Understanding variability in petroleum jet fuel life cycle greenhouse gas emissions to inform aviation decarbonization.

A pressing challenge facing the aviation industry is to aggressively reduce greenhouse gas emissions in the face of increasing demand for aviation fuels. Climate goals such as carbon-neutral growth from 2020 onwards require continuous improvements in technology, operations, infrastructure, and most importantly, reductions in aviation fuel life cycle emissions. The Carbon Offsetting Scheme for International Aviation of the International Civil Aviation Organization provides a global market-based measure to group all possible emissions reduction measures into a joint program. Using a bottom-up, engineering-based modeling approach, this study provides the first estimates of life cycle greenhouse gas emissions from petroleum jet fuel on regional and global scales. Here we show that not all petroleum jet fuels are the same as the country-level life cycle emissions of petroleum jet fuels range from 81.1 to 94.8 gCO2e MJ-1, with a global volume-weighted average of 88.7 gCO2e MJ-1. These findings provide a high-resolution baseline against which sustainable aviation fuel and other emissions reduction opportunities can be prioritized to achieve greater emissions reductions faster.

Greenhouse Gas Emissions of Western Canadian Natural Gas: Proposed Emissions Tracking for Life Cycle Modeling.

Natural gas (NG) produced in Western Canada is a major and growing source of Canada's energy and greenhouse gas (GHG) emissions portfolio. Despite recent progress, there is still only limited understanding of the sources and drivers of Western Canadian greenhouse gas (GHG) emissions. We conduct a case study of a production facility based on Seven Generation Energy Ltd.'s Western Canadian operations and an upstream NG emissions intensity model. The case study upstream emissions intensity is estimated to be 3.1-4.0 gCO2e/MJ NG compared to current best estimates of British Columbia (BC) emissions intensities of 6.2-12 gCO2e/MJ NG and a US average estimate of 15 gCO2e/MJ. The analysis reveals that compared to US studies, public GHG emissions data for Western Canada is insufficient as current public data satisfies only 50% of typical LCA model inputs. Company provided data closes most of these gaps (∼80% of the model inputs). We recommend more detailed data collection and presentation of government reported data such as a breakdown of vented and fugitive methane emissions by source. We propose a data collection template to facilitate improved GHG emissions intensity estimates and insight about potential mitigation strategies.

GHG Emissions Impact of Shifts in the Ratio of Gasoline to Diesel Production at U.S. Refineries: A PADD Level Analysis.

Fuel economy standards, driver behavior, and biofuel mandates are driving a decline in the Gasoline-to-Diesel ratio (G:D) in U.S. refineries. This paper investigates the GHG implications associated with two methods available to shift refinery output: 1) refinery operational changes and 2) input crude slate variation. This analysis uses an open-source refinery GHG emissions model, PRELIM. Newly developed modeling capabilities and publicly available data are used to present Petroleum Administration for Defense District (PADD) level results (energy consumption and GHG emissions) for U.S. refineries. The results are indicative of negligible changes in the U.S. refining GHG emissions on a country level (∼3%), while variations up to 8% are observed within individual regions. Meeting the 2040 national G:D projections may require drastic changes to the current U.S. crude mix (e.g., more than 30% shift from the current U.S. crude mix), which could increase the U.S. refining GHG emissions by 25%. The analysis provides insights about future changes in refining GHG emissions due to a shift in product demand and a framework for additional analyses such as evaluation of crude market changes or biofuel blending on refining GHG emissions that can inform development of environmental regulations such as low carbon fuel standards.

Evaluation of Variability in Greenhouse Gas Intensity of Canadian Oil Sands Surface Mining and Upgrading Operations.

We present a statistically enhanced version of the GreenHouse gas emissions of current Oil Sands Technologies model that facilitates characterization of variability of greenhouse gas (GHG) emissions associated with mining and upgrading of bitumen from Canadian oil sands. Over 30 years of publicly available project-specific operating data are employed as inputs, enabling Monte Carlo simulation of individual projects and the entire industry, for individual years and project life cycles. We estimate that median lifetime GHG intensities range from 89 to 137 kg CO2eq/bbl synthetic crude oil (SCO) for projects that employ upgrading. The only project producing dilbit that goes directly to a refinery has a median lifetime GHG intensity of 51 kg CO2eq/bbl dilbit. As SCO and dilbit are distinct products with different downstream processing energy requirements, a life cycle assessment ("well to wheel") is needed to properly compare them. Projects do not reach steady-state in terms of median GHG intensity. Projects with broader distributions of annual GHG intensities and higher median values are linked to specific events (e.g., project expansions). An implication for policymakers is that no specific technology or operating factor can be directly linked to GHG intensity and no particular project or year of operation can be seen as representative of the industry or production technology.

Statistically Enhanced Model of In Situ Oil Sands Extraction Operations: An Evaluation of Variability in Greenhouse Gas Emissions.

Greenhouse gas (GHG) emissions associated with extraction of bitumen from oil sands can vary from project to project and over time. However, the nature and magnitude of this variability have yet to be incorporated into life cycle studies. We present a statistically enhanced life cycle based model (GHOST-SE) for assessing variability of GHG emissions associated with the extraction of bitumen using in situ techniques in Alberta, Canada. It employs publicly available, company-reported operating data, facilitating assessment of inter- and intraproject variability as well as the time evolution of GHG emissions from commercial in situ oil sands projects. We estimate the median GHG emissions associated with bitumen production via cyclic steam stimulation (CSS) to be 77 kg CO2eq/bbl bitumen (80% CI: 61-109 kg CO2eq/bbl), and via steam assisted gravity drainage (SAGD) to be 68 kg CO2eq/bbl bitumen (80% CI: 49-102 kg CO2eq/bbl). We also show that the median emissions intensity of Alberta's CSS and SAGD projects have been relatively stable from 2000 to 2013, despite greater than 6-fold growth in production. Variability between projects is the single largest source of variability (driven in part by reservoir characteristics) but intraproject variability (e.g., startups, interruptions), is also important and must be considered in order to inform research or policy priorities.

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.

Development and Application of a Life Cycle-Based Model to Evaluate Greenhouse Gas Emissions of Oil Sands Upgrading Technologies.

A life cycle-based model, OSTUM (Oil Sands Technologies for Upgrading Model), which evaluates the energy intensity and greenhouse gas (GHG) emissions of current oil sands upgrading technologies, is developed. Upgrading converts oil sands bitumen into high quality synthetic crude oil (SCO), a refinery feedstock. OSTUM's novel attributes include the following: the breadth of technologies and upgrading operations options that can be analyzed, energy intensity and GHG emissions being estimated at the process unit level, it not being dependent on a proprietary process simulator, and use of publicly available data. OSTUM is applied to a hypothetical, but realistic, upgrading operation based on delayed coking, the most common upgrading technology, resulting in emissions of 328 kg CO2e/m3 SCO. The primary contributor to upgrading emissions (45%) is the use of natural gas for hydrogen production through steam methane reforming, followed by the use of natural gas as fuel in the rest of the process units' heaters (39%). OSTUM's results are in agreement with those of a process simulation model developed by CanmetENERGY, other literature, and confidential data of a commercial upgrading operation. For the application of the model, emissions are found to be most sensitive to the amount of natural gas utilized as feedstock by the steam methane reformer. OSTUM is capable of evaluating the impact of different technologies, feedstock qualities, operating conditions, and fuel mixes on upgrading emissions, and its life cycle perspective allows easy incorporation of results into well-to-wheel analyses.

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

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.

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 project's 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.

Model to investigate energy and greenhouse gas emissions implications of refining petroleum: impacts of crude quality and refinery configuration.

A petroleum refinery model, Petroleum Refinery Life-cycle Inventory Model (PRELIM), which quantifies energy use and greenhouse gas (GHG) emissions with the detail and transparency sufficient to inform policy analysis is developed. PRELIM improves on prior models by representing a more comprehensive range of crude oil quality and refinery configuration, using publicly available information, and supported by refinery operating data and experts' input. The potential use of PRELIM is demonstrated through a scenario analysis to explore the implications of processing crudes of different qualities, with a focus on oil sands products, in different refinery configurations. The variability in GHG emissions estimates resulting from all cases considered in the model application shows 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%). This variability is comparable to the magnitude of upstream emissions and therefore has implications for both policy and mitigation of GHG emissions.

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 Alberta's 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.

Life cycle greenhouse gas emissions of current oil sands technologies: GHOST model development and illustrative application.

A life cycle-based model, GHOST (GreenHouse gas emissions of current Oil Sands Technologies), which quantifies emissions associated with production of diluted bitumen and synthetic crude oil (SCO) is developed. GHOST has the potential to analyze a large set of process configurations, is based on confidential oil sands project operating data, and reports ranges of resulting emissions, improvements over prior studies, which primarily included a limited set of indirect activities, utilized theoretical design data, and reported point estimates. GHOST is demonstrated through application to a major oil sands process, steam-assisted gravity drainage (SAGD). The variability in potential performance of SAGD technologies results in wide ranges of "well-to-refinery entrance gate" emissions (comprising direct and indirect emissions): 18-41 g CO(2)eq/MJ SCO, 9-18 g CO(2)eq/MJ dilbit, and 13-24 g CO(2)eq/MJ synbit. The primary contributor to SAGD's emissions is the combustion of natural gas to produce process steam, making a project's steam-to-oil ratio the most critical parameter in determining GHG performance. The demonstration (a) illustrates that a broad range of technology options, operating conditions, and resulting emissions exist among current oil sands operations, even when considering a single extraction technology, and (b) provides guidance about the feasibility of lowering SAGD project emissions.

The truth about dirty oil: is CCS the answer?

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

Baseload coal investment decisions under uncertain carbon legislation.

More than 50% of electricity in the U.S. is generated by coal. The U.S. has large coal resources, the cheapest fuel in most areas. Coal fired power plants are likely to continue to provide much of U.S. electricity. However, the type of power plant that should be built is unclear. Technology can reduce pollutant discharges and capture and sequester the CO2 from coal-fired generation. The U.S. Energy Policy Act of 2005 provides incentives for large scale commercial deployment of Integrated Coal Gasification Combined Cycle (IGCC) systems (e.g., loan guarantees and project tax credits). This analysis examines whether a new coal plant should be Pulverized Coal (PC) or IGCC. Do stricter emissions standards (PM, SO2, NOx, Hg) justify the higher costs of IGCC over PC? How does potential future carbon legislation affect the decision to add carbon capture and storage (CCS) technology? Finally, can the impact of uncertain carbon legislation be minimized? We find that SO2, NOx, PM, and Hg emission standards would have to be far more stringent than twice current standards to justify the increased costs of the IGCC system. A C02 tax less than $29/ton would lead companies to continuing to choose PC, paying the tax for emitted CO2. The earlier a decision-maker believes the carbon tax will be imposed and the higher the tax, the more likely companies will choose IGCC w/CCS. Having government announce the date and level of a carbon tax would promote more sensible decisions, but government would have to use a tax or subsidy to induce companies to choose the technology that is best for society.

Should we transport coal, gas, or electricity: cost, efficiency, and environmental implications.

We examine the life cycle costs, environmental discharges, and deaths of moving coal via rail, coal gas via pipeline, and electricity via wire from the Powder River Basin (PRB) in Wyoming to Texas. Which method has least social cost depends on how much additional investment in rail line, transmission, or pipeline infrastructure is required, as well as how much and how far energy is transported. If the existing rail lines have unused capacity, coal by rail is the cheapest method (up to 200 miles of additional track could be added). If no infrastructure exists, greater distances and larger amounts of energy favor coal by rail and gasified coal by pipeline over electricity transmission. For 1,000 miles and 9 gigawatts of power, a gas pipeline is cheapest, has less environmental discharges, uses less land, and is least obtrusive.