our industry driven and supported R&D
program is to reduce the cost of manufacturing while increasing the durability and
reliability of both PEM and solid oxide fuel cell components and systems. Capabilities
include facilities for testing and evaluation of materials, components, and systems; CFD,
reaction kinetics, finite element, and failure modeling; and product cost modeling and
dynamic simulation of manufacturing systems.
Dr. Floyd R. Tuler
Executive Director
(613) 547-6459 or (613) 547-6700
(613) 547-8125
[email protected]
Contact:
Phone:
Fax:
Email:
4. Dynetek Industries Ltd.
Canadian Hydrogen
August 2004
Page E3
4410 - 46 Avenue SE
Calgary, AB T2B 3N7
Website:
www.dynetek.com
Products:
Advanced Lightweight Fuel Storage Systems™
Description:
Dynetek Industries Ltd. designs, produces and markets one of the lightest and most
advanced fuel storage and refueling systems for many compressed gases. Dynetek has
extensive knowledge in composite cylinder and systems design and is recognized around
the world as the solution-of-choice to the alternative fuel vehicle sector. Dynetek also
serves the industrial gas and energy sectors in the bulk transport and storage of
compressed gases. Dynetek works with its customers to provide the most practical and
innovative solutions.
Contact:
Phone:
Fax:
Robb Thompson
President & CEO
(403) 720-0262
(403) 720-0263
5. Enbridge Gas Distribution
500 Consumers Road
North York, ON M2J 1P8
Website:
www.cgc.enbridge.com
Products:
Natural Gas Distributor
Description:
Enbridge Gas Distribution is Canada's largest natural gas distributor and one of the
fastest growing natural gas companies in North America, serving 1.5 million residential,
commercial, and industrial customers.
Contact:
Phone:
Fax:
e-mail:
Canadian Hydrogen
For more than 150 years Enbridge Gas Distribution has been involved in natural gas
storage and distribution - providing its customers with safe, economical and reliable
products to make their homes and businesses comfortable.
Enbridge Gas Distribution is part of the Enbridge family of companies, which has business
segments in Energy Transportation, Energy Distribution, and Energy Services and is
owned by Enbridge Inc.
Enbridge inc. common shares trade on the Toronto stock Exchange in Canada under the
symbol "ENB" and on the NASDAQ National Market in the U.S. under the symbol
"ENBR".
Jeff Sim
Business Manager, Distributed Energy
(416) 495-5281
(416) 495-6163
[email protected]
August 2004
Page E4
6. FuelMaker Corporation
70 Worcester Road
Toronto, Ontario M9W 5X2
Website:
www.fuelmaker.com
Products:
Hydrogen drying, purification, and compression to 5000 psi. Complete fueling systems for
fleets of up to 50 vehicles. Natural gas compression for reformer feed.
Description:
FuelMaker has over 15 years experience in high-pressure gaseous fueling systems
around the world. It custom engineers the following hydrogen systems:
• Fast-fill or time-fill fleet fueling systems for electrolytic hydrogen (examples include
Honda demonstration station in Los Angeles and Stuart Energy PFAs).
• Fast-fill or time-fill fleet fueling systems for reformer based hydrogen (systems under
development with GTI)
• High pressure hydrogen compression and storage for stationary power/fuel cell
applications.
• Natural gas compression systems for pressurized reformer feed.
• Natural gas high pressure storage systems for reformer back-up in stationary
power/fuel cell applications.
Contact:
Phone:
Fax:
E-mail:
Ralph Rackham
VP – Engineering & Research
(416) 674-3034
(416) 674-3042
[email protected]
7. HERA Hydrogen Storage Systems Inc.
577 Le Breton
Longueuil Quebec J4G 1R9
Website:
www.herahydrogen.com
Products:
Hydrogen storage products using metal hydrides.
Description:
HERA develops hydrogen storage products based on metal hydrides for use in fuel cell,
internal combustion engine and other hydrogen applications.
Hydrides store hydrogen in a solid form enabling improved safety and compactness for
the provisioning of hydrogen energy in portable, stationary, mobile, military and other
power applications.
HERA is a world leader in the development of hydrogen storage materials. With a wide
portfolio of hydride technologies and its technical knowledge and engineering expertise,
HERA is a strong partner for original equipment suppliers that develop and manufacture
hydrogen based power products and applications.
Contact:
Phone:
Fax:
Email:
Canadian Hydrogen
Dave Dacosta
Director, Business Development
(450) 651-1200 ext 208
(450) 651-1209
August 2004
Page E5
8. Hydrogen Research Institute
Université du Québec à Trois-Rivières
3351 des Forges, P.O. Box 500
Trois-Rivières. Quebec G9A 5H7
Website:
www.irh.uqtr.ca
Products:
R&D
Description:
The Hydrogen Research Institute (I-RI) is an R&D unit of the Université du Québec à
Trois-Rivières, Quebec, Canada. The research interests of the HRI are diverse and
extend from the fundamental t the applied. Collaboration with industry and the training of
graduate students and qualified personnel is a constant preoccupation. The R&D activities
of the HRI are essentially focused on the following domains: storage, safety,
transportation, production and uses of hydrogen, mainly fuel cells and internal combustion
engine. The HRI has developed lasting partnerships with governmental agencies and the
industries. The HRI responds to the diverse interests and goals of its partners in
identifying and solving problems, as well as providing the expertise and facilities to
evaluate new technologies.
Contact:
Dr. Tapan Bose
Director
(819) 376-5139
(819) 376-5164
[email protected]
Phone:
Fax:
Email:
9. Institute for Integrated Energy Systems (IESVic)
University of Victoria
P.O. Box 3055 STN CSC
Victoria, BC V8W 3P6
Website:
www.iesvic.uvic.ca
Description:
The Institute for Integrated Energy Systems at the University of Victoria (IESVic) promotes
feasible paths to sustainable energy systems by developing new technologies and
perspectives to overcome barriers to the widespread adoption of sustainable energy.
Founded in 1989, IESVic conducts original research to develop key technologies for
energy systems and actively promotes the development of sensible, clean energy
alternatives.
All energy systems require technologies that link end-user services back to energy
sources. These linked technologies create pathways that harness, store and convert
energy in its various forms to deliver services on demand. Most of today’s energy systems
require technological pathways based on non-renewable or greenhouse gas emitting
energy sources, such as hydrocarbons. Because these dominant energy resources are
both unsustainable and harmful, IESVic is committed to promoting and developing
creative alternatives.
Our specific areas of expertise are fuel cells, cryofuels and hydrogen storage,
biohydrogen, computational modeling, energy systems analysis and energy policy
development.
Canadian Hydrogen
August 2004
Page E6
Contact:
Phone:
Fax:
E-mail:
Dr. Ned Djilali
Executive Director IESVic and Professor of Mechanical Engineering
(250) 721-6295
(250) 721-6323
[email protected]
10. Membrane Reactor Technologies Ltd.
499 – 200 Granville Street
Vancouver, BC V6C 1S4
Website:
[email protected]
Product:
Hydrogen Production Units using steam methane reforming in a proprietary membrane
reactor.
Description:
Membrane Reactor Technologies Ltd. is a privately owned, Vancouver based technology
firm with activities focused on the development and commercialization of membrane
reactor systems. With application of its patented Fluidized Bed Membrane Reactor
(FBMR) technology to steam methane reforming, the company is poised to become a
competitive supplier of small to medium scale, pure hydrogen production units for the
industrial hydrogen market and the emerging hydrogen economy.
Contact:
Mike Rushton
President and CEO
(604) 822-4343
(604) 822-1659
[email protected]
Phone:
Fax:
E-mail:
11. National Research Council of Canada
3250 East Mall
Vancouver, BC V6T 1W5
Website:
www.nrc-cnrc.gc.ca/main_e.html
Description:
The National Research Council’s Institute for Fuel Cell Innovation is working in
partnership with industry, university and government stake holders to build fuel cell
technology clusters across Canada and to support the innovation needs of Canadian fuel
cell companies through:
• Research and Development – strategic research aimed at advancing fuel cell science
and technology and facilitating the commercialization of fuel cells.
• People – a multidisciplinary team of over 60 researchers, all focused on fuel cell
research, provide advice and expertise to stakeholders.
• State-of-the-art facilities – hydrogen-ready labs and environmental chamber, MEA
characterization and fabrication facility, fuel cell test stations and specialized
equipment to support the NRC research program as well as the needs of Canadian
fuel cell companies
• Partnership – research collaboration, people exchange and large-scale strategic
initiatives and demonstration projects.
• Technology Acceleration – lab and office space to support emerging fuel cell
companies
Canadian Hydrogen
August 2004
Page E7
•
NRC Fuel Cell Program – headquarters of a horizontal program designed to leverage
NRC expertise and facilities across Canada.
Research is focused on five strategic areas of critical importance to Canada’s fuel cell
industry:
• Polymer Electrolyte Membrane Fuel Cells (PEMFC)
• Solid Oxide Fuel Cells (SOFC)
• Systems Integration, Testing and Evaluation (SITE)
• Microtechnology and Sensing
• Modeling
The institute is also home to the Mining Wear Resistant Materials Consortium, an
international group of industry giants in the mining and energy sector that work with NRC
to discover ways to lower costs associated with wear and tear of machinery and
equipment.
Contact:
Phone:
Fax:
E-mail:
Erica Branda
Communications Officer
(604) 221-3099
(604) 221-3001
[email protected]
12. Nexterra Energy Corp.
3650 Wesbrook Mall,
Vancouver, BC V6S 2L2
Website:
Products:
Commercial high-efficiency, low particulate, biomass gasifiers primarily
for sawmill heating systems. Demonstration project of 8 million btu/hr system completed in
2004.
Description:
Established May 2003, the company focused on development and
manufacture of gasifiers. Nexterra supplies full turnkey gasification-based energy systems
or individual gasifier units from 5 to 100 million btu/hr operating on wood waste and other
biomass fuels.
Business:
Develops & manufactures industrial-scale gasification systems that
enable customers to reduce energy costs by switching from natural gas
to lower cost waste fuels. On successful completion of biomass design the company
intends to develop a coal fueled gasifier for production of syngas for large industrial
applications.
Nexterra is owned by and financed by ARC Financial (Calgary) one of Canada’s largest
investment management company focused on the energy sector
Contact:
Phone:
Fax:
E-mail:
Canadian Hydrogen
Jonathan Rhone
President & CEO
(604) 222-5513
(604) 22-5516
August 2004
Page E8
13.
NORAM Engineering and Constructors Ltd.
200 Granville Street, Suite 400
Vancouver, BC V6C 1S4
Website:
www.noram-eng.com
Products:
Systems integration for industrial and utility scale power projects; design of chemical
design of chemical and electrical systems; supply of prototype and pilot plant systems;
supply of specialized balance-of-plant components including hydrogen generation and
delivery systems.
Description:
NORAM specializes in the development, commercialization and supply of electrochemical
processes. The privately owned company is known for its vision, innovation, and quick
response. It is a major shareholder of BC Research, a technology incubator, located at
the University of British Columbia.
NORAM is a multi-disciplined firm experienced in the design and operation of
electrochemical plants with loads between 5 and 200 MW.
Expertise includes plant modeling, handling of hazardous chemicals, materials of
construction, storage and pumping systems, material and heat balance, heat exchangers,
flow batteries, shunt currents and grounding of electrolytes, power rectifiers, inverters,
power quality and grid-connection.
NORAM is focused on stationary power applications for fuel cells.
The firm is evaluating opportunities where hydrogen is produced as a by-product in
existing electrochemical processes. NORAM also contributed to the development of a
Fluidized Bed Membrane Reactor (FBMR) technology, which converts natural gas into
high-purity hydrogen, on demand.
Contact
Phone:
Fax:
E-mail:
George A.E. Cook. P. Eng
President and CEO
(604) 681-2030
(604) 683-9164
[email protected]
Malcolm Cameron
Principal Electrical Engineer
(604) 681-2030
(604) 683-9164
[email protected]
14. PowerNova Technologies Corporation
680 - 1285 West Broadway
Vancouver, British Columbia
Canada V6H 3X8
Description:
Founded June 2000 when the company acquired 50% of the worldwide rights to a
hydrogen production technology. ... Moscow-base laboratory. One US patent pending
assigned to Powernova.
PowerNova aims to produce hydrogen at about 200° C from hydrocarbons by means of
chemical catalyst that breaks the H -C bond. It is a low temperature reaction that results
relatively pure H2 plus olefins (for which there is a ready market).
Canadian Hydrogen
August 2004
Page E9
Now seeking ~$1M to bring Russian scientists to BC (set up at Powertech Labs). The
business model = licensing or strategic partnerships.
Contact:
Phone:
Fax:
Email:
15.
Stuart Lew,
Co-Chairman and Chief Executive Officer
(604) 734-7488
(604) 734-7484
[email protected]
www.powernova.com
PrecisionH2 Inc.
4141 Sherbrooke Quest, Suite 550
Montreal, Quebec H3Z 1B9
Website:
www.precisionh2.com
Products:
CarbonSaver – Distributed Energy Systems
Description:
PH2 is developing non-thermal fuel processor technology for on-site hydrogen production
in distributed Natural Gas applications. During the decomposition of methane in the
CarbonSaver, the carbon in the methane is captured in a solid form for later use. Low
operating temperature and rapid start, load following features when integrated with fuel
cell installations, make the PrecisionH2 technology a leading approach to the distributed
supply of hydrogen. In a new R&D collaboration, PH2 will begin developing larger units for
roadside hydrogen fueling systems from a Natural Gas feed. In this process carbon black
will also be captured for use instead of released as CO2 or other GHG’s.
Contact:
Dan Fletcher
VP Development
(514) 781-1998
(514) 842-0162
[email protected]
Phone:
Fax:
E-mail:
16.
QuestAir Technologies Inc.
6961 Russell Avenue
Burnaby, BC V6J 4R8
Website:
www.questairinc.com
Products:
*Hydrogen purification technology for stationary and automotive PEM fuel cell systems,
and for reformer-based hydrogen fueling systems.
*Industrial systems for the purification of hydrogen, helium and methane.
Description:
QuestAir Technologies Inc has developed proprietary gas purification technology that is
being applied to several large existing and energy world markets, including industrial
hydrogen production and stationary and automotive fuel cells.
QuestAir’s proprietary fast-cycle pressure swing adsorption (“PSA”) technology allows the
developers of fuel cell systems to increase the efficiency of their products and offers a
compact, cost effective gas purification solution to QuestAir’s industrial customers and
Canadian Hydrogen
August 2004
Page E10
developers of hydrogen fueling infrastructure. QuestAir’s strategic partners include Shell
Hydrogen, Ballard Power Systems and The BOC Group.
Contact:
Phone:
Fax:
E-mail:
17.
Mr. Mark Kirby
Director, Business Development
(604) 454-1134 ext 204
(604) 454-1137
[email protected]
Royal Military College of Canada
Department of Chemistry & Chemical Engineering
PO Box 17000 Stn Forces,
Kingston, Ontario K7K 7B4
Products:
We are a research group consisting of 15 scientists, engineers and technicians. We offer
our services to industry and government organizations with home we presently have
several contracts.
Description:
RMC played an important role in much of the early fuel cell work in Canada, in that we
provided the scientific expertise and liaison with Ballard for the Department of Defense
(the sole supporter of Ballard in their first few years of fuel cell work). Today the group
has expertise in all areas of fuel cell systems and is carrying out research and
development on the following: membrane reformers, reforming catalysts, polymer
electrolyte membranes, MEA’s, DMFC’s, fuel cell component testing and modeling of all
components that make up a fuel cell power system.
Contact:
Dr. J.C. Amphlett or Dr. Brant Peppley
Electrochemical Group
(613) 541-6000 ext: 6272
(613) 542-9489
[email protected]. or [email protected]
Phone:
Fax:
E-mail:
18. Saskatchewan Research Council
125 - 15 Innovation Blvd.
Saskatoon, SK S7N 2X8
Website:
Product:
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August 2004
Page E11
19. Stuart Energy Systems Corporation
5101 Orbitor Drive
Mississauga, Ontario L4W 4V1
Website:
www.stuartenergy.com
Products:
Stuart Energy’s Hydrogen Energy Station is an electrolytic hydrogen infrastructure
solution designed to meet the hydrogen needs of a variety of markets and applications.
The Hydrogen Energy Station is, uniquely, a single system able to supply hydrogen for
industrial processes, transportation, fuel for vehicles, power for buildings and
communities, or any combination of these applications using clean hydrogen.
Description:
Stuart Energy is the leader in hydrogen infrastructure solutions and has over fifty years
experience in electrolytic hydrogen generation with a strong safety and reliability record.
Stuart Energy has a world-leading technology portfolio that includes all electrolytic
technologies; alkaline electrolysis, both atmospheric and pressurized, as well as access to
Proton Exchange Membrane (PEM) electrolysis.
Stuart Energy has important partnerships or projects with other global leaders such as
Cheung Kong Infrastructure Holdings Ltd, Ford Motor Company, Toyota Motors USA, and
Hamilton-Sundstrand.
Stuart-Energy is also the title-holder of over a 100 patents, including the most recent
patent giving Stuart Energy exclusive rights to develop and market “smart” on-site ondemand Hydrogen Energy Stations.
Contact:
Phone:
Fax:
E-mail:
20.
Wanda Cutler
Director of Marketing and Communications
(905) 282-7769
(905) 282-7777
[email protected]
University of Regina
Faculty of Engineering
3737 Wascana Parkway
Regina, Saskatchewan
Website:
www.uregina.ca
Description:
Research on hydrogen production from fossil fuels
We are aiming to develop a cost effective and reliable hydrogen fuel delivery system. This
will involve the design of a low-cost prototype to produce hydrogen from natural gas.
Contact:
Phone:
Fax:
E-mail:
Canadian Hydrogen
Dr. Raphael Idem. P. Eng
Associate Professor
Faculty of Engineering
(306) 585-4470
(306) 585-4855
[email protected]
August 2004
Page E12
21.
University of Alberta
Department of Chemical and Materials Engineering
510 – Material Engineering Bldg.
Edmonton, AB T6G 2G6
The Advanced Upgrading of Bitumen Group
Vision: New technology for integrated production and upgrading of Alberta’s heavy hydrocarbon resources
to provide clean energy and value-added products for 2030.
Scope of activities:
a) Research on the foundations of oilsands production and processing, including extraction, upgrading,
bitumen chemistry and thermodynamics.
b) Research on asphaltene chemistry, thermodynamics and interfacial properties to support new
technologies for in situ production of bitumen, separation of desirable and undesirable components
and new processing pathways.
c) New approaches to separation and catalytic conversion of heavy hydrocarbon components from
bitumen and coal to provide clean fuels and petrochemical products. Steve Kuznicki – Micro-porous
Structures Scientist, working in new Membrane Supports for the Purification of Hydrogen and Other
Gasses and in New Catalysts from Structured, Supported Precious Metal Grids of Nanodimensions
for Reformate and Other Reaction Systems.
.
Contact:
Dr. Murray Gray, Head
Professor, Department of Chemical and Materials Engineering
Phone:
(780) 492-7965
Fax:
(780) 492-2881
E-mail:
[email protected]
Canadian Hydrogen
August 2004
Page E13
APPENDIX F:
MULTI-NATIONAL LARGE-SCALE HYDROGEN SUPPLY COMPANIES
A. Conventional SMR Hydrogen Production and Purification
For installations with annual capacity of +100 million scfm (or 1,100 million NCMH):
1.
Technip (KTI): Head Office, Technip du France,
La Défense 12 – 92973Paris –
La Défense Cedex - FRANCE
KTI Corporation: 1990 Post Oak Blvd., Suite 200, USA
SYNCRUDE CANADA Ltd awarded TECHNIP a contract for the world's biggest single-train hydrogen plant. Will
produce 200 MMSCFD of hydrogen and 900 psig of steam for an integrated 75 MW condensing steam turbine
generator).
2.
Haldor Topsoe: Head Office: Denmark
Haldor Topsoe, USA,
17629 El Camino Real,
Houston, Texas 77058
offers Topsoe’s proprietary processes for: Ammonia, Methanol and Formaldehyde, Hydrogen, Synthesis Gas.
Topsoe provides a range of technologies and catalysts suited to the hydrogen and methanol decomposition needs
of industry.
The range of technologies covers two fundamentally different categories, one based on steam
% 456
8
4.
.
&6
"
7 Howe-Baker Engineers, Ltd
Howe-Baker International, L.L.C.
3102 East Fifth Street
Tyler, TX 75701 USA
Horton CBI Limited, Bow Valley Square II, #3500, 205 - 5th Avenue SW
Calgary, Alberta T2P 2V7
.key engineer, procure, construct aspects for a wide range of petrochemical processes.
Lurgi AG: Head Office; Lurgiallee 5, Frankfurt/Main, Germany
Lurgi GA North America, Inc
6724 Alexander Bell Drive
Columbia, Maryland 21046 Internet: www.lurgi.com
Its activities are targeted to technologies based on its proprietary technologies in the product lines gas-tochemicals, petrochemical and hydrocarbon technology. In gas technology, Lurgi offers the whole
technological chain for converting fossil raw materials to products, and oxygen-based technologies for gas
conversion.
Canadian Hydrogen
August 2004
Page F1
5.
UOP LLC
Head Office: 25 East Algonquin Road
Des Plaines, Illinois, USA 60017-5017
UOP Process Plants and Systems and associated catalyst and adsorbent development for a wide range of
petrochemical processes including in hydrogen production and purification systems.
6.
Praxair Canada Inc: Head Office, Praxair, Inc
175 East Park Drive, P.O. Box 44
Tonawanda, NY 14151-0044
Canada: 1 City Centre Dr., Suite 1200,
Mississauga, ON L5B1M2
Merchant gas company providing full range of design, construct and operate of hydrogen and oxygen production
and hydrogen purification including cryogenic.
7.
BOC Gases Ltd:
5975-T Falbourne St.,
Mississauga, ON
Merchant gas company providing a full range of design, construct and operate of hydrogen production plants.
Head Office Americas: New Jersey, USA
8.
Air Products & Chemicals, Inc: Head Office - 7201Hamilton Blvd,
Allentown, PA 18195-1501 USA
Merchant gas company providing a full range of design, construct and operate of hydrogen production plants.
Permea: Head Office – 11444 Lackland Rd., St. Louis, MO 63146 USA
Membranes separation systems(Part of Air Products & Chemicals)
9.
Air Liquide Canada Inc.: Head 9
:
75 Quai d'Orsay
75321 Paris cedex 07 Office:
Canadian Head Office: 1250 René Lévesque West Suite 1700,
Montreal, QB
Merchant gas company providing full range of design, construct and operate of hydrogen production plants.
10.
Dow Chemical Company: Head Office:
The Dow Chemical Company
47 Building, Midland, Michigan 48667
Dow Gas Treating Products and Services combines the advanced gas treatment products and technology
formerly offered by Union Carbide and Dow, one of the world's largest chemical companies and leader in gas
treatment technology.
Canadian Hydrogen
August 2004
Page F2
B.
Gasification Process for Heavy Hydrocarbons
1.
Chevron/Texaco:
ChevronTexaco Corporation
6001 Bollinger Canyon Rd.
San Ramon, CA 94583
925-842-1000 www.chevrontexaco.com
ChevronTexaco and Sasol in gas-to-liquids investments and gasification new gasification facility at China which
will generate sufficient synthesis gas to produce 300,000 metric tons/year of ammonia, plus 30,000 metric
tons/year of hydrogen.
2.
Shell USA: Head Office: Netherlands
Shell Global Solutions (US) Inc.
Westhollow Technology Center, 3333 Highway 6 South, Houston, TX
77082-3101, USA
www.shellglobalsolutions.com
A multinational petroleum company with established expertise gasification technology for hydrogen production.
3.
Lurgi AG:
Dusseldorf, Germany, Internet: www.lurgi.com
Lurgi Lentjes North America, Inc. 6724 Alexander Bell Drive
Columbia, Maryland 21046, Phone: +1 (4 10) 9 10-51 00
E-Mail: [email protected]
One of the world’s largest suppliers of petrochemcial process technology and turn-key systems
4.
Sasol USA: Head Office; Johannesberg South Africa
Houston TX, www.sasol.com
Sasol Limited – the world's largest synthetic fuels producer, major technology is coal based,
-- END -Canadian Hydrogen
August 2004
Page F3
NOTES
Canadian Hydrogen
August 2004
Page F4

DALCOR Consultants Ltd - Hydrogen Implementing Agreement

Transcription

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