Why did the NEB decide to prepare this Energy Market Assessment (EMA)?
In the course of carrying out its analyses in 2003 in connection with the preparation of the Board's report entitled Canada's Energy Future, Scenarios for Supply and Demand to 2025, the Board identified a number of important opportunities and challenges facing the oil sands. It decided to prepare this EMA as a means of outlining and discussing these issues.
What is the primary purpose of the EMA?
The primary purpose of the report is to provide an objective assessment of the current state of the oil sands industry and of the potential for growth. In addition, it identifies and discusses the major issues and challenges associated with further development and, in this regard, the report is intended to further the public dialogue.
What are the main conclusions of the EMA?
How much money is being invested in oil sands?
Over C$60 billion in oil sands related projects have been proposed. Approximately C$20 billion has been invested to-date in completed projects.
What is the estimated initial established reserve of oil in the oil sands?
The initial established reserves, estimated to be 28.3 billion cubic metres (178 billion barrels), would be sufficient to satisfy total domestic demand for crude oil, at current rates, for approximately 250 years.
What is the estimated ultimate volume of crude bitumen in place?
The Board has adopted the estimates of the Alberta and Energy Utilities Board and, according to it; the ultimate volume of crude bitumen in place is estimated to be approximately 260 billion cubic metres (1.6 trillion barrels).
What are the (i) operating costs, and (ii) the supply cost of producing a barrel of oil from the oil sands?
The estimated operating costs range from 4 to 14 dollars for bitumen and 12 to 18 dollars for synthetic crude oil. The estimated supply costs ranges from 10 to 19 dollars for bitumen and from 22 to 28 dollars for synthetic crude oil*.
* Supply costs include operating costs, capital costs, taxes, royalties and the rate of return on investment.
What is the industry doing to reduce emissions?
The oils sands industry has been actively dealing with emissions by using low nitrogen oxides burners, sour water treaters and flue gas desulphurization to reduce emissions. Other examples of gas emission reduction opportunities include:
In addition, there have been many multi-stakeholder groups established in recent years and all are examples of industry, governments and local communities working together to create policies and programs to address greenhouse gas emissions.
On a per unit recovery basis there have been significant reductions in greenhouse gas emissions due to investment in new technologies even though there has been an increase in production. The Board's report shows a 53 percent reduction in carbon dioxide emissions per barrel for the period from 1990 to 2010 due to investment in new technology; this represents a 2.6 percent improvement per year. Syncrude, for example, predicts that its greenhouse gas emissions per barrel of production will be 38 percent lower by 2008 compared to 1990 emissions.
Will there be markets to take the additional production of oil from the oil sands?
In the short-term, expansions in the traditional markets will occur for the additional supply and, in the longer term, new markets will need to be developed. The industry has been creative when seeking markets for its production.
In broad terms, market expansion will occur in four steps.
NOTE: See Figure 6.2 of the report for Major Canadian and U.S. Crude Oil Pipelines and Markets.
Will there be pipeline capacity to transport the additional production of oil from the oil sands?
To transport production to existing or new markets, pipelines will have to be expanded or new pipelines will have to be built.
What is the natural gas requirement relative to oil sands development?
It takes about 28 cubic metres (1000 cubic feet) of natural gas to produce one barrel of bitumen from in situ projects and about 14 cubic metres (500 cubic feet) for integrated projects. Currently, the oil sands industry uses about 17 million cubic metres (0.6 billion cubic feet) per day of purchased gas, or about four percent of the Western Canada Sedimentary Basin production. By 2015, this increases to about 40 to 45 million cubic metres (1.4 to 1.6 billion cubic feet) per day, or nearly 10 percent, assuming gas production stay level at 467 million cubic metres (16.5 billion cubic feet) per day.
How much water is required to produce one barrel of oil from the oil sands?
The water requirements for oil sands projects range from 2.5 to 4.0 barrels of water for each barrel of bitumen produced.
What is the oil sands industry doing to conserve water in the production of oil?
Oil sands operators have been involved in several initiatives to develop new technologies and integrated approaches to water conservation. Currently, the following methods to conserve and reduce the total use of fresh water are being used or investigated by the oil sands industry:
How can the oil sands industry provide opportunities for the petrochemical sector?
The Alberta petrochemical sector now faces a situation of tight ethane feedstock supply, raising the need to consider future ethane supply and feedstock flexibility.
The bitumen upgrading process produces off-gas from which ethane, ethylene, propylene and other light hydrocarbons could be extracted and used by the petrochemical industry as feed for the ethylene or derivative plants. Currently ethane and ethylene and most of the other light hydrocarbons are not removed, but used as fuel for operations.
In addition to off gas, upgrading bitumen represents potential feedstock in the form of intermediary refined petroleum products such as naphtha, aromatics, and vacuum gas oil.
Both sources - light hydrocarbons from off -gas or intermediary products - would require a coordinated/integrated approach to reach economies of scale and would likely be at least ten years away. By 2015, however, market conditions may evolve so that Alberta's huge bitumen resource base could provide a secure, substantial, and stable-priced feedstock for the petrochemical industry.
Why would the oil sands industry be interested in getting involved in an upgrader / refinery / petrochemical complex?
Upgrading bitumen, which is made up of very high-molecular-weight hydrocarbons produces smaller hydrocarbon compounds which are more suitable for use as refinery feedstock. Off-gas and vacuum gas oil are also produced as by-products.
In addition to these by-products, various intermediary products from the upgrading process could be combined with off-gas hydrocarbons and intermediary products from refinery processes, to accumulate feedstock for a petrochemical facility.
Opportunities from an integrated approach, if identified, could reduce total costs to the point where Alberta value-added petrochemical products can be competitive in the North American market. Perhaps piggy-backing petrochemical developments with the upgrading and refining sectors could improve economics and add flexibility. However, an upgrader/refinery/petrochemical complex would be capital intensive and would require a coordinated/integrated approach to reach economies of scale and would likely be at least ten years away.
What is cogeneration?
Electricity generation and oil production involve two distinct processes that convert energy from one form to another. A cogeneration plant realizes efficiency gains by combining the processes using fuel, typically natural gas, to run a combustion turbine to turn a generator and produce electricity. A heat recovery steam generator then captures the remaining heat that would normally be wasted, and uses it to produce steam, hot water or a mixture of the two. This is then used in the oil sands production.
How does using cogeneration versus stand-alone methods of producing steam and electricity impact natural gas fuel consumption?
If the oil sands producer is looking to minimize its total onsite natural gas consumption then using a boiler to just produce steam, while obtaining the electricity from an offsite source, can be the best option. In this case, how much fuel (natural gas) that may be burned to generate the electricity offsite is not considered.
If the oil sands producer is looking to minimize the total amount of natural gas consumed between steam and electricity generation, then a cogeneration facility will consume less gas for the same amount of steam and electricity generated as the respective stand-alone units.
What are some additional benefits of using cogeneration versus stand-alone steam and electricity generators?
Producers can help protect themselves from electricity price fluctuations by using a cogeneration facility. The benefits received from using cogeneration are long-term given the long economic life of oil sands projects, stretching out 30 years or more. What's more, when the cogeneration for thermal in situ recovery projects such as steam assisted gravity drainage are sized based on the amount of steam required, they produce so much electricity it is doubtful the oil sands project would expand to ever fully utilize the surplus electricity generated.
In summary, what are the opportunities and challenges of cogenerations in the oil sands?
Cogeneration enables an oil sands producer to increase their reliability of electricity supply, gain fuel efficiencies that translate into environmental benefits, and increase revenues through the sale of surplus electricity to the market. One of the greatest opportunities is being able to produce large quantities of inexpensive electricity while maximizing the previously listed benefits. The main challenges producers face achieving these opportunities are the slow pace of construction of new transmission infrastructure tying in the Alberta oil sands regions and the perception that the Alberta load is too small to support maximizing the potential cogeneration capacity.