canadian hydrogen futures - publication edition

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

DALCOR Consultants Ltd .


TABLE OF CONTENTS

Page

Executive Summary

Section 1: Hydrogen: An Element of Challenge and Promise

1.1 The Challenges of Hydrogen 1.2 Hydrogen Today: The Big Picture

1.3 Hydrogen Production & Purification: Processes, Economics & GHG Prodn

1.4 Hydrogen Storage – Current State of Art

1.5 Hydrogen Transportation – Current State of Art 1.6 CO2 Management

Section 2: Canadian Capacity, Supply & Demand – 2003

2.1 Introduction

2.2 Current Hydrogen Use 2.3 Canadian Hydrogen Surplus - 2003

2.4 Canada’s Hydrogen Storage and Transportation Infrastructure - 2003

2.5 Positioning for the Hydrogen Economy

Section 3: Possible Hydrogen Futures in Canada

3.1 Influencing Factors

3.2 Hydrogen Uses in Canada

3.3 Scenarios to 2023: Descriptions & Rationale

Section 4: Oil Refining in Canada: 2013 & 2023

4.1 Market evolution & demand

4.2 Oil Refinery Hydrogen Supply Capability

4.3 Implications for Oil Refinery Hydrogen Section 5: Heavy Oil in Canada: 2013 & 2023


5.2 2023 Hydrogen Supply Capability – Oil Sands Options

5.3 Implications for Production Section 6: Chemical Industries in Canada: 2013 & 2023


6.2 Chemical Sector: Hydrogen Supply Capability

6.3 Implications for Production

Section 7: Merchant & Fuel Use Hydrogen in Canada: 2013 & 2023


7.2 2023 Hydrogen Supply Capability

i

1.1 1.6

1.8

1.26

1.33 1.35

2.1

2.2 2.9

2.11

2.11

3.1

3.7

3.8

4.1

4.4

4.8

5.1

5.7

5.9

6.1

6.4

6.7

7.1

7.5


Section 8: Opportunities & Challenges on the Hydrogen Road Ahead 8.1 The Canadian Picture

8.2 Opportunities for Canadian Technology Development 8.3 Summary of Technology Opportunities

Appendices:

A. 2003 Canadian Hydrogen Production & Surplus by Sector & Region

(Dec 2003): Data tables

B. Scenario – Soldiering On: Projected Demand by Region & Sector (2013 & 2023): Data tables

C. Scenario – Carbon Conscious: Projected Demand by Region & Sector

(2013 & 2023): Data tables

D. Scenario – Hydrogen Priority Path: Projected Demand by Region &

Sector (2013 & 2023): Data tables E. Canadian Companies & Organizations Active in Hydrogen Production,

Transport & Storage

F. Multi-National Large Scale Hydrogen Supply Companies

7.5

8.1

8.2

8.11

Canadian Hydrogen Study August 2004 i By Dalcor Consultants Ltd Intuit Strategies Inc.


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

storage, and finally the areas of technical opportunities that arise with hydrogen in the 21st

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 self-

sufficiency 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 August 2004 ii By Dalcor Consultants Ltd Intuit Strategies Inc.

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

Canadian Hydrogen Study August 2004 iii By Dalcor Consultants Ltd Intuit Strategies Inc.

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: Ron Britton

BC Hydro: Allan Grant

Enbridge: Richard Luhning, Ho-Shu Wang and Jeff Jergens Tom McCann & Assocs. : Tom McCann

Royal Military College: Brant Peppley

Canadian Hydrogen Study August 2004 iv By Dalcor Consultants Ltd Intuit Strategies Inc.

i

Canadian Hydrogen Study August 2004 Page 1.1 By Dalcor Consultants Ltd. Intuit Strategies Inc

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.


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


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.

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

deadweight)1.

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 “well-

to-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)


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

about 15,000 t/y of liguid and some gaseous hydrogen, over 15 million m3/y of refined chemical

products, about 10 million m3/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.


The following list of negative perceptions, termed the “20 Hydrogen Myths”, has been developed and addressed by the Rocky Mountain Institute

“20 H YDROGEN MYTHS”

1. A whole hydrogen industry would have to be created from scratch

2. Hydrogen is too dangerous, explosive, or “volatile” for common use as a fuel.

3. Making hydrogen uses more energy than it yields, so it’s prohibitively inefficient.

4. Delivering hydrogen to users would consume most of the energy it contains.

5. Hydrogen can’t be distributed in existing pipelines, requiring costly new ones.

6. We don’t have practical ways to run cars on gaseous hydrogen, so cars must continue to use liquid fuels.

7. We lack a safe and affordable way to store hydrogen in cars.

8. Compressing hydrogen for automotive storage tanks takes too much energy.

9. Hydrogen is too expensive to compete with gasoline.

10. 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.

11. Manufacturing enough hydrogen to run a car fleet is a gargantuan and hugely expensive task.

12. Since renewables are currently too costly, hydrogen would have to be made from fossil fuels or nuclear energy.

13. Incumbent industries (e.g., oil and car companies) actually oppose hydrogen as a competitive threat, so their hydrogen development efforts are mere window-dressing.

14. A large-scale hydrogen economy would harm the Earth’s climate, water balance, or atmospheric chemistry.

15. There are more attractive ways to provide sustainable mobility than adopting hydrogen.

16. 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.

17. A viable hydrogen transition would take 30–50 years or more to complete, and hardly anything worthwhile could be done sooner than 20 years.

18. The hydrogen transition requires a big (say, $100–300 billion) Federal crash program, on the lines of the Apollo Program or the Manhattan Project.

19. A crash program to switch to hydrogen is the only realistic way to get off oil.

20. 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


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 Productio n (thousand tonnes)– revised to 2003 b

(based on SRI International CEH HYDROGEN – 1999 and 2003 data)

United States Canada

Western Europe 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

Methanol Producers 715 200 432 - 2,359 3,707

Other 321 534 798 162 - 1,802

Subtotal 7,539 2,952 5,849 1,710 23,263 41,099

Merchant Users

Pipeline or On-Site 1,016 0 459 7 - 1,507

Cylinder or Bulk 68 17 61 16 - 170

Sub total 1,084 17 520 23 - 1,677

Global Total 8,623 2,970 6,369 1,733 23,263 42,776

Canadian Surplus 200 Total Canadian 3,170 Notes:

a. Excludes Turkey

b. 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.


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 continue to industrialize2.

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


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 cost-

effective 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.


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

electrolytic cell produces about 1000 Nm3/hr or about 2.2 t/d. This rate is about 1/100th 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 � CO2 + 4H2


naphtha reforming CnH2n + 2 nH2O � nCO2 + 1.88 H2

residual partial oxidation CH1.8 + 0.98 H2O + 0.52 O2 � CO2 + 1.88 H2

coal gasification CH0.8 + 0.6 H2O + 0.7 O2 � CO2 + H2

water electrolysis 2H2O � 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 large-

capacity 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


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 hydrogen-

rich 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


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

combined with the high (~1100oC 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 life-

cycle. 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.

Canadian Hydrogen August 2004 Page 1.13

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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 Steam Reforming (SR)

Partial Oxidation (POX)

Texaco Gasification (TG)

Water Electrolysis

(Coal Thermal)

Capacity Range (NB: data

for larger versions)

Feedstock

(requirement per day)

Thermal efficiency, %

By-product

By-product capacity, t/d

Capital cost, $ x 106

Production costs, $/(100m3)

feedstock

Capital

O & m

Total

By-product credit

Net H2 production cost

in $/(100 m3)

$/t

Net production cost ranking

Average GHG production3 (gm of GHG/kg of H2)

1 – 1000 t/y

natural gas

1.1 x 106m3

78.5

steam

1.7

83.2

4,46

2.14

0.75

7.35

-0,16

7.19

672

1

11,000

1 – 1000 t/y

residual oil

1020 m3

76.8

sulphur

30

205

3.86

5.39

1.93

11.18

-0.03

11.15

1,092

2

17,000

100 – 500 t/y

bituminous coal

2320 t

63.2

sulphur

70

316

3.93

5.39

1.93

15.54

-0.08

15.46

1,510

3

21.250

Minute – 2.5 t/y

Water/ electricity

507 MW

27.2

oxygen

695

132

19.21

3.32

0.93

23.46

-0.83

22.63

2,029

4

52,300

Table 1.3 – 1 Summary of Process Characteristics - Efficiencies, Costs and Greenhouse Gas Production the Principal Large-scale Hydrogen P rocesses 4 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 D. O’Connor, GHGenius calculations, May, 2004 4 “Methods of Producing Hydrogen”, I. Potter, Alberta Research Council. Nov 2001.


below. Appendix F lists some of the principal global suppliers of these and other principal

technologies associated with production of large scale hydrogen.

Table 1.3 – 2 Cost Comparison - On-site Hydrogen P roduction for Alternate Technologies 5

Technology/Size (H2 kg/d)

Reference

Specific TCI ($/t)

Hydrogen Cost* ($/t)

SMR (natural gas) 900 40

48** 1,600 260

SR (methanol) 1600 260

**future optimized design

Berry et al. 1996

Thomas et al 1998

NAS&E 2004

(S&T)2 2003

“ “

(S&T)2 2003

“ “

9,053 2,672 2,667

n/a n/a

n/a n/a

3,692 1,738 3,110 2,720 4,760

2,960 4,360

Alkaline Electrolysis 1,170 234 39

1,600 260

Berry et al 1996

“ “

“ “

(S&T)2 2003

“ “

6,616

10,288 10,446

n/a n/a

4,383 4,975 5,024

7,800 9,300

PEM ELECTROLYSIS 1,170 850 234 39 32

250* * optimized design

Berry et al. 1996

Thomas 1995

Berry et al. 1996

“ “

Thomas 1995

NAS&E 2004

4,115

4,683

6,173

8,072

7,850

n/a

3,959

5,311

4,288

4,637

6,020

5,300 (est.)

Steam Electrolysis 1,170 234

Berry et al. 1996

“ “

2,880 6,965

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.


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

numbers generally fit current estimates6. 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.

The SMR process typically includes heating of the feedstock to temperatures of 700-900O 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


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

obtained (Leiby 1994; Kirk-Othmer7 1991; Foster-Wheeler 19968; Blok et al 19979). 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 Hydroge n Product Costs

Facility Size

(H2 tonnes/d)

Reference

Specific TCI

($/t)

Hydrogen Price*

($/t)

Large Facilities 120 190 250 600

2,280

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

Small Facilities

0.27 Leiby 1994

4,400

2,290

•

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.


0.48 0.48*

* optimized design

NAS 2004 NAS 2004

5,130 2,667

4,680 3,110

* costs adjusted for $6.50/GJ gas price

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 –

1500 O 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,

depends on the source document. Other authors (Thomas et al. 199810) 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

at lower temperatures around 770 – 900 O 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.


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 from 30 – 60 m3 per barrel of crude.

Purge and Off-gas Hydrogen from petrochemical sourc es 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 Petroc hemical Sources

Process % H 2 Concentration Range Petrochemical Processes Ammonia Purge 55 – 65

Ethylene by-product 65 – 90 Cyclohexane Purge ~45

Formaldehyde by-product 15 – 20

Methanol Purge 70 – 80

Refinery Processes Fluid Catalytic Cracker 15 – 50

Hydroprocessor Purge 50 – 90

Naphtha Catalytic Reforming 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.


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 cost-effective 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 Fischer-

Tropsch.

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


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 F uel Type, from the Canadian Clean Power Coalition, May 2004


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 by-

product 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


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 processe s 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


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 & Purificatio n 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

there is some optimism that new techniques will achieve 1 or 2 m2 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 requires to achieve this separation are in the order of 1000oC 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.


Figure 1.3.3.1 Very High Temperature Reactor for Di ssociation 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

into hydrogen and elemental carbon at a temperature of <700oC. 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.


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.


Compressed - High Pressure Gas Storage

Many vendors supply hydrogen as a high-pressure gas in steel cylinders. Pressures are typically

15-40 MPa, requiring around 2.3 kWh/kg11. Compressed hydrogen tanks for fuel cell vehicles

operating at 70 MPa have been certified in Europe and Japan12. 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

the hydrogen “bumpstop”13, 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

gasholders, high-pressure steel storage tanks or

cryogenic storage. Small amounts of hydrogen are

shipped in steel gas cylinders that hold up to 7.45 m3 of hydrogen at 16.6 MPa. High-pressure tube trailers are sized at 798 - 5100 m3.

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

pressure of 20-30 MPa14, 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

several large-scale undergrounds hydrogen storage systems15.

•

11 Wurster, R. & Zittel, W, http://www.hydrogen.org/knowledge/Ecn-h2a.html, section 9.7 12 http://www.eere.energy.gov/hydrogenandfuelcells/hydrogen/storage.html 13 http://www.airproducts.co.uk/bulkgases/hydrogen.htm 14 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.

Figure 1.4-1: Air Products “Bumpstop”


Figure 1.4-2: NASA Liquid Hydrogen Storage

Figure 1.4-3: Linde Liquid Hydrogen Tank

• 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

program, Figure 216. 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

and 13 kWh/kg depending on the plant size17.

Research continues on novel liquefaction methods

(e.g. magnetic liquefaction) aimed at reducing these costs.

Liquid hydrogen can be transported by rail in specially

built tank cars of 36 and 107m3 capacity18.

Large-scale use of hydrogen requires large insulated

storage tanks. The largest, some 3,800m3 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

•

16 http://www.fsec.ucf.edu/hydrogen/nasa.htm 17 Dutton, D. Hydrogen Energy Technology, Tyndall Centre for Climate Change Research, Working Paper 17, April 2002. 18 The 107m3 capacity jumbo cars are 23.7m in length


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

tank developed for vehicle applications19.

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


• 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.

• 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.

• Expense

• Hydride containers require heat exchangers to remove heat during charging.

• Can be unstable and affected by poisons.

• 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


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.


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 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

Compressed Gas

Long term (30 days) 3,900 391,900

3,919,000

3,235 1,028 580

36.93 12.34 7.35

Short term (1-3 days) 131 13,100 20,300

130,600

35,649 7,200 1,827 3,235

17.12 6.68 5.13 5.26

Liquefied Hydrogen

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

Short term (1-3 days) 131 - 130,600 4,191-18,372 2.89-7.46 Metal Hydride 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


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 by-

product 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.


Figure 1.5-1: Hydrogen Transport Truck

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

media. Figure 4 shows a Linde Liquid Hydrogen truck20. 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 tractor-trailer 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.

Amos21 reviewed rail shipment for compressed gas, liquefied

hydrogen and metal hydride, and ship transport for liquefied hydrogen.

1.5.1 Cost of Transport Options 22

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.


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

(Hydride @$18,375/GJ)



16 161 805

1,609

7.54 15.08 55.28 105.54

2.63 5.75 21.92 42.11

Ship 322 km 805 km

1,609 km

8.22 16.43 24.58

13.34 14.39 15.44

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


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, GHGenius23 and models by The Pembina Institute offer generally well accepted methodology and

results.

Fig 1.6.1 CO 2 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 Don O’Connor of (S&T)2 Consultants. The model is expected to be available to interested users in the first half of 2004.


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


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

over 1600 kms of CO2 pipelines and transports 400 million scf/d of the gas to several fields24. 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

are reasonably well understood25. 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 cost-

effective, 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

processes. There are three basic options26. These are:

•

24 http://www.kindermorgan.com/about_us/about_us_kmp_co2.cfm 25 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.


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 CO 2 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


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.


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 CO 2 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.


Some numbers have been extracted from operating data, for example the current cost of pipeline

transport is about $1.25 per tonne/100 km of CO2 27.

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

stored)28.

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 Pipeline costs are estimated by Hans-Joachim, Los Alamos Labs. NM, Nov 2002 28 Ref: IEA Greenhouse Gas Project


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

for an injection rate of 20 Nm3/s to US$13.3/tC for an injection rate of 2 Nm3/s29.

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


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 by-

product 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).


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)

2003 - Capacity 2003 - Production 2003 - Surplus Western Region (t/yr) (t/yr) (t/yr)

Oil Refining 198,270 185,355 0

Heavy Oil Upgrading 770,000 770,000 0

Chemical Industry 912,900 912,900 26,100

Chemical Industry By-product 463,000 398,609 147,653

Merchant Gas 0 0 0

Sub-total 2,344,170 2,266,864 173,753

Central Region

Oil Refining 437,362 437,362 0

Chemical Industry 74,075 73,591 0



Merchant Gas 16,700 16,700 0

Sub-total 600,137 598,365 22,154

Atlantic Region

Oil Refining 222,000 222,000 0

Chemical Industry 0 0 0

Chemical Industry By-product 2,000 2,000 0

Merchant Gas 0 0 0

Sub-total 224,000 224,000 0

Total Canadian Production/Surplus 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

2,344,170

600,137

224,000

0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

1 2 3

T/y

ear

Tonnes / year

Figure 2.2 – 1 Canadian Hydrogen Production Capaci ty – 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


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 tube-

trailer 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

rate in only 20 years) and each uses the anticipated average of about 0.230 t/y30 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.


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 by-product 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.


For perspective, the relative capacity in the Eastern Region is about 1/5th 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

198,270

770,000

912,900

463,0000

Oil Refining

Heavy Oil Upgrading

Chemical Industry

Chemical Industry By-product

Merchant Gas

Table 2.2.2 – 1 Canadian Western Region Hydrogen Ca pacity - 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


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

437,362

74,075

72,000

16,700 Oil Refining

Chemical Industry


Merchant Gas

Table 2.2.2 – 2 Canadian Eastern Region Hydrogen Ca pacity – 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.


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

222,000

0

2,690

0 Oil Refining

Chemical Industry


Merchant Gas

Table 2.2.2 - 3 Canadian Atlantic Region Hydrogen C apacity – 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.


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 end-user.

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%


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 off-

gas 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 pr ocess 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


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 In frastructure – 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


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.


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

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.

Hydrogen

Fossil fuels

Electricity

Chemicals

Manufacturing

Fuel

Nuclear

Solar, wind, hydro,

geothermal

Biomass


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

will peak in the not too distant future, possibly before 201031. 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.


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 one-

third 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


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


Gas Price Forecasts (Wellhead price in 2004 US$/GJ)

$2.0

$2.5

$3.0

$3.5

$4.0

$4.5

$5.0

$5.5

$6.0

$6.5

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

Time

US

$/G

J W

ellh

ead US DOE

McDaniels

PIRA

CERA Turmoil

CERA Technology

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.

Figure 3.1 -1:


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.


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. nano-

adsorbents, 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


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:

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.

FUEL CHOICE

Fuel availability

Operational logistics

Fuel price

Cost, availability & efficiency of conversion technologies

Price modifiers:

(taxes, regulations, incentives,

etc.)


Some well-reported scenarios33 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


�� 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

economy, and political upheaval34. 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


improvements by means of hybrid systems, and perhaps a greater range of fuel including

bioethanol, etc. Modest presence of FC vehicles by ~201535,36 in slowly expanding niche and

regional markets.

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


Gradual emergence of gaseous fuelled (natural gas � hythane � H2) i/c engines as

transition of gaseous fuelling stations.

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


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.


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%

over the next 25 years according to the NEB report37 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


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:

Table 4.1-1 Projected Rates of Increase 2013 & 202 3 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.

One US estimate38, 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 5-

10% 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

Projected Rates of Increase 2013 & 2023 in Canadian Oil Refin ery Demand for Hydrogen - (From base year of 2003) Scenario/Source 2013 2023

(%) (%)

Soldiering On (SO)

- Capacity increase 13 21

- spec & quality related 15 25

Carbon Conscious (CCA)

- capacity increase 13 15

- spec. & quality related 15 25

Hydrogen Priority (HPP)

- capacity increase 10 5

- spec. & quality related 15 25


standards. These impose more stringent gasoline and diesel trace components levels than most

other states.

OIL REFINERY HYDROGEN DEMAND - SCENARIOS 2013 & 2023

800,000850,000900,000950,000

1,000,0001,050,0001,100,0001,150,0001,200,0001,250,0001,300,000

2003 2013 2023YEARS

HY

DR

OG

EN

(T

/Y)

SoldieringOn

CarbonConsciousAgenda

HydrogenPriorityPathway

Figure 4.1.2-1 Canadian Oil Refinery Hydrogen Deman d 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 on-purpose 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.


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.


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

Products – Impact of Externally Generated Hydrogen, is from a recent US study39 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. �

�� Dedicated Hydrogen

Internal- Process

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 MTBE - $47.0/bbl 2,655 2,382 � �� !"#$%�� 5,540

Total Cost of Materials ($US) 2,298,600 2,456,600 Pre-change (2003) material costs ($US) 2,281,600

� ��

� ��&��

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 Diesel 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 Coke 3,584 2,165 Total Product for Sale ($US) 99,465 98,262 Total Value of Product for Sale ($US) 2,708,000 2,837,000 � ��'��($US)� (%)*(%%� +,%*(%%�

� -'�.��.�� !,#"+��

Table 4.2.1 - 1 Refinery Products – Impact of Externally Generated Hydrogen 40 •

39 M. Khorram, T. Swaty , Oil and Gas Journal, Nov. 25, 2002 40 ibid


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-of-

the-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


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:


• 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. .


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

hydrogen production41. 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.


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

OPTI Canada and Nexen

70 bpd Approval obtained 2003

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 Mahkeses 30K bpd Completed 2003

Nabiye/Mahihkan 30K bpd Application filed

BlackRock Ventures Orion EOR 20K bpd Application August 2001

Canadian Natural Resources Ltd.

Primrose/Wolf Lake Expansion

40K bpd

Producing 35K bpd

Encana Foster Creek

25-30K bpd Currently producing 30K bpd

Foster Creek Expansion 50K bpd Application filed

Husky Energy Tucker Project 30K bpd Application filed 2003

Peace River Area

Shell Peace River 9K bpd Company reviewing options

BlackRock Ventures 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

BA Energy Alberta Heartland Upgrader

UPGRADER IN 150K bpd Assessment filed 2003


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.

2) there is about 50 billion m3 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

160,000 m3 (1 m3 = 6.3 barrels). This amount is a combination of about 100,000 m3 of synthetic

crude oil (SCO), and about 60,000 m3 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.


OIL SANDS - ALTERNATE LONG-TERM DEVELOPMENT SCENARIOS

0

200,000

400,000

600,000

800,000

1,000,000

2003 2013 2023 2033

YEARS

SC

O &

BIT

UM

EN

BLE

ND

(M

3/da

y)

NEB - "bau"

NEB - "TV"

ALBERTA

TD BANK

Fig. 5.1–1 Oil Sands – Alternate Long-term Developm ent Scenarios. (from reports 2003 and 2004 of the listed agencies) The dominant vision is from Alberta and suggests about 800,000 m3 (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.


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.


Table 5.1-2 Estimated daily production of SCO (SO c ase)

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.

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) 350,00 0

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 projectio n

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)


OIL SANDS HYDROGEN DEMAND - SCENARIOS 2013 & 2023

0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

3,500,000

4,000,000

2003 2013 2023

YEARS

HY

DR

OG

EN

(T

/Y)

SoldieringOn



Fig 5.1-2 Oil Sands H2 – Scenarios 2003, 2013 and 2 023

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.


“..business as usual consumption (of natural gas ) for expanded oil sands production, will lead to an unsustainable dependence on natural gas well before 2030, and perhaps as early as 2015. Even today’s operators may need to retrofit for alternativesbeyond 2010”

Oil Sands Technology Road Map Update March 2004

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

technology will need to fulfill the majority of supply requirements. However, there is one important caveat: if natural gas continues to be the prime

syngas source there is growing evidence of

hydrogen production costs that will be unacceptable.

At this time there is good evidence that there is insufficient natural gas within the Western Canadian

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.


• 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 Implications for Production 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 pre-eminent 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,


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.


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.


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:

CHEMICAL INDUSTRY: TOTAL HYDROGEN DEMAND - SCENARIOS 2013 & 2023

900,000

1,100,000

1,300,000

1,500,000

1,700,000

1,900,000

2,100,000

2003 2013 2023YEARS

HY

DR

OG

EN

(T

/Y)

SoldieringOn



Figure 6.1–1 Chemical Industry Sector – Hydrogen D emand: 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.


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.


6.2 Chemical Sector – By-product Hydrogen Supply Ca pability 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

400,000

500,000

600,000

700,000

800,000

900,000

2003 2013 2023

YEARS

HY

DR

OG

EN

(t/d

ay)

Soldiering On



Figure 6.2 – 1 Chemical Industry By-Product Hydroge n 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.


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.


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.

Figure 6.2-3 Chemical Industry: On-Purpose Hydrog en 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.

CHEMICAL INDUSTRY: ON-PURPOSE HYDROGEN DISPOSITION (SO Scenario)

0200,000400,000600,000800,000

1,000,0001,200,0001,400,0001,600,0001,800,0002,000,000

2003 2013 2023

YEARS

HY

DR

OG

EN

(Y

/Y) On-purpose

ProductionSurplus

On-purpose Production


CHEMICAL INDUSTRY: BY-PRODUCT HYDROGEN DISPOSITION (SO Scenario)

0100,000200,000

300,000400,000500,000600,000

700,000800,000900,000

2003 2013 2023

YEARS

HY

DR

OG

EN

(t/y

) By-product Surplus(projected at same% as 2003)

By-Product Sold

Figure 6.2-4 Chemical Industry: By-Product Hydroge n 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.


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. .


7. MERCHANT & FUEL USE HYDROGEN IN CANADA : 2013 & 2023 7.1 Market evolution & demand

“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


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 Projectio ns 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) 50,330


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




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





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 � new vehicle

sales Source: Industry data

3. Assumed annual average hydrogen fuel consumption for vehicles types is:

a. Transit vehicles – 18.25 t/y Sourc; Industry information and Dalcor

Consultants

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


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.

Pipelining is an option both for local distribution or longer distance transmission42, 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 Implications for Production

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.


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 gas companies43.

MERCHANT AND FUEL HYDROGEN DEMAND

-

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

2003 2013 2023

HY

DR

OG

EN

(T

/Y)

Soldiering On

Carbon ConsciousAgenda

Hydrogen PriorityPathway

•

43 Air Products has recently signed a deal with PetroCanada to supply 71,000 tpy hydrogen for a PetroCan upgrader refinery.


“ Projections show that large industrial 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.

NRCAN WEBSITE

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.

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.

Natural Resources Canada, as a branch of the federal

government, has demonstrated both strong policy intent to

address CO2 emissions, and considerable technical

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


Challenges:

• Competition for government capital

• Competitive position vis-à-vis the US • Fragmented efforts

8.2 Opportunities for Canadian Technology Developme nt 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.

Table 8.2-1 Canadian Hydrogen Technology Organizati ons

Organization

Com

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cial

Pro

duct

s

H2

prod

uctio

n

H2

purif

icat

ion

H2

tran

spor

tatio

n

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stor

age

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

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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

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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 t he Canadian Hydrogen Industry

Relative Size of Opportunity*

Technology Development Large-scale Production

Small-scale Production

1. Alternate fossil fuel-based processes

2. Incremental mech. improvement – SMR/POX

3. Incremental mech. improvement – gasifiers

4. Incremental mech. improvement – PSA

5. More selective CO2 adsorbents

L

L

L

L

L

M

M

S

M

L


6. More cost-effective and selective H2 catalysts

7. More cost-effective and selective H2 adsorbents

8. Larger capacity of electrolytic cells

9. Improved H2 storage in materials

10. Hydrogen separation from hydrogen sulphide

11. Coal gasification & separation

12. Co-production of hydrogen & power

13. Portable reforming of lighter hydrocarbons

14. High temperature separation of hydrogen

15. CANDU applications in high temp H2 processes

16. Recovery and utilization of waste hydrogen

17. Steam cracking of heavy residuals

18. Bitumen upgrading for hydrocarbon fuel cells

19. Hydrogen storage cylinder technology

20. High octane fuels and hydrocracking

21. Modified air separation techniques

22. Process integration and improved efficiency

L

L

L

M

M

L

L

L

L

L

L

L

L

S

L

L

L

M

M

S

L

M

S

M

S

S

S

M

S

S

L

S

M

L

Note: * Relative size of the opportunity L - large, M – medium, S – small or nil

8.2.1 Canadian Technology in Large-scale Hydrogen P roduction 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.


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-the-

less, Canadian scientists and engineers should be able to contribute by working with multi-national 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


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 large-

scale 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 multi-

national 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

operating temperatures in the order of 800 and 1000 0 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


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 hydroge n 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.


8.2.2 Canadian Technology in Small-scale Hydrogen P roduction 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

manufacturers that anticipate the need to fuel the vehicles of the 21st 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.


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 near-

term 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.


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.


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 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

CONVERSIONS USED IN THIS REPORT

Energy

1 GJ ≅ 1 million btu ≅ 1 mcf natural gas

Volume

1 m3 ≅ 6.29 bbl

Hydrogen (specific)

1 million scf/day ≅ 1000 tonnes/year

1 kg ≅ 420 scf ≅ 11.1 Nm3

1 kg ≅ 120 MJ (LHV)

1 million btu = 7.43 kgm of Hydrogen

Canadian Hydrogen August 2004 Page A 1

Appendix: A 2003 Canadian Hydrogen Production & Surplus by Sect or

& Region (Dec 2003): Data tables


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 Western Region (t/yr) (t/yr) (t/yr)

Oil Refining 198,270 185,355 0




Merchant Gas 0 0 0

Sub-total 2,344,170 2,266,864 173,753

Central Region

Oil Refining 437,362 437,362 0

Chemical Industry 74,075 73,591 0


Merchant Gas 16,700 16,700 0

Sub-total 600,137 598,365 22,154

Atlantic Region

Oil Refining 222,000 222,000 0

Chemical Industry 0 0 0

Chemical Industry By-product 2,000 2,000 0

Merchant Gas 0 0 0

Sub-total 224,000 224,000 0

Total Canadian Production/Surplus 3,168,307 3,089,229 195,907

Sector Totals 2003 - Capacity 2003 - Production 200 3 - Surplus

Oil Refining 857,632 844,717 0




Merchant Gas 16,700 16,700 0


Western Region

Oil Refinery Company Plant

Location Capacity Principal

Product Prod’n Sold to

Others Surplus Remarks

tonne/year

Chevron Burnaby, BC

8,700 petroleum products

10,000 0 3,000 current surplus (fuel) destined for gasoline and diesel treatment over next 3 years

Consumers Co-op Refinery

Regina, SK 95,000 petroleum products

85,000 0

Husky Prince George, BC


5,000 0 By-product H2 from motor fuel reformer, new SMR unit planned for 2005, perhaps 15,000 t/yr

Imperial Oil Edmonton, AB


10,355 0 Ave daily volume 19.2 t/yr H2 processed - 12 t/yr increasing to 14.5 t/yr in 2006

Petro-Canada Edmonton, AB


32,000 0 NB: New 71 million t/yr merchant H2 plant by Air Product for April 2006

Shell Canada Scotford, AB


43,000 0 Additional H2 will be required for 2006 diesel hydrotreater

Total 198,270 185,355 0 Surplus in all gases

temporary, short term

Heavy Oil Upgrading Company Plant


Product Prod’n Sold to

Others Surplus Remarks

tonne/year

Husky Energy Lloydmin-ster, SK

75,000 synthetic crude oil

75,000 0

Albion Upgrader (Shell and others)

Scotford, AB


225,000 0 Includes 100 t/yr from Dow

Suncor Fort McMurray, AB


150,000 0

Syncrude Fort McMurray, AB


320,000 0

Total 770,000 770,000 0


Chemical Process Use

Company Plant Location

Capacity Principal Product

Prod’n Sold to Others

Surplus Remarks

tonne/year

Agrium Carseland, AB

72,000 ammonia, urea

72,000 0

Agrium Fort Saskatche-wan, AB


88,000 0

Agrium Joffre 0 0 0 Purchases H2 at 100,000 t/y from NovaChem

Agrium Redwater, AB

92,000 ammonia, ammonium nitrate,

urea

92,000 0

Alberta Envirofuels

Edmonton, AB

6,700 iso-octane 1,200 4,500 Needs slight purification when customer found. Air Liquide has short pipeline and H2 storage for AE.

Canadian Fertilizers

Medicine Hat, AB


168,000 0

Celanese Edmonton, AB

134,000 cellulose acetate,

formaldehdye, methanol

134,000 10,000 On Praxair pipeline, needs purification when customer found

Degussa Gibbons, AB

3,000 hydrogen peroxide

3,000 0 43000 Nm3/hr from Praxair pipeline, 3,300 Nm3/hr from own SMR

FMC Prince George, BC


0 3,000

Methanex Kitimat, BC 170,000 methanol 170,000 0

Methanex Medicine Hat, AB

150,000 methanol 0 0 Facility moth-balled - up to 150,000 t/y could be available

Saskferco Belle Plaine, SK


86,000 0

Simplot Brandon, MB

83,700 ammonia, ammonium nitrate,

urea

83,700 8,600 Could give small surplus of hydrogen ~ 10mscf/day.

*Sherritt Gordon

Fort Saskatche-wan, AB

15,000 15,000 0 Also may purchase from Praxair

Total 1,071,400 912,900 26,100


Chemical Process By-Product



Prod’n (t/y)

Sold to Others

Surplus Remarks

Cancarb Medicine

Hat 26,000 20,000 Most H2 is presently

used for process heat, some to steam ~ 30 MW power to city.

Chemtrade Pulp Chemicals

Prince George, BC

4,000 sodium chlorate

4,000 4,000 t/y sold to FMC for hydrogen peroxide production

0

Dow Chemical Ft Saskatche-wan, AB

14,000 chlorine, caustic

soda, hydrogen

chloride

14,000 7,000

ERCO Bruderheim, AB


3,100 3,100 By-product H2, about 75% for internal fuel use; remainder vented

ERCO Grand Praire, AB


4,000 4,000 By-product H2 from sodium chlorate manufacture

ERCO Hargrave, MB


2,000 2,000 By-product H2 from sodium chlorate manufacture

ERCO Vancouver, BC


5,500 5,500 By-product H2 - vented to air

ERCO Saskatoon, SK

5,000 sodium chlorate, chlorine,

caustic soda

5,000 0 Captive for hydrogen chloride production

Nexen Brandon, MB


11,245 2,982 By-product H2 from sodium chlorate manufacture, 7,138 t/yr used as fuel. 30-40% expansion by end of 2004

Nexen Bruderheim, AB


4,069 1,802 By-product H2 from sodium chlorate manufacture, 1,860 t/yr used as fuel, 407 t/yr ventilation mgmt, Remainder vented

Nexen Nanaimo, BC


1,500 1,269 Vented to air.

Nexen Vancouver, BC

4,000 chlorine, caustic

soda

4,195 0 Most is fuel, 3,100 t/yr. Some sold for re-refining of oil or used internally for HCL ~ 1,154 t/yr.

Dow LHC-1 Ft Saskatche-wan, AB

140,000 ethelyene 140,000 100,000 t/y sold to Shell

40,000 Check this surplus - may reflect Dow share of Joffre

Nova Chemicals - E-1,2,&3

Joffre, AB 240,000 ethylene 180,000 100,00 t/y sold to Agrium, 0.2 t/y sold to Air Liquide

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

Total 463,000 398,609 147,653


Hydrogen Pipe Lines



Production

Sold to Others

Surplus Remarks

tonne/year

Praxair Strathcona, AB, to Fort Saskatchewan

80,000 hydrogen 18,000 From Celanese methanol plant to Dow, Shell, Degussa

28,000 t/y additional capacity exists from Celanese if PSA is expanded. 30 km. 8 inch pipeline @ 800 psig.

Western Total

80,000 18,000 0


Eastern Region

Oil Refinery Company Plant


Product Prod’n Sold Surplus

Remarks

tonne/year

Imperial Oil Sarnia, ON 39,000 petroleum prods

39,000 0 Reported volume appears low. Has H2 catalytic reformer.

Imperial Oil Nanticoke, ON

54,362 petroleum prods

54,362 0

Petro-Canada Mississauga ON


9,000 0

Petro-Canada Montreal East, PQ


125,000 0 Capacity was increased in 2003.

Shell Canada Corunna, ON


17,000 0 Depending on feed H2 capacity is about 15mstc/day from CR3 reformer

Shell Canada Montreal East, PQ


45,000 0 Depending on feed, capacity is 30-35mstc/day. Trying to increase daily feed by 15%. Additional H2 is purchased from Coastal and Petromont.

Sunoco Sarnia, ON 48,000 petroleum products

48,000 0 H2 capacity also treats some of Shell diesel fuel production

Ultramar/Valero Levis, PQ 100,000 Petroleum products

100,000 Facility is 2nd largest Canadian refinery

Total 437,362 437,362 0

Chemical Process Use



Prod’n Sold Surplus Remarks

tonne/year

ADM - Archer Daniels Midland

Windsor, ON 1,075 Hydrogen-ated veg. oil

591 0 SMR unit on stream in 1996, production as needed, operating 50-60% of capacity

Kemira Chemicals

Maitland, ON


3,000 0

Terra International

Courtright, ON


70,000 0

Total 74,075 73,591 0


Chemical Process By-Product Production



Production

Sold Surplus Remarks

tonne/year

Coastal Petrochemicals

Montreal East, PQ

9,000 xylenes 9,000 0

Eka Chemicals Magog, PQ 6,000 sodium chlorate

5,100 Sold to BOC for liquid H2 production (5.9 million SCF/day), burned as fuel or vented

900 By-product H2, burned as fuel or vented

Eka Chemicals Valleyfield, PQ


6,000 6,000 By-product H2, burned as fuel or vented

ERCO Buckingham PQ



ERCO Thunder Bay, ON



Nexen Chemicals

Amherstburg ON


3,060 2,754 By-product H2, 306 t/yr internal requirements (Vent mgmt control), excess vented

Nexen Chemicals

Beauharnois PQ


2,552 2,500 By-product H2, burned as fuel 1,250 t/yr, remainder vented

Nova Chemicals Corunna, ON

15,000 ethylene 15,000 0 Ethylene by-product, H2 is consumed captively for reforming or fuel use

Nova Chemicals Sarnia, ON 7,000 styrene 7,000 Sales to Air Products 11,500 SCF/day

0 Styrene by-product, H2 for captive purposes

PCI Chemicals Becancour, PQ

8,000 caustic soda, chlorine

8,000 H2 is pipelined to ATOFINA Canada Inc's H2O2 plant or liquified by HydrogenAl.

0

Petromont Varennes, PQ

5,000 ethylene 5,000 H2 is sold to adjacent Petromont Olifins plant

0 Ethylene by-product

Allgoma, Dofasco, Stelco

Ontario 0 Coke oven off-gas

0 Medium purity H2. Estimated 100,000 t/y. Not successfully recovered to date.


Total 72,000 70,712 22,154

Merchant Gaseous Hydrogen Production



Production


tonne/year

Air Liquide Hamilton, ON

2,200 hydrogen 2,200 80% sold to steel mills, rest sold as merchant market

0 Also has 500 SCF/day compressor

Air Products Sarnia, ON 11,000 hydrogen 11,000 Receives H2 as a by-product from Nova Chemicals styrene manufacture.

HydrogenAL Becancour, PQ

3,500 hydrogen 3,500 Up to 4000 t/y sold to Hydrogen AL by Atofina

0 H2 from PCI Canada’s (7 metric t/d) HydrogenAL’s has 3,500 t/y steam reformer

Total 16,700 16,700 0

Hydrogen Pipe Lines



Production


tonne/year

PCI Chemicals Becancour, PQ

8,000 hydrogen 8,000 . 8,000 H2 is pipelined to Kemira’s H2O2 plant or liquified by HydrogenAl

Petromont Pipeline Varnnes, PQ 10,000 hydrogen 8,000 0 H2 is piped across St. Lawrence, serves facilities of several companies. Estimated 10 kms total.

Eastern Total 18,000 16,000 8,000


Atlantic Region

Oil Refinery


Capacity Production Principal Product

Sold to Others

Surplus Remarks

tonne/year

Imperial Oil Dartmouth, NS

12,000 12,000 petroleum products 0 H2 estimated by Dalcor. H2 by-product from refinery reformer

Irving Oil St John, NB

100,000 100,000 petroleum products 0 H2 estimated by Dalcor. Facility is largest Canadian refinery

North Atlantic Refining Come By Chance, NFLD

110,000 110,000 petroleum products 0 H2 from platformer as off-gas and from steam reformer unit

Total 222,000 222,000 0

Chemical Process Production


Capacity Production Principal Product

Surplus Remarks

tonne/year

PCI Chemicals Dalhousie, NB

2,000 2,000 caustic soda, chlorine, sodium chlorate

0 By-product H2, captive use for HCl

St Anne Chemical Nackawic, NB

690 690 caustic soda, chlorine, sodium chlorate

0 By-product H2, captive use for HCl

Atlantic Total 2,700 2,700 0

1Canadian Hydrogen August 2004 Page B

Appendix B Scenario – “Soldiering On”: Projected Demand by Reg ion

& Sector (2013 & 2023): Data tables

BCanadian Hydrogen August 2004 Page B

APPENDIX B – “ Soldiering On” Scenario Projected D emand by Region & Sector (2013 and 2023)

CANADIAN HYDROGEN PRODUCTION and SURPLUS BY SECTOR AND REGION (tonnes/year) SCENARIO - "SOLDIERING ON"

2003 - Capacity 2003 - Production 2003 - Surplus 2013 - Production 2013 - Est.Surplus 2023 - Production 2023 - Est.Surplus

Western Region (t/yr) (t/yr) (t/yr)

Oil Refining 198,270 185,355 0 237,254 0 270,618 0

Heavy Oil Upgrading 770,000 770,000 0 1,860,000 0 3,096,000 0

Chemical Industry 912,900 912,900 26,100 1,287,736 36,817 1,648,410 47,128

Chemical Industry By-product 463,000 398,609 147,653 523,976 194,092 661,127 244,895

Merchant Gas 0 0 0 865 17272

Sub-total 2,344,170 2,266,864 173,753 3,909,831 230,908 5,693,428 292,024

Central Region

Oil Refining 437,362 437,362 0 559,823 0 638,549 0

Chemical Industry 74,075 73,591 0 94,203 10,000 114,833 12,190


Merchant Gas 16,700 16,700 0 21,930 0 32416 0

Sub-total 600,137 598,365 22,154 760,781 36,575 884,946 43,253

Atlantic Region

Oil Refining 222,000 222,000 0 284,160 0 324,120 0

Chemical Industry 0 0 0 0 0 0 0

Chemical Industry By-product 2,690 2,690 0 2,408 1,000 2,836 1,178

Merchant Gas 0 0 0 141 0 3715 0

Sub-total 224,690 224,690 0 286,710 1,000 330,671 1,178

Total Canadian Production/Surplus 3,168,997 3,089,919 195,907 4,957,321 268,484 6,909,045 336,455

Sector Totals 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




Merchant Gas 16,700 16,700 0 22,936 0 53,402 0

Canadian Hydrogen August 2004 Page C 1

Appendix C Scenario – “Carbon Conscious Agenda”: Projected

Demand by Region & Sector (2013 & 2023): Data tabl es

Canadian Hydrogen August 2004 Page C 2

APPENDIX C – “Carbon Conscious Agenda” scenario Pro jected Demand by Region & Sector (2013 & 2023)

CANADIAN HYDROGEN PRODUCTION and SURPLUS BY SECTOR AND REGION (tonnes/year) SCENARIO - "LOW-CARBON"

2003 - Capacity 2003 - Production 2003 - Surplus 2013 - Production 2013 - Est.Surplus 2023 - Production 2023 - Est.Surplus


Oil Refining 198,270 185,355 0 237,254 0 255,790 0




Merchant Gas 0 0 0 865 7557.914094 0

Sub-total 2,344,170 2,266,864 173,753 3,392,804 216,559 4,818,935 257,760

Central Region

Oil Refining 437,362 437,362 0 559,823 0 603,560 0



Merchant Gas 16,700 16,700 0 18,613 0 14356.82982 0

Sub-total 600,137 598,365 22,154 745,641 35,452 838,643 44,088

Atlantic Region

Oil Refining 222,000 222,000 0 284,160 0 306,360 0



Merchant Gas 0 0 0 141 0 1570.202095 0

Sub-total 224,690 224,690 0 286,622 1,000 310,577 1,140



Oil Refining 857,632 844,717 0 1,081,238 0 1,165,709 0




Merchant Gas 16,700 16,700 0 19,619 0 23,485 0

Canadian Hydrogen August 2004 Page D 1

Appendix D Scenario – Hydrogen Priority Path: Projected Demand by Region &

Sector (2013 & 2023): Data tables

Canadian Hydrogen August 2004 Page D2

APPENDIX “D” – “Hydrogen Priority Path” Scenario Pr ojected Demand by Region & Sector (2013 & 2023)

CANADIAN HYDROGEN PRODUCTION and SURPLUS BY SECTOR AND REGION (tonnes/year) SCENARIO - "HYDROGEN PRIORITY PATH"

2003 - Capacity 2003 - Production 2003 - Surplus 2013 - Production 2013 - Surplus 2023 - Production 2023 - Surplus


Oil Refining 198,270 185,355 0 231,694 0 240,962 0




Merchant Gas 0 0 0 1,869 47,197

Sub-total 2,344,170 2,266,864 173,753 3,412,926 226,953 4,726,727 277,229

Central Region

Oil Refining 437,362 437,362 0 546,703 0 568,571 0



Merchant Gas 16,700 16,700 0 20,438 0 89,123 0

Sub-total 600,137 598,365 22,154 746,787 36,575 878,223 43,864

Atlantic Region

Oil Refining 222,000 222,000 0 277,500 0 288,600 0



Merchant Gas 0 0 0 415 0 10,451 0

Sub-total 224,690 224,690 0 280,323 1,000 301,887 1,178



Oil Refining 857,632 844,717 0 1,055,896 0 1,098,132 0




Merchant Gas 16,700 16,700 0 22,721 0 146,770 0

Canadian Hydrogen August 2004 Page E1

Appendix C

Companies & Organizations Active in Hydrogen Produc tion,

Transportation and Storage


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: Dr. Partho Sarkar Dean Richardson Dr Ian Potter Group Leader, FC Research Venture Manager Director Phone: (780) 450-5272 (780) 450-5334 (780) 450-5401 Fax: (780) 450-5477 (780) 450-5334 (780) 450-5083 Email: [email protected] [email protected] [email protected]

2. CANMET Energy Technology Centre Natural Resources Canada 580 Booth Street, 13 th 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


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: Nick Beck Chief, Transportation Energy Technologies CANMET Energy Technology Centre – Ottawa Phone: (613) 996-6022 Fax: (613) 996-9416 Email: [email protected]

3. Centre for Automotive Materials and Manufacturin g

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.

Contact: Dr. Floyd R. Tuler Executive Director

Phone: (613) 547-6459 or (613) 547-6700 Fax: (613) 547-8125 Email: [email protected]

4. Dynetek Industries Ltd.


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: Robb Thompson President & CEO

Phone: (403) 720-0262 Fax: (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.

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".

Contact: Jeff Sim Business Manager, Distributed Energy

Phone: (416) 495-5281 Fax: (416) 495-6163 e-mail : [email protected]


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: Ralph Rackham VP – Engineering & Research Phone : (416) 674-3034 Fax: (416) 674-3042 E-mail: [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: Dave Dacosta Director, Business Development Phone: (450) 651-1200 ext 208 Fax: (450) 651-1209 Email: ��


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 Phone: (819) 376-5139 Fax: (819) 376-5164 Email: [email protected]

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.


Contact: Dr. Ned Djilali Executive Director IESVic and Professor of Mechanical Engineering

Phone: (250) 721-6295 Fax: (250) 721-6323 E-mail: [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 Phone: (604) 822-4343 Fax: (604) 822-1659 E-mail: [email protected]

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


• 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: Erica Branda Communications Officer Phone: (604) 221-3099 Fax: (604) 221-3001 E-mail: [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: Jonathan Rhone President & CEO Phone: (604) 222-5513 Fax: (604) 22-5516 E-mail: ��


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 George A.E. Cook. P. Eng Malcolm Cameron President and CEO Principal Electrical Engineer Phone: (604) 681-2030 (604) 681-2030 Fax: (604) 683-9164 (604) 683-9164 E-mail: [email protected] [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).


Now seeking ~$1M to bring Russian scientists to BC (set up at Powertech Labs). The business model = licensing or strategic partnerships.

Contact: Stuart Lew,

Co-Chairman and Chief Executive Officer Phone: (604) 734-7488

Fax: (604) 734-7484 Email: [email protected]

www.powernova.com

15. 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 Phone: (514) 781-1998 Fax: (514) 842-0162 E-mail: [email protected]

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


developers of hydrogen fueling infrastructure. QuestAir’s strategic partners include Shell Hydrogen, Ballard Power Systems and The BOC Group.

Contact: Mr. Mark Kirby Director, Business Development Phone: (604) 454-1134 ext 204 Fax: (604) 454-1137 E-mail: [email protected]

17. 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 Phone: (613) 541-6000 ext: 6272 Fax: (613) 542-9489 E-mail: [email protected]. or [email protected]

18. Saskatchewan Research Council

125 - 15 Innovation Blvd. Saskatoon, SK S7N 2X8 Website: �� Product: ��

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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 on-demand Hydrogen Energy Stations.

Contact: Wanda Cutler Director of Marketing and Communications Phone: (905) 282-7769 Fax: (905) 282-7777 E-mail: [email protected]

20. 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: Dr. Raphael Idem. P. Eng Associate Professor Faculty of Engineering Phone: (306) 585-4470 Fax: (306) 585-4855 E-mail: [email protected]


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 F1

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��.��&�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

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4. 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-to-

chemicals, 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.


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.


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,

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NOTES

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