[Due to the increasing size of the archives, each topic page now contains only the prior 365 days of content. Access to older stories is now solely through the Monthly Archive pages or the site search function.]
Average carbon intensity of oil sands production has dropped ~36% in last 40 years; still 12-24% higher than conventional oil CI
November 21, 2013
|Trends in well-to-wheel pathway-specific CI. In situ production began in 1974, so no value is computable for 1970. Click to enlarge.|
The carbon intensity (CI) of Alberta oil sands production has significantly decreased over the last 40 years, according to a new study by a team from Stanford University published as an open access paper in the journal Environmental Research Letters.
Relying entirely on public and peer-reviewed data sources for the period from 1970 to 2010 (inclusive), the team found that industry-average full-fuel cycle (well-to-wheels, WTW) CI declined about 36% from 165 gCO2e MJ-1 higher heating value (HHV) of reformulated gasoline (RFG) to 105 (-12, +9) gCO2e MJ-1 HHV RFG. 2010 averages by production pathways are 102 gCO2e MJ-1 for mining and 111 gCO2e MJ-1 for in situ production.
U. Calgary analysis of energy balances and emissions of SAGD oil sands production finds need for improved processes; some operations not thermally efficient or net generators of energy
October 19, 2013
A team at the University of Calgary has assessed the thermal efficiencies, energy balances, and emissions of Steam-Assisted Gravity Drainage (SAGD)—both theoretically and as deployed at scale, using field data from the ERCB—for the production of bitumen from Athabasca oil sands reservoirs. In a paper in the journal Fuel, they report that current SAGD projects in Alberta show a very wide range of field performance.
Although optimized SAGD can yield “reasonably high” recovery factors, they found, the economic and environmental costs can be large given the amount of steam required. The data suggests that at the extreme, some operations are actually not net energy generating—i.e., the energy injected via steam exceeds the recovered chemical energy in the retrieved bitumen. The results suggest that in situ bitumen recovery processes need to advance well beyond current capabilities “if practical and sustainable energy balance and emissions scenarios are to be achieved,” they said.
Western Hydrogen produces first hydrogen from Molten Salt Gasification pilot plant
September 29, 2013
|Molten Salt Gasification Process. Click to enlarge.|
Western Hydrogen Limited reported first production of hydrogen from its Molten Salt Gasification (MSG) pilot plant in Fort Saskatchewan, Alberta. The MSG process, under license from Idaho National Laboratory, uses a combination of molten sodium salts (sodium carbonate and sodium hydroxide) to convert a carbon feedstock and water into hydrogen. The technology allows the production of high-pressure hydrogen without the need for compression and can use a variety of feedstocks, including renewables.
Following six years of testing at the Idaho National Laboratory, the pilot plant was constructed to demonstrate the technology’s reliability in a large-scale production facility.
AER reports recovery of 337,000 gallons of bitumen from surface seeps at CNRL Primrose site; earlier event in 2009
August 18, 2013
The Alberta Energy Regulator (AER) reports that 1,275.7 m3 (337,004 gallons US) total bitumen emulsion has been recovered from the ongoing bitumen upwelling at four sites in Canadian Natural Resources Limited’s Primrose project. The incident site locations are approximately 45 km NW of Cold Lake, Alberta.
CNRL is using high pressure cyclic steam stimulation (HPCSS) operations (also called “huff and puff”) at Primrose—i.e., underground, in-situ thermal production of the bitumen. HPCSS has been used in oil recovery in Alberta for more than 30 years, AER noted. However, there was an earlier, similar event of bitumen upwelling at the Primrose project initially reported in 2009. Primrose South/North is on stream with a target capacity of 80,000 barrels per day; Primrose East is on stream with a target capacity of 40,000 barrels per day.
IHS-CERA concludes “no material impact” on US GHG from Keystone XL; heavy crude from Venezuela most likely replacement
August 09, 2013
The proposed Keystone XL pipeline for transporting oilsands-derived crude to Gulf Coast refineries would have “no material impact” on US greenhouse gas (GHG) emissions, according to a new Insight report by IHS CERA. In a June speech at Georgetown University, President Barack Obama said that the controversial Keystone XL pipeline would only be built if the project “does not significantly exacerbate the problem of carbon pollution.” (Earlier post.)
In the absence of the pipeline, alternate transportation routes would result in oilsands production growth being more or less unchanged, IHS CERA found. The study also found that any absence of oil sands on the US Gulf Coast would most likely be replaced by imports of heavy crude oil from Venezuela, which has the same carbon footprint as oilsands crude.
BC government won’t support Northern Gateway oilsands pipeline as presented over spill response concerns
June 01, 2013
In its final written submission to the Northern Gateway Pipeline Joint Review Panel (JRP), the government of British Columbia states that it cannot support the project as presented to the panel primarily because Northern Gateway (NG) has been unable to adequately detail its response to a spill.
The Northern Gateway Pipeline is a proposed 1,170-kilometer (727-mile) twin pipeline from Edmonton, Alberta to Kitimat on the British Columbia coast. Northern Gateway’s West line, 36 inches in diameter, would transport an average of 525,000 barrels of oil sands crude per day to Kitimat. The East Line, 20 inches in diameter, will carry 193,000 barrels of condensate per day back to Edmonton. Condensate is used to thin petroleum products for pipeline transport (diluent).
Canada backs demonstration-scale algal biorefinery project in the oil sands; Algal Carbon Conversion
May 19, 2013
The Government of Canada is supporting a three-year project that will result in the construction of a $19-million, demonstration-scale facility in Alberta that will use algae to recycle industrial carbon dioxide emissions from an oil sands facility into commercial products such as biofuels. The Algal Carbon Conversion (ACC) Pilot Project is a partnership among the National Research Council of Canada (NRC); Canadian Natural Resources Limited, one of the largest independent crude oil and natural gas producers in Canada; and Pond Biofuels.
The demonstration-scale algal biorefinery will be established at Canadian Natural’s Primrose South oil sands site, near Bonnyville, Alberta. The demonstration facility will be integrated into the Canadian Natural’s operations with direct access to industrial flue gas emissions, wastewater and waste heat.
Ceramatec licensing molten sodium technology for heavy oil upgrading; removing the need for diluent for bitumen
April 10, 2013
|Flowchart of Molten Sodium Upgrading process. Source: Field Upgrading. Click to enlarge.|
An innovative oil-upgrading technology that can increase the economics of unconventional petroleum resources has been developed under a US Department of Energy-funded project. The technology, developed by Ceramatec and managed by the Office of Fossil Energy’s National Energy Technology Laboratory (NETL), has been licensed to Western Hydrogen of Calgary for upgrading bitumen or heavy oil from Canada. A new company, Field Upgrading (Calgary, Alberta), has been formed dedicated to developing and commercializing the Molten Sodium Upgrading (MSU) technology.
The MSU process involves mixing elemental molten sodium and small quantities of hydrogen or methane to reduce significantly the levels of sulphur, metals, TAN (total acid number) and asphaltenes in heavy oil feedstocks, including oil sands bitumen. MSU also significantly increases the API gravity of the feedstocks while achieving a relatively higher yield compared to conventional upgrading technologies. In the case of oil sands bitumen, the API gravity is increased from 8 API to more than 20 API, eliminating the need for diluent for pipeline transportation.
Major spill from the ExxonMobil Pegasus pipeline in Arkansas
March 31, 2013
|Route of the Pegasus pipeline. Source: ExxonMobil. Click to enlarge.|
A breach in ExxonMobil’s Pegasus crude oil pipeline occurred late Friday afternoon near Mayflower, AR (about 20 miles north northwest of Little Rock and at the southwestern end of the Lake Conway reservoir). The pipeline has been shut in and crews are working to contain the spill. The US Environmental Protection Agency (EPA) categorizes the incident as a “major spill”—i.e., greater than 250 barrels (10,500 gallons).
ExxonMobil said that it observed a few thousand barrels of oil in the area (approximately 84,000 gallons), but is staging a response for more than 10,000 barrels (420,000 gallons) to be conservative. The cause of the spill is under investigation.
Univ. of Calgary team developing nanocatalysts for underground upgrading of heavy oil and bitumen; possible “next generation” of oil sands production
March 25, 2013
|Total injected hot fluid and total produced liquid for the nanocatalyst experiments at temperatures of 320 and 340 °C. Credit: ACS, Hashemi et al. Click to enlarge.|
Researchers at the University of Calgary are developing ultra-dispersed (UD) nanocatalysts for the in situ upgrading of heavy oil and bitumen from deep reservoirs. Such an “underground refinery” approach is one of the alternatives to surface upgrading that may become the next-generation of oil sands industry improvement, they suggest in a paper published in the ACS journal Energy & Fuels.
One of the challenges of such an approach is the placement of the catalyst deep into the heavy oil plume by transporting a catalyst suspension through the sand medium. In their paper, they report that water-in-vacuum gas oil microemulsions containing trimetallic (W, Ni, and Mo) ultradispersed colloidal nanoparticles could penetrate inside the porous medium and react with the bitumen, resulting in enhanced recovery.
State Department issues Draft Supplemental Environmental Impact Statement on Keystone XL Pipeline: climate change impacts
March 02, 2013
|Comparison of proposed Keystone XL route to previously proposed project segment. Source: Draft SEIS. Click to enlarge.|
The US Department of State (DOS) has released its Draft Supplemental Environmental Impact Statement (SEIS) in response to TransCanada’s May 2012 application for the Keystone XL pipeline that would run from Canada’s oils sands in Alberta to Nebraska. The document is a detailed draft technical review of potential environmental impacts associated with the segment of the pipeline in the US, including: impacts from construction, impacts from potential spills, impacts related to climate change, and economic impacts.
Aside from the potential construction and spill impacts of the pipeline, the scope of the climate change impacts have become the most contentious and politicized issue surrounding the pipeline. The DOS SEIS accordingly takes a detailed look at life-cycle greenhouse gas emissions of petroleum products from Western Canadian Sedimentary Basin (WCSB) oil sands crudes compared with reference crudes and the potential impact the pipeline might have on climate change as well as on the future development of the oils sands resource in Canada.
SDTC awards C$1.5M to support Molten Salt Catalyzed Gasification for hydrogen production; targeting reduced GHG footprint for oil sands synthetic crude
February 16, 2013
|Flowchart of the MSG process. Source: Western Hydrogen. Click to enlarge.|
A consortium led by Canada-based Western Hydrogen Ltd. will receive a $C1.5-million investment from Sustainable Development Technology Canada to support the development and commercialization of a new hydrogen manufacturing technology called Molten Salt Catalyzed Gasification (MSG), originally developed at the US Idaho National Laboratory (INL).
Hydrogen is necessary in the upgrading of oil sands bitumen into synthetic crude, but it is a costly and carbon-intensive part of the process, given current hydrogen production technologies. MSG converts natural gas into hydrogen with a 23% reduction in GHG emissions compared to steam methane reforming.
Researchers propose framework for CCS infrastructure optimization to reduce GHG emissions from oil sands extraction and processing
January 28, 2013
Two researchers from Los Alamos National Laboratory and Stanford University have developed an integrated framework that simultaneously considers economic and engineering decisions for the capture, transport, and storage of oil sands CO2 emissions (CCS). The model, developed by Richard Middleton (LANL) and Adam Brandt (Stanford) optimizes CO2 management infrastructure at a variety of carbon prices for the oil sands industry.
In a paper published in the ACS journal Environmental Science & Technology, they report that the oil sands industry lends itself well to development of CO2 trunk lines due to geographic coincidence of sources and sinks. This reduces the relative importance of transport costs compared to nonintegrated transport systems.
New study concludes oil sands development has significantly increased PAH and DBT loadings in regional lakes; combined with effects of climate change, a “new ecological state” for the lakes
January 09, 2013
A new study by a team from Environment Canada and Queen’s University (Canada) has shown that polycyclic aromatic hydrocarbons (PAHs) within the sediments of lakes in the Athabasca oil sands region in Canada—particularly C1-C4–alkylated PAHs, increased significantly after development of the oil sands resource began some 50 years ago—followed by significant increases in dibenzothiophenes (DBTs).
Total PAH fluxes in the modern sediments of six study lakes, including one site ∼90 km northwest of the major development area, are now ∼2.5–23 times greater than ∼1960 levels. Total DBT enrichments over the same time period ranged between ∼2.6 and 57 times.
New petroleum refining lifecycle model finds the variability in GHG emissions from refining different crudes as significant as magnitude expected in upstream operations
December 09, 2012
|Comparison of GHGenius, JACOBS, TIAX, and the new PRELIM gasoline greenhouse gas (GHG) estimates using base case estimates and variations from the scenario analysis. Credit: ACS, Abella and Bergerson. Click to enlarge.|
Researchers at the University of Calgary (Canada) have developed the Petroleum Refinery Life-cycle Inventory Model (PRELIM). PRELIM uses a more comprehensive range of crude oil quality and refinery configurations than used in earlier models and can quantify energy use and greenhouse gas (GHG) emissions with detail and transparency the better to inform policy analysis, the duo suggests.
Using a scenario analysis to explore the implications of processing crudes of different qualities in different refinery configurations, and with a focus on oil sands products, they found differences of up to 14 g CO2eq/MJ of crude, or up to 11 g CO2eq/MJ of gasoline and 19 g CO2eq/MJ of diesel (the margin of deviation in the emissions estimates is roughly 10%). Put another way, “the variability in GHG emissions in the refining stage that results from processing crudes of different qualities is as significant as the magnitude expected in upstream operations”, they found.