Energy efficiency and emissions intensity of SAGD

Fuel 115 (2014) 706–713

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Energy efficiency and emissions intensity of SAGD Ian D. Gates a,⇑, Stephen R. Larter b a b

Department of Chemical and Petroleum Engineering, University of Calgary, Canada PRG, Department of Geosciences, University of Calgary, Canada

h i g h l i g h t s  Steam-Assisted Gravity Drainage is process of choice for extra heavy oil recovery.  Average recoveries from heavy oil and oil sand reservoirs are typically low.  Some SAGD operations are actually not net energy generating.  New oil sands processes needed to improve energy and carbon dioxide intensities.

a r t i c l e

i n f o

Article history: Received 5 February 2013 Received in revised form 18 July 2013 Accepted 18 July 2013 Available online 9 August 2013 Keywords: Steam-Assisted Gravity Drainage SAGD Bitumen Thermal process Energetics

a b s t r a c t Currently, to mobilize and produce bitumen from Athabasca oil sands reservoirs, Steam-Assisted Gravity Drainage (SAGD) is the method of choice. SAGD, requires large amounts of energy and emits significant volumes of greenhouse gases to the environment. Here, we discuss the thermal efficiencies, energy balances, and emissions of SAGD. While the world’s heavy oil and oil sand resource is large, average recoveries from heavy oil and oil sand reservoirs are typically low, ranging from 5% to 15% for cold heavy oil production and from 25% to 60% percent for steam-based in situ processes. This is for two reasons: firstly, geological heterogeneity and secondly, ubiquitous large scale fluid property heterogeneities are common on a range of spatial scales. Thus, there is a strong motivation to develop better recovery processes with lower energy and emission intensities. The thermal efficiencies, energy balances, and emissions of SAGD show a very wide range of field performance for the current thermal recovery projects in Alberta, with earlier pilots being more successful. The data suggests that at the extreme, some operations are actually not net energy generating with injected energy via steam, exceeding recovered chemical energy in recovered oil. Differential pricing of oil and natural gas, the main steam generating fuel, still permits these extreme cases to be economically profitable due to low natural gas prices. In all cases, carbon dioxide intensity is high. Ó 2013 Elsevier Ltd. All rights reserved.

1. Introduction With global estimates of over 6 trillion barrels, the majority of the world’s petroleum is stored in the form of biodegraded heavy oil and oil sand (bitumen) reservoirs [1,2]. In Western Canada alone, there are over 1.7 trillion barrels of bitumen trapped in oil sand reservoirs [3]. This volume in place is second only to the conventional oil reserves of Saudi Arabia [4]. With current surface mining and in situ recovery technology, it is estimated that roughly 10% of oil sands resource in Western Canada is recoverable. The key challenge for producing heavy oil and bitumen is complex, compartmentalized reservoir geology and its high and variable in situ viscosity related to variable levels of crude oil biodegradation ⇑ Corresponding author. Tel.: +1 (403) 220 5752; fax: +1 (403) 284 4852. E-mail address: [email protected] (I.D. Gates). 0016-2361/$ - see front matter Ó 2013 Elsevier Ltd. All rights reserved. http://dx.doi.org/10.1016/j.fuel.2013.07.073

[5]. For heavy oil (between 10° and 20°API), the dead oil viscosity can range up to the thousands, or tens of thousands of cP. For bitumen (less than 10°API), the viscosity typically ranges from the tens of thousands to over 10 million cP at reservoir conditions. One useful property of heavy oil and bitumen is that its viscosity drops by several orders of magnitudes when the oil temperature is raised from original reservoir conditions, typically between 5 and 15 °C, to steam temperatures, typically over 180 °C. For example, for a typical Athabasca bitumen, the dead oil viscosity at 100 °C is equal to roughly 220 cP [6]. For a successful in situ oil sands bitumen recovery process, two requirements must be met: first, it is necessary to raise the oil mobility (often done by lowering its viscosity which results from raising its temperature) until it can be moved by natural forces such as gravity, and secondly, it is necessary to move the mobilized oil to a production wellbore so it can be produced to the surface.

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2. In situ bitumen recovery processes Currently, commercial steam-based in situ processes used to recover bitumen from oil sands reservoirs are either one of Cyclic Steam Stimulation (CSS), or Steam-Assisted Gravity Drainage (SAGD) [7]. In this work, we will focus on SAGD although the analysis and results, conceptually, also apply to CSS. CSS is a cyclic high pressure steam injection process that uses a single well where the formation is fractured by a steam injection pulse followed by a period of soaking and then oil and water co-production [7]. SAGD, displayed in cross-section in Fig. 1, is a continuous steam injection process that uses two horizontal wells. The top well injects steam, at near reservoir pressure, into a depletion chamber that forms in the oil sands reservoir. The steam releases its remaining latent heat through condensation at the edge of the chamber, heating the oil sands (oil, sand, and water) there. The viscosity of the heated oil drops and under the action of gravity drains through the steam chamber, or down its edges, to the production well at the base of the chamber [7]. The key controls on the productivity and efficiency of the SAGD process are: 1. The rate of reduction of oil viscosity with increased temperature i.e. the extent of viscosity reduction given an amount of latent heat added; 2. The rate of heat transfer at the edge of the steam chamber (set by the thermal conductivity of the oil sand and any convective contributions due to steam condensate or hot oil flow into the oil sand); 3. The relative amount of injected steam heat lost to the cap rock or thief zones e.g. zones of mobile gas or water, compared to delivering heat to the bitumen; 4. Any geological barriers such as shales or siltstones in the reservoir that would interfere with steam rise and gravity drainage of oil to the production well; 5. Natural oil compositional variations that yield relatively low oil viscosities at the top of the oil column and relatively high viscosities at the bottom of the oil column with often, lateral viscosity gradients which perturb uniform steam chamber development and can slow the production of oil; 6. The relative permeability of oil in the reservoir at the edge of the steam chamber and its effect on oil phase mobility there; 7. The ability of the recovery processes operator to prevent live steam production by maintaining a liquid barrier between the injection and production wells to enforce steam trap control, and;

Steam Chamber

Native bitumen

Injection Well

Bitumen flow zone

Production Well

Fig. 1. Cross-section schematic of the Steam-Assisted Gravity Drainage (SAGD) process.

707

8. The maintenance of an effective density difference between fluids in the depletion chamber (vapor and steam condensate) and fluids in the oil sands (bitumen and water) at the chamber edge to enable gravity drainage. If any one or more of these factors are adverse or the process controls fail e.g. the steam chamber is not charged with steam as there is a complete loss of the injected steam to a thief zone (such as a water saturated reservoir zone) rather than the growing steam chamber, then SAGD productivity and thermal efficiency suffers and the process may be rendered in viable and not commercially successful. Given that the driving force in SAGD is gravity drainage of heated oil and condensed water, process productivity is directly tied to the underlying fluid mobility field in the reservoir controlled by geological and fluid compositional heterogeneity [8]. The oil sand reservoirs are geologically very variable and complex reservoirs with many interbedded sandstones and shale [9,10] that together generate a complex variably permeable medium that steam, oil and water must migrate through. Actual oil sands reservoirs are completely different from the homogeneous sandstones with uniform fluids envisaged by the reservoir engineers that developed the early SAGD process [7]. Geological heterogeneity impacts the recovery process through permeability changes of the reservoir sandstones within the oil column and the shale or mudstone barriers and baffles that prevent or retard fluid flow, respectively [10,11]. The more laterally extensive the barrier, the longer it takes steam or production fluids to go around it and the longer it takes for mobilized oil to get to the production well. Also, non-productive reservoir within the oil column represents a heat sink which erodes the thermal efficiency of the process. The main impact of fluid compositional heterogeneity is the due to effect of vertically and laterally varying oil phase viscosity. The oil phase viscosity at the bottom of the oil column, due to biodegradation occurring over geological time scales, can be several times to several tens of times the oil phase viscosity at the top of the oil column over a scale of as little as a few tens of meters [5]. These viscosity variations also occur horizontally with 3–5 times variations along lateral length scales of about 1000 m [8]. Furthermore, these spatial oil phase viscosity variations persist, to a lesser degree, at the steam temperatures used in SAGD. During SAGD startup, the variability of the oil phase mobility is thus often largely controlled by oil viscosity and water saturation rather than by variations in the absolute reservoir permeability. Further, at the edge of the steam chamber, the majority of the flowing oil is at temperatures below the steam temperature (typically about 75% of the steam temperature) and at this temperature the oil phase viscosity can vary four to six times over the height of the oil column which is of similar order of magnitude to the variations in absolute permeability [7]. Thus, during SAGD production, both permeability and oil viscosity variations are important and adversely impact theoretical SAGD productivity. A key limitation on the SAGD process is set by deployment approaches. During large scale deployment of SAGD, to scale production, rather than tailor individual well settings to highly variable local geological realities, large scale SAGD operations are commonly deployed in a rather uniform cookie cutter style with uniform process characteristics. Thus, despite very variable local reservoir and fluid property combinations, SAGD injection and production wells are placed at the base of the oil column, typically 2 m above the base of the oil zone for the production well with the injection well 5 m above that. The lowest viscosity oils are typically in about the upper portion of the oil column and thus placing the wells higher in the formation than directly at the bottom will enhance production rates in real reservoirs, not only at start-up but also beyond [8], but practice is to place essentially all wells at the base of the oil column as this is where the theoretically

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maximum oil recovery would be attained in an ideal SAGD process working in an ideal reservoir. For SAGD, average oil recovery factors are between 40% and 60% [7]. Although optimized SAGD can, in the best reservoirs, yield reasonably high recovery factors, economic and environmental costs can be large given the amount of steam required to extract oil from the reservoir. In this paper, the energy efficiency and emissions intensity of the SAGD process is assessed both theoretically and as deployed at scale, from publically field data available from the ERCB in Alberta. 3. Theoretical energy efficiency for an oil sands recovery process Based on established bitumen heat capacities [7], the theoretical minimum amount of energy required to heat Athabasca bitumen from reservoir temperature (10 °C-viscosity equal to millions of cP) to steam temperature (200 °C and a dead oil viscosity of 10 cP) is equal to about 1.75 GJ/m3 oil. This is simply the sensible heat required to raise the temperature of a cubic meter of bitumen from 10 to 200 °C. For heating oil within the reservoir, not only is the oil volume heated but also any trapped water and the mass dominant solid mineral phases in the rock volume containing the oil. Thus, ideally, the amount of energy required to raise the temperature of the oil also includes the minimum sensible energy, Q, required to heat the water and rock of the oil sand to the temperature at whichoil will flow:

Q ¼ b/So qo cpo ðT s  T r Þ þ /Sw qw cpw ðT s  T r Þ þ ð1  /Þqr cpr ðT s  T r ÞcBV ð1Þ where BV is the bulk volume of the reservoir rock, / is the porosity, Sx is the fluid saturation of phase x, x and cpx are the average density and specific heat capacity of phase x over the temperature range from Ts to Tr, and the subscripts o, w, and r refer to the oil, water, and rock phases, respectively. By re-arranging Eq. (1), the amount of energy required to raise the temperature from Tr to Ts per unit oil volume, tEOR, becomes:

  Q Sw 1/ tEOR ¼ ¼ qo cpo þ qw cpw þ qr C pr ðT s  T r Þ /So BV /So So

ð2Þ

The energy required can be converted to an equivalent amount of steam, expressed as cold water equivalents (CWE), at steam quality xs. This gives the theoretical minimum possible steam-to-oil ratio, tSOR:

ms hL þ xs km

Q produced ¼ 0:90b/So qo cpo ðT s  40  T r Þ þ /Sw qw cpw ðT s  40  T r ÞcBV ð4Þ and used in the tEOR and tSOR calculations. In Eq. (4), the produced fluids have been taken to be at a temperature equal to 40 °C below that of the injected steam. Fig. 2a displays the tEOR versus steam injection pressure (set by the steam saturation temperature, Ts) and Fig. 2b shows the tSOR versus steam injection pressure both for 60% and 100% steam quality taking energy from the produced fluids into account as described by Eq. (4). The results show that the tEOR and tSOR rise as the steam pressure and steam temperature increases and that under ideal heating conditions, for the majority of SAGD operations which operate in the range of from about 1000–5000 kPa steam injection pressure, the tEOR lies between about 1.0 and 2.5 GJ/m3 for 60% steam quality delivered at the edge of the chamber. Over the same pressure range, the tSOR ranges from about 0.38– 0.9 m3 CWE steam/m3, for 60% steam quality at the chamber edge. The tSOR curve gives the theoretical minimum steam-to-oil ratio if the steam’s latent heat was ideally transferred to the oil sand with produced energy as given by Eq. (4) which implies that average steam-to-oil ratios below this value are not possible unless some other energy or material vector such as solvent reduces the viscosity of the bitumen. Given the difficulty of distributing steam uniformly within an oil sands reservoir due to its geological and

(a)

2 1.5 1 0.5



0

ð3Þ

where hL and kv are the liquid water phase enthalpy and steam latent heat, respectively. To express the steam as a cold water equivalent, vs is set equal to the specific volume of water at standard conditions (0.001 m3/kg). The density, heat capacities, liquid enthalpy, and latent heat of water depend on the temperature. The steam quality, xs, is that at the edge of the steam chamber. From typical steam quality gradients within the saturated steam chamber, at the edge of the chamber, the steam quality ranges between 0.1 and 0.6 [12]. Eq. (3) gives the ideal amount of steam, at temperature Ts, required to mobilize the oil to temperatureTs. That is, in other words, given the porosity and fluid saturations, the tSOR is the minimum achievable, to mobilize the oil to its flow viscosity at temperature Ts. In steam-based recovery processes, the produced fluids are typically about 40 °C below the injection temperature and typically about 90% on average of the water injected is produced and if oil is mobilized by steam heating, typically about 90% of the oil is produced from the reservoir zone where oil can flow (the low recovery factors of steam-based recovery processes arise from regions of the reservoir that are not contacted by steam). This produced energy

3 2.5

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6000

7000

Steam Pressure, kPa

(b)

1 0.9 0.8 0.7

tSOR, m3/m3

tSOR ¼

 S 1/ qo cpo þ w qw cpw þ qr cpr ðT s  T r Þ /o So

from the returned hot water is often used to pre-heat boiler feed water via heat exchange prior to its entry into the steam generator. This produced energy must be accounted for in the energy balance as follows:

tEOR, GJ/m3

708

0.6 0.5 0.4 0.3 0.2 0.1 0

0

1000

2000

3000

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5000

Steam Pressure, kPa Fig. 2. (a) Theoretical energy-to-oil ratio, tEOR, and (b) steam-to-oil ratio, tSOR, versus steam chamber pressure for SAGD.

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fluid compositional heterogeneity, the actual steam-to-oil ratio of a block of oil sand would be some value greater than the tSOR. Also, since the oil saturation and porosity varies in the reservoir, the tSOR will vary in the reservoir. The lower the porosity, the higher the tSOR since the rock volume increases and oil volume drops per unit bulk volume. Similarly, the lower the oil saturation, the higher the tSOR. Given the variability of bitumen composition in oil sands reservoirs, there will also be some small variability of the tSOR curve since each composition implies a different heat capacity but this will be a minor secondary factor. The tSOR is a spatially-distributed variable parameter within an oil sands reservoir. The theoretical steam-to-oil ratio tSOR, derived above, includes the heat losses to the formation water and mineral grains of the bulk reservoir rock volume which also holds the bitumen. There are also unavoidable heat losses associated with SAGD, including surface line and wellbore heat losses, losses of heat to formation water and sand grains, and losses to the overburden and understrata. This implies that the actual steam-to-oil ratio achieved in the field will always be larger than the tSOR. Another factor that leads to higher steam-to-oil ratio than the tSOR is the oil recovery factor which is substantially controlled by geological heterogeneity. Even if the oil in a volume of reservoir rock is heated so that it is mobile, some of it will not gravity drain and move from the reservoir rock due to high capillary entry pressures at fine grained lithology boundaries with, in extreme cases, local shales acting as baffles, barriers and underseals to oil and water flow. From Eq. (3), the thermal efficiency of the steam-based field operation is then given by:

gTH ¼

tSOR cSOR

ð5Þ

where the cSOR is the cumulative steam-to-oil ratio of the field operation. Since the cSOR from field operations does not include the energy recovered from produced fluids, this is not included in the tSOR calculation in Eq. (5). Once the steam requirements are known, as described by the tSOR, then the theoretical amount of carbon dioxide emitted per unit volume recovered bitumen, tCOR, can be determined by:

tCOR ¼

tSORqCWE ðhL þ xs km Þsg MW CO2 DHr

ð6Þ

where qCWE is the density of water (1000 kg/m3), the subscript ‘sg’ denotes steam conditions in the steam generator, MW CO2 , is the molecular mass of carbon dioxide, and DHr is the heat of reaction

for methane combustion (0.000802 GJ/mol). Fig. 3 shows the CO2 emitted per unit bitumen recovered, versus steam pressure under ideal heat transfer to the oil sand. The results show that the amount of carbon dioxide emitted per unit volume oil produced is large. For example, for a steam recovery process operating at about 3000 kPa, under ideal heating conditions, just over 0.2 tonnes of carbon dioxide are emitted per cubic meter of bitumen recovered for 0.6 steam quality provided to the edge of the chamber. In reality, boiler efficiencies will be less than 100%. 4. Field data analysis for actual SAGD operations Fig. 4 displays cumulative steam-to-oil ratios versus time for all major commercial SAGD operations in Alberta reported by project/ field. The data was obtained from public databases [13] and consists of over 200 SAGD well-pairs. The results show that although there has been a reduction in the cSOR with time, the cSOR is leveling off for most operations, at values above 2 m3/m3. Many of the operations display a decline of cSOR caused by oil production volumes increasing after the initial circulation stage of SAGD. However, a projection of these cSOR declines with time shows that the cSORs will still persist at levels above 2 m3/m3. The results show that the range of cSOR values narrows with time and that it appears to be converging to within the range of 2–4 m3/m3 cSOR, with the largest variability in cSOR typically occurring in the first four project years. Some of the project cSOR profiles increase suddenly and then decline. This is the result of additional SAGD well-pairs coming on production through a project. The variation in energy content of the steam used among the different operations is not assessed here as the steam will have different enthalpies at the different injection pressures of each SAGD project. Recalling the cSOR results of the ideal SAGD heating case shown in Fig. 2b with cSOR values below 1 m3/m3, the majority of the real field well-pair cSORs are many times higher than that of the ideal case. Figs. 5–10 display cSOR values versus average steam injection rate for all SAGD well-pairs in Alberta after 1, 2, . . ., 6 years of operation, respectively. As shown in Fig. 5, after 1 year of operation, the range of project cSOR is large, being from about 1.64 to over 40 m3/ m3 with an average value after year 1 equal to about 34.9 m3/m3. The large cSOR values are due to steam circulation that occurs for several months to warm the region between the injection and production wells prior to oil production. The data reveals that up to steam injection rates equal to about 400 m3/day, variability in cSORs is largest. Beyond about 400 m3/day, the variability appears reduced. The field data also reveals that in some cases it is possible

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cSOR, m3/m3

tCOR, kg CO2/m3

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0 0

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Steam Pressure, kPa

0

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24

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84

96 108 120 132 144

Time, Months Fig. 3. Theoretical emitted carbon dioxide-to-bitumen ratio, tCOR, at chamber edge for SAGD with a steam quality equal to 0.6 and 1 (ideal) versus steam chamber pressure. The efficiency of the steam generator is equal to 0.75.

Fig. 4. Cumulative steam-to-oil ratio, cSOR, versus time for all SAGD well-pairs operating in Alberta, Canada. Values over 16 m3/m3 are not plotted.

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50

10

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cSOR, m3/m3

cSOR, m3/m3

710

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Fig. 7. cSOR of SAGD well-pairs after 36 months of operation.

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0

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Steam Rate, CWE m3/day

50

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m3/day

Fig. 5. cSOR of SAGD well-pairs after 12 months of operation. Well-pairs with cSOR greater than 50 m3/m3 are not plotted.

cSOR, m3/m3

6

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Steam Rate, CWE m3/day

400

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Steam Rate, CWE m3/day

Fig. 6. cSOR of SAGD well-pairs after 24 months of operation.

Fig. 8. cSOR of SAGD well-pairs after 48 months of operation.

10 9 8 7

cSOR, m3/m3

to obtain relatively low cSORs across the entire range of steam injection rates. As displayed in Fig. 6, after two years of operation, the cSORs have dropped significantly with averages equal to about 6.05 m3/m3 and a range between 1.53 and 37.2 m3/m3. The cSOR is dropping now since the SAGD steam chambers are maturing and becoming more productive per unit volume of steam injected. More of the data is clustered at cSORs under 5 m3/m3. After three years of operation, as shown in Fig. 7, the cSORs have fallen further, with a range between 1.82 and 8.47 m3/m3 with an average equal to about 3.27 m3/m3. The minimum cSOR has risen since the second year which suggests that the low values observed in the second year may be a transient effect in many cases resulting from oil stimulated during start-up steaming. As shown in Fig. 8, after four years of operation, the cSORs now range from 1.65 to 7.83 m3/m3 with an average equal to about 3.12 m3/m3. Several of the well-pairs are below 2 m3/m3 and are demonstrating good performance. The variability of the data has reduced most likely because the steam chambers are now mature and well-established within the reservoir. After 5 years of operation, as plotted in Fig. 9, the average cSOR is equal to about 3.13 m3/m3 with range from 1.56 to 8.39 m3/m3. The average cSOR is starting to level off although the range is not narrowing. The variability is even further reduced and it appears that the lowest cSORs result at low steam injection rate. As shown in Fig. 10, after 6 years of operation, the range of cSOR is between 1.66 and 9.14 m3/m3 with average value equal to about 3.21 m3/m3. For those well-pairs under 2 m3/m3, their performance is good however the majority of well-pairs are

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Steam Rate, CWE m3/day Fig. 9. cSOR of SAGD well-pairs after 60 months of operation.

above 2.5 m3/m3. The data at 6 years is similar to that at 5 years suggesting that the performance of the well-pairs is leveling off. In general the best performing well pairs are from regions with better quality reservoir which have thick, highly oil saturated accumulations with few shale barriers and high vertical permeability throughout the reservoir. Operator experience is clearly an important factor but reservoir geology is king!

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9 8

cSOR, m3/m3

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Steam Rate, CWE m3/day Fig. 10. cSOR of SAGD well-pairs after 72 months of operation.

Fig. 11. Thermal efficiency, defined by Eq. (5), of field SAGD operations.

Fig. 11 displays the thermal efficiency, as calculated by Eq. (4), for all SAGD well-pairs plotted versus steam injection pressure. From a heat engine point of view, if the reservoir temperature is about 10 °C, for steam temperatures ranging from 180 to 250 °C, the thermal efficiency will remain limited to values less than 38% and 46%, respectively. The field SAGD data reveal that the majority of well-pairs are operating with a thermal efficiency less than 40%. For those few well-pairs operating above this limit, this is probably an artifact of interaction between proximal well pairs and implies that some well-pairs are not operating independently and thus one may appear highly efficient whereas its neighbor does not. Wellpairs operating between 30% and 40% efficiency are probably operating as thermally efficiently as can be expected, given the factors that detract from ideal SAGD behavior as listed above. Real SAGD is about 30% as efficient as ideal SAGD with many well pairs less efficient than this!

5. Energy analysis Eq. (2) gives the theoretical energy required to heat a volume of oil sand reservoir containing a unit volume of bitumen to raise the temperature from Tr to Ts. At a steam injection pressure equal to 2.5 MPa (the approximate average value used in many Alberta SAGD operations), the tSOR is equal to 0.71 m3/m3 and the amount of energy required is equal to about 2 GJ/m3 oil produced. At cSORs equal to 3.5 and 4.5 m3/m3, the amount of energy required is equal to about 9.5 and 12.2 GJ/m3 produced oil, respectively. These

values do not include the additional energy required for field operations e.g. electricity for water and oil pumping, water treatment and separation or fluid storage and pipelining/transportation. The heating value of bitumen is equal to about 43 GJ/m3 [14]. This implies that at tSOR = 0.7 m3/m3, the chemical energy output within the bitumen from combustion for a steam-based process is roughly about 21 times the energy supplied per unit volume bitumen produced under ideal heating conditions. The solid curve plotted in Fig. 12 displays a plot of cSOR versus the ratio of energy produced, in the form of chemical energy contained in the bitumen if combusted, to the energy injected in the form of steam taking into account 75% efficient steam generation. The results show that the larger the cSOR, the lower the net energy return and figure also shows that the decline in energy return is very rapid at lower cSOR values. The breakeven point, where the energy output equals the energy input in the process, is at cSOR values equal to around 11.5 m3/m3. This means that above this cSOR, the SAGD process is a net energy consumer and thus is not an energy generation process. The economic viability of the process under current fiscal regimes is less related to cSOR and the energy balance, as in situations where natural gas is used to generate steam the price differential between low gas and high oil prices means that economic return does not depend on an energy efficient recovery process. The majority of extracted bitumen is upgraded to synthetic crude oil (SCO), which in turn is refined into transportation fuels. On average, a further 6 GJ per m3 of bitumen processed is consumed to upgrade the bitumen to synthetic crude oil [15]. This value depends on whether a coking (about 5–6 GJ/m3) or ebullated bed (6–7 GJ/m3) upgrader configuration is used. SCO has on average a heating value similar to crude oil which is equal to about 39 GJ/m3 [14,15]. However, during upgrading, approximately 25% of the bitumen volume is lost [15,16]. This implies that the heating value content per unit volume bitumen recovered from the reservoir is equal to about 31 GJ/m3. For refining and conversion of SCO to transportation fuels (average heating value equal to about 46 GJ/m3), the average energy intensity for refining SCO is equal to about 2.7 GJ/m3 SCO [15]. Transportation fuels, mainly consisting of gasoline, diesel, and jet fuel, have an average heating value equal to about 46 GJ/m3 [15]. Given that typical volume losses for refining crude oil are typically between 5% and 8% (we assume 5% here), on a bitumen volumetric basis, the heating value of the transportation fuel is equal to about 35 GJ/m3 bitumen recovered from the reservoir. Also plotted in Fig. 12 (dashed curve) is the net energy return for in situ recovery with both upgrading and refining taken into account. The results reveal that the overall

24 22

Chemical Energy Out / Steam Energy In, GJ/GJ

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20 18 16 14 12 Energy Return for In Situ Recovery Only

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Energy Return for In Situ Recovery Plus Upgrading Plus Refining

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7 8 9 10 11 12 13 14 15 16 17 cSOR, m3/m3

Fig. 12. Energy out in form of chemical energy of product per unit energy generated in the form of injected steam for steam-based recovery and case taking upgrading and refining into account.

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net energy breakeven point is now equal to a production cSOR of about 6.5 m3/m3. Based on the cSOR field data displayed in Fig. 4, many operations exceed this value and thus are not net energy generation processes yet may be ‘‘economic’’! With disconnected price markets for natural gas and bitumen, it is possible for bitumen recovery under these conditions to be economically viable today even though it makes no sense to pursue such an energy inefficient process when cSOR values are high. 6. Carbon dioxide emissions analysis

CO2 Per Volume Bitumen Produced, kg/m 3

Given the amount of steam generated, by using the enthalpy of steam and combustion stoichiometry, the amount of carbon dioxide generated can be determined. As shown in Fig. 3, for steam injection at 2100 kPa, with 60% steam delivery to the chamber edge, the tSOR is equal to about 0.7 m3/m3 and consequently about 190 kg of carbon dioxide is generated per m3 bitumen produced. This assumes that the steam generator has an efficiency of 75%. Fig. 13 displays the CO2 intensity, measured in kg CO2 generated per unit volume bitumen produced versus the cSOR. At a cSOR equal to 3.5 m3/m3, roughly 716 kg of carbon dioxide is released to the atmosphere per m3 bitumen generated. On a carbon dioxide per unit energy basis, at a tSOR equal to about 0.7 m3/m3, approximately 2.2 m3 of carbon dioxide is generated per GJ of energy in the form of chemical energy contained in the bitumen. At a cSOR equal to 3.5 m3/m3, about 9.1 m3 of carbon dioxide is emitted per GJ chemical energy contained in the produced bitumen. Fig. 14 displays the mass of CO2 emitted per unit energy generated (in the form of chemical energy in the bitumen) versus the cSOR of the bitumen recovery process for the case with no cogeneration of electricity from waste heat. The results show that the CO2 emitted grows significantly as the cSOR increases. If the CO2 generated from bitumen upgrading to SCO and SCO refining to transportation fuels is taken into account, the overall net production of CO2 per unit energy realized in the transportation fuel is raised dramatically. Here, for bitumen upgrading to SCO, the amount of CO2 equivalent emitted per m3 of bitumen processed ranges from about 233 kgCO2/m3 for a coking configuration to 399 kgCO2/m3 for an ebullated bed configuration [15]. For this study, the average value is used (316 kgCO2/m3 bitumen processed). For refining of SCO, the amount of CO2 released is taken to be 360 kgCO2/m3 bitumen recovered from the reservoir and the amount generated for bitumen transportation is taken to be 20 kgCO2/m3 bitumen recovered [15].

5000 4500 4000 3500 3000 2500 2000 1500 1000 500 0 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

cSOR, m3/m3 Fig. 13. Mass of emitted carbon dioxide-to-oil ratio versus cSOR (100% steam quality generated with efficiency of the steam generator equal to 0.75) from steambased recovery process operating at 2100 kPa.

CO2 Per Net Energy Produced, g/MJ

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cSOR, m3/m3 Fig. 14. CO2 emitted per unit net energy generated (100% steam quality generated with efficiency of the steam generator equal to 0.75) from steam-based recovery process operating at 2100 kPa.

7. Conclusions A thermodynamic limit on the thermal efficiency for steambased bitumen recovery processes has been developed in the form of a theoretical steam-to-oil ratio(tSOR). The analysis shows that although some SAGD operations are achieving good steam-to-oil ratios, many are not achieving thermally efficient operation, with cumulative steam-to-oil ratios many times the theoretical value. This results from combinations of geological realities, operator decisions and the limitations of the SAGD process. The results demonstrate that on an energy and carbon dioxide emissions basis, bitumen or bitumen-based energy recovery processes need to step well beyond the capabilities of current steam-based bitumen recovery processes, such as SAGD, if practical and sustainable energy balance and emissions scenarios are to be achieved from the in situ oil sands operations. Acknowledgements Financial support was provided by the Natural Sciences and Engineering Research Council of Canada (NSERC), Carbon Management Canada and the Canada Research Chairs program. References [1] Roadifer RE. Size distributions of the world’s largest known oil and tar accumulations. In: Meyer RF, editor. Exploration for heavy crude oil and natural bitumen: American Association of Petroleum Geologists Studies in Geology, vol. 25. Tulsa: American Association of Petroleum Geologists; 1987. p. 3–23. [2] Head IM, Jones DM, Larter SR. Biological activity in the deep subsurface and the origin of heavy oil. Nature 2003;426:344–52. [3] AED (Alberta Economic Development). Oil Sands Industry Update. Alberta Department of Energy; 2008. . [4] CIA (Central Intelligence Agency). The World Factbook; 2009. Available at CIA [5] Larter SR, Adams JJ, Gates ID, Bennett B, Huang H. The origin, prediction and impact of oil viscosity heterogeneity on the production characteristics of tar sand and heavy oil reservoirs. J Can Petrol Technol 2008;47(1):52–61. [6] Mehrotra AK, Svrcek WY. Viscosity of compressed Athabasca bitumen. Can J Chem Eng 1986;64(5):844–7. [7] Butler RM. Thermal recovery of oil and bitumen. Calgary (Alberta, Canada): GravDrain Inc.; 1997. [8] Gates ID, Adams JJ, Larter SR. The impact of oil viscosity heterogeneity on the production characteristics of tar sand and heavy oil reservoirs. Part II: intelligent, geotailored recovery processes in compositionally graded reservoirs. J Can Petrol Technol 2008;47(9):40–9. [9] Ranger MJ, Gingras MK. Geology of the Athabasca oil sands – field guide and overview. Alberta (Canada): Department of Earth and Atmospheric Science, University of Alberta; 2006. 119 p.

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