IHS CERA meta-analysis finds lifecycle GHG emissions for fuel produced solely from oil sands crude average 11% higher than from average crude refined in the US; high variability
|Average values for WTW GHG emissions for oil sands and other crudes, tight boundary. Source: IHS CERA. Click to enlarge.|
When the boundary for measuring GHG emissions is placed around crude production and processing facilities, for fuels produced solely from Canadian oil sands the average well-to-wheels (WTW) life-cycle GHG emissions are 11% higher than for the average crude refined in the United States (results range from 4% to 18% higher), according to a new meta-analysis by energy market consultancy IHS CERA.
When the oil sands products refined in the United States are considered—a mixture of oil sands and lower-carbon blending components—the GHG emissions are, on average, 9% higher than the average crude processed in the US.
Although crudes derived from the Canadian oil sands are more carbon-intensive than the average oil refined in the United States, they are within the range of some other crude oils produced, imported, or refined in the United States, including crudes from Venezuela, Nigeria, Iraq, and California heavy oil production, according to the report.
The new analysis updates the company’s September 2010 report, Oil Sands, Greenhouse Gases, and US Oil Supply: Getting the Numbers Right, and includes the most recent GHG emissions estimates and clarifies its meta-analysis methodology. Both reports analyzed the complete well-to-wheels life cycle—the extraction, processing, distribution and combustion of the refined fuel.
The original 2010 report had found the average for oil sands products refined in the US was 6% higher than the average crude processed in the United States with total emissions from refined products wholly derived from oil sands being 5-15% higher than the average barrel.
The widening range in emissions estimates compared to the original report is the result of a more detailed estimate for US oil sands imports—the latest update accounts for all major sources of oil sands production. However, the majority of the difference was due to increases in the estimate for GHG intensity of some oil sands extraction methods, such as SAGD dilbit, mining SCO and CSS dilbit.
These results do not necessarily indicate an increase in oil sands carbon intensity since 2010, IHS said, but rather a revision of the results based on new studies that have applied different modeling techniques and data. The latest report is drawn from the results of 12 recent studies from government, academic and industry sources.
The new report also includes results measuring Canadian oil sands GHG intensity accounting for emissions that occur beyond the crude production and refining facilities such as the production and processing of natural gas used in oil production or emissions from off-site electricity production.
When accounting for these “wide boundary” results the new report found that transportation fuels produced solely from oil sands result in average well-to-wheels GHG emissions that are 14% higher than the average crude refined in the United States (results range from 5% to 23% higher). Emissions beyond the facility site include those from producing natural gas used at oil production facilities and from electricity generated off site.
Although not part of the typical method a few years ago, these emissions are accounted for in more recent studies. For many crude oils these indirect emissions are not material, but for some crudes (including oil sands) they are more consequential. However, as the boundary for measuring GHG emissions grows wider, the uncertainty in the estimate also increases.
Variability. IHS CERA compared 12 sources in its meta-analysis. When multiple studies estimated the carbon intensity of a single crude oil, the production emissions estimates varied by an average of 30%.
This significant variability in results highlights the level of uncertainty in measuring life-cycle greenhouse gas emissions. Indeed, in many cases the uncertainty in emissions estimates is larger than the GHG emissions reductions that the policy requires—a key challenge in developing policies that are based on life-cycle analysis.—2012 Update
Most differences among studies arise in four places, the company noted:
Data quality and availability. Accurate data are often difficult to obtain for comparing GHG emissions across specific crude types. Frequently, oil and gas data are considered proprietary. Even when data can be obtained, data vintage is a second issue. The GHG intensity of a specific operation changes over time, so more current data are preferred.
Allocation of emissions to co-products. Life-cycle analysis often requires attributing emissions from a process to multiple outputs of that process. Depending on how emissions are allocated to each product, the emissions for a specific product can vary substantially. Studies of well-to-wheels emissions vary greatly in their methods of allocating emissions to refined products. Some studies allocate all GHG emissions to the gasoline stream (with the reasoning that all other products are simply by-products of gasoline production). Other studies allocate the emissions across all products by volume, while others divide GHG emissions based on the energy content of the products or the energy consumed in making the products.
Differing system boundaries. Deciding which steps and processes in oil production to include in the system boundary—including how far back in the supply chain to reach—is another difference among life-cycle analyses. Emissions directly attributable to production are typically included, but some studies do not include secondary or indirect emissions, such as emissions from upstream fuels (producing the natural gas or electricity off site), the impacts of land use change, or emissions from construction of the facility. Generally, as the boundary is drawn wider, the uncertainty in the estimate increases.
Differing study purpose. Some studies aim to present a detailed “bottom-up” analysis of a specific operation and crude type and require a high level of data precision. Other studies—often those supporting policy—aim to represent the average GHG emissions for the industry or a country as a whole and consequently rely on less precise data.
Since 1990, the GHG intensity of mining and upgrading operations has fallen by 37% on a well-to-tank basis. Since the inception of SAGD (steam-assisted gravity drainage) about a decade ago, well-to-tank emissions have declined by 8%.
For mining, major drivers of GHG emissions reductions have included hydrotransport, improvements in bitumen extraction, shifting to natural gas cogeneration for electricity and steam, and efficiency improvements in upgrading.
For SAGD, major drivers of GHG emissions reductions have included improved reservoir characterization and wellbore placement, use of electric submersible pumps, and wellbore liner improvements. These technical advances have reduced the steam-to-oil ratio (SOR), a critical metric of efficiency in SAGD production.
Further gains in GHG intensity are still possible and continue to be pursued by industry, according to IHS CERA.
For in-situ extraction, the focus is on decreasing steam use. Ongoing efficiency improvements and the penetration of new hybrid steam-solvent technologies that partially substitute solvents for steam could reduce steam use of in-situ production by perhaps 5% to 20% (on a well-to-tank basis). Even if solvent techniques were to cut steam injection for in-situ recovery by half, on a well-to-wheels basis emissions would still be greater than for the average crude refined in the United States. However, this strategy would put oil sands in-situ emissions lower than some other US supply sources, including some crudes from Venezuela, Africa, Iraq, and California.
Original mining operations focused on synthetic crude oil (SCO). IHS CERA notes that a new mining operation is under construction that will not upgrade to SCO; instead the bitumen will be shipped to market as dilbit (bitumen mixed with a diluent). On a well-to-wheels basis, the process is expected to result in GHG emissions that are 6% lower than for a traditional mine and upgrading operation.
Although technical advancements in oil sands production are possible, they are not inevitable. As with conventional production, reservoir quality is one factor that could push back against technical advances. Generally, the first generation oil sands projects selected some of the best parts of the oil sands deposit—those with characteristics that allow the most efficient recovery. As reservoir quality declines, more energy is required to extract the bitumen. This is especially the case with in-situ production, where more steam injection is needed to stimulate the flow of bitumen in poorer quality reservoirs. But technology advances may mean that all other things aren’t equal. In other words, two trends—one of declining reservoir quality and the other of continued technical advances in oil sands production methods—will exert opposing forces on GHG emissions trends. Another factor is economics: money still matters. Even if a new green technique reduces emissions, it will not be adopted if it is not competitive with established methods.—2012 Update