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Techno-economic Evaluation of Technologies to Mitigate Greenhouse Gas Emissions at North American Refineries Kavan Motazedi, Jessica Patricia Abella, and Joule A. Bergerson Environ. Sci. Technol., Just Accepted Manuscript • DOI: 10.1021/acs.est.6b04606 • Publication Date (Web): 21 Dec 2016 Downloaded from http://pubs.acs.org on January 5, 2017

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Environmental Science & Technology

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Techno-economic Evaluation of Technologies to

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Mitigate Greenhouse Gas Emissions at North

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American Refineries

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Kavan Motazedi, Jessica P. Abella, Joule A. Bergerson*

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Chemical and Petroleum Engineering Department, University of Calgary, 2500 University Drive

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NW, Calgary, Alberta, Canada T2N1W4

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ABSTRACT

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A petroleum refinery model, Petroleum Refinery Life-cycle Inventory Model (PRELIM), that

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estimates energy use and CO2 emissions was modified to evaluate the environmental and

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economic performance of a set of technologies to reduce CO2 emissions at refineries.

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Cogeneration of heat and power (CHP), carbon capture at Fluid Catalytic Cracker (FCC) and

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Steam Methane Reformer (SMR) units as well as alternative hydrogen production technologies

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were considered in the analysis. The results indicate that a 3 to 44% reduction in total annual

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refinery CO2 emissions (2 to 24% reductions in the CO2 emissions on a per barrel of crude oil

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processed) can be achieved in a medium conversion refinery that processes a typical U.S. crude

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slate obtained by using the technologies considered. A sensitivity analysis of the quality of input

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crude to a refinery, refinery configuration, and prices of natural gas and electricity revealed how

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the magnitude of possible CO2 emissions reductions and the economic performance of the

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mitigation technologies can vary under different conditions. The analysis can help inform

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decision making related to investment decisions and CO2 emissions policy in the refining sector.

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TOC/Abstract Art

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KEYWORDS: Greenhouse gas emissions, CO2 mitigation technologies, Refineries, Life cycle

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analysis

46 47 48 49 50 51 52 53 54 55 56 57



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INTRODUCTION

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The petroleum refining industry is one of the largest stationary sources of CO2 emissions1-3

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(second-largest in U.S.4, and third-largest in the world1) and is under pressure to reduce these

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emissions in several jurisdictions due to current and potential future regulations (e.g. California

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Assembly Bill 325)6, 7. In 2014, annual emissions from U.S. refineries were reported to be 175

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million tonnes of CO2eq accounting for approximately 5.5% of total emissions from stationary

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sources in the U.S.2, 4.

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Refinery energy consumption and CO2 emissions are influenced by parameters such as the

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input crude slate (i.e., a combination of crude oils blended to form a refinery’s feedstock)

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properties, refinery configuration, product slate specifications, product demand, and operating

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efficiency8. As a basic indicator of crude quality, crude oils are commonly categorized based on

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their overall API gravity (a measure of petroleum liquid density) and sulfur content. Supply and

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demand projections for crude oils with different qualities pose challenges for both existing and

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future refineries in terms of configuration and level of processing intensity9,

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processing heavier and sourer crudes in more complex refineries require more energy and results

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in more CO2 emissions than processing lighter and sweeter crudes in less complex refineries11.

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. Generally,

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Options to reduce CO2 emissions include: shifting the types of crudes processed (minor

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changes within existing refineries or shifting process unit capacities to handle lighter or heavier

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crudes), mitigation measures to improve energy efficiency (e.g. modifying existing processes), or

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the implementation of mitigation technologies (e.g. cogeneration of heat and power)12.

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Mitigation measures include equipment and operational changes (e.g. improving insulation) to

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improve energy efficiency in the near term13. However, for the longer term employment of more

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complex technologies such as carbon capture and storage could become more important14. 4 ACS Paragon Plus Environment

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Therefore, it is important to evaluate promising mitigation technologies in terms of cost, energy

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and CO2 emissions performance and assess the potential CO2 emissions reductions their

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implementation in a refinery could offer. To accomplish this, development of tools that allow for

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the investigation of refinery CO2 emissions and energy consumption as well as mitigation

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strategies is imperative to help future decision making in the refining sector.

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Several tools have been built to assess the CO2 emissions from refineries. However, none of

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these tools provide the capability of assessing technologies that could improve the CO2 footprint

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of refineries. For instance, Natural Resource Canada’s GHGenius15 and Argonne National

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Laboratory’s Greenhouse Gases, Regulated Emissions, and Energy Use in Transportation

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(GREET)16 are two prominent North American life cycle (LC) tools that are widely used.

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However, these models do not provide a process-unit level presentation of a refinery, thus

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precluding evaluation of CO2 mitigation technologies at an individual process unit level (e.g.

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evaluating carbon capture technologies on a steam methane reformer in a refinery).

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The current literature in this area indicate that if the quality of input crude to the U.S. refineries

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remains the same (or if the crude input becomes heavier) in the future, the CO2 emissions from

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refineries will grow considerably due to the additional processing that is required in refineries to

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comply with more stringent environmental regulations (e.g. fuel sulfur requirements) unless CO2

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mitigation strategies are adopted6,

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technologies considering both environmental and economic performance to inform decisions

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about cost-effective CO2 emission reduction options across the refining industry is missing in the

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literature. Nimana et al.19 investigated energy consumption and CO2 emissions associated with

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upgrading and refining of Canadian crudes (bitumen, synthetic crude oil (SCO), and dilbit) but

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did not consider different levels of conversion (different refinery configurations) for heavy

7, 17, 18

. However, an evaluation of a set of CO2 mitigation



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(bitumen and dilbit) and light (SCO) crudes19 when estimating the refining CO2 emissions. Also,

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their study did not include the potential impact of CO2 mitigation technologies on refining CO2

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emissions. Hirshfeld et al.20 created scenarios for average input crude quality to U.S. refineries in

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2025 and used a proprietary linear programing (LP) model to predict a 3.7% to 6.3% increase in

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energy consumption, and a 5.4 to 9.3% increase in CO2 emissions, above a 2012 U.S. refinery

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baseline. However, they did not consider technology changes or CO2 mitigation efforts in their

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scenarios.

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Elgowainy et al.21 used the results of a linear programming model based on data for 43 large

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U.S. refineries to investigate the average U.S. refining efficiency as well as the range of

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efficiencies among these 43 refineries due to processing crudes with different qualities, refinery

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complexity, and product slate demand in the U.S. Forman et al.22 used the same model and the

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results of Elgowainy et al.21 to study the impact of future changes in U.S. input crude quality

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(considering the influx of U.S. domestic crude (i.e. tight oil)), and shifts in future gasoline and

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diesel demands on refinery efficiency across the same 43 refineries. However, neither of these

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studies investigated the impacts of CO2 mitigation technologies on refinery emissions. Morrow

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et al.23 developed a notional refinery model and analyzed the U.S. refining industry in aggregate

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as to the potential for energy efficiency improvements. Since this study was focused on energy

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efficiency, other potential mitigation technologies were out of scope.

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A 2010 EPA report24 assesses 37 CO2 reduction measures that could be employed in refineries.

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They summarize ranges of possible efficiency improvements/CO2 reductions from literature for a

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subset of these CO2 reduction measures (efficiency measures such as improving insulation,

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maintenance and process control) in individual process units (e.g. steam generating boilers) in

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which each measure is employed (as opposed to the overall impact on total refinery emissions).


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They do not provide economic estimates for these measures nor the competitiveness of these

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measures or their performance in different types of refineries. Johansson et al.25 estimated

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potential CO2 reductions obtainable by employing carbon capture, fuel substitution, and

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improving energy efficiency for European refineries26, 27. Their results were specific to European

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refineries and may not be expandable to the North American refineries. Petrick and Pellegrino 13

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focused on energy and CO2 emissions savings in U.S. refineries through improvements such as

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heat integration, advanced process control and replacement of atmospheric distillation with

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thermal cracking. However, they did not provide economic estimates for the measures and

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technologies considered in their study. In addition, none of these studies investigate mitigation

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opportunities in the context of the variability in the potential CO2 reductions due to parameters

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such as refinery configuration and quality of the input crude to the refinery.

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A range of CO2 mitigation options and technologies such as carbon capture technologies28-31,

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energy efficiency measures (e.g. heat integration)32, and hydrogen production technologies (e.g.

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biomass gasification)33-36 have been evaluated by several researchers in various industrial

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processes. However, a study that investigates the economic and environmental performance of a

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set of promising CO2 mitigation technologies deployed in refineries using consistent boundaries

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and assumptions is missing in the literature37.

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There are no publicly available refinery-specific CO2 emissions estimate models that allow for

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the investigation of refinery CO2 emissions on a process unit level and provide the capability of

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assessing technologies to improve the carbon footprint of refineries. Abella and Bergerson8,

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developed and released an open-source petroleum refinery model, Petroleum Refinery Life Cycle

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Inventory Model (PRELIM)37, and investigated the energy use and CO2 emissions associated

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with processing a variety of crude oils with different qualities within a range of configurations in



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a refinery. PRELIM is the first open source refinery model of its kind with transparent excel-

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based process-level calculations. These characteristics of the model, unlike other models, provide

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a structure that allows for the evaluation of implementing a range of mitigation technologies

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using a common tool, assumptions and boundaries for the analysis.

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The present study presents an evaluation of 12 technologies, each modelled using PRELIM37

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that has been modified to consider technical, environmental (CO2 emission reduction) and

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economic performance. The technologies are prioritized using a cost-effectiveness assessment.

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Given that several technologies considered are still in the research and development stage, the

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impact of the high degree of uncertainty is explored through a detailed sensitivity analysis. The

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analysis can be used to inform decision making related to investment decisions and CO2

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emissions in the refining sector.

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METHODS

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Modification of PRELIM to assess mitigation technologies. In the present study, a set of 37

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CO2 mitigation technology options were incorporated into PRELIM

to conduct a techno-

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economic analysis that helps prioritize the technologies based on cost-effectiveness. To do this,

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PRELIM was modified by adding calculations to estimate the CO2 emissions after employment

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of mitigation technologies and comparing the results with model runs where no mitigation

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technology was considered.

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In evaluating potential mitigation technologies processes such as combustion related processes

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(e.g. process heaters and boilers), fluid catalytic cracking (FCC), and hydrogen (H2) production

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units are the starting point as they are the largest contributors to total emissions in refineries 8, 25.

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The technologies considered include heat and power cogeneration (CHP), carbon capture and


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sequestration (CCS) systems for FCC and SMR, biomass gasification and high temperature

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electrolysis (HTE) for H2 production. Most U.S. refineries already employ CHP systems

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(approximately 75% of U.S. refineries), and account for 19% of the total installed CHP capacity

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in the U.S38. However, information on the effectiveness of the CHP technologies in terms of CO2

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emissions reduction capability is rare in the literature. Therefore, this assessment can help inform

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decision-making about the adoption of these technologies by the refineries that do not use CHP,

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and to provide a basis for comparison of the cost effectiveness compared to alternative mitigation

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options. Table 1 and supporting information present additional information about the

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technologies considered in this study.

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The selection of potential technologies was based on a screening analysis to identify a subset

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of the most promising technologies to investigate in depth. Technologies were prioritized by

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targeting the most CO2/energy intensive processes such as FCC and H2 production8, as well as

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technological readiness. The technologies used in this analysis have either found applications in

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industry, or have been tested at a pilot scale (see Table 1 for technology readiness levels).

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The capacity of the process units following the atmospheric tower in the previous version of

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PRELIM are unrestrictedly determined using the information obtained from the crude oil assay

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entering the atmospheric unit, i.e. true boiling point (TBP) curve. PRELIM was modified for this

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analysis by adding the capability to fix the capacity of the process units, which is required to

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represent a refinery with process units that are fixed in size. The EIA U.S. refinery capacity

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report was used to represent capacities close to the average process unit capacities of U.S.

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refineries39 (see Table S-1). These capacities were kept constant throughout the study to make a

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consistent comparison between the baseline and the case where a mitigation technology is

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employed.



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Life cycle assessment (LCA) is a technique for determining the potential impacts associated

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with a product or process40. It can be used to evaluate the full supply chain CO2 emissions from

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charges to different processes within a refinery. The potential CO2 emission reductions in a

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refinery by employing the abovementioned mitigation technologies, were investigated by

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conducting a gate-to-gate attributional LCA using the PRELIM model that provides estimates of

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the CO2 emissions from the operations of a refinery with, and without CO2 mitigation

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technologies. Indirect emissions of fuels consumed in refinery are included in the boundaries of

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the analysis, but upstream and downstream activities within the life cycle of crude are excluded.

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Refinery fuel gas, and by-product hydrogen produced in the naphtha catalytic reformer were

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considered as CO2 emissions neutral streams.

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A cost analysis was also performed for each technology over its lifetime while also taking into

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account the corresponding CO2 emission reductions estimated by PRELIM. In this analysis, an

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annual interest rate of 10% was assumed to amortize the capital costs. Operating and

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maintenance costs were added to the annualized capital costs to estimate the total annualized cost

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of each technology. In addition to the crude input feedstock, natural gas and electricity are two of

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the main inputs to a refinery. The cost of natural gas was assumed to be $4.4/GJ based on the

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average U.S. price data for the period of 2009-201441, and the cost of electricity was considered

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to be $60/MWh according the OpenEI historical cost-of-generation database in the same

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period42. The sensitivity of the results to these costs was tested in the sensitivity analysis.

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Base case. A “base case” was defined to estimate potential CO2 reductions in a “typical” U.S.

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refinery and crude oil. The mitigation technologies were initially evaluated for this base case. A

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crude oil assay with close to an average U.S. crude oil input quality reported by the EIA for 2015

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(i.e., API of ~32 and sulfur content of ~1.4 wt%) was chosen43. A medium conversion refinery


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configuration with an FCC unit was chosen (most refineries in the U.S. are either medium or

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deep conversion refineries; deep conversion refineries include a coker)39. More details about the

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different refinery configurations available in PRELIM can be found in 8, 37.

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Sensitivity analysis. The purpose of the sensitivity analysis is to test how the relative

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competitiveness of the mitigation technologies changes in the face of the variability within

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individual existing refineries as well as across refineries. Therefore, the following parameters

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were altered by changing each parameter individually: the impact of variations in the quality of

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the input crude, refinery configuration, and prices of natural gas and electricity on potential CO2

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emission reductions and costs of the mitigation technologies were explored through a sensitivity

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analysis. Sensitivity of the economic performance of hydrogen production from biomass

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gasification due to changes in the price of biomass feedstock was also tested.

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The effect of crude slate quality on the performance of the technologies in the base case

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refinery configuration was determined by running PRELIM for a set of 52 crude oil assays. This

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set included assays with APIs ranging from 15 to 48 allowing for the analysis to represent a wide

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variation in crude fraction properties (i.e., sulfur, hydrogen, and API), and its impacts on the

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results. The authors acknowledge that refineries do not typically process single crudes. However,

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for the purposes of this analysis, we believe that the wide range of quality covered by these

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single crudes also captures the range of quality that blends of crudes could have.

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To determine whether the results can be generalized for different types of refineries across

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North America, the effect of refinery configuration was also investigated as part of the sensitivity

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analysis. The base case crude was run in 7 refinery configurations, already available in

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PRELIM8,

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deep conversion refinery with a coking unit. Detailed results and explanation of the sensitivity

37

, covering a simple hydroskimming refinery configuration through to a complex



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analysis including the results of the sensitivity analysis of the prices of natural gas and electricity

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are presented in Supporting Information. There are also uncertainties associated with the

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technical parameters of the CO2 mitigation technologies (e.g., efficiency). The sensitivity of the

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CO2 mitigation technologies’ performance to changes in the technical parameters of the

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technologies could be the focus of future studies.

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showed that small variations within 10% of the assumed values for the technical parameters (see

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Table 1) did not change the ranking of the technologies or the absolute results. Throughout this

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paper, “ranking” refers to the competitive ness of the technologies based on percent reduction in

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total refinery CO2 emissions that the technologies can offer.

However, our preliminary investigation

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Cogeneration of heat and power. CHP systems consist of a number of components such as

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prime mover (heat engine), generators, and electrical interconnections. The type of prime mover

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typically identifies the CHP system. Six prime movers, namely gas turbines (single and

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combined cycle), microturbines, reciprocating engines, steam turbines, and fuel cells make up

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97% of the CHP projects in place today in the U.S. and are included in this analysis44.

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The modelling parameters and cost data for these types of CHP systems are summarized in

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Table 1. It was assumed that all six main CHP technologies considered provide utilities at the

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scale required to satisfy demand at a refinery level except for the microturbine and reciprocating

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engine CHP systems that provide utilities only to specific process units. These two systems do

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not produce high pressure steam (600-900 psig45, 46) which is required for process units such as

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the hydrotreaters. The heat and electricity requirements of the refinery on a process unit level

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were assessed for microturbines and reciprocating engine systems, and on a refinery level were

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assessed for the remaining CHP systems. Further details on the assumptions for the CHP

263

technologies are provided in Supporting Information.


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PRELIM calculates the amount of natural gas that is combusted in the refinery to produce the

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required heat and steam. The associated CO2 emissions due to the combustion of this natural gas

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are calculated using a life cycle emissions factor of 67.4 gCO2eq/MJ of natural gas37, 47. If the

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SMR is utilized to produce hydrogen, the amount of natural gas consumed by the SMR (as

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feedstock for hydrogen production and for combustion to produce the required heat) is also

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calculated. An emissions factor of 56.3 gCO2eq/MJ for natural gas consumed as feedstock for

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hydrogen production is employed11, 48. Cost estimates were converted to 2014 US dollars using

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economic indicators from the chemical engineering plant cost index 49.

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Carbon capture from the steam methane reformer (SMR) and fluid catalytic cracker

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(FCC) streams. Carbon Capture technologies can typically capture 85-90% of the CO2

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emissions from large point emission sources such as power plants and industrial processes31, 50.

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The captured CO2 can be transported via pipelines and stored in geological sites such as saline

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aquifers. Due to economies of scale, employment of CCS at a refinery would likely be limited to

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the larger CO2 emitting units such as FCC, and SMR24, 51.

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There are three types of CCS: post-combustion, pre-combustion and oxyfuel combustion.

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Supporting Information provides additional background information on these technologies. The

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post-combustion process is suited both to new and existing plants (e.g., refineries and power

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plants) and can be combined with almost any type of combustion system, such as process units in

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a refinery52. Oxyfuel CCS can also be retrofitted into existing plants, but it is a less mature

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technology, and there are safety concerns associated with oxygen being piped through to a

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refinery. In the present study, the potential use of oxy-firing and post-combustion CCS at the

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FCC unit, and post combustion CCS at the SMR unit were considered. Pre-combustion CCS was

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not considered due to a lack of fit with the processes in an existing refinery. This study assumes



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that the captured CO2 is compressed and transported by onshore pipeline 300km and injected in a

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saline aquifer. Compression costs were included in the original capital cost of the technologies,

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and the transportation costs were estimated based on McCollum and Ogden53.

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Post-combustion CCS technologies remove CO2 from the flue gas using absorption by solvent

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scrubbing, typically monoethanolamine (MEA), or adsorption of CO2 using a solid sorbent. Two

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systems for CCS on the SMR were considered. In the first system, a SMR unit with carbon

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capture to remove the CO2 emissions from natural gas combustion at the furnace and CO2

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emissions from the reforming reactions was considered (hereafter refer as SMR with complete

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CCS). In the second system, an electrically heated SMR with electricity from a low carbon

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source (as an example, nuclear power with a life cycle emissions factor of 23 gCO2/kWh54) and

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CCS to remove the CO2 emissions from the reforming reactions was considered (hereafter

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referred to as electrically heated SMR with CCS). In the FCC, oxy-firing can be used in the

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catalyst regeneration step to reduce the emissions from coke burn-off. A cryogenic air separation

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unit (ASU) to produce oxygen of 99.5% purity for oxy-firing, and a 99% efficiency for CO2

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recovery was assumed based on reference

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post combustion CCS in PRELIM are summarized in Table 1.

55

. The required data for embedding oxy-firing and

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Alternative H2 production technologies. In order to reduce the emissions associated with H2

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production in a refinery, biomass gasification followed by H2 production and purification, and

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high temperature electrolysis technologies can replace the SMR. Supporting information

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provides a brief explanation about these technologies. Data from the U.S. Department of Energy

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(DOE) H2 production via biomass version 3.1, and H2 Production from Nuclear Energy via High

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Temperature Electrolysis version 2.1.1 models (summarized in Table 1) were used to add these

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technologies into the PRELIM36.


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If additional H2 was required, the net H2 requirement of the refinery (total H2 required by

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different process units in the refinery minus the amount of H2 produced in the naphtha catalytic

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reformer) was considered to be met by these alternative H2 production technologies.

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Subsequently, the required utilities (i.e. natural gas and power) for the production of this amount

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of H2 using the alternative H2 production technologies, and the corresponding CO2 emissions

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were calculated. The total CO2 emissions avoided was then calculated by comparing the total

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emissions from a refinery with a new H2 production technology with a refinery that employs a

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conventional SMR unit.

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In the next section, results for the base case and the results of the sensitivity analyses as

319

described in the methods section are presented and discussed. Percentage of total refinery CO2

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emissions reduced in conjuncture with annual cost (that allows for comparing decisions about

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capital investment on a consistent basis), and cost per tonne of CO2 avoided (that allows for a

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broad comparison across a range of mitigation technologies, e.g. performance of mitigation

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technologies in the refining industry versus another industry) were used to evaluate the

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environmental and economic performance of the technologies.



Project lifetime, years

Technology Readiness Level (TRL)

Installed cost, 2014$

Operation and maintenance, 2014$

Reference

Microturbine CHP

0.03-0.25

0.70

67.5

7

9

4402 per kWe

0.02 per kWhe

44, 56

Reciprocating engine CHP Steam turbine CHP

0.10-5.00

1.10

76.0

6

9

1831 per kWe

0.02 per kWhe

44, 56

0.50-15.00

0.10

79.6

50

9

1346 per kWe

0.01 per kWhe

44, 56

Fuel cell CHP

0.01-2.00

2.00

71.5

7

8-9

7867 per kWe

0.04 per kWhe

44, 56

Natural gas combined cycle CHP Biomass gasification

11.82

0.28

58.0

20

9

1645 per kWe

0.20 per kWhe

29, 44, 56

40

7

4% of the installed cost

36, 57, 58

40

5

Function of H2 production capacity* Function of H2 production capacity* Function of carbon capture capacity** Function of carbon capture capacity** Function of carbon capture capacity**


36, 57-59


57, 60-66


57, 60-66


57, 60-66

High Temperature Electrolysis (HTE) Oxyfiring at FCC

0.98 40.02

6.22

CO2 recovery efficiency, %

44, 56

Electricity for CCS, kWh/kg CO2

0.01 per kWhe

Steam requirement for CCS, MJ/kgCO2 captured

3396 per kWe

Steam requirement, MJ/kgO2

9

Electricity for cryogenic air separation, kWh/kgO2

20

Oxygen requirement, kgO2/kg coke

69.2

Nuclear power emissions factor, gCO2/kWh

1.20

Biomass price, 2014$/kg H2

Average efficiency, %

1.00-40.0

Natural gas usage, MJ/kg H2

Power to heat ratio

Gas turbine CHP

Electricity usage, kWh/kg H2

Nominal capacity, MW

Table 1. Modelling assumptions used for modelling the mitigation technologies in PRELIM

Technology

325

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1.23 22.8 0.01

0.37

99

25

7

Post combustion CCS at FCC

5.97

0.20

90

25

9

Post combustion CCS at SMR

5.97

0.20

95

25

9

326 327 328 329 330 331

3

0.3

0.07

* Installed costs of $198MM for a biomass gasification H2 production plant with a capacity of 140 tonneH2/d, and $1207MM for a high temperature electrolysis H2 production plant with a capacity of 734 tonne H2/d were used as reference costs based on 36. ** Installed costs of $144 MM and $214 MM for a post-combustion carbon capture system and an oxy-fuel combustion system (excluding pipeline cost which was calculated separately based on53) both with a capacity of 2440 tonneCO2/d were used 57. These values were then used to estimate the cost of hydrogen production and carbon capture systems with different capacities based on the cost estimation method presented in 64, 65. More details are included in Supporting Information.

ACS Paragon Plus Environment

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332


RESULTS AND DISCUSSION

333

Base case results. The results of the investigation showed 3.2-43.7% in reductions in the total

334

annual refinery CO2 emissions in the base case over the range of technologies considered. Figure

335

1 compares the CO2 emissions reduction technologies for the base case in terms of the fraction of

336

potential CO2 reductions out of the total refinery emissions using each technology (values on the

337

horizontal axis), total annual cost of the technologies (represented by the size of the bubbles), as

338

well as the cost of CO2 avoided (values on the vertical axis).

339

The technology ranking presented is mainly based on the percent reduction in total refinery

340

CO2 emissions that the technologies can offer. However, once an absolute CO2 reduction target

341

has been set for a refinery (e.g. tonnes CO2 reduced per year), good decision making must

342

consider all three metrics (percent reduction in total refinery CO2 emissions, total annual cost,

343

and cost of CO2 avoided), along with other factors such as technology readiness level, and

344

policies that the technologies might be used to comply with. For instance, a refinery might opt

345

for purchasing carbon credits instead of employing CO2 mitigation technologies after

346

consideration of the economic performance of the CO2 mitigation technologies on a $/tonne CO2

347

basis.

348 349 350 351 352 353 354


17


Page 18 of 37

355 356 357 358 359 360 361 362 363 364 365 366 367 368 369 370 371 372 373 374 375 376

Figure 1. Annual cost of technologies, and potential CO2 reductions. The fraction of potential CO2 reductions out of the total refinery emissions using each technology has been presented on the horizontal axis. The vertical axis presents the cost per tonne of CO2 avoided for each technology. The size of the circles indicates the total annual cost associated with the employment of each technology. The results have been presented for a medium conversion refinery with a capacity of 67600 bpd and processing an average U.S. crude oil input (as reported by the EIA for 2015, i.e., API of ~32 and sulfur content of ~1.4 wt%).

377

For the base case, employment of alternative H2 production technologies provided the highest

378

levels of CO2 emissions reduction in the refinery (approximately 44% and 19% reductions for

379

biomass gasification and HTE, respectively). Annual costs of biomass gasification and HTE

380

technologies were $62MM/y and $52MM/y, respectively (which would translate into an

381

additional cost of $2.5 and $2.1 per bbl of crude, respectively). The high annual cost of these


18

Page 19 of 37


382

technologies might be justifiable under different policy conditions given their potential for

383

providing significant reductions in CO2 emissions. Due to the large reduction potential that the

384

alternative H2 production technologies offer, the cost of CO2 avoided per tonne of CO2

385

(estimated to be at $104/tonne CO2 and $195/tonne of CO2 for biomass gasification and HTE,

386

respectively) was smaller for these technologies than the rest of technologies considered (except

387

for the electrically heated SMR with a low carbon electricity source). This finding is likely an

388

indication of why these alternative hydrogen production technologies have not been deployed

389

extensively when compared to technologies such as gas turbine and steam turbine CHP systems

390

where a lower capital expenditure and a more variable operational expenditure is required. The

391

high annualized costs of the alternative H2 production technologies can be explained by the high

392

capital cost of the process units (such as biomass gasifier, electrolysis stacks, shift reactors, and

393

H2 purification unit) that are required in these H2 production systems. However, these results are

394

specific to the assumptions and application designed in the base case. A discussion of how these

395

results may change are provided in the sensitivity analysis section.

396

Biomass supply and transportation, and the large power requirement of the HTE system are

397

other considerations that complicate the employment of these technologies. It was found that

398

high temperature electrolysis can only provide a reduction in CO2 emissions if powered by a

399

low-carbon power source (such as nuclear power which was assumed in this analysis). At

400

electricity emissions factors higher than 370 g/kWh electricity, the HTE system was found to

401

cause an increase in the refinery CO2 emissions. Therefore, the results of the HTE system

402

powered by fossil based electricity (electricity from natural gas or coal) is not presented in

403

Figure 1.


19


Page 20 of 37

404

After the alternative H2 production technologies, electrically heated SMR with CCS, provided

405

the largest reductions in total CO2 emissions of the refinery (15.4% reductions in the CO2

406

emissions and annualized cost of $12MM/yr). This was followed by the fuel cell and gas turbine

407

CHP systems that both provided close to 11.5% CO2 reductions. However, the annualized cost

408

and cost of CO2 avoided for the fuel cell CHP technology (i.e., $68MM/yr and at $443/tonne of

409

CO2) were nearly twice the costs for the gas turbine CHP system. The gas turbine CHP

410

technology was the best CHP option for the base case refinery both in terms of CO 2 emissions

411

reduction and cost. This is consistent with the fact that gas turbine CHP systems (including gas

412

turbine/steam turbine combined cycle CHP systems) also have the highest share (64%) of the

413

total installed CHP capacity in the U.S.44.

414

After the gas turbine CHP, the SMR with complete CCS system provided 7.2% reduction in

415

the refinery CO2 emissions at an annualized cost of $24MM/yr. In the SMR with complete CCS

416

the SMR furnace natural gas combustion CO2 emissions and the incremental emissions and costs

417

associated with the compression and transportation of the CO2 that is produced would allow for

418

lower CO2 reductions compared to the electrically heated SMR.

419

The rest of the CHP technologies (steam turbine, microturbine, reciprocating engine, and

420

natural gas combined cycle CHPs) and FCC with CCS, provided CO2 reductions in a range of 3-

421

5%. The costs of the CHP systems were significantly higher than those for the FCC with CCS

422

systems because of the high operational cost of the CHP systems.

423

Although CHP systems have already found vast applications in the refining industry38, very

424

limited information about the performance of these systems in terms of CO2 emissions reduction

425

could be found in the published literature. Furthermore, in the information available, refinery

426

specific CO2 savings and costs were not included. In addition, the data were too aggregated and


20

Page 21 of 37


427

would not allow for distinguishing the types of refineries they corresponded to. An Argonne

428

National Laboratory report study suggests a 2% potential energy savings (corresponding to 5%

429

reduction in CO2 emissions) between 1996 and 201013, which is in the range of CO2 reductions

430

estimated for the CHP systems in the present study (3 to 12% for the base case). The Canadian

431

Industrial Energy End-use Data and Analysis Centre (CIEEDAC) states that a cogeneration

432

system with a heat to power ratio of 3 can produce 24% less emissions than a standalone heat

433

generation system with the same efficiency67. However, CIEEDAC results were not refinery

434

specific and did not include estimates of CO2 reductions that could be obtained if CHP systems

435

were used in a refinery.

436

Sensitivity analysis. The economic and environmental competitiveness of the mitigation

437

technologies considered in this study, strongly depend on a number of factors, namely, quality of

438

input crude slate, refinery configuration, the economics of competing technologies, market, and

439

policy conditions. In the present study, a sensitivity analysis was conducted to investigate the

440

effects of five relevant parameters (crude quality, refinery configuration, prices of natural gas

441

and electricity, and price of biomass feedstock). Sensitivity analysis showed that the

442

environmental, and economic performance of the CO2 mitigation technologies strongly depend

443

on crude quality, and refinery configuration. The bars in Figure 2 demonstrate the results of the

444

analysis for the base case, and the lines on the bars indicate the ranges of the results observed in

445

the sensitivity analyses based on quality of the input crude and refinery configuration as

446

described in the methods section. The analysis also concludes that technology rankings are

447

insensitive to the prices of natural gas, electricity, biomass and degree of integration (please see

448

the SI for details). However, it should be noted that the price of biomass can greatly impact the

449

economic performance of biomass gasification. For example, at a price of $0.27/kgH2, annual


21


Page 22 of 37

450

cost, and cost of CO2 avoided for the biomass gasification technology could drop to $42.3MM/y,

451

and $72.3/tonne CO2, respectively (from $62.4MM/y, and $104/tonne CO2. That is comparable

452

to sensitivity of the biomass gasification results to the crude quality, and refinery configuration.

453

Detailed results of the sensitivity analyses including the sensitivity analyses of prices of natural

454

gas, electricity, and biomass feedstock are presented in Table S-2 in Supporting Information.

455

Low carbon fuel standards (LCFS) such as the BC’s Low Carbon Fuel Standard, consider life

456

cycle reductions in CO2 emissions intensity of petroleum refining products. The reduction targets

457

are established on a per MJ of product basis (e.g., MJ gasoline). The analysis in this paper

458

indicates that employment of the mitigation technologies considered could yield approximately 2

459

to 26 percent reductions in the CO2 emissions on a per MJ of gasoline basis (see Table S-2). The

460

results differentiate from those on a per barrel of crude basis/refinery level (i.e., 3 to 44 percent

461

reductions) because of the need to allocate emissions to different refinery products. Nonetheless,

462

the ranking of the technologies in terms of competitiveness remained the same.

463 464 465 466 467 468 469 470 471 472


22

Page 23 of 37


473 474 475 476 477 478 479 480 481 482 483 484 485 486 487 488 489

Figure 2. Base case analysis results of the cost and CO2 reductions for refinery mitigation technologies. The lines on each bar represent variability associated with different input crude quality and refinery configurations. For the base case, a medium conversion refinery processing an average U.S. crude (API ~32 and sulfur content ~1.4) was used.

490

Figure 2 shows that the overall performance and relative competitiveness of each technology

491

can vary greatly depending on the type of crude and refinery that the crude is processed in. The

492

largest variations in the potential refinery emissions reductions were observed for the alternative

493

H2 production technologies and the SMR technologies. This is primarily due to the fact that the

494

net H2 requirement of a refinery can significantly vary depending on the quality of the crude

495

being processed in the refinery as well as the complexity of the refinery (due to presence of

496

additional hydroprocessing units). The net H2 requirement of a refinery is one of the most

497

significant drivers of CO2 emissions in a refinery, and is proportional to the potential for

498

reduction of CO2 emissions produced in the SMR. It was observed that a SMR unit that satisfies


23


Page 24 of 37

499

the net hydrogen requirement of a refinery could constitute 2% to 44% of the total CO2

500

emissions from a refinery, which explains the large variations in the potential CO2 reductions

501

offered by the alternative H2 production and SMR technologies.

502

For the carbon capture technologies at the FCC process unit, the opposite trend was observed

503

(smaller percentages of CO2 reductions were observed for refineries with higher net H2

504

requirements). This is due to the CO2 emission intensiveness of the SMR operations that

505

overshadowed the CO2 reductions that the CCS technologies provided at the FCC as the H2

506

requirement in the refinery increased. The sensitivity analyses on crude quality and refinery

507

configuration showed that employment of carbon capture on the SMR becomes more attractive

508

in refineries with large net H2 demands. In such refineries larger reductions in CO2 emissions

509

can be obtained (at higher annualized cost but lower cost of CO2 avoided per tonne of CO2). In

510

addition, it was found that in a refinery where CO2 emissions from the FCC unit contribute a

511

larger share than the SMR unit of the total refinery CO2 emissions, carbon capture at the FCC

512

unit could provide larger CO2 reductions than carbon capture at SMR.

513

The sensitivity analysis of the effect of crude quality showed that with the increase of net H 2

514

requirements in the refinery, biomass gasification and HTE provided up to 70% and 28%

515

reductions in the refinery CO2 emissions, respectively. The corresponding estimated annualized

516

costs were $74MM and $82MM per year, and estimated costs of CO2 avoided were 65 and 175

517

dollars per tonne of CO2 avoided. These results suggest that employment of biomass gasification

518

for H2 production is more favorable than HTE. However, due to the challenges associated with

519

the employment of biomass gasification for H2 production (e.g. complexity of some required

520

processes such as carbon capture, biomass supply, and the technology not being commercialized

521

yet68), this technology might be further away from commercialization than HTE 35.


24

Page 25 of 37


522

The sensitivity analysis of the quality of input crude and refinery configuration showed that

523

fuel cell and gas turbine CHP systems were able to consistently (for all crudes in all

524

configurations) provide the highest level of CO2 reduction among the CHP technologies. The

525

fuel cell CHP system consistently provided slightly higher (less than 0.5%) CO2 reductions than

526

the gas turbine. However, the gas turbine CHP was more attractive in that it was the least

527

expensive CHP option both in terms of annual cost and cost of CO2 avoided per tonne of CO2.

528

Gas turbine CHP was also remarkable in that it consistently performed better than CCS in the

529

FCC and the SMR with complete CCS systems in terms of reductions in the refinery CO 2

530

emissions. However, the sensitivity analysis of crude quality showed that the electrically heated

531

SMR with CCS could prevail over the performance of the gas turbine CHP if the share of SMR

532

emissions in the total refinery emissions is larger than 20%. Sensitivity analysis of refinery

533

configuration revealed that in more complex refineries, in the presence of a gas oil

534

hydrockracker this technology always prevails over the gas turbine CHP. This sensitivity

535

analysis also showed that in a deep conversion refinery with a coker and FCC (no gas oil

536

hydrocracker), the electrically heated SMR with CCS system prevails over the gas turbine CHP

537

in a refinery where SMR contributes to over approximately 20% of the total refinery CO2

538

emissions. However, CCS in the FCC and the SMR with complete CCS systems consistently

539

performed inferior to the gas turbine CHP.

540

The runs in the hydroskimming refinery typically indicated lower utility requirements (natural

541

gas, electricity, steam, and H2) and lower CO2 emissions than the more complex refineries. The

542

results showed that for such refineries employment of CO2 mitigation technologies would result

543

in lower annualized cost (mainly due to smaller capital costs), but given the small reductions in

544

the total CO2 emissions from these refineries, the costs of CO2 mitigation per tonne of CO2


25


Page 26 of 37

545

avoided in these refineries would be very high. This combined with the low net H2 requirement

546

of these refineries could likely rule out alternative H2 production technologies as viable options

547

to obtain CO2 reductions in these refineries. Also, the hydroskimming refinery modeled in

548

PRELIM does not include the FCC unit, and therefore CCS in the FCC process unit does not

549

apply to this configuration.

550

In more complex refineries, significantly higher utility requirements (due to the presence of

551

process units such as FCC, gas oil hydrocrackers, and coking units) and CO2 emissions generally

552

necessitate mitigation technologies with higher capacities that in turn deliver higher reductions in

553

CO2 emissions at lower costs of CO2 avoided, but at higher annualized costs (mainly due to

554

larger capital costs).

555

DISCUSSION

556

The unique structure of PRELIM8,

37

was exploited to evaluate the environmental and

557

economic performance of a set of CO2 mitigation technologies that could be employed in

558

refineries. The analysis suggests that 3 to 44% CO2 reductions can be achieved in a typical U.S.

559

refinery with the employment of mitigation technologies at an additional cost of $57 to $1180

560

per tonne of CO2 avoided. The additional cost of these technologies was $0.5 to $2.8 per barrel

561

of crude (the order of the costs of the technologies on a per barrel basis is the same as the order

562

of their annual cost). An alternative representation of Figure 1 based on $/bbl crude values can

563

be found in the SI. For example, employment of a gas turbine CHP at a refinery could reduce the

564

total CO2 emissions of a refinery by approximately 11%, however this would impose a cost of

565

approximately $241 per tonne of CO2 avoided ($1.5/bbl of crude). The potential CO2 reductions

566

can be significantly different depending on how it is deployed (i.e. in refineries with different

567

configurations processing different crude slates). Based on the results of this study, and


26

Page 27 of 37


568

technology readiness level of the technologies considered (see Table 1), gas turbine CHP may be

569

the most suitable technology to provide incremental CO2 reductions in near term. However, if a

570

low carbon power source (such as nuclear or renewable power) is available, electrically heated

571

SMR could be a better choice for refineries. If the complications associated with the alternative

572

hydrogen production technologies (e.g. biomass supply, high cost of electrolysis stacks) are

573

overcome, the HTE and biomass gasification have potential for more significant CO2 reduction

574

in the mid to long term. Future analysis could include evaluating new technologies close to

575

commercialization such as the hydrogen generator under development by Pratt & Whitney69.

576

Results indicate that some technologies may be appropriate to contribute to LCFS targets (e.g.

577

10% reduction in the carbon intensity of gasoline by 2020 compared to 201070). Moreover, LCFS

578

usually do not account for a method to evaluate CO2 mitigation at the refining stage (e.g.,

579

gasoline and diesel carbon intensities are default values). The use of the methodology in this

580

analysis can inform the discussion and decision making on refinery industry investments for CO2

581

reduction.

582

The effectiveness of technologies such HTE and electrically heated SMR with CCS were

583

found to hinge upon the availability of a low carbon power source. Further analysis is required to

584

investigate the feasibility of such technologies considering the implications and costs associated

585

with low carbon electricity power plants or potential synergies between CO2 mitigation

586

technologies (e.g., Use of HTE O2 byproduct in a FCC oxyfiring system and offsetting the ASU

587

associated electricity requirements and investment/operational costs). The PRELIM application

588

shown in this paper demonstrates the strengths of detailed process modeling for evaluation of

589

CO2 mitigation technologies and identifying the parameters that could influence the performance

590

of such technologies in a refinery.


27


Page 28 of 37

591 592

ASSOCIATED CONTENT

593

Details on literature review, methods, and results.

594

AUTHOR INFORMATION

595

Corresponding Author

596

*E-mail: [email protected]; phone: 403-220-5265.

597

Notes

598

The authors declare no competing financial interest.

599

ACKNOWLEDGMENTS

600

We thank Carbon Management Canada and Natural Sciences and Engineering Research Council

601

of Canada (NSERC) for their financial support. Any opinions, findings, and recommendations

602

expressed in this material are those of the authors.

603 604 605 606 607 608 609 610 611 612


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613 614


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