Unconventional Heavy Oil Growth and Global Greenhouse Gas

Jun 26, 2015 - Enormous global reserves of unconventional heavy oil make it a significant resource for economic growth and energy security; however, i...
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Unconventional Heavy Oil Growth and Global Greenhouse Gas Emissions Experience I. Nduagu* and Ian D. Gates Department of Chemical and Petroleum Engineering, Schulich School of Engineering, University of Calgary, 2500 University Dr. NW., Calgary, Alberta T2N 1N4 Canada S Supporting Information *

ABSTRACT: Enormous global reserves of unconventional heavy oil make it a significant resource for economic growth and energy security; however, its extraction faces many challenges especially on greenhouse gas (GHG) emissions, water consumption, and recently, social acceptability. Here, we question whether it makes sense to extract and use unconventional heavy oil in spite of these externalities. We place unconventional oils (oil sands and oil shale) alongside shale gas, coal, lignite, wood and conventional oil and gas, and compare their energy intensities and life cycle GHG emissions. Our results reveal that oil shale is the most energy intensive fuel among upgraded primary fossil fuel options followed by in situ-produced bitumen from oil sands. Lignite is the most GHG intensive primary fuel followed by oil shale. Based on future world energy demand projections, we estimate that if growth of unconventional heavy oil production continues unabated, the incremental GHG emissions that results from replacing conventional oil with heavy oil would amount to 4−21 Gt-CO2eq GtCO2eq over four decades (2010 by 2050). However, prevailing socio-economic, regional and global energy politics, environmental and technological challenges may limit growth of heavy oil production and thus its GHG emissions contributions to global fossil fuel emissions may be smaller.

1. INTRODUCTION Unconventional oil production received a boost recently especially in North and South America with the significant increases in production from oil sands in Canada, tight oil and oil shale in the U.S, and growth projections of extra heavy oil in Venezuela. Unprecedented attention has been paid lately to oil sands due to uncertainties that surround the approval of the TransCanada Keystone XL Pipeline Project by the U.S. Government.1 Among other fuel choices available including tight light oil, natural gas, shale gas, and liquefied natural gas, given their environmental record and rapidly changing business environment, liquid fuels from unconventional heavy oil resources face challenges in the marketplace. Climate change and ecological issues are some of the key concerns that motivate action against the expansion of unconventional heavy oil. On the other hand, job creation, economic growth and importantly, resource utilization and energy security, all encourage unconventional heavy oil production and growth. Exploration of petroleum resources, like other energy resources (e.g., wood, coal, peat), follows a pattern where the best quality and most accessible resources are extracted first before progressing to often lower quality, less accessible resources that require more effort and have higher energetic, economic, and environmental costs. With depleting conventional oil, attention is shifting toward unconventional oil. Unconventional heavy oil has a high energy intensity and as a © 2015 American Chemical Society

result emits significant greenhouse gases (GHGs); typically requiring more energy and emitting more GHGs than does conventional crude oil. In addition to environmental implications of unconventional heavy oil production, a fundamental question we ask in this paper is whether it makes sense to extract and use heavy oil resources as a substitute for the dwindling volumes of conventional crude oil, considering fuel extraction energy intensity. Although this question appears to be simple, its answer is not straightforward, yet, answers to the following questions may provide suggestions for policy: What fraction of energy from the resource is lost during the recovery process? How does this relate to the life cycle greenhouse gas (GHG) emissions intensity? How do energy and GHG emissions intensities of oil sands bitumen compare to conventional crude oil and other fuel options? We use bitumen extraction from oil sands as a case study to illustrate the energy intensive nature and climate change impact of recovering unconventional heavy oil. This paper places unconventional heavy oils alongside conventional oil and other fuels such as natural gas, shale gas, Received: Revised: Accepted: Published: 8824

July 31, 2014 June 17, 2015 June 24, 2015 June 26, 2015 DOI: 10.1021/acs.est.5b01913 Environ. Sci. Technol. 2015, 49, 8824−8832

Article

Environmental Science & Technology

intensity is computed, EROI is calculated as a simple mathematical ratio of energy extracted to the energy required to get that energy.4 Recent studies5,6 present calculations related to energy return ratios (ERR), a similar concept as EROI, of bitumen produced from Alberta oil sands. Details on energy return ratio methods and calculations are presented in the SI. These studies on energy return ratios of oil sands extraction provide a good background work for this present study. However, the information they provide are not entirely consistent due to data paucity, uncertainties and errors that may arise from gathering data from several sources, different assumptions and uncertainties in the models used. In summary, this study presents the energy intensity (or the amount of energy amount expended in extracting bitumen divided by the amount of chemical energy contained in the bitumen produced, expressed as percentage) and the NER of 10 major SAGD bitumen production projects in Alberta. More so, energy intensity estimation gives what we are looking for in this analysisexplicit values of the percentage of fossil fuel energy lost to bitumen extraction. Thus, energy intensity value gives the same value as the reciprocal of NER values. 2.1.2. Energy Requirements. The use of SAGD technology involves injection of large volumes of high pressure, high temperature steam into the reservoir to produce bitumen. In addition to the steam energy requirements, electricity is required for water treatment processes and auxiliary equipment such as downhole pumps, pad auxiliaries, glycol system, evaporators, etc. 2.1.3. Steam Energy Requirements. Steam enthalpy injected into the reservoir to extract bitumen is calculated from average steam conditions (steam quality, pressure or temperature are presented in the SI). The quality of energy used for energy extraction is factored in by accounting for efficiency losses of generating such energy based on the second Law of Thermodynamics. The amount of natural gas used to generate the steam at the given conditions was calculated (the efficiency of the boiler is 0.85) by

coal, lignite, and wood and compares their energy intensities and life cycle GHG emissions. Based on global growth projections of unconventional heavy oil production, we estimate on a life cycle basis how much GHG emissions that unconventional heavy oil production and consumption may add to the environment based on a projected growth scenario.

2. MATERIALS AND METHODS 2.1. Energy Intensity of Oil Sands Bitumen Extraction. We analyze 10 major SAGD projects (Figure 1) in Alberta to

Figure 1. Average daily oil production presented as linear function of injected steam enthalpy for major SAGD projects from 1992 to 2011. Data for these ten SAGD projects are aggregated: Cenovus−Christina Lake, Cenovus−Foster Creek, Connacher−Great Divide, Devon− Jackfish, MEG−Christina Lake, ConocoPhillips−Surmount, Suncor− Mackay River, Suncor−Firebag, Nexen−Long Lake, and Total E&P− Joslyn Creek. Data collected from in situ projects information provided by the AER2-individual projects data are shown in Supporting Information (SI) Figure S1. The start-up and redundant phases of the projects, where steam was injected without significant oil production, are not included in the analysis since this period often occupies the less than 2% of the total operation.

gain an insight into data availability, and uncertainties associated with estimating energy intensities and environmental footprints of unconventional heavy oil production. Steam injection and bitumen production data are obtained from the annual in situ progress presentations and database at the Alberta Energy Regulator (AER).2 The average daily bitumen production, daily steam injection and steam injection conditions for SAGD projects (Figure 1) are used. Details of each project analyzed, average steam injection conditions and equations that correlate average bitumen production capacity as a function of steam energy injected are listed in the SI (SI) Table S1. 2.1.1. Energy Intensity and Net Energy Return. In this section, we determine whether it is sustainable to extract unconventional heavy oils, using the bitumen from Alberta oil sands as a case study, considering fuel extraction energy intensity. Energy is expended in the process of extracting a primary energy resource, and thereafter energy is also expended in transforming primary fuels to energy forms that are directly useful to the society. By using physical parameters, we determine the fraction of energy from the oil sands bitumen that is lost during the extraction or production process. Energy intensity, which is measured as the ratio of energy inputs to the useful output,3 is one of the parameters assessed. Another parameter assessed is energy return on energy invested (EROI) on a net energy return (NER) basis. Similar to how energy

mNG =

msHs, x LHVNGη

(1)

where mNG is the mass of natural gas (kg), mS the mass of steam, Hs,x the enthalpy of steam at steam quality x, η the boiler efficiency, and LHVNG the low heating value of natural gas. 2.1.4. Power Requirements. The major energy inputs are steam and electricity. Steam is generated on-site using oncethrough steam generators (OTSG) whereas electricity is drawn mostly from the grid. We considered two cases: (i) power purchase from the grid or (ii) using natural gas cogeneration (also referred to as cogen) to meet on-site power requirements - assumes that grid power is avoided. Many operating cogeneration plants in the oil sands operate at about 80−85 MW capacity, so we used 80 MW in our calculations. The heat to power ratio of cogeneration systems with supplementary firing is assumed to be 3:1 (GJ heat to GJ electricity).7 We consider exergy analysis method in allocating life cycle GHG emissions of cogeneration to steam production and electricity generation.8 Although there are several ways to allocate emissions of cogeneration, the exergy method was chosen because it accounts for both the quantity and quality of energy in its construct, a method consistent with the analysis in this study. Details current electricity usage and the exergy allocation method are presented in the SI Section 5 8825

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Environmental Science & Technology 2.2. GHG Emissions Footprint of Oil Sands Bitumen. Following ISO 140449 guidelines for life cycle assessment (LCA), the goal of this study is to assess the GHG emissions of in situ bitumen extraction from oil sands. Note that this study is a full life cycle assessment, which takes into account the environmental impacts of all the activities in the entire process chain of the product (cradle to grave stage or raw material to disposal stage). This study assesses the energy and GHG emissions of bitumen extraction, upgrading and combustion of the upgraded project. The GHG emissions (including CO2, CH4, and N2O) associated with all the processes leading to the production of crude bitumen from oil sands reservoirs were calculated and compared with published values of other primary fuels. Upgraded bitumen is the main output of the extraction process. The GHG emissions are computed based on the 100year time horizon of the GHGs and results presented as CO2eq (carbon dioxide equivalents).10 The amount of GHG emissions from fuel extraction per GJ energy derived from burning upgraded primary fuel (low heating value) was chosen as a basis for comparison−also known as the functional unit of this study. More details on methods, calculation boundary and data sources can be found in SI. 2.3. Bitumen Transformation into Dilbit or SCO. We consider two pathways bitumen is processed downstream before it is transformed to transportation fuels in refineries: dilibit or SCO pathways. This stage of analysis was conducted to present an “apple to apple” comparison of energy and emissions of bitumen products and those of other primary or upgraded fuels which are of high quality, transport-ready fuels, for example, oil shale and conventional crude oil. Further processing of bitumen to dilbit or SCO makes the bitumen product suitable for transportation by pipelines even at low temperatures with reduced risks of solidification and pipeline blockage. Energy requirements and GHG emissions of the upgrading step were added to the upstream emissions of SAGD extraction step. Energy requirements for dilbit production were calculated by assuming that diluent is made of natural gas condensate with a NER of 20 which is the high limits for natural gas production.11 Energy requirements for SCO production reported in previous studies6,12−14 were used. Loss of bitumen volume by about 20% during upgrading to SCO was accounted for. We also accounted for GHG emissions from upstream diluent production and transport (3000 km), dilbit transport from extraction to upgrading site (500 km) and upgrading emissions. It is assumed that diluent used for dilbit production is not recycled and was transported through a 3000 km distance whereas dilbit is transported through a 500 km distance, equivalent to a distance between Ft. McMurray and Edmonton where bitumen extraction and upgrading to SCO take place in Alberta, respectively.15

fuel used to generate steam which consequently indicates the GHGs emitted. Only steam enthalpies injected into oil sands reservoirs are included in Figure 1 − power requirements are not included. 3.1. Energy Intensity of Oil Sands Bitumen Extraction. If the energy content of bitumen is taken to be 42.8 GJ/m3,16 the results shows that on average, the SAGD oil sands industry is achieving ∼4.1 GJ return per GJ invested, equivalent to ∼25% of bitumen energy lost during SAGD extraction process. This is calculated based on average steam energy requirements (SI Table S1) taking into account individual steam qualities (between 0.94 and 0.98), steam boiler efficiency of 0.85, and the electricity requirements estimated at 66.5 kWh/m3 bitumen.17 The overall average for all the projects were estimated using the individual bitumen production capacity correlation which is expressed as a function of steam energy injected into the reservoir (SI Table S1). With the estimated electricity requirement and steam enthalpies (SI Table S1), results show that natural gas requirements make up 96.6− 98.8% of the entire process energy requirements, whereas electricity is the rest (1.2−3.4%). Though a NER of 4.1 could represent an industry average for Alberta SAGD projects, noteworthy also is the fact that the most and the least efficient SAGD projects have NERs of 6.1 (16% energy loss to extraction) and 2.1 (47% energy loss to extraction), respectively. The NERs of 6.1 and 2.1 represent the upper and lower bounds for the SAGD projects studied, respectively. However, the industry-average results were significantly affected by the energy intensity values of Nexen-Opti−Long Lake project, which has a net energy value of 4 GJ/m3 higher than the second most energy intensive project. This project stands out as an outlier in SI Table S1 and Figure S1. This may be as a result of difficult or lean reservoir characteristics or “plays” that require substantially more steam energy for the extraction of bitumen than for other projects with rich reservoirs properties. On the other hand, if we use the linear fit equation in Figure 1, we realize an industry-wide estimate of 5.6 GJ return per GJ invested in SAGD bitumen extraction (18% energy loss to extraction). However, we prefer to use the average value of 4.1 GJ return per GJ instead of 5.6 GJ return per GJ because the correlation in Figure 1 is not perfectly linear. It is startling to observe that the NER increased slightly with increase in steam injection, and consequently increase in bitumen production. This is more pronounced with the Suncor-Firebag and DevonJackfish projects which experienced a dramatic improvement in energy return ratios of ∼1.6 and ∼2.9 points, respectively. The reason for the observed increase of energy return ratio as steam injection increased is associated with greater mobilization of oil due to higher temperature arising from greater injection pressure. 3.1.1. Bitumen Transformation into Dilbit or SCO. Processing raw bitumen into dilbit involved producing a bitumen:diluent mixture of about 70%:30% ratio. Although the ratio can vary but that is a typical mixing composition. Properties of bitumen, diluent, dilbit and SCO are listed in SI (Table S1). Addition of diluent helps boast the NER of the dilbit product because natural gas condensates displaces 30% of the relatively low NER bitumen. Depending on the type of upgrading (delayed coking or hydrocracking), additional energy requirements of 5−7 GJ/m3 SCO is expected.6,12−14 Results show that upgrading to SCO reduces the NER of the bitumen product compared to dilbit production (Table 1).

3. RESULTS AND DISCUSSION As shown in Figure 1, the results show that despite the heterogeneities of the reservoirs, the oil production rate appears to be loosely linearly correlated to the amount of steam energy injected into the formation but with quite a broad range of enthalpies for any oil recovery rate. This reinforces a cardinal requirement of oil sands recovery processes, the oil mobilized is almost directly proportional to the amount of energy injected into the reservoir. The key learning here is that most of the data falls on a single broad trend. This provides a means to estimate the net energy return of these processes and their associated GHG emissions. The enthalpy injected reflects the amount of 8826

DOI: 10.1021/acs.est.5b01913 Environ. Sci. Technol. 2015, 49, 8824−8832

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However, depending on the configuration of the refinery, dilbit may have to be processed further to the equivalence of upgraded SCO before its final refining to transportation fuels. Further processing of dilbit may likely bring the NER values of refined fuels from both pathways close to each other. The results presented in Figure 2 show that the fraction of energy in the SAGD bitumen product lost by the extraction process itself ranges from 14 to 77% of the useable energy recovered. The lower bound represents the minimum extraction and processing energy penalty if dilbit production is the product whereas the upper bound represents the maximum extraction and processing energy penalty if SCO is produced. About 97−99% of the energy losses are caused by generation of high pressure steam injected into bitumen reservoirs whereas the rest is from electricity requirements of the SAGD operations. Bitumen mining, on the other hand, is a less energy intensive process. We estimate that 4−7 GJ/m3 bitumen is expended during bitumen mining (details are presented in SI Table S2). Following the methods described earlier, we estimate this to be 8−16% of energy lost to bitumen mining process. These values are the minimum and maximum values obtained by dividing the energy of bitumen produced by the net energy expended in mining, expressed as a percentage. Bitumen extraction gives a wide range values for NER. This is because the major commercially practiced bitumen recovery methods differ in terms of energy intensities, resulting in different ranges of NERs for extraction. 3.1.2. Comparison with Other Fuels. Table 1 shows that for conventional oil, energy losses from upstream processing are below 10% of the energy content of the crude oil produced. Conventional natural gas, on the other hand, has a maximum energy loss of about 15% of the recovered energy.11,17,19 The EROI for US production of the oil and gas industry was estimated to have declined from 20 in 1972 to 11 in the late 2000s.30 Global EROI for oil and gas has similarly declined from 26 in 1992 to 18 in 2006.31 This is close to the value calculated as average value for EROI for oil and gas. Usually the EROI for oil and gas are calculated together because both are extracted from the same wells and the energy inputs for EROI calculation are very difficult to separate.31 Similar to the trend for aggregated EROI values for oil and gas, natural gas production in Western Canada has its EROI fallen from 38 in 1993 to 15 in 200611 whereas the EROI for oil production and for natural gas production is around 20.21 Based on these

Table 1. EROI of Fuels

fuel

EROI

EROI

extraction

upgraded fuel

comments/refs.

conventional NG

20 8.5−10

ref 11 ref 17

shale gas

64−112

ref 18

conventional oil and gas

11 11 18 17 15 20

ref ref ref ref ref ref

oil sands SAGD

4−7 5 5 2.2−6.3

mining and SAGD5 average values20 ref 21 this study this study

2.7−7.3 (Dilbit) 1.3−2.9 (SCO) oil sands mining

3.3−6.7 (4.1) 7.4−13.7 (Dilbit) 2.4−4.1 (SCO)

wood

27.6 20−30 20−29

oil shale

19 12 12 20 11 21

mining projects17 (See Table S3 in the SI) calculated from GHGenius17 energy requirements from diluent/upgrading added.

ref 22 ref 23 ref 24 1.4 1.6−2.0

average value20 in situ and ex situ conversion processes25−27 - values for refining process discounted.

coal

70 50−85 28

ref 28 ref 21 average value20

lignite

16.1−30.3

values calculated from primary energy demand for lignite extraction in West Germany.29

Figure 2. Percentage of harvested energy lost to process considerations (on y-axis) against life cycle fuel GHG emissions intensities (on the x-axis). 8827

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Environmental Science & Technology Table 2. Extraction and Processing Emissions of Conventional and Unconventional Fossil Fuels (kgCO2/GJ Fuel)a fuel conventional NG

extraction and processing emissions GHG kgCO2eq/GJ fuel

upgrading emissions if applicable kgCO2/GJ upgraded fuel

life cycle emissions (extraction, processing and combustion) kgCO2eq/GJ upgraded fuel

13 (5.1−25) (7.1−27)

68 (60−80)

comments/refs. ref 33 ref 34 ref 35 ref 36 Used in this study

7.7 11

71 (62−81) 63 66 (60−81)

conventional crude oil

(0.3−17) 11

71−88 83

extraction data from ref 12 ref 17 Combustion emissions -70.9 kgCO2/GJ

shale gas

9.7 (4.0−24) (15−33) 7.7 8.8 (0.1−9.2) 8.8

65 (59−79) 70−88 63 64 65−74 63 (59−88)

ref 33 ref 34 ref 35 ref 36 ref 37 used in this study

oil sands SAGD

12 (9−24) 12 (8−23) 12 (9−24)

82−97 81−96 92−116

Dilbit, no cogen. Dilbit, cogen. SCO, delayed cooking−no cogen SCO, delayed cooking−cogen SCO, hydrocracking−no cogen SCO, hydrocracking−cogen

12 (8−23) 12 (9−24) 12 (8−23) oil sands mining

2.9−8.9 2.5−8.1 2.9−8.9 2.5−8.1 2.9−8.9 2.5−8.1

1.5−5.6 8.2−17

92−115 92−118 91−117

7.5−18

1.5−5.6

78−86 77−85 86−101

8.2−17

86−100 85−102 85−101

7.5−18

Dilbit, no cogen. Dilbit, cogen SCO, delayed cooking−no cogen SCO, delayed cooking−cogen SCO, hydrocracking−no cogen SCO, hydrocracking−cogen

wood

1.7−7.6

low (demolition wood) to high (birch wood) ranges. ref 24

oil shale

97−121

Shell in situ conversion process (ICP)b. ref 25 Alberta Taciuk Processor, ref 26 upgraded shale oilc, ref 38

129−147 116−271 coal

93−99

92−101

ref 34 surface and deep mined coald ref 33 surface and deep mined coale upstream data from ref 17

103−164

ref 39

104−117

lignite a

Values in brackets are the reported range. The use of cogen or not refers to the extraction process whereas upgrading assumes no use of cogen for both cases. Bitumen upgrading emissions are from ref 15. bReported values for upstream emissions (52.1−73.2 gCO2eq/MJ refined fuel was converted to per MJ upgraded oil shale using upgraded fuel to refined fuel efficiency of 88%40) was added to oil shale combustion emissions 83.8 gCO2eq/MJ. Oil shale contains 20.1 gC/MJ.27 cAccounted only for CO2 emissions. dLower limit is for surface-mined whereas the upper limit is for deep-mined coal. eThe lower limit represents the lower limits of surface mined coal (104−109 gCO2e/MJ) whereas upper limit is the upper limit for deep-mined coal (110−117 gCO2e/MJ).

associated with early stages of development, the energy lost during oil shale extraction and emissions seems unclear,26 but recent studies19,25,26 may have narrowed the estimate to values significantly higher than the energy losses of the most SAGD bitumen extraction processes. Oil shale has NER of 1.6−2.0 for both in situ and ex situ oil shale extraction processes. The

values, we estimate that an EROI of 11−20 captures the current range of EROI for conventional oil and gas. For unconventional natural gas (e.g., from the Marcellus Shale), the energy extraction losses could be up to about 2% of the energy extracted. The reported EROI for Marcellus Shale gas is 64− 112 with an average of 85.18 As a result of uncertainties 8828

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requirements for SAGD recovery or bitumen mining, respectively. However, the impact of cogen application on process emissions becomes more important when assessed at bigger scales, e.g. per m3 or terra joule (TJ) of fuel. Oil sands mining produces bitumen products of lower GHG emissions intensity than SAGD recovery process because higher amounts and quality of steam are required in the latter whereas the former requires mostly hot water for oil−water-sand separation. Dilbit production has a lower GHG emissions impact than SCO production. This is because dilbit volume blend is 70% bitumen and 30% natural condensate. 3.2.2. Comparison with Other Fuels. The life cycle GHG emissions intensity of wood has an upper bound value of 7.6 kgCO2eq/GJ representing birch wood used in buildings and a lower bound value of 1.6 kgCO2eq/GJ for demolition wood (Table 2).24 Model results from Ecoinvent database in SimaPro Software32 collaborate these values giving life cycle GHG emissions of 3−7 kgCO2eq/GJ. Though the latter are Europespecific, values for North America are in the same range, 2.4 kgCO2eq/GJ for residential wood.17 The life cycle GHG emissions footprint of conventional crude oil represents emissions associated with extraction, venting and flaring for different conventional crudes. These include low emissions intensity crudes from Saudi Arabia (0.3 kgCO2eq/GJ), Mexico (3.1 kgCO2eq/GJ), Iraq (5.1 kgCO2eq/GJ) to high emissions intensity crude from Nigeria (16.8 kgCO2eq/GJ).12 Emissions from natural gas and shale gas do not differ significantly, and uncertainties in estimating associated fugitive emissions and flaring from natural gas production are responsible for range of emissions presented in Table 2. GHG emissions intensities of coal and SAGD bitumen upgraded to SCO are very close to each other (Table 2 and Figure 2). Life cycle GHG emissions associated with burning wood range from six times to an order of magnitude less than the value for the fossil fuels with the lowest GHG emissions footprint, natural and shale gas. It is not surprising that wood stands out as the most environmentally friendly fossil fuel given the emissions intensity from growing and burning wood biomass. On the other hand, mined bitumen upgraded to dilbit has the lowest GHG emissions footprint among the bitumenderived fuels, followed in order by mined bitumen-derived SCO, and SAGD bitumen-derived dilbit. SAGD bitumen upgraded to dilbit has a lower GHG emissions footprint than its SCO counterpart. The environmental performance of upgraded bitumen from in situ oil sands extraction would be worst if fuel sources such as coal and lignite are used as energy sources for bitumen extraction and processing. In typical oil sands SAGD practice, the energy system of choice is natural gas, which is a comparatively low cost fuel having very low energy input and GHG emissions in its life cycle. Oil sands extraction benefits from consumption of low cost energy available in the form of cheap natural gas to produce a higher revenue form of energy (bitumen). There do not appear to be any revolutionary new recovery processes available that will deliver oil to surface with an energy intensity near that of primary conventional oil recovery.41 Oil shale and lignite are the worst polluting of the fossil fuels presented here; they have minimum life GHG emissions of 97 and 103 kgCO2eq/GJ, respectively. The upper bound of life cycle emissions of oil shale and lignite are high as 147 and 271 kgCO2eq/GJ, respectively. The upper bound for oil shale can be reduced to 160 kgCO2eq/GJ if we consider recent studies26,25 to be closer to reality than the former study.38

values were calculated on the basis of upgraded oil shale after discounting refining energy requirements.25,26 Within the same range is the average EROI values of 1.4 for oil shale from a recent review paper.20 The minimum oil shale extraction losses can be up to two and five times the minimum percentage losses of SAGD extraction and mining processes, respectively. The range of values presented in Figure 2 cover in situ retorting for oil recovery from oil shale, otherwise known as the in situ conversion process (ICP) and the above-ground (ex situ) oil shale retorting process. The EROI of harvesting/extracting wood is between 20 and 3022−24 whereas that of coal falls between 50 and 85 coal20,21,28 and lignite between 16 and 30.32 The aforementioned primary fuels fall broadly into three major energy intensity classifications: I. Class I fuels with 1−5% of its energy lost to the extraction processes, examples are shale gas, wood, coal and lignite. II. Class II fuels with 5−12% of its energy lost to the extraction processes, which include conventional oil, and natural gas and mined bitumen III. Class III fuels, high energy intensive fuels with percentage amount of fuel (energy) expended above 12%. These include mined bitumen (losses 7.3−42%), SAGD bitumen (losses 14−77%) and oil shale (losses 37−63%). Mined bitumen falls into both Class II and III fuels because the percentage amount of fuel energy expended during mining and upgrading is between 7.3 and 40%. If dilbit is produced from mined bitumen, the resulting fuel energy penalty is 7.3− 13.6%, whereas SCO from mined bitumen has a fuel energy penalty of 24.2−40%. Thus, mined bitumen upgraded to dilbit can be classified as a Class II fuels but mined bitumen upgraded to SCO is clearly a Class II fuel. Our results show that the fractional energy loss (expressed as a percentage) climbs from shale gas to coal, lignite, wood, conventional oil and natural gas, mined upgraded bitumen, SADG upgraded bitumen and to oil shale (Figure 2). The computed range of values for percentage amounts of fuel (energy) lost during the extraction and upgrading for individual fuels as well as their GHG emissions intensities (kgCO2eq/GJ energy) are shown in Figure 2. 3.2. Life Cycle GHG Intensity of Oil Sands SAGD Recovery. 3.2.1. Bitumen Transformation into Dilbit or SCO. The dilbit pathway adds 1.5−5.6 kgCO2/GJ dilbit from upstream diluent production and 3000 km transport to extraction site.15 Assuming an efficient combustion of dilbit, when the combustion emissions are added to emissions from bitumen extraction, diluent production and transport, and a 30%-points reduction in bitumen content accounting for, the life cycle emissions for a non cogen case give average of 90.3 kgCO2/GJ. For bitumen upgrading to SCO, the two pathways considered, delayed coking and hydrocracking, (both without cogen) result in emissions of 8.2−16.6 kgCO2/GJ SCO and 7.5−18.3 kgCO2/GJ SCO, respectively.15 This value is inclusive of 0.4−1.6 kgCO2/GJ SCO emitted by a 500 km transport of recycled diluent from the refinery to the extraction site. Combustion emissions are added to emissions on bitumen mining, diluent production, upgrading and transport to produce the life cycle emissions presented in Table 2. On a GJ of fuel basis, the difference between cogen and no cogen cases is not significant. This is not surprising given that electricity requirements are significantly less than steam or hot water 8829

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Environmental Science & Technology Overall, in terms of life cycle emissions, oil shale is the worst performing fossil fuel here, sequentially followed by lignite, SAGD bitumen and coal (which seems to be a tie), mined bitumen, convention crude oil and shale gas, natural gas, and wood biomass. Again, the wide range of values for fuels (Figure 2), for example, for oil shale life cycle emissions, indicate uncertainties arising from different computational boundaries and analysis at different stages of technology development, different technologies to produce and process the fuel, and different fuel characteristics as well as geologic reservoir differences. We note also that with time, technologies for fuel extraction improve and mature, consequently driving down fuel energy intensity as well as reducing its GHG emissions footprint. We expect that the energy and environmental perfomance of fuels such as oil shale and oil sands bitumen will improve in the future with technological advancements. However, greater research efforts should be put into resolving the challenges facing massive commercial deployment of alternatives to heavy oil as a souce of transportation. These alternatives include wide deployment of electric and solarpowered vehicles, and vehicles powered by biofuels, compressed natural gas, natural gas liquids, etc.

Figure 3. Projected unconventional oil demand44,46,47 and potential life cycle emissions. Upper and lower bounds of the life cycle emissions are presented.

If this rate of growth continues uninterrupted, about 21−26 GtCO2eq/yr will be emitted from oil consumption by 2050. These result in cumulative emissions from conventional oil production and use of 746−925 Gt-CO2eq between 2010 and 2050. When unconventional heavy oil is included in the global oil demand projections, total life cycle global emissions of oil consumption is estimated to grow from 16 to 20 Gt-CO2/yr in 2014 to 21−27 Gt-CO2/yr in 2050 resulting in cumulative emissions of 750−946 Gt-CO2eq over these four decades. Based on the results presented above, we can put GHG emissions impact of unconventional heavy oil in perspective of global oil emissions. The difference that arises from the use of heavy oil becomes 4−21 Gt-CO2eq over four decades. This is the potential life cycle emissions from unconventional heavy oil production from 2010 to 2050 assuming that factors effecting oil demand and supply favor the growth projections. Based on mid-21st century carbon-climate response model estimates, which give ensemble mean earth surface temperature rise of 1.6 °C per Tt C (1018 gC),42 we can estimate that the warming associated with the use of heavy oil amounts to this level of emissions may lead to about 0.002−0.009 °C increase in earth surface temperature. However, the projected growth in heavy oil production is optimistic given several factors that make prediction of the growth path of heavy oil difficult. Regional and global energy security and politics, accessibility, affordability, attractiveness as investment options, and associated energy intensity and GHG emissions of other competing energy resources are key parameters that influence the economics and consequently, the growth of heavy oil production. Thus, a realistic value for incremental GHG emissions arising from the displacement of conventional crude oil with heavy oil could be less than the amounts presented due to limited growth of heavy oil production and new operations. In view of this, the oil sands industry, regulator, and provincial and federal governments need to devise and implement policies that shift in situ operations to the energy recovery efficiency trends of other fuels. If this shift is not made, potential technology shifts to natural gas for transportation fuels may sideline an extensive oil sands transportation fuel-based economy. The future of the unconventional heavy oil industry, arising from environmental concerns, public perceptions, investment, other fuel options and markets could be either promising or dismal−the former if rapid development and deployment of effective technologies occurs, or the latter if business as usual

4. FUTURE OUTLOOK AND POLICY IMPLICATIONS Given that global mean temperature change of the earth’s surface is approximately linearly related to a given amount of cumulative carbon dioxide emissions42,43 we consider the implications of large scale increase in production of unconventional heavy oil on global anthropogenic GHG emissions. According to the projections of the Organization of Petroleum Exporting Countries (OPEC), about 18 million barrels per day (mbd) of additional oil is required to meet the expected worldwide demand growth by 2035.44 Out of this amount, OPEC countries are expected to produce 11 mbd while nonOPEC countries are expected to produce the rest (7 mbd), which is expected to come mostly from unconventional oil resources from the U.S. and Canada.45 The unconventional heavy oil’s share of global crude oil production is expected to double by 2035 from its current share of less than 4%. If oil shale/tight oil is included, the unconventional oil’s share of global crude oil production grows to become 15% by 2035. Current unconventional heavy oil production is about 3 million barrels per day (mbd) but is projected to reach almost 8 mbd by 2035.44 Canadian oil sands alone is projected to produce about 4.8 mbd by 2030, which is a 2.5 times growth from the current (2014) value of 1.9 mbd.46 If the projected growth44 is extrapolated further, unconventional heavy oil production rises to 10 mbd by 2050 (Figure 3). We estimate a similar trend where associated GHG emissions rise from the current value of 0.8−1.3 Gt-CO2eq/yr (2014) to 2−3 Gt-CO2eq/yr by 2050. Based on these projections, we estimate that cumulative emissions of unconventional heavy oil use will amount to 55−84 Gt-CO2eq over four decades (2010−2050). This is a huge amount of emissions, equivalent to the global liquid fuel carbon emissions for 5−7 years from 2006 to 2012. However, it is important to know the difference in emissions if unconventional heavy oil is eliminated from the global oil supply mix. In other words, if we stopped heavy oil production today, what amount of global warming-causing emissions can we obviate? Based on global oil projections,44,47 if conventional crude oil alone provides for the world oil demand, GHG emissions from oil production and use will grow at an approximate rate of 140−180 Mt-CO2eq/yr from 2010 to 2035. 8830

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continues. If industry and government invests heavily in GHG emissions reduction and water consumption technologies (to be competitive with conventional oil recovery processes), solves social issues (aboriginal issues, perceptions of oil sands),48,49 and market access limitations (pipelines), then the outlook for oil sands and its economic and social benefits could be bright. If no significant change in strategy toward reducing oil sands energy and GHG emissions intensity is put in place, in an environment of growing momentum of environmental concerns and alternative fuel developments and increasing market access limitations, the industry may experience limited growth with investment communities migrating away from oil sands toward other fuel enterprises.

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ASSOCIATED CONTENT

S Supporting Information *

The Supporting Information is available free of charge on the ACS Publications website at DOI: 10.1021/acs.est.5b01913.

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AUTHOR INFORMATION

Corresponding Author

*Phone: (403) 210-7148; e-mail: [email protected]. Author Contributions

The study was jointly conceived by the two coauthors. Data was analyzed by EIN and the manuscript was jointly written by the two coauthors. All authors have given approval to the final version of the manuscript. Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS Financial support from the University of Calgary Eyes High Postdoctoral Scholar Program (EIN) is acknowledged. Dr. Steve Larter, Dr. Cosmas Ezeuko, Dr. Da Zhu, and anonymous reviewers are acknowledged for their useful comments.

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REFERENCES

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