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Effect of Steam-Assisted Gravity Drainage (SAGD) Produced Water Properties on Oil/Water Transient Interfacial Tension Maryam Razi, Shayandev Sinha, Prashant R. Waghmare, Siddhartha Das, and Thomas Thundat Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.6b01686 • Publication Date (Web): 19 Oct 2016 Downloaded from http://pubs.acs.org on October 28, 2016

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Effect of Steam-Assisted Gravity Drainage (SAGD) Produced Water Properties on Oil/Water Transient Interfacial Tension Maryam Razi a, Shayandev Sinha b, Prashant R. Waghmare c, Siddhartha Das b* and Thomas Thundat a* a Department of Chemical and Materials Engineering, University of Alberta, Edmonton, AB, T6G 1H9, Canada b Department of Mechanical Engineering, University of Maryland, College Park, MD 20742, USA c Department of Mechanical Engineering, University of Alberta, Edmonton, AB, T6G 1H9, Canada KEYWORDS: Steam assisted gravity drainage (SAGD), Oil/Water separation, Interfacial tension, humic acids (HAs), WardTordai, Langmuir isotherm

ABSTRACT: Steam assisted gravity drainage (SAGD) produced water (PW) consists of oil, solids, clays, petroleum-derived compounds and other dissolved organic matters (DOMs) which make the SAGD PW highly stable and therefore very hard to treat. Developing a correlation between SAGD PW properties and dynamics of interfacial tension between dispersed and continuous phases is important to understand the coalescence of dispersed phase droplets, which in turn leads to demulsifications of these difficult emulsions produced during SAGD operations. This work sheds light on the interfacial activity of SAGD PW endogenous surfactants, humic acids (HAs), as well as the interaction dynamics of these compounds with naphtha-diluted Alberta oil sand bitumen (AOSB) present in a model SAGD PW. We quantify the dynamics of the interfacial tension of a naphtha-diluted AOSB oil drop in pure water as well SAGD synthetic brine. Our results pinpoint the distinctive influence of the percentage weight composition of the naphtha-diluted AOSB and the surrounding model SAGD PW pH on the dynamics of this oil-water interfacial tension. We anticipate that the results of this study will bring about a better understanding of interfacial film properties leading to a predictable coalescence mechanism in SAGD PW emulsions facilitating the design of next generation SAGD deoiling unit operations.

process that has found extensive recent applications owing to advantages such as significantly greater per well production rates, greater reservoir recoveries, reduced water treating 3 costs, and dramatic reductions in SOR (steam/oil ratio). A typical characteristic of the SAGD produced water (PW) is the presence of complex emulsions where the dispersed phase is heavy oil with high viscosity (100−10000 mPa.s at room temperature) present in bulk water. Such oil-in-water emulsions are generally very difficult to treat due to high TDS (Total Dissolved Solids), TSS (Total Suspended Solids) and high oil content. In order to treat such emulsions specific to the SAGD process or other oil recovery processes, there have been extensive efforts employing chemical, electrical, thermal, ultrasonic and biological demulsification techniques 4 or a combination of them. For example, Razi et al. evaluated the effect of a different formulation of demulsifiers on the 5 efficiency of chemical demulsification of heavy crude oil. On the other hand, Petrowski et al. examined the stability of an 6 emulsion using microwave irradiation , while Gao used Gibbs adsorption isotherm to monitor the interfacial tension characteristics of the interfacial film of water-in-diluted bi7 tumen emulsion droplets. Further, Poteau et al. investigated the effect of pH on stability and dynamic properties of asphaltenes and other amphiphilic molecules at the oil/water 8 interface and Angle et al., monitored the effect of surface

INTRODUCTION Whether it is bitumen films in emulsions occurring in oil sands extractions techniques or bitumen droplets present in oil sands process-affected water (OSPW), the interfacial properties of oil/water system and the ability to treat emulsions play vital roles in designing bitumen recovery tech1 niques which promote environmental sustainability. In an oil production setting, these emulsions are typically very stable due to the stabilizing interactions (e.g., pickering emulsion effects or electrostatic stabilization) in the presence of highly surface-active and localized (at the oil-water interface) endogenous chemical moieties such as saturates, asphaltenes, resins, aromatics and also solids, clays, naphthenic acids and waxes. The occurrence of these stable emulsions induces challenges associated with oil transportation or catalytic poisoning, enforcing a constant need to find more efficient and sustainable methods and techniques to handle and 2 break such emulsions. Understanding the handling of emulsions is central for the successful operations of most of the Enhanced Oil Recovery (EOR) processes. Steam Assisted Gravity Drainage (SAGD), utilized to produce bitumen and heavy crude oil, is one such

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16-17

activity of simulated tailing ponds natural surfactants on dynamic interfacial tension of toluene-diluted bitumen in 9 5-9 simulated tailings water. These studies primarily focus on general behaviors of oil-water interfacial tensions in context of EOR systems. Studies more specific in context of SAGD 10 11 are those by Nguyen et al. and Thakurta et al. Nguyen et al. examined the effect of diluents on interfacial rheology in SAGD emulsions and related that to its emulsion stability, while Thakurta et al. characterized the dissolved organic matter (DOM) in SAGD boiler blow-down (BBD) water.

tively. CHNS elemental analysis of the bitumen sample, which has been done using Flash 2000 elemental analyzer (Thermo Fisher), is also provided in Table 1.

Table 1. CHNS analysis of AOSB (Alberta Oil Sands Bitumen) Elemental Analysis Results of AOSB sample

Carbon

Hydrogen

Average 83.22608795 10.16238556

In addition to these understandings on crude oil-water or bitumen-water interfacial tensions, understanding of interaction of humic acids (HAs), which are endogenous surface active components naturally present in SAGD PW, with bitumen is also vitally important for optimizing the performance of the SAGD process. While there has been substantial research on quantifying different properties of humic 12-14 acids as surfactants , relatively less is known on the humicacid-bitumen interactions in the functioning of the SAGD process.

Error (SD)

Nitrogen

Sulfur

0.552172315 5.308692646

0.586248542 0.467123537 0.015116601

0.13411086

15

SARA analysis of AOSB sample

There is a significant need for understanding the interfacial interactions of diluted bitumen with the endogenous surface -active components present in the SAGD PW. These interactions are the basis for the bitumen film stability which is a predominant factor in SAGD produced water emulsions stability. These natural surfactants which mostly include naphthenic acid (NAs) and humic acid (HA) compounds have the capability to modify the interfacial properties of oil/water emulsions encountered in SAGD operations. Adsorption mechanism of these surface active compounds at the oil/water interface in SAGD operations is not well9 understood. There are only a few publications which address the interaction effects of endogenous surfactants with diluted bitumen in tailing ponds and aquifers, whereas the effects of SAGD PW characteristics on dynamic interfacial properties of diluted bitumen drops affected by natural surfactants have not yet been reported. Therefore, in the first section of this study, we present the dynamic interfacial tension effects, and in the second section of this work, we examine the effects of interaction of natural surfactants present in naphtha-diluted bitumen and endogenous surfactants in a model SAGD PW on interfacial properties of oil/water. In this regard, it is anticipated that the results of this study bring about a better understanding of interfacial film properties which lead to a predictable coalescence mechanism in SAGD PW emulsion separation studies and facilitate the design of next generation SAGD de-oiling unit operations.

Saturates, wt%

17.30

Aromatics, wt%

39.70

Resins, wt%

25.70

Asphaltenes, wt%

17.30 15

Properties of AOSB sample o

Density, g/cc at 15.6 C

1.011

API gravity

8.46 o

Viscosity at 40 C, cP o

Viscosity at 60 C, cP

26900 3070

Methods. Industrial treated Naphtha (SAN # 7764) provided by Syncrude Canada Ltd., has been used as diluent. Naphthadiluted bitumen (or dilbit) solutions with different dilution ratios were prepared using the following method: Bitumen sample was weighed and added to graduated bottles containing pre-weighed naphtha, followed by agitating the prepared solution using a digital vortex mixer (Fisher Scientific) with a mixing speed of 3000 rpm for the duration of 15 minutes. Different dilution ratios of bitumen ranging from 20 wt% to 60 wt% were eventually prepared using this method. The water used in these experiments was milli-Q water (pH=5.73) obtained from lab-scale Millipore purification process. The SAGD synthetic brine used and referred to throughout this paper was prepared from Fisher Scientific ACS-grade CaCl2, NaCl, MgCl2, Na2CO3, KCl, FeSO4, NaHCO3 salts in 18 MΩ cm milli-Q water from our lab-scale Millipore purification process. The amount of each compound present in SAGD synthetic brine is 45, 1021, 24, 100, 50, 10 and 220 (mg/L), respectively. This SAGD synthetic brine exhibits the same pH at ambient conditions (pH 9.3), density (0.998 g/mL), ionic –4 strength (4.29 × 10 mol/mol) as the actual SAGD produced water.

EXPERIMENTAL SECTION Materials. Alberta oil sand bitumen (AOSB) provided by Syncrude Canada Ltd. has been used as received. The results of the SARA (Saturates, aromatics, resins and asphaltenes) 15 analysis of the sample are provided in Table 1. TAN (total acid number, obtained by ASTM D664 method), sulphur content and ash content of the bitumen sample are known to be 3.5 mg of KOH/g of bitumen, 5.3, and 0.59 wt %, respec-

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Surfactant solutions for interfacial studies were made by dissolving a given mass of humic acids (HAs) in this buffer solution. As needed, the pH of different solutions was adjusted by adding pre-prepared ACS-grade Fisher Scientific 1.0 M NaOH or 1.0 M HCl. The pH of all aqueous liquids was measured using a Mettler Toledo Benchtop pH-meter. A threepoint calibration was carried out using standardized Fisher Scientific solutions for pH 4, 7, and 10.

Fig.1. (a) Steelink model of the humic acid monomer , (b) a portion of proposed "type" structure of humic acid (repro19 duced from , courtesy of Ray von Wandruszka). Dynamic Interfacial Tension: Measurement and Analysis. Adsorption analysis of endogenous surfactants present in SAGD PW at O/W interface has been carried out using different runs of dynamic interfacial tension measurement. These measurements were performed using a pendant drop tensiometer (KRÜSS GmbH Drop Shape Analyzer, DSA100) which employs time-dependent drop shape analysis. A drop shape analysis system can be used to determine the dynamic interfacial tension between two liquids which is quantified from an estimation of the dynamic (or time-varying) shape of the pendant drop.

SAGD PW samples, WLS (warm lime softening) inlet and BBD (boiler blowdown) water have been obtained from Suncor Energy. Commercial humic acid (HA, Sigma-Aldrich, technical grade) was used as model natural surfactants present in SAGD produced water. The published chemical structures of these surfactants, the Steelink model of the humic acid monomer and a proposed typical structure of these surfactants are depicted in Figure 1.a and Figure 1.b, respectively. Two sets of experiments have been conducted; in the first set, dynamic and equilibrium interfacial tension of dilbit samples with different dilution ratios has been studied in pure water. No surfactant was present in the buffer solution for this run. Temperature and pH of the aqueous phase remained constant in all of the experiments. In the second runs of experiments, dynamic interfacial tension of dilbit in SAGD synthetic brine solutions with different pH values has been monitored.

The pendant drop shape is primarily determined by the interplay of surface tension and gravitational forces, with the former seeking to minimize the drop surface area by enforcing it into a spherical-cap shape while the latter deforming and elongating the drop from its spherical-cap shape. The drop shape analysis is based on the Young-Laplace equation that relates the pressure difference (Laplace pressure) across a curved interface to the principal radii of curvature 𝑅! and 20-32 the drop-surrounding liquid interfacial tension 𝛾: 𝛾

(a)

! !!

+

!

= ∆𝑃 ≡ ∆𝑃! − ∆𝜌𝑔𝑧 (1)

!!

where 𝑅! and 𝑅! are the principal radii of curvature, ∆𝑃 ≡ 𝑃!" − 𝑃!"# is the Laplace pressure across the interface, z is the vertical height from the drop apex, and ∆𝜌 = 𝜌! − 𝜌 is the density difference of two medium (see Fig. 2). Dropphase and continuous phase densities are denoted as 𝜌! and 𝜌, respectively. As shown in eq.(1), this pressure gradient ∆𝑃 can be written in terms of a reference pressure ∆𝑃! (pressure at 𝑧 = 0) and a hydrostatic pressure of ∆𝜌𝑔𝑧. To obtain principal radii of curvature for a pendant drop, one can consider drop radius 𝑅! at the apex, i.e., 𝑅! = 𝑅! = 𝑅! . Accordingly, for each point above this apex, 𝑅! = 𝑥/𝑠𝑖𝑛 𝜑 (see Fig. 2). Consequently, eq. (1) reduces to ! !!

(b)

+

!"# ! !

=

! !

∓

∆𝜌𝑔𝑧 !

(2)

Using axisymmetry, eq. (1) can be expressed in terms of the cylindrical coordinates 𝑟 , 𝑧 and the tangent angle 𝜑 (see Fig. 2). In this case, the Young–Laplace equation can be obtained as a coupled set of three first-order differential equations with three boundary values in terms of the arc length 𝑠 measured from the drop apex, which is solvable by numerical procedures and results in: !" !" !" !" !" !"

=−

!"# ! !

!

∆!"#

!

!

+ ∓

(3a)

= cos 𝜑 (3b) = sin 𝜑 (3c)

0 = 𝑥 𝑠 = 0 = 𝑧 𝑠 = 0 = 𝜑 𝑠 = 0 (3d)

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The dilbit drop volume was kept constant for the total aging time of the droplet. Each experiment has been repeated five times to ensure the reproducibility of the interfacial tension measurements. Temperature for all the experiments was kept constant at 23 °C.

(b)

RESULTS AND DISCUSSION In Fig. 4, we show the dynamic interfacial tension (IFT) of dilbit in pure water (pH=5.74), for different dilution ratios ranging from 20 to 60 wt%, plotted as a function of time (see Fig. 4). We observe that increasing the dilution ratio causes an increase in the IFT at t=0. By definition, x wt% of a dilbit drop implies (100-x) % of bitumen in x% of naphtha solvent. Consequently, smaller wt% of dilbit drop implies a larger amount of bitumen in a smaller amount of the naphtha solvent. Accordingly, such smaller wt% of the dilbit drop will also imply larger concentration of asphaltene within the drop. This can explain smaller value of the IFT at t=0 for smaller wt% of the dilbit drop, given that larger asphaltene concentration in a dilbit drop has been known to cause a 33 larger reduction in the IFT. The central finding expressed in Fig. 4 is the temporal variation of the IFT for different wt% of the dilbit drop. In fact, for 20 wt% of dilbit drop in pure water, we observe that the IFT curve reaches near-equilibrium 33 values, which is consistent with the finding of Zakar et al. We hypothesize that this dynamic lowering of the surface tension of the dilbit drop is caused by the gradual adsorption of the asphaltene present within the dilbit drop on the oilwater interface. We employ a combination of the WardTordai surface adsorption model and the Langmuir isotherm to theoretically explain this time-dependent asphaltene adsorption from the bulk phase (within the dilbit drop) to the oil-water interface and the corresponding time-dependent 34 lowering of the IFT. Following Mysels , we can express the Ward-Tordai equation as:

Fig.2. (a) a schematic of pendant drop hanging from a needle. (b) a dilbit drop image which is captured by CCD camera in the experiments. Drop shape is recorded by the camera and the fitting of the numerically computed theoretical drop shape to this recorded image eventually yields the interfacial tension between the two phases. Different volumes of dilbit droplets (ranging from 15 μL-40 μL) depending on the dilution ratio, were generated at the tip of an inverted needle (20-gauge diameter) immersed in a cuvette filled with water. The needle was connected to a syringe (500 μL, Hamilton Co., USA). The syringe was mounted in a syringe holder positioned above a cuvette containing 25 mL of the aqueous phase. The needle was immersed in the cuvette aqueous phase by adjusting the syringe position. To obtain a clear visualization on the computer screen, the alignment adjustments were made in such a way that the drops were in line with the tensiometer charge-coupled de20-32 vice (CCD) camera. A schematic diagram of the method is depicted in Fig. 3.

()

Γ t =2

{

} {

}

t t D D c t − ∫ c (τ ) d t − τ + c t − c (τ ) d (t − τ ) , 0 π b r b ∫0

(4)

where D is the average diffusivity of asphaltene migrating from the dilbit drop bulk phase to the oil-water interface, r is the drop radius, Γ(t) is the surface concentration of asphaltene adsorbed at the oil-water interface, and cb is the bulk concentration of asphaltene within the oil drop and c(τ) is the sub-surface asphaltene concentration. Also “d” in eq. (4) is the differential, i.e., “d” of dx. Therefore, in eq. (4), we have the dx1 (where x1 = t − τ ) and dx2 (where x2 = t − τ ). Langmuir isotherm provides the equations of state (EOS) relating this sub-surface concentration with the surface concentration as well as the surface concentration with the surface pressure (i.e., the decrease of the surface tension from the bulk value). Therefore:

Fig.3. Schematic diagram of the method used for adsorption analysis of endogenous surfactants present in SAGD produced water. Dynamic interfacial tension 𝛾!(!) measurements were initiated immediately as the droplet generated to record images at the rate of 1 frame/s for the whole duration of the experiment. The recordings continued until the dilbit drop detached from the needle.

c=

1 Γ , KL Γ∞ − Γ

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(5)

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⎛ Γ ⎞ Π = γ 0 − γ = −nRT Γ ∞ ln ⎜ 1− ⎟, ⎝ Γ∞ ⎠

Energy & Fuels (6)

where KL is a constant, Γ∞ is the saturation surface excess, R is the universal gas constant, T is the absolute temperature, n is an integer (takes a value of 1 for non-ionic surfactants or 2 for ionic surfactants), Π is the surface pressure, and γ0 and γ are the bulk value (or value at t=0) and the dynamic value of the surface tension of the oil-water interface. In Fig. 5, we compare the result from this theoretical model with the experiments for two chosen values of dilbit weight percentage (see the caption of Fig. 5 for the parameters values). We got reasonably acceptable match for the experimental trend using our theoretical predictions. Of course, our theoretical predictions yield similar acceptable match for experimental results corresponding to other dilbit weight percentage; we intentionally do not show them here for the sake of brevity. Fig.5. Comparison of the Oil/Water dynamic interfacial tensions (IFT) obtained from the theoretical model, i.e., eqs. (46) (shown by continuous lines) with the experimental results (shown by markers) for two values (20% and 30%) of dilbit weight percentage. Parameters used in the theoretical model −10 2 −1 −6 −2 3 -1 are D=3.5×10 m s , Γ∞ =4 ×10 mol m , KL=1838 m mol and r=0.001 m at T=298 K. The bulk concentrations are, cb,30% −4 −4 −3 =7×10 and cb,20% =8×10 mol m . Fig. 6 depicts IFT versus t for dilbit/SAGD synthetic brine interface at different pH values of the aqueous phase for 40 wt% dilbit ratio. As seen in this figure (Fig. 6), in pH values of 7-9, the dynamic interfacial tension of naphtha-diluted bitumen/SAGD synthetic brine is decreasing. However, towards the basic spectrum of the pH values (pH=9), which is relevant for SAGD operations (pH 9 to 11), the instability of the dilbit drop is observed. The fluctuations in dynamic interfacial tension in this case can be related to the frequent adsorption and desorption of indigenous surfactants present in the oil phase. Observed increase in interfacial activity of surfactants at higher pH values, responsible for such frequent adsorption-desorption dynamics, is consistent with 9 the work reported by Angle et al. The initial IFT (i.e., IFT value at t=0) is almost the same for all of pH values. The detachment time of dilbit drop from the needle is different for different pH values. As seen in this figure as pH goes toward basic pH values, the detachment time of dilbit drop from the needle reduces from 1800 sec to 100 sec. This can be related to the increase in the rate of reaction of surfactants at the neck of droplet at higher pH values.

Fig.4. Variations in Oil/Water dynamic interfacial tension: Effect of different dilution ratios of naphtha-diluted bitumen (dilbit) on Oil/Water dynamic interfacial tension (water in these sets of experiment is milli-Q water and pH of the aqueous solution has been measured as 5.74). Please see the Supplementary Material (Figs. S1-S6), where the plots for each weight percentage of dibit/pure-water have been provided with appropriate error bars.

In Fig. 7, we depict the variation of the IFT of the dilbitSAGD (synthetic brine) interface for pH values 9.5 and 10 for 40 wt% dilbit ratio. Most remarkably, we find that the IFT increases with time. While at pH=9.5, the dynamic IFT does decrease with time for the first 415 sec (see inset of Fig. 5), this temporal enhancement of the IFT is prevalent for the rest of the cases (for larger time for pH=9.5 and for all time for pH=10). It is expected that larger the increase in pH val-

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ues, greater will be the interfacial activity of the surfactants. The fact that by increasing pH from 7 to 9 there is a reduction in IFT (see Fig.6) is due to the increased saponification of indigenous surfactants present in bitumen (asphaltenes) at basic pH values which causes the enhanced interfacial activity of these surfactants and a lower IFT is expected. It has 35-36 been previously shown by earlier publications that indigenous surfactants present in bitumen reorganized as nanoclusters at these bitumen concentrations. It can be concluded that at higher pH values, transport, rearrangement, and reordering of surfactants occur over larger timescales. It is also concluded that at higher pH values, the complexity of nature of dilbit/SAGD brine interfaces is much higher, paving the way for such highly non-intuitive IFT versus t variation. It is due to the fact that as pH of SAGD synthetic brine increases, the consumption of free OH ions in SAGD brine is + decreasing and thus there is a decrease in the H ions in solution. This is the same as the response associated with the saponification of carboxylic groups in higher pH values of SAGD brine solution. The interaction of indigenous surfactants present in bitumen with HAs present in SAGD synthetic brine at dilbit/SAGD brine interface is evident from the reductions in IFTs which is an indicator of elevated interfacial activity of surfactants. These results are in accordance 9 with the work done by Angle et al. in which they concluded that IFTs of heavy crude oils interfaces are less at high pH values in comparison with lower pH values.

Fig.7. IFT versus t for 40 wt% naphtha-diluted bitumen/SAGD synthetic brine at increasing basic pH values (9.5 and 10) of SAGD synthetic brine. Please see the Supplementary Material (Fig. S8, S9), where the plots for each pH have been provided with appropriate error bars.

CONCLUSIONS In this study the effect of bitumen dilution ratios and pH of model SAGD produced water on dynamic interfacial tension of naphtha-diluted bitumen/SAGD synthetic brine interface has been monitored. A theory based on the combination of Ward-Tordai model (for surface concentration) and Langmuir isotherm has been applied to explain the experimental trends. Dynamic IFT of naphtha-diluted bitumen in SAGD synthetic brine solutions with different pH values has been monitored and it has been concluded that as pH goes towards basic pH which is the case for SAGD operations (pH range 9-11), there is no exponential reduction in interfacial tension between O/W interface. To the best of our knowledge, it is the first time that such a study has been done for SAGD PW. The results of this study can usher in a better quantification of interfacial film properties, thereby paving the way for a controllable de-emulsification mechanism for emulsions in SAGD PW, which in turn will be vital for designing next generation SAGD de-oiling unit operations.

Fig.6. IFT versus t for 40 wt% naphtha-diluted bitumen/SAGD synthetic brine at different pH values (7.1, 8.0 and 9.0) of SAGD synthetic brine. Please see the Supplementary Material (Fig. S7), where the plots for each pH have been provided with appropriate error bars.

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AUTHOR INFORMATION Corresponding Author * Siddhartha Das E-mail: [email protected]. Fax: +1 301.314.9477 Tel: +1 301.405.6633 *Thomas Thundat E-mail: [email protected]. Fax: +1 780.492.2881. Tel: +1 780.492.2068.

Author Contributions M.R. conceived the experiment. M.R. and P.W. designed the experiments. M.R. conducted the experiments and collected data. M.R., P.W. and T.T. analyzed the data. S.S. and S. D. performed the theoretical modeling. P.W., S.D. and T.T. played an advisory role. All authors contributed to the writing of the manuscript. All authors have given approval to the final version of the manuscript.

Notes

The authors declare no competing financial interest.



ACKNOWLEDGMENTS This work was supported by Canada Excellence Research Chairs (CERC) Program and Natural Sciences and Engineering Research Council of Canada (NSERC). The authors would like to acknowledge IOSI (Institute for Oil Sands Innovation) at University of Alberta for the elemental analysis of bitumen sample. The authors also would like to thank the support from Advanced Water Research Lab (AWRL) University of Alberta specifically Mohtada Sadrzadeh, for providing SAGD produced water samples. Finally, Shayandev acknowledges Laboratory of Physical Sciences (LPS) for partly supporting his graduate studies.

ABBREVIATIONS SAGD, steam assisted gravity drainage; PW, produced water; DOMs, dissolved organic matters; HAs, humic acids; AOSB, Alberta oil sand bitumen; OSPW, oil sands process-affected water; EOR, Enhanced Oil Recovery; SOR, steam/oil ratio; TDS, Total Dissolved Solids; TSS, Total Suspended Solids; TLF, thin liquid film; BBD, boiler blow-down; NAs, naphthenic acids; SARA, Saturates- aromatics- resins and asphaltenes; TAN, total acid number; ASTM, American Society for Testing and Materials; CHNS, Carbon Hydrogen Nitrogen Sulfur; WLS, warm lime softening.

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