Mining - Analogy for working with Oil Sands

Here is the best simple analogy for describing the challenges facing the bitumen extraction.

Alberta writer David Finch, the author of Pumped: Everyone's Guide to the Oil Patch, suggests this experiment: “Take molasses out of your kitchen cupboard, put as much sand in there as molasses, stir it up, and then put it outside where it gets cold and thick and won't flow – well, that's what the tar sand is like. It's extremely hard to work with, and it wrecks all your equipment.”
The muddy dirt clogs gears and conveyors; the sand corrodes pipelines. To mine bitumen, the land must first be cleared and drained. Clumps of sand are shovelled out and then mixed with water and heated, to force the hydrocarbon to rise to the top. It is then processed in an “upgrader” to produce synthetic crude before being sent to a refinery and turned into gasoline and heating oil.
Estimates vary, but environmental groups says it now takes two to four barrels of fresh water from the Athabasca plus 750 cubic feet of natural gas and about two tons of oily sand to produce one barrel of oil. The process produces two to three times the carbon emissions of a conventional oil well and creates toxic waste water, called tailings, that cannot be allowed back in the river.

Markets - Connecting the Oil Sands to Cushing

Cushing is a major hub in oil supply connecting the Gulf Coast suppliers with northern consumers. Cushing is famous as a price settlement point for West Texas Intermediate on the New York Mercantile Exchange (NYMEX) and has been cited[1] as the most significant trading hub for crude oil in North America. Signs made of a pipe and valve on the major highways near town proclaim Cushing to be the "Pipeline Crossroads of the World", and the town is surrounded by several tank farms.

Project OVERVIEW
The 3,456-kilometre (2,148-mile) Keystone Pipeline will transport crude oil from Hardisty, Alberta to U.S. Midwest markets at Wood River and Patoka, Illinois and to Cushing, Oklahoma. The Canadian portion of the project involves the conversion of approximately 864 kilometres (537 miles) of existing Canadian Mainline pipeline facilities from natural gas to crude oil transmission service and construction of approximately 373 kilometres (232 miles) of pipeline, pump stations and terminal facilities at Hardisty, Alberta. The U.S. portion of the project includes construction of approximately 2,219 kilometres (1,379 miles) of pipeline and pump stations.

The Keystone Pipeline will have an initial nominal capacity of 435,000 barrels per day in late 2009 and will be expanded to a nominal capacity of 590,000 barrels per day in late 2010. Keystone has contracts with shippers totalling 495,000 barrels per day with an average term of 18 years.

The question to be asked is can the oil sands production flowing into Cushing be blended to create West Texas Intermediate. This will increase the supply of WTI and decrease the price of WTI.

Environment - Partnerships to handle byproducts

Aux Sable Canada Ltd. has struck a deal to sell ethane and ethylene from its Heartland off-gas plant to Dow Chemical Canada Inc. The financial terms of the agreement were not disclosed Thursday.

Aux Sable, a joint venture of Enbridge Inc. (TSX:ENB), Fort Chicago Energy Partners (TSX:FCE.UN) and Williams Cos. (NYSE:WMB), will be the first in Canada to extract ethane and ethylene from the byproduct gas of a bitumen upgrader.

The Heartland off-gas plant is under construction just north of Dow Chemical's complex in Fort Saskatchewan, northeast of Edmonton. Its feedstock will come from BA Energy's Heartland upgrader.

The "long-term" arrangement with Dow announced Thursday involves up to 8,000 barrels per day of ethane and ethylene. Aux Sable and Dow also have entered into a strategic alliance to develop future upgrader off-gas processing projects supplying feedstock for Dow in Fort Saskatchewan. Aux Sable's Sable NGL Canada affiliate is to build, own and operate these off-gas facilities, with Dow as the exclusive customer.

"A key element of our strategy is to be a leader in the processing of upgrader and refinery off-gas," stated Aux Sable CEO Bill McAdam. Aux Sable says its Heartland plant will have no sulphur dioxide emissions and "limited" emissions of nitrogen oxides, while the BA upgrader will cut its carbon dioxide emissions by 12 to 16 per cent by using clean gas as fuel instead of burning the off-gas.

For Dow Chemical Canada, "the oilsands represent a large, untapped feedstock source," said Jeff Johnson, president of the Canadian division of U.S.-based Dow Chemical Co. (NYSE:DOW). "Our alliance with Sable Canada allows us to secure a long-term supply of petrochemical feedstock."

Legislation - The Energy Independence and Security Act of 2007

The Senate Commitee on Energy and Natural Resources passed legislation on December 7, 2007 that limits the ability of SCO to be used by the American government. Alberta Premier Ed Stelmach said the oil sands industry is cleaning up its act.

Stelmach predicted that the oil sands will soon be clean enough for any green-fuel standards the U.S. government might impose, the Edmonton Journal said.

"I'm confident that by the time the regulations are put in place, we will meet or exceed the regulations that are put in place by the United States," Stelmach said.

Activists in California may begin penalizing Alberta oil exports because oil sands production emits greenhouse gases.

But Stelmach said there's new technology, like carbon dioxide sequestration, that will help oil sands meet California and U.S. federal standards.

The tar sands traditionally use vast amounts of water and land, and emit tons of greenhouse gases; Canada is set to triple its oil sands production by 2016.

"Even if we're to shut it down completely and not export the 1.25 million barrels to the United States, where would the oil come from?" Stelmach asked. "And if it be shut down, it's one-tenth of 1 percent (of global carbon-dioxide emissions)."

SEC. 526. PROCUREMENT AND ACQUISITION OF ALTERNATIVE FUELS.
No Federal agency shall enter into a contract for procurement of an alternative or synthetic fuel, including a fuel produced from nonconventional petroleum sources, for any mobility-related use, other than for research or testing, unless the contract specifies that the lifecycle greenhouse gas emissions associated with the production and combustion of the fuel supplied under the contract
must, on an ongoing basis, be less than or equal to such emissions from the equivalent conventional fuel produced from conventional petroleum sources.

Markets - Asia Pacific vs. U.S.

Canadian producers are keen to secure markets for their swelling volumes of synthetic crude oil (SCO). Western Canada's crude oil production is forecast to grow from 2.35 million barrels a day in 2005 to 3.37 million in 2015, and most of this growth will be comprised of SCO and bitumen produced from Alberta's vast oil-sand deposits.

SCO producers have been looking hard at the Asia-Pacific region, the U.S. Gulf Coast and California as importers of oil, and several pipeline projects, according to Abe Albert, St. Louis-based executive director of global refining and technical services, Hart Energy Publishing.
Still, there are issues with each market. At present, the U.S. has no spare conversion capacity available, and refiners will have to upgrade facilities to process additional Canadian crude, he says.

In the Gulf Coast region in particular, Canadian crude will not easily wrest market share away from Mexico, Venezuela and Saudi Arabia. These countries supply 40% of the U.S. Gulf Coast refining product, including most of the heavy sour crude requirements.

Canadian producers will have to offer significant discounts in addition to significant capital expenditures on pipeline and terminal infrastructure to gain entry into that market.
Meanwhile, Saudi Arabia has staked claims on the heavy-crude market in the Asia-Pacific region, and has the benefit of lower transportation costs to that part of the world than the Canadians.

California and the Midcontinent regions will provide the highest netbacks for the Canadian producers. "The U.S. Midwest should be a focus of their efforts, because the Midcontinent region provides the most attractive pricing alternative," Albert says, "taking into account the capital expenditures and marine transportation costs associated with the expansion of the Canadian synthetic crude supply orbit to the Asia-Pacific region."

Historically, bitumen-upgrading projects in Alberta have been very expensive, due to their massive sizes, the short construction seasons and high Canadian labor costs. For Canadian producers, another plus of U.S. markets is the broader financial benefits they can gain by shifting more processing south of the border.

"Canadian synthetic producers should consider investing in U.S. Midcontinent refineries. Such investments could reduce the processing complexity at the tar-sands projects," says Albert. This approach would maximize returns on capital.

Markets - Refining SCO

The bitumen portion of the synthetic crude oil is like tar. Both gravity and viscosity are high. It contains significant aromatic and asphaltene compounds. It is high in sulfur, nitrogen, and metals and contains highly corrosive organic acids. It must be diluted or upgraded in order to ship.

Bitumen is not a good fit with refineries designed for light sweet crudes. There is significant hydroprocessing of converted material because it is H2 deficient. Bitumen also produces alot of coke and sulphur. Synthetic crude oil only works well in refineries designed for synthetic crude oil (SCO). In order to be SCO friendly, refineries need the following:

• Serious hydroprocessing capability.
• Metallurgy upgrades.
• Ability treat for air, water pollution and manage byproduct disposal
• Conversion capability for bitumen blends or SCO.

Markets - Pipeline Expansion

A February 2005 report from the Canadian Association of Petroleum Producers on oil pipeline expansion describes how western Canada has sufficient pipeline capacity to move crude oil to
markets for the next several years. The total excess capacity across the three major
trunk line systems exiting western Canada is about 300,000 b/d. The majority of western Canada’s crude oil supply continues to be sold into eastern markets, primarily in the U.S. midwest. These primary market areas are accessed through the Enbridge pipeline system. Crude oil shipped to secondary markets, such as cargoes moved off the west coast, generally arise after the available capacity on the Enbridge system is fully subscribed, i.e., the Enbridge system is in apportionment. The distinction between primary and secondary markets is important in assessing future pipeline capacity requirements. From a planning perspective, adequate pipeline capacity out of western Canada is defined as sufficient space to avoid sustained apportionment on the Enbridge system.

A comparison of the forecast growth in crude oil production and supply versus available Enbridge pipeline capacity shows a potential shortfall as early as 2007-08. At that time, Enbridge is forecast to be apportioned thus displacing barrels into secondary markets. To accommodate this near term shortfall in capacity on Enbridge, small scale expansion and debottlenecking options are available for the Enbridge system to boost capacity by about 150,000 b/d. Other pipelines also have potential to implement small system expansions. Overall, these capacity increases are forecast to provide sufficient aggregate pipeline capacity until 2010-11.

The production forecast for light crude oil and equivalent (synthetic) shows significant growth. However, the combination of declining conventional light oil production and synthetic supplies shipped as diluent in heavy crudes (Synbit) tend to mitigate the net growth in supply so that existing light oil pipeline capacity is forecast to be sufficient until 2015. The future increases in pipeline capacity are required primarily to accommodate growth of new supplies of Synbit and Dilbit, i.e., medium sour and heavy crudes.

Markets - Western Canadian Future Oil Supply

Western Canada’s crude slate has been dominated by light and heavy crudes over the last 15 years. The next decade will see a marked shift in this trend.


Heavy crude oil production, including bitumen from oil sands, traditionally has relied on condensate as the source of diluent to reduce the viscosity and meet pipeline specifications for transport. The primary source of condensate has been pentanes from western Canada’s growing natural gas production. Heavy crude oil and bitumen blended with condensate are generally referred to as Dilbit blends.


In recent years, slower natural gas growth, a shift to producing drier gas with less pentanes and competing demands for natural gas liquids have constrained available supplies of condensate. Escalating prices and insufficient condensate supplies combined with growing supplies of heavy/bitumen crude that need a source of diluent have forced producers to examine other options. As a replacement for condensate, producers of oil sands bitumen are starting to use light synthetic crude oil as an alternative source of diluent for blending to pipeline viscosity requirements. This trend to use synthetic crude has led to the evolution of a synthetic-bitumen blend referred to as Synbit.


Whereas traditional Dilbit blends approximate a 25:75 percent diluent-to-crude oil ratio, Synbit blends are closer to a 50:50 mix. The higher proportion of light products has changed the composition of the resulting crude oil blend. From a refining perspective, Dilbit blends are predominantly heavy. Synbit blends, however, look more like medium sour crudes to a refinery.


As a consequence of this emerging trend in blending, western Canada crude supplies will no longer be predominantly light and heavy. The growth in medium-like crudes is forecast to become an important component of the overall crude slate available to refiners.

Markets - Access and Capacity

The primary consideration in assessing the alternative routings for new pipelines is the potential market that can be served.

Canadian crude oil has historically been consumed in five market areas: the prairie provinces, Ontario, B.C./Washington State, U.S., Rocky Mountains, and U.S. midwest. As depicted in the chart, eastern markets dominate the flow of crude. For the predicted growth in crude supply, producers will need to expand their market horizons to more distant markets.

Western Canada’s crude oil marketing is currently focused on four core markets: western Canada, Ontario, the U.S. midwest (upper PADD II) and the U.S. Rockies (PADD IV).

In 2003, these core market areas represented an aggregate demand of over 3.0 million b/d. The demand in these traditional core markets, however, has been predominantly light and heavy, reflecting the composition of the historical crude slate developed and supplied by producers.

In addition to these coremarkets, crude oil supplies are occasionally also delivered into extended markets, the lower midwest (PADD II) and Washington State (PADD V) regions. Market demand in these areas tends to be seasonal or when pricing parity shifts create competitive opportunities for Canadian crudes. The extended market represents a potential crude oil demand exceeding 2.0 million b/d.

Much of the demand in the extended markets is for light and medium sour crudes. Historically, western Canada has not produced large volumes of medium crudes. The potential demand for medium crudes in these markets offer significant opportunities related to the growing supplies of oil sands Synbit, which can be blended to resemble a medium crude.

Pricing - Light/Heavy Differentials

Canadian heavy crude oil prices are generally set by Midwest refining economics. Global light / heavy crude spread ultimately sets the price for oil sands blends.

According to Purvin and Gertz, a major independent energy consulting firm, The light/heavy differential significantly increases the profitability of upgrading the bitumen to a synthetic crude oil. The Lloyd blend heavy sour oil was worth $57 on November 2, 2007. NYMEX WTI was around $96. Upgrading of the bitumen to a synthetic crude oil (SCO) that is comparable to WTI would cost $12.

While SCO commands a premium price to WTI and is in many ways comparable to light sweet crude, the high aromaticity of bitumen from which it is derived limits its penetration into refineries that are not specially equipped to handle it. A typical refinery is limited to between 10-20% of SCO in its crude slate. Part of the solution lies in additional technical/infrastructure capability in existing or new refineries and another lies in producing a higher quality light sweet synthetic crude, something being planned by a few of the new oil sands projects.

According to the Canadian Association of Petroleum Producers:

Synthetic Crude Oil (SCO) trades at a premium to WTI
-Current: $ 1US/bbl
Bitumen Blends trade at a discount to WTI
-Current: $ 23 US/bbl

Unprocessed bitumen is also marketed, but for pipeline transportation reasons must be shipped in diluted form. It sells at a considerable discount to synthetic crude as can be explained by the light-heavy differential: because heavy oil is worth less to a refiner, it typically sells at a discount to light oil. This difference in price is referred to as the differential. When the differential widens, it means that heavy oil is trading at a larger discount to light oil and it fetches a lower price. Bitumen is discounted yet again with respect to heavy oil.

Therefore, refiners are able to profit significantly from the end products. Petro-Canada has calculated that the bitumen netback depends on value of bitumen blend and the cost of diluent.
The Canadian Association of Petroleum Producers state that in recent years, slower natural gas growth, a shift to producing drier gas with less pentanes and competing demands for natural gas liquids have constrained available supplies of condensate.

Escalating prices and insufficient condensate supplies combined with growing supplies of heavy/bitumen crude that need a source of diluent have forced producers to examine other options. As a replacement for condensate, producers of oil sands bitumen are starting to use light synthetic crude oil as an alternative source of diluent for blending to pipeline viscosity requirements. This trend to use synthetic crude have led to the evolution of a synthetic bitumen blend referred to as Synbit. Synbit is more leveraged due to the higher diluent ratio, lowering netback. Therefore, lower diluent costs increases the bitumen netback

There are a lot of proposed pipeline expansion projects that aim to be able to move the SCO to markets with significantly more refining capacity. This will decrease the amount to which bitumen is currently being discounted.

There are also a number of projects underway to increase the refining capabilities of bitumen and synthetic crude oil.

Fort McMurray - Population Growth

The regional municipality of Wood Buffalo, which contains Fort McMurray and all the areas that contain oil sands, conducted a study to determine how much the population of Fort McMurray would grow in the next decade.

According to their website, they are now projecting 250,000 people by 2015. The municipality even has its own job requirements listed on the front page of their website.

This is a chart of the number of dwelling units that need to be constructed in order to keep up with the population growth.


The average rent is $2,000. There are many complaints that now one can afford to retire in Fort McMurray.







This chart shows the number of dwellings Fort McMurray will be short if the population growth rate stay around 12%. Since this chart was created, the Wood Buffalo municipality upped its growth rate projections to 15%.

The current average resale on a property is 35%. This will only get worse as the population grows and the housing starts are not able to keep up.

The average single family home is $441,924 in 2006. That would be a profit of $154,000 for one year.

Crude Oil Supply - Labour Requirements

The jobs growth required by the cities of Fort McMurray and Edmonton are significant in order to reach the projected production targets and to satisfy the requirements of the pending oil sands projects.

This is a sample put forward by the Canadian National Energy Board to illustrate the demand that Alberta must face.

The problem is compounded by the fact that Fort McMurray is in a remote cold location and $100 oil has created a lot of jobs for skilled labour in the oil field services industry.

Crude Oil Supply - Upgrader Alley

This is the town of Fort McMurray that is located in the remote North Central Alberta. A decade ago the population was reaching 35,000.

The map shows the 1 lane (both directions) highway 63 that was built to service the town from Edmonton.

The highway sees an increasingly high volume of traffic due to the booming oilsands industry in Wood Buffalo, causing potentially serious transportation-related problems. Not surprisingly, many residents in Fort McMurray and others who frequently use the highway view this as an issue that needs to be dealt with in a timely manner. Trucks carrying large equipment can delay the traffic greatly, since they can be large enough to occupy two traffic lanes. Most of Highway 63 is two-lane undivided highway, with the exception of just a few kilometres south of and through Fort McMurray to roughly 25 km (15 miles) north of Fort McMurray. It is also the only all-weather road leading out of Fort McMurray, which makes it a critical link.

Crude Oil Supply - Transmission Capacity

Western Canada and the Western U.S. have vast potential to supply growing electricity markets in the Pacific Northwest and the U.S. Southwest with environmentally attractive, stable-priced electricity. Meanwhile, the Western Electricity Coordinating Council (WECC) estimates demand for power in the region will grow by more than 26,000 megawatts (MW) by 2015.

TransCanada’s NorthernLights initiative proposes to connect these sources of low-cost and renewable supply to growing markets via long distance, High Voltage Direct Current (HVDC) transmission lines that maximize the use of existing and emerging energy infrastructure corridors and rights-of-way where practical.

The NorthernLights Project aims to connect Fort McMurray's transmission lines with the NorthWestern United States in order to have a place to send any excess generation capacity.


This NorthernLights consists of two major projects:

• Three long distance, High Voltage Direct Current (HVDC)transmission lines Each line up to 3,000 MW and $1.5 to $2.0 Billion
• Celilo Project Oil Sands cogeneration, wind, and other clean energy sources in Alberta and British Columbia

Crude Oil Supply - Forecasted Excess Cogeneration

The increased requirements for electricity to support the increased oil sands production will also produce an abundance of excess electricity.

TransCanada forecasts that the electricity will cause alot of congestion on the Alberta grid. Calgary and Edmonton do not provide enough load to use up any excess capacity. Therefore, there are many projects in development to link the transmission in Fort McMurray with other high load areas (California, Las Vegas, Seattle).

Crude Oil Supply - Natural Gas Demand

Energy Alberta Corporation calculated that Alberta would become a net importer of natural gas (5 bcf per day) if the proposed oil sands projects become a reality. The demand for natural gas for oil sands production is expected to increase by 300% by 2015. Oil sands production is forecasted to increase 4 fold by 2015 according to the Canadian National Energy Board.

Energy Alberta Corporation is a proposing to use nuclear technology to supply oil sands operators and Alberta with a stable glow of electricity, steam and hydrogen at the lowest cost.

Crude Oil Supply - SCO and Bitumen Supply Costs

Most of the crude bitumen that is produced will be upgraded to synthetic crude oil. The SCO would be sold to downstream refineries.

The analysis, conducted by the Canadian Energy Research Institute, of upgrading costs indicates that a mining project producing SCO in the Athabasca area would also need WTI prices of about US$25/b to be economic.

One of the key parameters for these analyses is the assumed natural gas prices, since these projects are very large natural gas consumers.

For their analysis, they assumed:

• NYMEX natural gas price of US$4.25/MMBtu – this translates into a plant gate natural gas price of C$4.74/GJ (March 2, 2004 closing prices were US$5.565/MMBtu and C$5.98/GJ respectively)
• Canada US exchange rate of 0.75 US$/C$ (March 1,2004 closing rate was 0.7448 US$/C$)

The costs of upgrading crude bitumen is estimated to be C$12.71/b

This is a summary, provided by the Canadian Energy Research Institute, of supply cost results for crude bitumen from Athabasca and Cold Lake. This bitumen has not been upgraded but can still be valued in the market as shown here.

Their analysis indicates that the oil sands industry requires West Texas Intermediate (WTI) oil prices of about US$25 per barrel at Cushing, Oklahoma to cover all costs and earn an adequate return on investment. While current oil prices are much higher, many project proponents are basing their plans on prices in the midtwenties.

The difference between the plant gate price and the WTI price takes into account:

• Transportation costs to market
• The value of the bitumen in the market having regard for its high sulphur content and low API gravity.

Crude Oil Supply - Project Costs by Type

The majority of the proposed projects will be for projects related to open pit mining. This is surprising since the majority of the crude oil is projected to come from In Situ production methods (SAGD). In situ production is regarded as being more energy intensive due to the large amount of steam that needs to be produced inorder to extract the bitumen from the oil sands. However, the open pit mining requires more heavy machinery and labour.

Crude Oil Supply - Project Realization Probabilities

According to StrategyWest, 1/4 of all projects, that have been announced or disclosed to the public, will be actualized. The projects that will come to fruition will probably be delayed by 2 years.

The high rate of project terminations will significantly hamper Alberta's attempt to reach 5 million barrels per day.

The projects that have been disclosed and announced to the public account for production capabilities of 2 million barrels per day.

Crude Oil Supply - Status of projects to increase production

StrategyWest believes issued a report detailing the status of all current oil sands projects and their production potential. There is a slim amount currently under construction. These construction initiatives are taxing the materials, supply and labour capabilities of the Fort McMurray region. There is a significant amount of projects that are still pending at various stages that will compete for those supply, materials and labour costs.

Crude Oil Supply - Natural Gas Supply

Recent projections of natural gas supply indicate that total production from the WCSB is expected to
stay relatively flat, in the range of 16.5 to 17.0 Bcf/d until the 2010 to 2011 timeframe

Alternative sources of gas supply are postulated, such as increased CBM and imports of liquefied natural gas (LNG) and, in the 2009 to 2013 timeframe, supplies from the North via the Mackenzie Valley and Alaska pipelines. If supply from these sources develops more slowly than projected, it is possible that tight gas market conditions might prevail over the next five to six year period or longer, until alternative supply can be delivered in sufficient quantity.

In order to reduce their exposure to gas prices, oil sands operators are actively seeking to reduce their dependence on natural gas, by increasing efficiency through improved energy management, and by researching and developing alternate sources of energy.

Crude Oil Supply - Natural Gas Costs per Barrel

The following chart created for the Alberta Chamber of Commerce technology roadmap, provides an estimate of energy costs for all facets of the value added chain with natural gas consumptions.

For recovery and full upgrading, and for full reliance on natural gas, costs for energy and hydrogen range from $5 to $8 per barrel.

Several oil sands companies have instituted energy efficiency into their operations in the form of cogeneration systems; the simultaneous production of electricity and thermal energy from a single facility (usually gas turbines with heat recovery steam generators). The electricity is used to meet project energy needs, such as operating mine machinery and in-situ well pumps, with excess electricity being supplied to the provincial grid. It is evident from the chart that cogeneration is a better balanced option for mining or upgrading; to generate sufficient steam via cogeneration for In-Situ production will result in a vast excess of power, with limited transmission facilities to handle it at this time.

Crude Oil Supply - Natural Gas Usage

High natural gas prices have encouraged oil sands operators to use gas more efficiently and to look for alternative fuels. The extent to which bitumen gasification or other alternatives to natural gas use prove successful and are adopted in additional operations will materially affect the purchased gas requirement in the oil sands.

The chart shows the approximate distribution of natural gas requirements for oil sands operators, and provides the basis for developing longer-term projections of natural gas demand for oil sands operations. The incremental future upgrading category is included to recognize that the demand for higher quality, cleaner SCO, and thus the demand for hydrogen in upgrading, will rise in the future.

Crude Oil Supply - Electricity Requirements

Electricity costs are expensive due to the remoteness of the oil sands. Most companies have developed their own cogeneration plants to supply electricity to their projects.

Due to the relatively weak demand for electricity by population of Alberta, oil sand development companies are unable to develop substantial amounts of surplus, because there is no where to put it on the grid.

Supply Costs - Diluent Availability

The supply of Canadian condensate or pentanes plus (C5+) is inadequate to meet the growing demand as heavy crude diluent, which is needed to allow rising bitumen supplies to move by pipeline to refi ning markets. Many diluent options are potentially available, including imports, use of alternative diluents and/or upgrading to avoid diluent and possibly produce diluent. The challenges and opportunities associated with any of these options dictate short-term solutions as well as planning for longterm commitments. A particular diluent option may be positive for one stakeholder, but negative for another. Diluent issues pose a dilemma for producers, refi ners, upgraders and pipeline companies.

The projections of available supply take into account the diluent requirements for blending heavy oil and non-upgraded bitumen, recycled volumes of diluent, product losses during upgrading and volumes of condensate not available for blending. There are a number of potential solutions to deal with anticipated shortfalls of condensate for blending purposes, such as offshore imports, long haul recycle by truck or rail, diluent-return pipelines from the U.S., specifically refined diluents, and blending with light crude oil or SCO. If the proposed Mackenzie Valley Gas Pipeline is built, another 2 850 m3/d (18 Mb/d) of condensate could be available.

Supply Costs - Natural Gas Costs

Both integrated mining and thermal in situ operations are intensive users of natural gas. Over the past several years, the price of natural gas has increased substantially. The future price of natural gas and the development of alternatives, including fuel substitutes and gasification, will have a material impact on supply costs and project economics.

Supply Costs - Development Costs

Oil field development costs have grown significantly in Canada 1997 to 2001 due to development of the oil sands. Oil sands projects, particularly those involving upgrading facilities, are very capital intensive and project economics are extremely sensitive to capital costs. Continued escalation in raw material and labour costs will have a material impact on supply costs and project economics.

Capital costs have risen dramatically due to higher prices for steel, cement and equipment. The rising pace of development has also led to a shortage of skilled tradespersons and a reduction in the overall productivity of labour. These cost escalations and the challenge in attracting skilled labour are being felt all across the world, but are particularly severe in the oil sands region because of its relatively remote location, the high pace of development, and the scope and complexity of the projects being undertaken.

The rise in energy prices has been the most dominant factor influencing project economics and the oil sands development drive. Higher oil prices have boosted revenues; however, operating costs have also increased significantly with the rise in electricity and natural gas prices. The latter is of particular importance with an estimated 1 Mcf required to produce each barrel of bitumen. For in situ producers, the availability and price of diluent for blending has become a more pressing issue, as has the market value of heavy versus light crude oil (the differential) in traditional markets.

Lower production costs have been an important factor driving investment. However, in 1996, the Federal and Alberta governments established generic oil sands fiscal terms to make oil sands investment more competitive with oil developments elsewhere in the world. Investment dollars for oil sands projects compete with projects in areas like the U.S. Gulf of Mexico or the west coast of Africa. Governments’ vision to develop a royalty and tax regime that provides long term fiscal certainty is a key factor that supports the current oil sands growth forecasts.

Supply Costs - Economical Oil Prices

The oil sands are only economical to mine and refine when the price is above $20-$40 USD. This is based on 2004 estimates. However, a new study from StrategyWest proclaims that most oilsands projects need to have oil prices between $60-$70 in order to be profitable due to increased input costs.

Influences on Oil Sands Development

There are 8 factors that will influence whether the oil sands become a conventional global source of crude oil and promote Canada to the country with the second highest crude oil reserves.

Detractors

1. Market Development and Pipelines


2. Rising Capital and labor costs


3. Rising Operating Costs


4. Managing Environmental Impact

Promoters

1. High Crude Oil Prices


2. Rising Global Energy Demand


3. Technology Innovations


4. Stable Investment Climate

Forecasted Oil Sands Production

The annual production forecast for oil sands from Alberta is projected to be 5 million b/day by 2030. These production levels are expected to last well beyond 2050.

In situ mining is expected to be the dominant production method as open pit mines are exhausted and become to costly.

Oil sands contain 12% bitumen. In situ extraction takes place when water is boiled into steam. The steam is blasted into the oil sands to separate the bitumen from the sand. The bitumen is then pumped back to the surface.

Steam assisted gravity drainage

Introduction

This blog aims to inform and educate people on the major challenges facing the future of the Alberta oil sands as a major domestic petroleum source in the 21st century.

For over 200 years Canada has known about the existence of the oil sands. Canadians, throughout the nations short history, had forecasted its great potential for the future of the global energy supply. However, it took until the beginning of the 21st century for the global factors to align just properly for the oil sands to move from a dream worth dreaming to a dream worth chasing.

So what events occured that kicked off the oil sands rush. Oil exploration, production and services companies needed to have two things happen: The technology had to improve and the price of oil had to go up. In the early 1990s, a simple switch helped to solve the first problem. Companies went back to using enormous dump trucks – as big as a two-storey house – to haul out the sand, rather than conveyer belts, which were difficult to move when needed and often froze in the northern cold. At Suncor, this yielded immediate results: Energy requirements were reduced by 40 per cent and the overall cost per barrel was slashed by several dollars.
Syncrude also fared better after it figured out how to transport the bitumen more cheaply by sending it through pipes as a watery slurry. Even with the price of oil bouncing around $20 a barrel, the improvements were enough for both companies to turn a profit. But to the rest of the world, the oil sands might as well have been on another planet. The year Mr. George arrived at Suncor, they were producing about 350,000 barrels a day, a tiny fraction of what geologists believe the sands hold.

And how much oil is there? Estimates bounced around for years until 1999, when Alberta got serious about determining its potential. Based on data from 56,000 wells and 6,000 core samples, the Energy and Utilities Board (EUB) came up with an astonishing figure: The amount of oil that could be recovered with existing technology totalled 175 billion barrels, enough to cover U.S. consumption for more than 50 years. With the new math, Canada slipped quietly into second place behind Saudi Arabia's 265 billion barrels in oil reserves, followed by Iran and Iraq.
To the frustration of Albertans, nobody paid much attention. There was no war on terror and the world was awash in oil. The news “went virtually unnoticed,” recalls Rick Marsh, a geologist who leads the EUB's oil-sands section.

Then, in the spring of 2002, Murray Smith, recently installed as Alberta's energy minister, was called to a Saturday-morning meeting to review the EUB's annual report. He spotted the big figure and “his eyes lit up,' says Neil McCrank, then the board's chairman. “Murray is a salesman and he could see the impact this would have on Alberta. This obviously put Alberta in a different position on the world energy scene.”

The scale of bringing the oil sands into the pantheon of conventional oil is monumental. The construction of the Hoover dam is nothing compared to the scale of contructing the infrastructure that will enable the economical producing, upgrading, transporting and refining of the Albertan oil sands.

1. Supply Costs



2. Project Costs



3. Natural Gas Supplies



4. Electricity Requirements



5. Fort McMurray Infrastructure



6. Fort McMurray Population



7. Markets expansion



8. Light/Heavy Differentials