CN (Canadian National Railway Company) is acquiring the Athabasca Northern Railway Ltd. (ANY), which has the rail link to the oil sands region of northern Alberta. CN’s purchase and rail-line rehabilitation plan are premised on long-term traffic volume guarantees that the company has negotiated with shippers Suncor Energy Inc., OPTI Canada Inc., and Nexen Inc.

CN rail network and acquisition of the Athabasca Northern Railway. Click to enlarge.

CN will pay C$25 million for ANY and invest C$135 million in rail-line upgrades over three years to improve transit times and service consistency.

The 202-mile ANY connects with CN at Boyle, Alta., located 101 miles north of Edmonton. CN’s plans for the line will preserve market access to existing and potential receivers along the rail corridor—today sulfur and petroleum coke move southbound on the ANY, and increased volumes of these commodities are expected to move over the line in future. CN’s line rehabilitation, including upgraded rail, ties, bridges and new ballast, will allow greater volumes of northbound shipments of construction materials and machinery to support oil sands development.

While ANY’s current traffic volumes are too low to keep it going as a stand-alone operation, we and our shipper partners see the ANY playing a critical role in one of the world’s largest construction projects—the oil sands reserves in northern Alberta are second only to Saudi Arabia’s, and industry is expected to invest more than C$100 billion over the next decade in oil sands development, construction and infrastructure upgrading.

—E. Hunter Harrison, CN president and CEO

Without the commitment and investments being made by Suncor, OPTI Canada, Nexen and CN, the rail line faced abandonment this month.

Originally Syndicated via RSS from Green Car Congress

Most geologically prospective oil shale resources within the Green River formation basins in Colorado, Utah, and Wyoming. Click to enlarge.

As required under the Energy Policy Act of 2005, the Bureau of Land Management (BLM) has published a Draft Programmatic Environmental Impact Statement (PEIS) to guide future management of public lands containing oil shale and tar sands resources in the US.

Under the recommended proposal in the Draft PEIS, the BLM would amend land use plans to allocate approximately 1.9 million acres of public lands in Utah, Colorado and Wyoming for potential commercial oil shale development.

Most US oil shale resources are found in the Green River Formation of Colorado, Utah and Wyoming. The federally owned portion of this resource is more than 50 times the country’s proven conventional oil reserves and nearly five times the proven reserves of Saudi Arabia.

The PEIS does not authorize any commercial development projects, provide for any leases to be issued, or commit the BLM to any particular course of action in the future. The BLM says that its approach is designed to ensure that oil shale technologies can operate at economic and environmentally acceptable levels before the agency authorizes full-scale commercial leasing on public lands.

Between 305,000 and 1.5 million acres of BLM-managed lands would be excluded from oil shale leasing under the alternatives presented in the Draft PEIS. No leasing would be allowed in Wilderness areas, wilderness study areas, other units of the BLM’s National Landscape Conservation System, or Areas of Critical Environmental Concern that are closed to mineral development, among other areas. The PEIS anticipates that oil shale resources on identified lands would be leased as a solid mineral, and additional site-specific NEPA analysis would be completed on each application before any lease could be issued.

Resources

• Oil Shale and Tar Sands Programmatic EIS Information Center

• Oil Shale and Tar Sands Draft Programmatic Environmental Impact Statement (EIS)

• Oil Shale and Tar Sands (BLM)

Originally Syndicated via RSS from Green Car Congress

Saskatchewan’s oil sands deposit is contained within the Mannville Group of the Western Canadian Sedimentary Basin which was deposited across B.C., Alberta, Saskatchewan, Manitoba and the US. Click to enlarge.

The Canadian province of Saskatchewan, the eastern neighbor of Alberta, the locus of the oil sands boom in Canada, held its first public offering of oil sands rights at its 16 Aug sale. Saskatchewan holds oil and gas sales six times a year.

The auction raised about C$38 million in total. Sales of the new oil sands dispositions included six oil sands exploration licenses that attracted C$3.3 million in bonus bids.

The highest price paid for an oil sands parcel came from Petroland Services Ltd., with a bid of more than $1 million or $108 per hectare for a 36-section oil sands exploration licence located north of the Clearwater River in northwest Saskatchewan.

This historic sale also heralds the beginning of a potential new oil sands industry in Saskatchewan.

—Government Relations Minister Harry Van Mulligen

Another provincial first in the August sale was the awarding of oil shale exploration permits under the competitive work commitment process. Two permits were issued, both in the Hudson Bay area. One was issued to Noble Hydrocarbons Alta Ltd. with a commitment to spend over $1 million on 38,000 hectares. The other was awarded to Cavalier Land Ltd. on the basis of a commitment to spend over $300,000 in exploration on 34,000 hectares.

Alberta’s three primary oil sands deposits. Click to enlarge.

Saskatchewan’s oil sands deposit is contained within the Mannville Group of the Western Canadian Sedimentary Basin which was deposited across B.C., Alberta, Saskatchewan, Manitoba and the US. However, to date, Alberta contains the only three major known economic oil sand deposits: Peace River, Athabasca and Cold Lake, with Athabasca being the largest. (See chart at right.)

While there was some oil sands exploration and activity in Saskatchewan in the 1970s, it was limited. Drilling identified a resource, but exploitation of the oil sands was deemed uneconomic due to technological limitations.

Resources:

• Oil Sands in Saskatchewan (2005)

Originally Syndicated via RSS from Green Car Congress

BP is moving into the Canadian oil sands by acquiring a half-share in the Sunrise field, located in the Athabasca oil sands in northeast Alberta, operated by Husky Energy. At the same time Husky will acquire a half share in BP’s Toledo oil refinery in Ohio, US, between them forming an integrated North American oil sands business. Two independent 50/50 joint ventures will be formed from the equally valued assets to own and develop the businesses.

The Sunrise oil sands field is expected to be sanctioned in 2008 with first production of bitumen in 2012, building to 200,000 barrels of oil a day (bpd) by the end of the next decade with a 40-year production plateau.

The field has been fully delineated by the drilling of 650 appraisal wells. Front End Engineering is well advanced on Sunrise with completion expected in early 2008. Joint investment up to 2012 is estimated at around US$3 billion. Site preparation work, including clearing of the various development areas and the rough grading of the central plant site, field facility roads and well pads is ongoing. The partnership will be responsible for sourcing fuel gas and diluents for Sunrise; and delivering product to a market transfer point at Hardisty where each party will take their respective production share.

SAGD is a thermal in-situ recovery process using pairs of horizontal wells. A horizontal production well is located near the bottom of the reservoir and steam is injected into a second horizontal well placed above it heating the bitumen and enabling it to flow. The bitumen and condensed steam, under the influence of gravity, drain to the lower horizontal well and are produced through the wellbore to the surface.

The bitumen will be piped to Hardisty, Alberta, from where it will be transported via existing pipeline networks for refining. Sunrise will be operated by Husky as a Canadian oil sands partnership, based in Calgary.

Toledo Refinery is located in the city of Oregon in northwest Ohio and has a crude distillation capacity is currently 155,000 bpd of which 60,000 bpd capacity is currently heavy oil. The refinery is located in one of the largest energy consumption regions of the US and, subject to necessary approvals and permits, will be expanded to process approximately 170,000 bpd of heavy oil and bitumen by 2015. It will be operated by BP as a US refining LLC. Joint investment of around US$2.5 billion is expected up to 2015 to sustain and reposition the refinery to process increased amounts of heavy crude oil and bitumen.

The refinery is well positioned to receive Canadian crudes for refining and supply into the US mid-west and the neighboring Canadian markets. It is a heavy sour coking refinery and is highly flexible (Nelson complexity index of 11.6), one of the few complex refineries outside the Gulf Coast region and California. It can take heavy and medium sour crudes and upgrade them to advanced, cleaner transport and heating fuels such as low sulphur gasoline, ultra low sulphur diesel, aviation fuels, propane, kerosene and asphalt. It produces daily 3.8 million US gallons of gasoline, 1.1 million gallons of diesel, 756,000 gallons of jet fuels—about 0.5% of US total refining capacity. The value of Toledo in the books of BP Products North America Inc. as at 30 September 2007 was US$494 million.

Toledo and Sunrise are excellent assets. BP’s move into oil sands is an opportunity to build a strategic, material position and the huge potential of Sunrise is the ideal entry point for BP into Canadian oil sands. In addition this deal will help guarantee a supply of advanced transportation fuels to major North American markets from Toledo which is a flexible and advantaged site.

—Tony Hayward, BP group chief executive

Full regulatory approval of the proposed deal and final commercial agreements are expected to be completed in 1Q 2008, with a partnership effective date of 1 January, 2008.

Originally Syndicated via RSS from Green Car Congress

The Canadian province of Alberta will use carbon capture and storage (CCS) as a major component of a proposed plan to cut projected greenhouse gas emissions in half by 2050.

Alberta’s GHG reduction commitments. Click to enlarge

Alberta’s emissions are projected to grow to 400 million tonnes by 2050, largely due to forecast growth in the oil sands sector. Alberta’s new plan will cut the 400 million tonnes in half by 2050, with much of the reduction coming from oil sands activities.

New and next generation CCS technologies will deliver about 70% of the new plan’s projected 200 megatonne-reduction by 2050, according to the government, with the bulk of those reductions coming from activities related to oil sands production. Up to C$500 million could be directed towards these initiatives, including allocations through the Canada ecoTrust and the Climate Change and Emissions Management Fund.

Alberta will establish a government-industry council to develop a made-in-Alberta plan for carbon capture and storage. It will respond to a federal-provincial task force report on carbon capture and storage and will deliver a strategy for implementing the technology that will include consultations with industry.

This technology will dramatically reduce greenhouse gas emissions from oil sands production. This will help us continue to green our growth in that sector.

—Doug Horner, Minister of Advanced Education and Technology

About 12% of Alberta’s reductions will be achieved through conservation and energy efficiency. Offering consumer incentives to become more energy efficient is a key action under this theme. A detailed implementation plan will be completed this spring.

The plan calls for increased investment in clean energy technologies and incentives for expanding the use of renewable and alternative energy sources such as bioenergy, wind, solar power, hydrogen and geothermal energy. Initiatives under this theme will account for 18% of Alberta’s reductions. A detailed implementation plan will be developed and released this spring.

Originally Syndicated via RSS from Green Car Congress

UOP LLC, a Honeywell company, has expanded its portfolio of technologies to help refiners produce clean gasoline from heavier crude oil with a new slurry hydrocracking process based on a technology licensed from Natural Resources Canada (NRCan).

The new process is designed to upgrade bitumen, a heavy, tar-like, highly contaminated oil derived from oil sands commonly found in Canada, Venezuela and the United States, as well as other heavy, highly contaminated feeds found in other parts of South America and the Middle East.

Oil sands, also known as tar sands, are a mixture of sand, water, clay, and bitumen. The bitumen extracted from oil sands is nearly in solid form, making it difficult and expensive to process into gasoline, diesel fuel and other products, and many of these heavy crude oils contain high concentrations of metals such as nickel and vanadium as well as complex hydrocarbons that make conventional processing methods uneconomic. UOP’s slurry hydrocracking process utilizes a slurry catalyst to upgrade bitumen and heavy crudes to lighter distillates that can then be used to produce clean gasoline and ultra-low sulfur diesel.

UOP’s slurry hydrocracking technology is based on a technology originally developed by NRCan. It was further developed and proven commercially viable at the Petro-Canada facility in Montreal over a 15-year period starting in 1985. High availability of cost-effective lighter crudes at that time left little demand for the technology, but feedstock availability is now shifting. The volume of non-OPEC heavy crude supplied to the market increased 23% between 2000 and 2004 while the volume of light crude oil dropped 10% over that same period.

According to the US Energy Information Association, roughly 80% of the world’s bitumen is located in Canada. Independent energy industry consultant Purvin & Gertz predicts that bitumen-derived synthetic crude oil production will increase from the approximately one million barrels per day (bpd) produced today to four million bpd by 2015.

UOP’s residue upgrading portfolio currently includes a wide range of solutions to convert petroleum residues to ultra-clean gasoline, jet fuel and diesel. UOP has licensed more than 200 hydrocracking units and residue hydrotreaters worldwide, with more than 120 in production today.

Originally Syndicated via RSS from Green Car Congress

Mine-based oil sands production, in which the oil sands dug up and processed to extract the bitumen, results in large amounts of tailings which have significant deposits of heavy minerals. Titanium Corporation, a Canadian start-up, has made the recovery of minerals such as titanium and zircon from tailings the core of its business plan. The company is also working to expand its ability to recover additional bitumen from the tailings as a strategic extension of its business.

Overview of the process of recovering minerals from tailings. Click to enlarge.

Titanium and zircon a represent a $12 billion a year industry and growing. Zircon is currently in critical short supply as worldwide demand continues to outpace supply.

Titanium Corporation began in 2004 with the commissioning of a facility in Regina, which worked with dry, deposited tailings trucked down from the oil sands site. Following encouraging results from this pilot, the company designed and moved a portable facility on-site in Fort McMurray, connected directly to the fresh tailings line.

Fresh tailings are somewhat different than the dry material, and the company redesigned its process and commissioned a pilot concentrator on site in the fall of 2006. This pilot facility was designed to concentrate the heavy minerals, remove bitumen and recover
bitumen and solvents used in the removal process.

Processing fresh tailings proved more complex and is taking more time than the company had anticipated, said Scott Nelson, president and CEO, during an annual update conference call on 11 December.

We came out of the on-site program late last year with a number of areas requiring improvement, including water recycling, solvent usage, equipment and mechanical issues.

—Scott Nelson

One of the problems is that bitumen remaining on the minerals is impeding downstream separation processing. The company has determined hat minerals and bitumen recovery are interdependent. This has led to work on an integrated approach to tailings processing, according to Nelson.

This work entails categorizing the hydrocarbons in the tailings stream,
testing different solvents, testing alternate physical and hydraulic separation methods, testing organic and inorganic chemicals among other approaches.

—Scott Nelson

The company’s research partners are Canmet and SRC (the Saskatchewan Research
Counsel) located in Regina.

The company has also engaged an independent engineering consultant to advise on the environmental impacts of oil sands tailings processing, including estimated CO₂ and SO_x, NO_x, and VO_x emissions.

In consultations with the oil sands industry, however, the company has consistently been told that extraction of the additional bitumen in the tailings would be most important to the industry, according to Nelson.

The Froth treatment from oil sands extraction processes generally contained bitumen losses in the range of 3% of the original bitumen mined. In the current oil sands production rate, this represents an excess of 8 million barrels per year of lost bitumen in total from the mine-based sites. Industry forecasts expect mine-based oil sands production to more than double by the 2015 time frame, which will likely increase proportionally the amount of bitumen lost in the tailing.

More efficient use of resources, both minerals and bitumen and decreased emissions from tailings ponds all related to a high growth industry, is a very
compelling value proposition.

Accordingly, the company is “redoubling” its efforts to resolve bitumen removal and to develop bitumen recovery technology, according to Nelson. The company anticipates that it may be able to recover 50% of the bitumen now lost in the tailings.

Resources

• Developing the Recovery of Minerals and Hydrocarbons from Oil Sands Tailings

Originally Syndicated via RSS from Green Car Congress

The diagram depicts the assets of the 200,000 bpd “Voyageur” expansion program; however, Voyageur will be operated on an integrated basis with existing operations. Click to enlarge.

The Board of Directors of Suncor Energy gave final approval to a C$20.6 billion (US$20.7 billion) investment to boost crude oil production at the company’s oil sands operation, located north of Fort McMurray, by 200,000 barrels per day (bpd) over its planned 2008 levels to 550,000 bpd in 2012.

The expansion plans include constructing four additional stages of in-situ bitumen production, a new upgrader (Suncor’s third) to convert that bitumen into higher-value crude oil, and various infrastructure and utilities.

An investment of approximately $9 billion (with an estimate accuracy range of +16%/-13%) is to be made to construct the four stages of in-situ production. Each stage is expected to produce an average of approximately 68,000 bpd of bitumen. (Depending on certain operational and market conditions, excess bitumen may be sold to market as a heavy crude blend.)

An investment of approximately $11.6 billion (with an estimate accuracy range of +12%/-8%) will go towards construction of an upgrader designed to process 245,000 bpd of bitumen into 200,000 bpd of crude oil. The product slate is expected to consist of approximately 85% sweet crude oil and diesel, and 15% sour crude oil. Oil products are planned to be shipped to market through third-party and Suncor-owned pipelines.

The expansion puts in-situ production on more of an equal footing with Suncor’s historical reliance on oil sands mining. Of the estimated total of $20.6 billion, Suncor has already invested approximately $2.5 billion on the expansion, including detailed engineering, site work and fabrication of major vessels.

One area of particular focus of the project, in an attempt to mitigate the environmental impacts of oil sands development, is improved water management. Suncor has reduced water use per barrel by nearly 50% during the past five years. With this expansion program, the company plans to spend $225 million to further improve water management. As a result of plans to reduce water consumption and increase treatment and recycling, the company did not seek an increase in its water licence for the construction or operation of its planned third upgrader. In Suncor’s in-situ operations, more than 90% of the water used for steam generation is expected to be recycled.

Suncor has reduced greenhouse gas emission intensity at its oil sands plant by approximately 50% compared to 1990 levels. While this expansion will lead to an increase in absolute greenhouse gas emissions, the company says it continues to investigate technologies such as carbon capture and storage that hold the potential for reducing absolute emissions in the longer term.

The company also continues to target technologies to reduce intensity in other emissions. For example, approximately $800 million is being spent to reduce sulfur dioxide emissions through the construction of a new sulfur plant. Improvements in emissions of nitrogen oxides are also expected and Suncor will continue to investigate gasification options, which could enable the company to process petroleum coke, an oil sands by-product, into an energy source. Investments in new equipment and processes are also expected to mitigate operational odors.

The expansion is designed to be completed in a phased manner. Mechanical completion of the new upgrader is expected to be completed in 2011, while bitumen feed from the new stages of in-situ production is expected to begin operation in 2009 through 2011. Crude oil production is expected to begin ramping up in late 2011, with full production capacity of 550,000 bpd expected to be achieved in 2012. Suncor’s plans for some components of in-situ expansion are still subject to regulatory approval and, as such, the company’s schedule is subject to change.

The capital required to fund the expansion is expected to be financed through cash flow from operations, credit facilities and access to debt capital markets.

Resources

• Suncor Investor Presentation

Originally Syndicated via RSS from Green Car Congress

Rendering of the heat transport system in the ACR-1000. Click to enlarge.

Energy Alberta Corporation (Energy Alberta) has filed an application for a site preparation license for two twin-unit ACR-1000 CANDU nuclear reactors to provide power for the oil sands operations in Alberta.

Energy Alberta, a privately held company incorporated in Calgary in October 2005, plans initially to build one twin-unit ACR-1000 that will ultimately produce a total net 2,200 MW of electricity with a targeted in-service date of early 2017.

The chosen site is on private land adjacent to Lac Cardinal, approximately
30 km west of the town of Peace River, Alberta. Energy Alberta said it chose the Peace River region as its preferred site “because of the demonstrated support from the community, existence of essential infrastructure and support services, and technical feasibility.”

The ACR-1000 is an evolutionary, Generation III+, 1,200 MWe class nuclear power plant built on Atomic Energy of Canada, Ltd.’s (AECL) CANDU nuclear technology. With a 60-year design life, the ACR-1000 reactor core consists of fuel and light-water coolant in pressure tubes with a heavy water moderator.

The ACR-1000 features low enriched fuel, higher steam pressure for increased
efficiency, a smaller reactor core with improved stability to enable higher output, and much larger thermal margins designed for end-of-life conditions.

The ACR-1000 incorporates 80% of the technical specification from the proven CANDU 6 design such as the modular, horizontal fuel channel core, low-temperature heavy-water moderator, waterfilled vault, two independent diverse shutdown systems, on-power fuelling and a reactor building accessible for on-power maintenance.

There are currently 10 CANDU 6 reactors in operation worldwide, with one more under construction. The CANDU 6 is a 700 MWe class nuclear power reactor.

The project to build the new Peace River reactors will be subject to review under the Canadian Environmental Assessment Act.

Two oil sands developers—Husky Energy Inc. and Total—have also indicated possible interest in using nuclear power for their operations.

Resources:

• The ACR-1000: Operator-Driven CANDU Development

Originally Syndicated via RSS from Green Car Congress

Radio Frequency / Critical Fluid Oil Extraction Technology. Click to enlarge.

Schlumberger, a leading oilfield services company, has acquired Raytheon’s technology for the extraction of oil from oil shale and oil sands. Financial details of the transaction were not disclosed.

The technology, developed by Raytheon and partner CF Technologies for oil shale processing, combines radio frequency (RF) technology from Raytheon with critical fluid (CF) technology from CF Technologies. (Earlier post.) Raytheon has projected that the same process could also be used to retrieve oil from Canadian oil sands and to reprocess spent wells.

Field experience indicates that the Raytheon RF heating technique obtains recovery rates of 75% of the oil shale’s Fisher Assay value. (A method used to approximate the energy potential of an oil-shale deposit.) Coupling RF heating with the CF technology has resulted in recovery rates as high as 90 to 95%.

Critical fluids, or supercritical fluids (SCF), are liquids or gases used in a state above their critical temperature and pressure (critical point). In this state, the SCF has unique properties different from those of either gases or liquids, offering a combination of liquid-like density and solvency, with gas-like viscosity, diffusivity, compressibility and lack of surface tension.

As a result, supercritical fluids can rapidly penetrate porous and fibrous solids, offer good catalytic activity and can dissolve and extract a wide range of chemicals. Carbon dioxide is commonly used as a supercritical fluid.

Under the oil shale extraction scenario, oil well holes are drilled into the shale strata using standard oil-industry equipment. RF antennae, or transmitters, are lowered into the shale. The antennae then transmit RF energy to heat uniformly the buried shale rock. This results in the volatilization of water, which, in turn, results in the microfracturing of the formation, enhancing product recovery.

Samples of kerogen extracted from oil shale with the RF/CF process. Click to enlarge. Credit: Raytheon

Supercritical carbon-dioxide fluid is then pumped into the shale formations to separate the petroleum from the rock and direct the freed fuel to another well, where it is extracted. Next, the carbon-dioxide fluid is separated from the oil and gas, which is sent to a refinery and further processed into gasoline, heating oil and other products. Ultimately, a self-sequestration
approach is expected to yield a neutral carbon foot print for process operations.

The RF/CF combination is more economical and environmentally responsible than older oil shale extraction techniques as it uses less power, does not severely disrupt the landscape or leave behind residue that can enter groundwater supplies.

Raytheon earlier estimated that the technology would retrieve four to five barrels of oil for every one barrel invested. Other in-situ processes retrieve one and a half to three barrels of oil for every barrel consumed estimated.

For tar sands and heavy oil, the Raytheon process could yield 10 to 15 barrels of oil equivalent per barrel consumed, due to the lower heating temperatures required. When applied in tar sands, the combined RF/CF technology performs a mild upgrading in-situ, yielding an attractive light sweet crude oil. The process is “tunable”, facilitating production of various product slates.

The use of RF technology in shale processing would enable the fuel to be extracted from the earth in only one to two months. In-ground heating methods that do not employ radio waves, by contrast, require three to four years to replicate the natural conversion process.

Raytheon’s RF technology was commercially proven for oil shale applications in the 1970s. Since then, the company has continued to perfect the technology, focusing on antenna design and system integration.

Resources

• Draft OSTS PEIS, Appendix A: Oil Shale Development Background and Technology Overview (December 2007)

• Geology and Resources of Some World Oil-Shale Deposits (USGS Scientific Investigations Report 2005–5294)

• Secure Fuels from Domestic Resources: Profiles of Companies Engaged in Domestic Oil Shale and Tar Sands Resource and Technology Development (US DOE, June 2007)

Originally Syndicated via RSS from Green Car Congress