Joule A. Bergerson

Understanding the Canadian oil sands industry's greenhouse gas emissions

The magnitude of Canada’s oil sands reserves, their rapidly expanding and energy intensive production, combined with existing and upcoming greenhouse gas (GHG) emissions regulations motivate an evaluation of oil sands-derived fuel production from a life cycle perspective. Thirteen studies of GHG emissions associated with oil sands operations are reviewed. The production of synthetic crude oil (SCO) through surface mining and upgrading (SM&Up) or in situ and upgrading (IS&Up) processes is reported to result in emissions ranging from 62 to 164 and 99 to 176 kgCO2eq/bbl SCO, respectively (or 9.2–26.5 and 16.2–28.7 gCO2eq MJ −1 SCO, respectively), compared to 27–58 kgCO2eq/bbl (4.5–9.6 gCO2eq MJ −1 ) of crude for conventional oil production. The difference in emissions intensity between SCO and conventional crude production is primarily due to higher energy requirements for extracting bitumen and upgrading it into SCO. On a ‘well-to-wheel’ basis, GHG emissions associated with producing reformulated gasoline from oil sands with current SM&Up, IS&Up, and in situ (without upgrading) technologies are 260–320, 320–350, and 270–340 gCO2eq km −1 , respectively, compared to 250–280 gCO2eq km −1 for production from conventional oil. Some variation between studies is expected due to differences in methods, technologies studied, and operating choices. However, the magnitude of the differences presented suggests that a consensus on the characterization of life cycle emissions of the oil sands industry has yet to be reached in the public literature. Recommendations are given for future studies for informing industry and government decision making.

Life Cycle Greenhouse Gas Emissions of Current Oil Sands Technologies: Surface Mining and In Situ Applications

Life cycle greenhouse gas (GHG) emissions associated with two major recovery and extraction processes currently utilized in Albertas oil sands, surface mining and in situ, are quantified. Process modules are developed and integrated into a life cycle model-GHOST (GreenHouse gas emissions of current Oil Sands Technologies) developed in prior work. Recovery and extraction of bitumen through surface mining and in situ processes result in 3-9 and 9-16 g CO(2)eq/MJ bitumen, respectively; upgrading emissions are an additional 6-17 g CO(2)eq/MJ synthetic crude oil (SCO) (all results are on a HHV basis). Although a high degree of variability exists in well-to-wheel emissions due to differences in technologies employed, operating conditions, and product characteristics, the surface mining dilbit and the in situ SCO pathways have the lowest and highest emissions, 88 and 120 g CO(2)eq/MJ reformulated gasoline. Through the use of improved data obtained from operating oil sands projects, we present ranges of emissions that overlap with emissions in literature for conventional crude oil. An increased focus is recommended in policy discussions on understanding interproject variability of emissions of both oil sands and conventional crudes, as this has not been adequately represented in previous studies.

A life cycle greenhouse gas emissions perspective on liquid fuels from unconventional Canadian and US fossil sources

The life cycle Greenhouse Gas (GHG) emissions associated with the production and use of transportation fuels from conventional and unconventional fossil fuel sources in Canada and the USA are investigated. The studied pathways include reformulated gasoline and low sulphur diesel produced from oil sands, oil shale, coal and natural gas, as well as reference pathways from conventional crude oil. A comparison of Life Cycle Assessments (LCAs) completed for these fuels indicates considerable uncertainty in these emissions, illustrating the need for further LCAs with particular attention to completeness and transparency. Based on the considered studies, only one unconventional pathway has better GHG emissions performance than the conventional pathways: Fischer-Tropsch diesel from natural gas. However, the limitations of the data used here and other factors that may restrict a switch to natural gas must be considered. Furthermore, there are considerable opportunities to reduce emissions from the unconventional pathways.

The truth about dirty oil: is CCS the answer?

Does carbon capture and sequestration (CCS) make sense in the oil sands?

Life cycle greenhouse gas emissions and freshwater consumption associated with Bakken tight oil

Significance The growth of production from tight oil plays such as the Bakken and Eagle Ford has prompted public interest in understanding the greenhouse gas (GHG) emissions and freshwater consumption associated with these resources, specifically with regard to hydraulic fracturing and flaring. Therefore, we conducted a comprehensive life cycle assessment of Bakken crude, using thousands of data from XTO Energy and other Bakken operators, establishing robust estimates of the footprint of current production practices. We conclude that flaring and hydraulic fracturing have a small impact on the life cycle (well to wheel) GHG emissions associated with Bakken and that these GHG emissions are comparable to those of other crudes. In recent years, hydraulic fracturing and horizontal drilling have been applied to extract crude oil from tight reservoirs, including the Bakken formation. There is growing interest in understanding the greenhouse gas (GHG) emissions associated with the development of tight oil. We conducted a life cycle assessment of Bakken crude using data from operations throughout the supply chain, including drilling and completion, refining, and use of refined products. If associated gas is gathered throughout the Bakken well life cycle, then the well to wheel GHG emissions are estimated to be 89 g CO2eq/MJ (80% CI, 87–94) of Bakken-derived gasoline and 90 g CO2eq/MJ (80% CI, 88–94) of diesel. If associated gas is flared for the first 12 mo of production, then life cycle GHG emissions increase by 5% on average. Regardless of the level of flaring, the Bakken life cycle GHG emissions are comparable to those of other crudes refined in the United States because flaring GHG emissions are largely offset at the refinery due to the physical properties of this tight oil. We also assessed the life cycle freshwater consumptions of Bakken-derived gasoline and diesel to be 1.14 (80% CI, 0.67–2.15) and 1.22 barrel/barrel (80% CI, 0.71–2.29), respectively, 13% of which is associated with hydraulic fracturing.

Use of highly alkaline conditions to improve cost-effectiveness of algal biotechnology

Phototrophic microorganisms have been proposed as an alternative to capture carbon dioxide (CO2) and to produce biofuels and other valuable products. Low CO2 absorption rates, low volumetric productivities, and inefficient downstream processing, however, currently make algal biotechnology highly energy intensive, expensive, and not economically competitive to produce biofuels. This mini-review summarizes advances made regarding the cultivation of phototrophic microorganisms at highly alkaline conditions, as well as other innovations oriented toward reducing the energy input into the cultivation and processing stages. An evaluation, in terms of energy requirements and energy return on energy invested, is performed for an integrated high-pH, high-alkalinity growth process that uses biofilms. Performance in terms of productivity and expected energy return on energy invested is presented for this process and is compared to previously reported life cycle assessments (LCAs) for systems at near-neutral pH. The cultivation of alkaliphilic phototrophic microorganisms in biofilms is shown to have a significant potential to reduce both energy requirements and capital costs.

Environmental Implications of United States Coal Exports: A Comparative Life Cycle Assessment of Future Power System Scenarios

Stricter emissions requirements on coal-fired power plants together with low natural gas prices have contributed to a recent decline in the use of coal for electricity generation in the United States. Faced with a shrinking domestic market, many coal companies are taking advantage of a growing coal export market. As a result, U.S. coal exports hit an all-time high in 2012, fueled largely by demand in Asia. This paper presents a comparative life cycle assessment of two scenarios: a baseline scenario in which coal continues to be burned domestically for power generation, and an export scenario in which coal is exported to Asia. For the coal export scenario we focus on the Morrow Pacific export project being planned in Oregon by Ambre Energy that would ship 8.8 million tons of Powder River Basin (PRB) coal annually to Asian markets via rail, river barge, and ocean vessel. Air emissions (SOx, NOx, PM10 and CO2e) results assuming that the exported coal is burned for electricity generation in South Korea are compared to those of a business as usual case in which Oregon and Washingtons coal plants, Boardman and Centralia, are retrofitted to comply with EPA emissions standards and continue their coal consumption. Findings show that although the environmental impacts of shipping PRB coal to Asia are significant, the combination of superior energy efficiency among newer South Korean coal-fired power plants and lower emissions from U.S. replacement of coal with natural gas could lead to a greenhouse gas reduction of 21% in the case that imported PRB coal replaces other coal sources in this Asian country. If instead PRB coal were to replace natural gas or nuclear generation in South Korea, greenhouse gas emissions per unit of electricity generated would increase. Results are similar for other air emissions such as SOx, NOx and PM. This study provides a framework for comparing energy export scenarios and highlights the importance of complete life cycle assessment in determining net emissions effects resulting from energy export projects and related policy decisions.

Techno–Economic Evaluation of Technologies to Mitigate Greenhouse Gas Emissions at North American Refineries

A petroleum refinery model, Petroleum Refinery Life-cycle Inventory Model (PRELIM), that estimates energy use and CO2 emissions was modified to evaluate the environmental and economic performance of a set of technologies to reduce CO2 emissions at refineries. Cogeneration of heat and power (CHP), carbon capture at fluid catalytic cracker (FCC) and steam methane reformer (SMR) units, and alternative hydrogen production technologies were considered in the analysis. The results indicate that a 3-44% reduction in total annual refinery CO2 emissions (2-24% reductions in the CO2 emissions on a per barrel of crude oil processed) can be achieved in a medium conversion refinery that processes a typical U.S. crude slate obtained by using the technologies considered. A sensitivity analysis of the quality of input crude to a refinery, refinery configuration, and prices of natural gas and electricity revealed how the magnitude of possible CO2 emissions reductions and the economic performance of the mitigation technologies can vary under different conditions. The analysis can help inform decision making related to investment decisions and CO2 emissions policy in the refining sector.

Predicting Project Environmental Performance under Market Uncertainties: Case Study of Oil Sands Coke

A method combining life cycle assessment (LCA) and real options analyses is developed to predict project environmental and financial performance over time, under market uncertainties and decision-making flexibility. The method is applied to examine alternative uses for oil sands coke, a carbonaceous byproduct of processing the unconventional petroleum found in northern Alberta, Canada. Under uncertainties in natural gas price and the imposition of a carbon price, our method identifies that selling the coke to China for electricity generation by integrated gasification combined cycle is likely to be financially preferred initially, but eventually hydrogen production in Alberta is likely to be preferred. Compared to the results of a previous study that used life cycle costing to identify the financially preferred alternative, the inclusion of real options analysis adds value as it accounts for flexibility in decision-making (e.g., to delay investment), increasing the projects expected net present value by 25% and decreasing the expected life cycle greenhouse gas emissions by 11%. Different formulations of the carbon pricing policy or changes to the natural gas price forecast alter these findings. The combined LCA/real options method provides researchers and decision-makers with more comprehensive information than can be provided by either technique alone.

Updating the U.S. Life Cycle GHG Petroleum Baseline to 2014 with Projections to 2040 Using Open-Source Engineering-Based Models

The National Energy Technology Laboratory produced a well-to-wheels (WTW) life cycle greenhouse gas analysis of petroleum-based fuels consumed in the U.S. in 2005, known as the NETL 2005 Petroleum Baseline. This study uses a set of engineering-based, open-source models combined with publicly available data to calculate baseline results for 2014. An increase between the 2005 baseline and the 2014 results presented here (e.g., 92.4 vs 96.2 g CO2e/MJ gasoline, + 4.1%) are due to changes both in modeling platform and in the U.S. petroleum sector. An updated result for 2005 was calculated to minimize the effect of the change in modeling platform, and emissions for gasoline in 2014 were about 2% lower than in 2005 (98.1 vs 96.2 g CO2e/MJ gasoline). The same methods were utilized to forecast emissions from fuels out to 2040, indicating maximum changes from the 2014 gasoline result between +2.1% and -1.4%. The changing baseline values lead to potential compliance challenges with frameworks such as the Energy Independence and Security Act (EISA) Section 526, which states that Federal agencies should not purchase alternative fuels unless their life cycle GHG emissions are less than those of conventionally produced, petroleum-derived fuels.