Let's go to the vote, then.
(Motion agreed to)
The Chair: Let's get to the witnesses.
Thank you all very much for that.
We're continuing our study on innovation in the energy sector. We have with us today here in the room, from Gradek Energy, Thomas Gradek, president. From Titanium Corporation we have Scott Nelson, president and chief executive officer.
By video conference we have, from Edmonton, Alberta, from Alberta Innovates Technology Futures, Brent Lakeman, general manager, and Mary Pat Barry, vice-president of communications. Welcome to you.
Also by video conference, from Paris, France, from the International Energy Agency, we have Keisuke Sadamori, director of energy markets and security; Adam Brown, energy analyst, renewable energy division; and Anne-Sophie Corbeau, gas analyst. Welcome to all of you from Paris, as well.
One of the witnesses isn't at the table yet. Often we have delays getting into the building, so we will start with the second witness on the list today, who is Scott Nelson, president and chief executive officer of Titanium Corporation.
Would you go ahead with your presentation, sir, for up to 10 minutes? Again, thank you very much for being here today.
First of all, thank you, Mr. Chairman and committee members, for the opportunity to appear today to describe a “made in Canada” solution to one area of oil sands tailings. Our technology will dramatically reduce emissions and recover bitumen, solvents, and valuable minerals currently being lost in tailings ponds.
Canada has a unique opportunity to create a new minerals export industry. Our company, Titanium Corporation, is federally incorporated and listed on the Toronto Stock Exchange. Our people hold advanced degrees and have deep experience in the oil sands and mineral sands industries.
Over the past seven years, our team of scientists has developed innovative technology solutions that remediate one of the most complex oil sands tailings streams, called froth treatment tailings. Our company holds six patents, and our technology has been prioritized and ranked in the top 20 technologies in the recent oil sands industry COSIA technology road map. The Alberta government is developing a new fiscal regime to support the production of minerals from oil sands and the recovery of bitumen from tailings.
Our shareholders have invested more than $50 million in developing these technologies, and government has invested more than $10 million, including $6.3 million of Canadian government Sustainable Development Technology Canada grant funding. Over the past three years, SDTC support has been highly valuable and instrumental in our success.
Our scientists have worked with the leading research and testing firms in Canada and the United States to find solutions, rigorously test them, and bring these technologies to commercial readiness. We have followed a highly disciplined program, involving more than 20 R and D projects with 12 expert organizations.
Before I describe the outcomes and benefits, I would like to briefly explain the oil sands tailings area we are dealing with.
We are working in the mining oil sands sector, in which large volumes of ore are truck-and-shovel mined. A hot water process separates the bitumen from the ore and creates large volumes of fluid tailings—sand, water, and bitumen. This process produces an intermediate product called bitumen froth.
After the extraction process, the bitumen froth is sent to another process, called froth treatment. In this process, a hydrocarbon solvent such as naphtha or condensate is mixed with the froth to remove the remaining bitumen and sand, creating a final bitumen product for upgrading on-site to light synthetic crude oil or for dilution and pipelining to refineries that can accept heavy crudes.
As in any large industrial process, there are small percentage losses after processing. However, due to the massive volumes of material processed by the oil sands, even small percentages amount to very significant values. The tailings from the froth treatment process contain losses of 2% to 3% of the original bitumen, lost solvent, and valuable heavy minerals. Today, all of the tailings streams discharge to tailings ponds, where the solvents and bitumen cause VOCs—volatile organic compound air emissions—and GHGs. The minerals are lost in the tailings ponds.
Our primary interest in the oil sands has been recovering minerals and creating a new minerals export industry for Canada. Along the way, we saw the opportunity to also recover hydrocarbons, which would reduce environmental impacts and create another value chain.
The benefits of implementing our technology at the oil sands mining sites, based on today's production volumes, are very significant for Canada. We would create a new minerals industry exporting 170,000 tonnes per year of zircon to Asian markets, valued at $425 million annually at today's prices. Some 28,000 barrels per day of bitumen that are being lost in tailings ponds would be recovered, at a value of $700 million per year. In total, this means more than $1 billion of additional resource recovery and more than $400 million of associated taxes and royalties to governments.
In the next decade, at projected growth rates for the mining sector, the annual value of additional resource recovery with our technology would surpass $3 billion per year. The environmental benefits are equally impressive. Recovering lost bitumen and solvents would eliminate 80% or 60 kilotonnes per year of volatile organic compound emissions from oil sands extraction and would reduce GHGs by 5.6%, or almost one megatonne per year of GHGs.
After our technology removes the hydrocarbons and minerals, the water from these tailings streams can be used for other services in the oil sands that currently use fresh river water. River water usage could be reduced by a further 25%. All of these outcomes have been validated by independent analytical and engineering firms.
Following recovery of commodities by our technology, the residual tailings will thicken much faster than at present, and the requirements for thickeners or polymers are less than for the other thickening methods.
Titanium Corporation has become expert in heavy minerals, and we see an exciting opportunity for Canada to enter international markets. Our management team has made numerous visits to Asia and to the world's largest and most rapidly growing markets in China. We have a vice-president stationed in Brisbane, Australia, the heart of the minerals production and technology industry, where we conduct our minerals testing with expert partners. We plan to first produce zircon, due to its relative higher value, and later on produce titanium. Zircon is primarily used to make ceramic tiles and other products that we use in everyday life. Zircon currently sells for $2,400 per tonne versus mined titanium, called ilmenite, which is valued at $300 per tonne.
We have completed the detailed R and D and demonstration piloting required to commercialize the three naphtha-based oil sands operations: Syncrude, Suncor, and CNRL. Over the past two years we conducted a $15 million demonstration pilot at CanmetENERGY for these firms.
Based on third party engineering cost estimates, facilities to recover minerals and lost bitumen at a large oil sands site are approximately $400 million. At these cost levels, the capital and operating costs of recovering lost tailings bitumen are one-third the cost of newly mined bitumen of similar volumes. The conclusion here is that innovative technology that recovers products from waste is highly efficient. This is the low-hanging fruit that many industries are harvesting.
We have a unique opportunity to move Canada's oil sands to the forefront, from a widely criticized and defensive position to a leader in innovation and recovery of value from waste.
Following the completion of our demonstration pilot last year, we have provided detailed technical reports to all of the participating oil sands firms, government agencies, third party independent experts, and other stakeholders. All agree that together with our industry, research, and independent partners, we have taken all measures to demonstrate the strong performance of our technology.
Despite the compelling benefits, industry has not moved forward with the first project, and we are concerned with the delays. The reasons for delays can vary, including regulations that focus on tailings volume reduction but not on recovery of any valuable products, no regulations around VOC emissions, concerns about the risks of new technologies, lack of resources in the oil sands for new projects, and a focus on operational reliability.
We fully understand these business pressures. However, there is a window of opportunity to create a minerals industry for Canada, to resolve an area of environmental concern, and to improve resource recovery.
In light of delays, we have been reaching out to stakeholders to inform you of our work, our success, and the opportunities that are now available. We have developed relationships with large international mining markets and customers for minerals, bringing them to Canada and the oil sands. They are keen to participate, but need to see willingness here in Canada by stakeholders to move forward.
Canada's energy sector is facing serious challenges, including growing new oil and gas supplies in the United States, opposition to pipeline projects to export markets, and price discounts affecting higher-cost crudes, particularly the oil sands. Canada's oil sands industry is the subject of widespread environmental concerns, threatening the industry's social licence to operate.
These issues combine to threaten Canada's future development of our energy resources and the country's economic prosperity. Projects like Titanium's address a number of these issues and must be moved ahead rapidly with support by government stakeholders.
We appeal to government, already invested in our successful R and D and demonstration piloting as a stakeholder, to lend your support to develop a collaborative venture to move the first project forward.
We believe there is a role for the ministries of natural resources, environment, and perhaps international trade to facilitate a new industry for Canada for the benefit of all Canadians.
I'd like to thank you for the opportunity to appear before the committee, and I look forward to any questions you may have.
Good morning, committee members.
I would like to thank the standing committee for inviting Alberta Innovates Technology Futures to present before the standing committee. I would like to send the regrets of our president and CEO, Mr. Stephen Lougheed, who is unable to be here today due to other commitments.
I'm pleased to see that the standing committee is reviewing the topic of innovation in Canada’s energy sector. This is a very important topic for my organization and for the Alberta government. While I will be speaking today on the topic of CO2 capture and storage, Alberta Innovates Technology Futures, or AITF, is actively advancing a wide range of technologies to support environmentally sustainable energy production.
Briefly, part of the Alberta Innovates system, Technology Futures, comprises over 600 staff in five research facilities in Alberta. We undertake technical services and strategic research as well as the development and commercialization of technologies. We also administer programs designed to attract technical and scientific talent to Alberta and fund other academic institutions to stimulate research in emerging areas, including nanotechnologies, information and communication technologies, and “omics”.
AITF currently manages over $160 million in total revenue. We provide grants to universities and other institutions, undertake contract research work, and work with a wide range of clients, including industry, government organizations, and not-for-profit institutions.
Technological innovation has been a fundamental component of Alberta’s energy sector for over a century. The province’s early investments in science and research resulted in Dr. Karl Clark's developing the hot water process for oil sands extraction in 1921, a process that became the foundation for the first commercial oil sands project in 1967.
After commercializing the hot water process, Alberta recognized the need to invest in technologies to unlock the remaining oil potential found in Canada’s oil sands resource. In 1974 the Alberta Oil Sands Technology and Research Authority, AOSTRA, was created. AOSTRA pursued a range of technologies, including steam-assisted gravity drainage or SAGD, that have been instrumental in developing deeper in situ oil sands resources.
SAGD had marked advantages over earlier technologies. It enhanced bitumen recovery rates by up to 45%, significantly lowered natural gas—
I'll move to carbon management.
Just as the province was a champion and an investor in oil sands technologies, Alberta has also been a leader in advancing the global adoption of carbon management technologies, including CO2 capture and storage. It was through the innovation and foresight of scientists in Alberta that CCS, or CO2 capture and storage, was identified as a key technology for carbon management and value-added resource recovery. As other nations started to investigate this option, the International Energy Agency estimated in 2008 that CCS could lead to approximately 17% of the global emission reductions necessary to prevent dangerous levels of greenhouse gases in our atmosphere. Alberta's work in this area, which dates back to the late 1980s, contributed to building the base of support in industry and government that has led to significantly larger-scale demonstrations, complemented by a supportive regulatory framework.
Currently, Alberta and Canada are regarded internationally as the leading jurisdictions for advancing CCS technologies in a timely and effective manner. What do these two examples have in common? They demonstrate the value of early investments in key technical capabilities; a collaborative approach involving industry, government, academia, and other stakeholders; and the wisdom of a clear road map and vision in unlocking the potential of these resources and technologies.
Before I get into the specific innovation topics the committee is exploring, I would like to summarize the process known as CO2 capture and storage, or CCS.
While the focus is typically on the capture, transport, and storage of carbon dioxide associated with industrial facilities, it is important to remember that the process for converting the resource—coal, bitumen, oil, or natural gas—into useful energy, such as electricity, greatly influences the technologies and costs of CO2 capture.
For example, a coal gasification process will result in a high-purity and high-pressure stream of CO2 that can be captured relatively easily. Conventional coal combustion technologies used for power generation, while lower cost, result in low-purity and low-pressure CO2 streams that require more expensive CO2 capture systems.
Depending on the nature of the CO2stream, different technologies can be used to capture it, including conventional amine chemical-based systems. Emerging capture technologies include the use of membranes and solid absorption, and other technologies. Over the past decade there has been a global effort to develop new approaches for CO2 capture that are less costly and less energy-intensive than the current amine processes.
The CO2 enters a pipeline, where it is transported for storage in a geological formation or utilized for value-added resource recovery. Formations where CO2 is injected are at least one kilometre underground, beneath several layers of non-permeable caprock. The formation may be a deep brine formation or a depleted oil and gas well, an underground coal seam, or an existing oil reservoir. Each formation will have undergone a detailed geological characterization. As with other similar industrial practices, companies model the expected behaviour of the CO2 and undertake surface and subsurface monitoring to verify that the CO2 is behaving as predicted.
It is important to recognize that in addition to the technological issues related to CCS, there are a variety of important socio-economic factors that must be taken into consideration, including public and stakeholder perspectives and financial and economic analysis, all of which can be as important to a project as the technical details.
Canada has built its leadership in CCS literally from the ground up. Recognizing that one can't import geology, Canada has based its leadership on the country's significant geological endowment. The western Canadian sedimentary basin, spanning the four western provinces, is truly a world-class location for CO2 storage. The same geological forces that have provided Canada with vast amounts of oil and natural gas and coal also provide value-added opportunities for using CO2 as well as for storing it in a safe and permanent manner. Our geological expertise around CO2 storage and other similar applications is sought out from around the world, with our experts collaborating with leading international organizations in advancing CCS technologies.
Our leadership is also a reflection of the extensive regulatory framework that has been established to manage oil and gas development in Alberta. Because Alberta has had the foresight to develop regulatory expectations related to applications such as CO2 enhanced oil recovery and acid gas injection, the province has been able to move forward in a clear and logical manner in the regulation of future CCS projects. Alberta's CCS regulatory framework assessment process, which will soon be delivering recommendations back to government, is providing leadership to other jurisdictions from around the world that are now starting to advance their own CCS projects. As well, Alberta experts have made contributions to a new CCS standard recently developed through the Canadian Standards Association.
Alberta's leadership comes from the collaborative approach the province has taken in engaging industry, the academic sector, and government. This approach has been used by organizations such as Carbon Management Canada, which pulls together 27 research institutions from across Canada to pursue interdisciplinary research related to CCS.
Much of our focus is on key industry sectors, such as oil sands producers searching for carbon management solutions. While the costs of CCS technologies will be higher in the oil sands sector due to the dilute nature of much of its CO2 emissions, reducing capture costs will result in an acceleration of the deployment of CCS technology in this sector.
Where should we focus our efforts? With respect to CCS, the issue is not necessarily one of research but of accelerating commercial deployment of integrated CCS systems to reduce costs for greater economy of scale deployment. Globally this has been challenging, as the focus has been on integrating CCS into the coal-based power generation sector, a typically risk-averse sector. The situation is further complicated in North America, where low-cost natural gas resources have deferred investment in CCS demonstration projects.
Since 2008 there has been a global effort to acquire practical experience with CCS through commercial or near-commercial demonstrations. In Alberta, the Quest project at the Shell Scotford upgrader and the Alberta Carbon Trunk Line that will take CO2 from the proposed North West upgrader in Fort Saskatchewan are being closely watched. In Saskatchewan, the Weyburn CO2 EOR project has been a leading example of CO2 injection for over a decade, and the proposed aquastore project will allow for CO2 capture and storage associated with SaskPower’s coal-fired power generation facility at Boundary Dam.
CO2 capture costs remain significantly higher than costs of CO2 compliance. For example, while Alberta has a CO2 charge of $15 per tonne for CO2 emissions above regulated levels, the cost to implement CCS at an in situ oil sands project may be more than $150 per tonne of CO2. I put together a chart that's prepared by Alberta’s CCS Development Council, which shows the gap between CCS costs and the benefits of action, including avoided compliance costs and the sale of CO2 for value-added activities.
Industry and governments are investing in a range of alternative technologies for CO2 capture, and some of them will ultimately drive down capture costs, but the challenge is enormous. In Alberta, organizations such as the province’s Climate Change and Emissions Management Corporation, known as CCEMC, have recently invested in several projects aimed at driving down CO2 capture costs.
In the short to medium term, what is required is an economic driver encouraging CO2 use, such as the production of more oil from depleted formations or the production of new products with existing markets. While CCS represents a backstop technology that can be turned to when no other options are available, it would be preferable to find ways to make use of CO2 so that it ultimately does not need to be captured at a high cost and stored in geological formations.
Finally, we should not forget about building greater public understanding and confidence. In certain jurisdictions like Alberta, there is a strong history and good understanding of subsurface operations such as oil and gas operations. In many other jurisdictions, however, there is a degree of public fear and distrust about this technology. For example, the Netherlands has recently seen public opposition result in the cancellation of several industrial CCS projects.
Thank you, Chairman, for giving us the opportunity to talk about natural gas, oil, energy efficiency, carbon capture and storage, and renewables.
First let me focus on the natural gas. Canada has been exporting natural gas to its southern neighbour for decades, and until the end of the last decade, nobody expected that trend to change. On the contrary, U.S. gas production was seen by many as stagnating and ultimately declining. Mexico was slowly turning into an LNG importer.
Then the shale gas output in the United States was multiplied by a factor of 10 between 2005 and 2011, and this changed everything. Canada’s gas exports to the United States declined abruptly, leading to a 30-bcm drop in production from 2005 to 2011, to 160 bcm. More important, since 2011 the United States has been pushing more gas towards its two neighbours because of the oversupply in its own market.
Mexico is importing less LNG and more Henry Hub indexed gas from the United States. The worst may still be coming as Marcellus, the prolific shale player in the northeast of the United States, is just at the beginning of its development.
But Canada has gas, conventional and unconventional. Tight gas has been produced for a long time, while shale gas is still in its infancy. The only problem is that this gas, once the transport costs to bring it to the United States are added, may no longer be competitive enough against U.S. natural gas production.
Additionally, there are concerns regarding the environmental impacts of developing shale gas, but shale gas can be produced in a way that respects the environment, as our recent report, “Golden Rules for a Golden Age of Gas”, demonstrated.
In order to stabilize gas production and revenues from gas exports, Canada should look at other markets. There is only one solution—LNG exports. Japanese, Korean, and Chinese companies have been acquiring assets on the west coast of Canada to bring the gas back home. Two of these projects have been given authorization to export.
These projects have one crucial advantage: they are better located than the U.S. projects, most of which are located in the Gulf of Mexico. Many U.S. LNG projects are based on existing LNG import facilities, so the investment costs will be lower. The U.S. greenfield projects, however, will not benefit from this advantage. Similarly, most new planned LNG projects in the world in Australia, Papua New Guinea, Africa, and Russia will be greenfield projects, and their development costs will depend on the specificities of the LNG projects.
Finally, there is the question of the price at which this gas will be exported, or rather of the indexation, oil or spot. The only LNG project recently sanctioned in North America, Sabine Pass, will be based on Henry Hub indexation, but it is sourcing its supply on the wider U.S. gas market, while the Canadian LNG projects will depend on the more dedicated—and still to be developed—sources of gas supply in western Canada.
International oil companies involved in these LNG export projects may prefer the traditional oil indexation, similar to what has taken place in Australia, but if Asian buyers are involved in the project, they may push towards spot indexation, either Henry Hub or its Canadian brother, AECO. Unlike in North America and Europe, there is no spot price in Asia. The IEA has been recently working on a report looking at how a spot market could be developed in Asia. This report will be issued in early 2013.
Second, there is oil. Canada is also an oil-rich country. Let us now have a look at the development of oil resources, notably oil sands.
In the medium term, the production of oil sands is expected to increase by 1.1 million barrels per day to 4.6 million barrels per day by 2017. Increasing volumes of Canadian bitumen production will still find their way to U.S. markets as heavy oil refining capacity is added, but Canadian producers will have to seek new markets and new transport solutions.
Looking forward, there are clearly political and local constraints to expanding, reversing, and/or building new pipelines. It is clear that Canada, along with the provinces, is looking for new options, but in the meantime output is rising quickly. Tight pipeline capacity is one of the major reasons that Canadian crudes are priced at a discount to WTI, but the spike in the discounts has hurt Canadian producers’ bottom line this year, and companies are now openly questioning to what extent they will remain a fixture in the market in 2013 and the medium term.
Canadian oil sands are set to play a key role in the medium term by raising the non-OPEC supplies by an additional 1.1 million barrels per day. That's the second-largest source of growth among the non-OPEC countries besides the United States, but Canada's projects will compete for financing, labour, and takeaway capacity with the rising output of tight light oil in the United States. As a result, these constraints and market dynamics are expected to delay around 200,000 to 300,000 barrels per day of Canadian oil sands output to beyond the 2017 timeframe.
Canada should be commended for its proactive approach to improving the social licence to produce from world-class oil sands resources. Now the challenge moves outside Alberta. The solutions of minimizing environmental and social impacts are based on technological and process innovation, and I want to recognize and commend the efforts industry is making in these areas, especially through such collaborative efforts as COSIA, but I urge industry to redouble those efforts and I remind you that the onus is on producers.
My point with regard to responsible unconventional oil and gas production is simple. This is not just good PR, it is good business. It is in all our interests that these industries remain healthy and welcome to operate.
Third, let me turn to energy efficiency. The release of the World Energy Outlook this month highlights the vast scale of what we call “the hidden fuel”, the energy efficiency. Despite the vast scale and high economic returns, it's not always easy to engage all the different consumers and decision-makers in the imperative to improve energy efficiency.
Canada has higher energy intensity, adjusted for PPP, than any IEA member country. This is largely due to its concentration of output in energy-intensive sectors: cold climate, large distances, and high standard of living. Final energy consumption has grown continuously over the past decade, though at a lower rate than the economy as a whole.
Canada's energy intensity, adjusted for PPP, has declined on average by 1.4% between 1990 and 2009 due mainly to the energy efficiency improvements, and this improvement in energy efficiency, led by the Office of Energy Efficiency at Natural Resources Canada, is the progress IEA is delighted to see.
Canada has strengthened energy efficiency policies across all sectors—industry, buildings, transport, and utilities—in the past two years. In July 2011 Canada’s energy ministers agreed to a collaborative approach to energy with a companion action plan. Specific areas covered by the plan include a more stringent model energy code for buildings, a next-generation energy rating system for homes, project financing tools, transportation, product regulation, and industrial energy management standards.
Fourth, let me turn to carbon capture and storage, CCS.
Canada has been actively supporting and developing carbon capture and storage technologies, both on a federal and a provincial level. The provinces of Alberta and Saskatchewan especially have been at the forefront of development. Saskatchewan is host to one of the best-known CCS projects in the world in Weyburn, successfully combining the long-term storage of CO2 and enhanced oil recovery with CO2. The main power utility in the province, SaskPower, also has a large power sector CCS project under construction. Furthermore, with significant financial support from the Province of Alberta, Shell has recently announced its investment decision on a new CCS project called Quest, linked with oil sands development at a large upgrader facility. Alberta has also put a lot of effort into developing a comprehensive legal framework to cover various aspects of storing CO2. The IEA welcomes Canada’s leading efforts in the field of CCS.
Fifth is renewable energy.
Renewable energy is playing a large and growing role in Canada's energy mix. Canada's power system already relies to a great extent on hydro power and accounted for almost 59% of total generation in 2011. This large hydro power potential should be further developed over the medium term. Known hydro power renewable developments are expected to take place mostly in solar PV and onshore winds, with Ontario and Quebec providing the largest growth. In 2011, cumulative installed capacity in Canada stood at 560 megawatts for solar PV and 5.3 gigawatts for onshore winds, mostly located in these two provinces. From 2011 to 2017, growth in these two technologies is expected at 3 gigawatts and 9 gigawatts respectively.
The IEA's 2009 in-depth review recommended that Canada develop a long-term policy that integrates renewable energy into the overall national energy strategy while taking into account the geographic, geological, and resource differences between the provinces and territories. It stressed the need to remove and overcome non-economic barriers as a first priority to improve policy and market functioning while having regard to Canada's unique national circumstances. The IDR called on Canada to commit to long-term, effective, and predictable support mechanisms in order to provide developers and investors with a stable regulatory framework. It also urged the government to develop more ambitious programs to facilitate the use of renewable electricity generation, microgeneration, and heating in geographically isolated regions in order to offer an alternative to the consumption of petroleum products. Many of these messages are still relevant today and for the outlook over the medium term.
Thank you very much.
Thank you, Mr. Chair, Hon. Mr. McKay, and distinguished members of Parliament.
I thank you for inviting me to make a presentation on Gradek Energy Inc.'s technology.
Imagine if we had the technology to clean up tailings ponds. Imagine if Canada could extract oil sands without creating a tailings pond. What if we had a new technology?
Gradek Energy Inc. is an innovative cleantech company that has designed an energy-efficient, reusable, environmentally responsible, hydrocarbon separation technology that can be used to assist the Canadian oil sands industry achieve its ultimate goal, which is sustainable production growth, together with reclamation and restoration of operating sites in a timely and cost-efficient manner.
Gradek Energy Inc.'s pilot plant has proven that its proprietary RHS process is capable of treating tailings by separating hydrocarbons from solids while recovering valuable bitumen and recycling warm process water.
According to an independent study conducted in July 2010, the Oil Sands Research and Information Network estimated that in 2008, about 750 million cubic metres of tailings existed within Alberta's tailings ponds. The study predicts that if there is no change in tailings management, the inventory of fluid tailings is forecast to reach one billion cubic metres in 2014 and two billion cubic metres in 2034. The growth in tailings volumes attest that current technologies have not been successful in meeting the criteria and objectives as outlined by directive 074 of the Energy Resources Conservation Board and by the Canadian Environmental Assessment Agency.
The criteria and objectives can be summarized as follows: to minimize and eventually eliminate long-term storage of fluid tailings in the reclamation landscape; to maximize intermediate process water, recycling it to increase energy efficiency and to reduce freshwater import; to minimize loss of valuable resource associated with tailings ponds; to create a trafficable landscape at the earliest opportunity to facilitate progressive reclamation; to eliminate or reduce containment of fluid tailings in an external tailings disposal area during operations; to reduce stored process-affected waste water volumes on site; and to ensure that the liability for tailings is managed through reclamation of tailings ponds.
The Pembina Institute and the Water Matters Society of Alberta conducted a review of the submitted tailings plans. They found that only two of the nine mine projects would meet the requirements for the regulations to reduce toxic tailings starting in 2011. The proposals for the other seven projects would not meet the targets for reducing tailings by 2011. Furthermore, a number of project proposals indicated that they would not meet reductions until 2023, and would not meet rules for developing solid surfaces for over 40 years.
This reality will have a direct negative impact on the perception of sustainable energy development in the Canadian oil sands. Gradek Energy Inc. can mitigate this by deployment of its technology to help Canadian oil sands operators meet criteria and objectives as outlined by directive 074, the Energy Resources Conservation Board, and the Canadian Environmental Assessment Agency.
The reusable hydrocarbon sorbent technology is an organic bipolymer bead that allows instantaneous hydrocarbon recovery upon direct physical contact without the need for any catalyst or chemical reaction. I have brought with me some samples in order to show you the process. The attraction of hydrocarbons to the RHS beads is strictly a physical attraction, causing no alteration to the absorbed hydrocarbons, thereby providing the perfect transport medium to extract hydrocarbons from any stream with minimal energy requirements.
In June 2010 Gradek Energy Inc. commissioned, in collaboration with a major Canadian oil sands operator, a three-and-a-half tonne per hour pilot plant to test the proprietary bitumen recovery process using RHS bipolymer beads. The pilot plant is located in the heart of the Montreal East petrochemical refinery district. The pilot plant benefits from access to qualified petrochemical expertise and a full-scale bitumen laboratory, including monitored security and established best safety practices. The facility currently employs seven full-time specialized workers and carries out research and development for advanced testing and process improvement.
The pilot plant is currently processing over 300 cubic metres of Alberta oil sands tailings. Based on pilot plant test results to date, Gradek Energy Inc.'s bitumen recovery process has achieved the following results: greater than 98% bitumen and total petroleum hydrocarbon recovery; 95% naphthenic acid reduction; over 60% of process-affected water is recyclable, and at a high temperature; high confidence of the economic viability of the business model; and feasible scale-up designs and performance.
On conclusion of the pilot test protocol, Gradek Energy Inc. will build a 500-ton-per-hour commercial prototype of the RHS bitumen recovery process in Alberta. Gradek Energy Inc. has attracted international recognition, and, in pursuit of a bold vision, has formed a strategic collaboration with Veolia Water Solutions and Technologies North America and BASF Global, which are keen to contribute their extensive expertise in engineering, testing and design, project management, and construction and operating experience to ensure operational success of the commercial prototype.
BASF is the world’s leading chemical company, employing over 111,000 employees in 370 production sites worldwide and serving customers and partners in almost all countries of the world. Veolia is a wholly owned subsidiary of Veolia Environnement, a publicly listed company on the New York and Paris stock exchanges with a $5 billion capital market, operating in 69 countries with 96,650 employees.
In summary, Gradek strives to become the partner of choice to the Canadian oil sands industry for the provision of tailings management services. The near-term objective is to offer a sustainable solution for tailings management that will favourably position the Canadian oil sands on the international scene. Gradek’s hydrocarbon recovery process translates into significant value added by allowing Canadian oil sands operators to increase bitumen production in an environmentally sustainable manner by transforming tailing stream waste into a clean and alternative energy source.
The main challenges and barriers to innovation, development, and deployment of Gradek technology have been determined to be access to necessary financial and human resources to bridge technology from development stage to commercial deployment, collaboration and alignment between industry operators and technology providers, and timely access to tailing ponds. As well, the Canadian renewable and conservation expenses program has not evolved to consider the growing importance and visibility of the Canadian oil sands industry and does not encourage innovation regarding waste heat recovery, water conservation, and resource maximization.
The role of the federal government to foster innovation and deployment would be to adapt the CRCE to incorporate investments in innovation regarding Canadian oil sands tailings reclamation; to formulate policy and metrics to recognize the transformation of extracted bitumen from Canadian oil sands waste tailings into a clean alternative energy source; to play a proactive role in promoting the adoption of innovation to achieve internationally recognized low carbon fuel standards; to level the playing field for the competitive benefit of the Canadian oil sands industry by permitting the expansion of production in an environmentally sustainable manner without increasing the carbon footprint, using Gradek’s technology; and to facilitate the collaboration from a Canadian oil sands operator by providing incentives to implement the commercial prototype on a small-scale settling pond and conduct temporary and/or permanent reclamation testing.
Thank you very much.
Thank you very much for your question.
Last month we released the Medium-Term Oil Market Report, and in the report we have estimated the oil demand and supply structure in the coming six years, from 2011 to 2017. In this, we expect that we'll see substantial growth of oil demand. By the way, that is mostly coming from the non-OECD countries, the growth in demand in China, India, and also in the Middle East.
We expect that we'll see the continuation of substantial growth, but at the same time, we are seeing somewhat slower growth compared with the forecast that we made last year. That is due to slower growth. Immediately before we released the Medium-Term Oil Market Report, IMF revised downward the global economic growth forecast. That is the fundamental picture of the growth.
On the other hand, in terms of the supply, we'll see somewhat comfortable growth in supply all over the world. First, about half of the world supply capacity of growth will be coming from North America. The biggest factor is obviously the light type oil from the United States, but at the same time we expect a substantial contribution by the Canadian oil sands. Also, we expect supply growth will be coming from the deepwater resources in Brazil as well.
That is the non-OPEC supply capacity. On the other hand, we have the OPEC growth as well. That is mostly led by Iraq. That is something that we looked at in detail in the World Energy Outlook that we released very recently for this year.
Mr. Mike Allen: Thank you very much.
Mr. Keisuke Sadamori: Yes, so that's the— [Inaudible—Editor]
Yes. Thank you very much, and I'll do it quickly.
In our case, it was putting together a team of people with the right backgrounds and expertise to tackle the oil sands industry. We attracted those people from, in our case, Syncrude Research and organizations such as that, folks who had a vision that more could be done in these areas.
I had to get the money together; that's important. It's the same with the minerals; we had to hire minerals experts, who generally aren't in Canada. Then you align yourself with the best organizations you can find. We established our first research centre in Regina, Saskatchewan, at the Saskatchewan Research Council. We've now moved to Alberta, to CANMET.
So it's a question of getting the right partners together, which is a lot of what Tom was saying. In our case, it was people such as SGS: we did a tremendous amount of work here in Ontario at Lakefield Research, of all places, on the oil sands, and had some breakthroughs there. We went down to Chicago and worked with the Gas Technology Institute on solvent recovery.
You need to be flexible, and you're not going to solve these things on your own; you're going to pull together the talent that we have in Canada and certainly throughout North America to solve these problems. That's the challenge through that visionary R and D stage—lab scale to small pilots.
Then once you have solutions—and in our case we applied for patents and headed into that process—you're going to have to do a demonstration. For that you're going to need a lot of money, so you're going to have to convince investors that something is getting closer here—we went through about three years of demonstrations— and you have to get the oil sands people onside to provide you with tailings, to review results. That's where we brought in SDTC, on the federal government side; it is very helpful in getting you through that pre-commercial stage.
I would agree with you that Canadians are very good at doing all those things. What we're not good at, as a country and perhaps as an industry, is commercializing things. As compared with the U.S., Germany, Scandinavia, and so on, we're a little bit on the conservative side from a business point of view. We have all the skills and all the resources; we just have to finish them off. The whole business of the U.S. companies we dealt with is around commercial applications.
That's the challenge we're in now, and there we're not as competitive. It's maddening, to be honest, but we're not giving up. Don't run out of money, and don't run out of tenacity to get these through to the finish line.
Thank you to the witnesses for appearing.
Mr. Trost asked a question: if a business is profitable, why does it need a subsidy? I think it's a valid question.
We see that the federal government has given $500 million in subsidies that have gone to CCS technologies, $1.3 billion in oil industry subsidies. I could redirect the question to Mr. Trost. If these businesses are profitable, why do they need subsidies?
Following that, in the 2011 joint report of the IEA, OPEC, OECD, and World Bank on fossil fuel and energy subsidies, there was a recommendation made to Canada to rationalize and phase out over the medium term inefficient fossil fuel subsidies that encourage wasteful consumption.
As you said, there can be signals given to industry. Subsidies can act as signals.
I would ask Mr. Gradek and Mr. Nelson this: you mentioned before that the oil sands seemed to be focused solely on increasing production, so what does a no-strings-attached $1.3 billion subsidy to the oil industry give as a signal from the federal government to the oil sands? Do you think it tells them without the environmental piece in place, “Go ahead, increase production, increase growth. We're going to let you go ahead and do what you want”, and we lose that value-added piece that you too could add to that industry?
Again, as Mr. Nelson mentioned, on the $1.4 billion, I don't know where it went.
The oil sands industry has an approach with side issues whereby, since they are not generating revenue, they are left on a schedule that is not very short. This is where government should come in and impose a timeline.
Luckily, in 2009 Alberta put through directive 074. If you look at the oil sands expansion and what they are deemed to be going for by 2030, there is not much space left to build tailings ponds. Suncor presently has an issue in where a plant can be set up on its lease, because tailings ponds take up so much area. The world's largest man-made dam is the Mildred Lake dam, which is holding back toxic waters. It's unfortunate that engineers conceive to go ahead and build structures as such rather than treat those wastes and eliminate them.
There is potential to go ahead and eliminate waste. The way to incite it, if the government wants to put a timeframe, would be to say, “Listen, you are going to clean up your image. You are going to be more efficient. You are not going to be producing waste. You are going to be generating a revenue stream and maximizing a resource out of that waste.”
That's the focus where government should go ahead and be involved. They should look very seriously at innovative technologies, assist them, and take a role whereby they would collaborate and coordinate all of the effort for the industry. The bottom line is that we can export low-carbon fuel, not dirty oil, into the United States. The way to do it is to recover the waste heat, increase our efficiency, eliminate waste, and demonstrate that we are socially responsible with our resources for future generations.