Environmental and financial implications of ethanol as a bioethylene feedstock versus as a transportation fuel

Life cycle inventory analysis spreadsheet-based models are developed to quantify GHG emissions and fossil energy use associated with two alternative uses of ethanol: as a feedstock for bioethylene production; and as a light-duty vehicle fuel (figure 1). The starting point of the models is the ethanol plant exit gate. This truncated system boundary is specifically designed to provide a clear assessment of the relative impacts of different ethanol uses by excluding activities common to both systems. Full life cycle impacts, accounting for all activities from the production of biomass feedstocks and conversion to ethanol through to the ethanol uses considered in this study, are subsequently assessed by appending to this model the 'well-to-gate' modelling results of ethanol production routes to understand the impacts of different biomass sources and ethanol production methods on results. Examining market impacts of producing bioethylene and ethanol (e.g., changes in demand for ethylene, gasoline) is beyond the scope of this study.

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Bioethylene production from ethanol is modelled on a gate-to-gate basis (from ethanol plant exit gate to bioethylene plant exit gate) and is assumed to displace conventional ethylene production from a mix of natural gas liquids and petroleum feedstock representing average US production (NREL 2014). We do not consider the final manufacture of products from bioethylene (e.g., polymerization to polyethylene), use phase of these products, nor end-of-life treatment (recycling; incineration with/without energy recovery). These downstream activities are assumed to be identical to those of fossil ethylene, given that bioethylene and fossil fuel-derived ethylene are chemically and functionally identical, and therefore have no influence on the relative impacts of bioethylene and fossil fuel-derived ethylene. When used as a transport fuel, ethanol is assumed to be blended with gasoline and combusted in a flexible fuel light-duty vehicle, displacing US gasoline from the 2015 projected crude oil mix on an energy-equivalent basis (ANL (Argonne National Laboratory) 2014). Consistent with typical practice, we assume that ethanol displaces gasoline on an energy-equivalent basis (ANL (Argonne National Laboratory) 2014) and do not consider a specific ethanol fuel blend. Cradle-to-gate modules for energy and material inputs into the life cycle stages are obtained from existing databases, including NREL (2014) (ethylene production) and ANL (Argonne National Laboratory) (2014) (ethanol transport/distribution/use; bioethylene process material inputs; gasoline reference pathway) and are included within the system boundaries (e.g., recovery and processing of petroleum; production of process chemicals; generation of electricity).

GHG emissions (CO₂, CH₄, N₂O) are quantified for each life cycle stage and reported as CO₂equivalent (CO₂eq) emissions based on 100-year global warming potentials (IPCC (Intergovernmental Panel on Climate Change) 2013). We do not directly account for CO₂ uptake by growing biomass and instead credit the bioethylene and ethanol products at plant gate or point of use. Bioethylene is considered to sequester biogenic carbon, which is accounted for as a CO₂ sink (negative emission). CO₂ emissions arising from ethanol combustion are assumed to not impact atmospheric GHGs. Fossil energy use (petroleum, natural gas, coal) is also quantified. The functional unit is 1 kg ethanol produced and used as a feedstock in bioethylene production or as a transport fuel in a light-duty vehicle.

The bioethylene production process is modelled in a published consulting report (Intratec 2013), based on publicly-available process and financial data. To the best of our knowledge, this is the only detailed cost estimate of bioethylene production that is publicly available. The process includes three main sections: (1) three stage reaction of ethanol to ethylene; (2) quench, compression, washing and drying; and (3) purification (figure 1). Bioethylene produced by this process is polymer grade (99.9%wt purity) and is chemically identical to conventional fossil fuel-derived ethylene. Employing technology described by Intratec yields 1.0 tonne of bioethylene per 1.85 tonnes of ethanol. The electricity requirement of the process is assumed to be provided by the US average grid mix (ANL (Argonne National Laboratory) 2014) while thermal energy demands (fuel, steam) are assumed to be provided by natural gas, including a steam generation efficiency of 85%.

The capital and operating costs associated with bioethylene production are estimated for a bioethylene production facility that is integrated with an ethanol production facility. We do not assess costs of ethanol production; instead, we use relevant market prices (AgMRC (Agricultural Marketing Resource Center) 2015) to allocate a cost to the ethanol inputs used for bioethylene manufacture. The financial viability of bioethylene production is assessed by determining the bioethylene minimum selling price (MSP), which is compared with historic market prices for both ethanol and ethylene. To account for the impacts of scale, we consider bioethylene production capacities based upon integration with 'medium' and 'large' ethanol production facilities of 150 000 t_ethanol yr⁻¹ and 450 000 t_ethanol yr⁻¹, corresponding to 50 and 150 million US gallons (USG) per year (NEO 2015). The large bioethylene production scales considered in this study correspond to the large potential market for this product, with ethylene demand exceeding 140 Mt yr⁻¹ in 2013 (True 2013).

2.3.1. Capital and operating expenses

The installed cost of a bioethylene production facility is calculated considering data in Intratec (2013) for a facility with a production capacity of 270 000 t bioethylene/yr. We use an exponential relationship (equation (1)) to estimate the equipment costs for bioethylene capacities of 80 000 t yr⁻¹ and 240 000 t yr⁻¹, corresponding to the 150 000t yr⁻¹ and 450 000 t yr⁻¹ ethanol production facilities mentioned previously. It is assumed that the plant salvage value is zero, and the economic life of the plant is 15 years.

$$\begin{eqnarray}&&C1/C2={(A1/A2)}^{0.6},\end{eqnarray} \tag{ 1 }$$

where C1 and C2 are equipment costs at capacities of A1 and A2, respectively.

According to Intratec (2013), the cost associated with ethylene storage contributes 70% of the total installed cost in an independent ethanol-to-bioethylene plant. Integration with a downstream ethylene consumer (e.g., polyethylene plant) reduces storage capital costs by 90%, and the cost of storage is thus 20% of the total equipment cost. While downstream processing of bioethylene is not considered in the present study, we include a lower capital cost scenario that accounts for potential cost savings due to integration with polyethylene production. Two bioethylene production scenarios are thus considered in the financial analysis: an 'independent' bioethylene production scenario (with full cost of bioethylene storage); and an 'integrated' bioethylene production scenario (with reduced bioethylene storage costs).

The annual operating cost of the bioethylene process is calculated as the sum of operating costs (labour, utility and chemical costs, and ethanol cost), plant insurance and maintenance cost. The maintenance and insurance costs are considered to be 2 and 1% of capital investment, respectively. Labour, utility and chemical costs are taken from Intratec (2013). Ethanol prices from 250 to 1000 USD/t are examined, taking into account recent market prices (AgMRC (Agricultural Marketing Resource Center) 2015). Existing policies, such as the US Renewable Fuel Standard (US EPA 2015), are assumed to not influence ethanol market prices and thus to not impact our assessment of bioethylene production costs. In particular, we note recent corn ethanol production has exceeded quantities mandated by the Renewable Fuel Standard and US-produced ethanol is currently exported to markets that lack similar ethanol mandates (RFA 2015) as indicators that ethanol markets are not significantly distorted by this policy. This issue is discussed further in section 3.2.

2.3.2. Minimum bioethylene selling price

Figure 2 illustrates GHG emissions and fossil energy consumption for ethanol use as a bioethylene feedstock and as a transport fuel, exclusive of activities associated with ethanol production. Ethanol use as a fuel and as a feedstock for bioethylene production leads to comparable GHG emissions reductions relative to their counterparts produced from fossil sources. The production of bioethylene from ethanol results in the emission of 0.7 kgCO₂eq. kg⁻¹_bioethylene, primarily due to consumption of natural gas (88% of emissions), while electricity and caustic soda inputs represent smaller shares of production emissions (8% and 4%, respectively). Bioethylene sequesters biogenic carbon, equivalent to 3.1 kg CO₂eq. kg⁻¹_bioethylene, and displaces conventional ethylene production, which is associated with GHG emissions of 1.8 kg CO₂eq./kg ethylene. These factors result in net GHG emissions for bioethylene of −4.3 kg CO₂eq. kg⁻¹_bioethylene or −2.3 kg CO₂eq. kg⁻¹_ethanol input to bioethylene manufacture. Bioethylene production represents only a small fraction of GHG emissions associated with bioethylene—sequestered CO₂ and avoided fossil ethylene emissions are far more significant—and therefore, these results are robust when considering uncertainty in bioethylene production parameters. Inclusion of activities downstream of bioethylene production (further processing, product use, end of life) would not impact the relative performance compared to fossil fuel-derived ethylene, assuming that these activities would be identical for both bioethylene and fossil ethylene. Use of ethanol as a transport fuel is found to result in similar GHG emissions per unit of ethanol input (−2.5 kgCO₂eq. kg⁻¹_ethanol) when displacing gasoline on an energy-equivalent basis. Under the assumptions of this study, the relative performance of using ethanol as a bioethylene feedstock or a transport fuel is independent of the ethanol source: for all ethanol production routes, use as a transport fuel or for bioethylene production will achieve similar GHG emissions reductions. These results do not consider possible impacts on ethylene and transport fuel markets arising from bioethylene and ethanol production, respectively. If introduction of biomass-based alternatives drives increasing consumption (e.g., Hochman et al 2010), the performance of ethanol and bioethylene in avoiding GHG emissions may be affected.

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To estimate full life cycle GHG emissions of bioethylene, we append previously published well-to-gate estimates of GHG emissions associated with ethanol production from the GREET 2014 model (ANL (Argonne National Laboratory) 2014). Ethanol derived from corn grain and corn stover are associated with GHG emissions of 1.2 kg CO₂eq. kg⁻¹ and 0.4 kg CO₂eq. kg⁻¹ , respectively, when employing default assumptions (process inputs; land use change impacts) and system expansion allocation to account for biorefinery co-products (ANL (Argonne National Laboratory) 2014). Inclusion of ethanol well-to-gate activities results in bioethylene life cycle GHG emissions of −0.3 kg CO₂eq. kg⁻¹ and −1.8 kg CO₂eq. kg⁻¹ for corn grain and corn stover ethanol, respectively. Relative to fossil fuel-derived ethylene (1.8 kg CO₂eq. kg⁻¹), bioethylene production from both ethanol sources is able to significantly reduce life cycle GHG emissions, by 114% (corn grain) and 200% (corn stover). On the basis of one kg ethanol input to bioethylene production, GHG emissions for the corn grain and corn stover pathways are 1.2 kg CO₂eq. kg⁻¹_ethanol and 2.0 kg CO₂eq. kg⁻¹_ethanol. As indicated above, using ethanol as a transport fuel would achieve similar GHG emissions reductions. On a full life cycle (well-to-wheel) basis, displacing gasoline with ethanol derived from corn grain and corn stover would reduce GHG emissions by 28% and 80%, respectively, equivalent to absolute GHG emissions reductions of 1.2 kg CO₂eq. kg⁻¹_ethanol and 2.1 kg CO₂eq. kg⁻¹_ethanol, respectively. Uncertainty regarding GHG impacts of ethanol production routes (e.g., Mullins et al 2010) would impact the absolute results presented here, but would not impact the primary outcome of this analysis: that the use of ethanol as a transport fuel or bioethylene feedstock results in similar GHG emissions.

Figure 2(b) shows fossil energy use associated with the bioethylene and transport fuel scenarios for activities downstream from the ethanol plant exit gate. Results are presented as net fossil energy consumption, which measures energy used by each pathway (direct energy consumption and energy used to produce inputs), less energy consumption avoided by displacing the production of fossil fuel-derived ethylene or production and use of gasoline. Use of ethanol as either a bioethylene feedstock or as a transport fuel significantly reduces fossil energy consumption (indicated in figure 2(b) by a negative net fossil energy value). However, the composition of avoided fossil energy varies between the two uses of ethanol. Bioethylene primarily reduces natural gas consumption (28 MJ/kg_ethanol), due to the heavy reliance on natural gas liquids feedstock in steam crackers in the US petrochemical industry: natural gas represents over 86% of the life cycle energy inputs to conventional ethylene production. Ethanol use as a transport fuel reduces fossil energy use to a slightly lesser degree, but, by displacing gasoline use in vehicles, this pathway is able to significantly reduce petroleum consumption (26 MJ kg⁻¹_ethanol), which is a key energy security concern. The capacity of natural gas and natural gas liquids-fed steam crackers continues to expand in the U.S. as a response to low cost feedstock available from shale gas production (Platts 2015). As such, bioethylene production for US markets cannot significantly reduce petroleum energy use. In contrast, ethylene production in the EU is more heavily reliant on petroleum-based feedstock (e.g., naphtha) (PlasticsEurope 2012); bioethylene production/use in the EU could therefore achieve greater reductions in petroleum energy consumption than in the US, although such an analysis is outside of the scope of the present study.

Capital costs are assessed for both 'independent' and 'integrated' bioethylene production scenarios for output capacities of 80 000 t_bioethylene yr⁻¹ and 240 000 t_bioethylene yr⁻¹. Capital costs of the independent bioethylene scenario are 240 million USD and 460 million USD for the two capacities, equivalent to production capacity costs of 3000 USD/t_bioethylene yr⁻¹ and 1900 USD/t_bioethylene yr⁻¹ for the lower and higher capacities, respectively. Integration of the bioethylene plant with a downstream user (e.g., polyethylene production) can substantially reduce capital costs for the two output capacities, to 73 million USD and 140 million USD. Bioethylene production on larger scale than those considered here would not be expected to result in lower production costs. Integration with ethanol production facilities would no longer be feasible as ethanol demands would exceed the production capacity of typical, 'large' ethanol biorefineries; as such, larger bioethylene plants would incur additional costs associated with independent facilities. We estimate that 'independent' bioethylene facilities would have to reach approximately 1000 000 t_bioethylene yr⁻¹ capacity to achieve the same production capacity capital costs (approximately 600 USD/t_bioethylene-yr) of an integrated, 240 000 t_bioethylene yr⁻¹ facility; this capacity is approximately on par with large fossil ethylene facilities (e.g., Linde 2014).

The MSPs of bioethylene for independent and integrated facilities at 'medium' scale (80 000 t/yr) and 'large' scale (240 000 t/yr) are shown in figure 3. Capital and operating expenses for bioethylene production are associated with some uncertainty as these values are not based on a producing facility. However, this uncertainty has a very small impact on the financial analysis results as the ethanol feedstock cost dominates the bioethylene MSP. Considering an ethanol cost of $800/t, ethanol feedstock costs represent 68% and 75% of bioethylene production costs for 'medium' and 'large' independent production facilities, and 82% to 86% of production costs for integrated facilities. Similarly, variation in financial analysis parameters (discount rate, facility lifetime) would have a small impact on results. Costs associated with chemicals and energy inputs to the process are the second highest contributor to ethylene production cost in the integrated bioethylene plant, whereas capital-related costs are the second highest cost in the independent plant.

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To be cost-competitive with the 2013 average US ethylene market price, an independent bioethylene plant would require ethanol costs at or below 300 USD/t or 410 USD/t (80 000 t and 240 000 t capacity, respectively), while an integrated plant would require ethanol costs at or below 500 USD/t or 540 USD/t (80 000 t and 240 000 t capacity, respectively). These ethanol prices are significantly below the 2013 average US ethanol price (805 USD/t or 2.35 USD/USG) (AgMRC (Agricultural Marketing Resource Center) 2015), indicating that it would be more profitable to sell ethanol for use as a transport fuel than to process it further to bioethylene. Based on the US average ethanol price, bioethylene production would have to achieve a price premium over fossil fuel-derived ethylene ranging from 37% (integrated, 240 000 t capacity bioethylene plant) to 65% (independent, 80 000 t capacity plant) based on 2013 average market prices. Recent ethanol and ethylene price data (December 2014) reveal significant price declines for both commodities; however, the estimated MSP of bioethylene , based on December 2014 ethanol prices, ranges from 1 150 to 1 500 USD/t, and would still significantly exceed the market price for ethylene during that period (850 USD/t) (Argus 2015, AgMRC (Agricultural Marketing Resource Center) 2015).

The potential exists for biofuel-related policies to influence market prices for ethanol and thus impact the cost of producing bioethylene. As discussed in section 2.3.1, this analysis assumes that existing policies, such as the Renewable Fuel Standard (US EPA 2015), do not significantly impact ethanol prices. To test the importance of this assumption, we consider a conservative case where the price of ethanol is set based on gasoline market prices (adjusted for energy content), while noting that this approach ignores the value of ethanol as an oxygenate in blended fuels and its role in fuel economy improvements and reduction of certain air pollutant emissions (e.g., Al-Hasan 2003). Even at a discounted ethanol price of 650 USD/t based on the 2013 average gasoline price (US EIA 2015), bioethylene remains uncompetitive with conventional ethylene and would require a price premium of 20% (integrated, 240 000 t capacity plant) to more than 50% (independent, 80 000 t capacity plant).