Properties and Performance of Newly Developed Demulsifiers in Oil

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Study the properties and performance of newly developed demulsifiers in oil sands froth treatment Ishpinder Kaur Kailey Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.6b01940 • Publication Date (Web): 25 Sep 2016 Downloaded from http://pubs.acs.org on September 28, 2016

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Study the properties and performance of newly developed demulsifiers in oil sands froth treatment

Ishpinder Kailey* th

*Baker Hughes Incorporated, 7020 45 Street, Leduc, Alberta, Canada T9E 7E7

ABSTRACT Chemical demulsification with EO-PO block copolymers is widely employed to treat bitumen froth in oil sands operations. In this effort, the relation between demulsifier properties and demulsification efficiency was explored using three EO-PO block copolymer demulsifiers DMO A, DMO B and DMO C. The EO-PO block copolymers were categorized by their relative solubility number (RSN) and dynamic interfacial tension (IFT). The dewatering and solids removal efficiencies of EO-PO block copolymer demulsifiers were in the order of DMO C > DMO B > DMO A from 0 to 50 ppm dosage at 30 min settling time. DMO C also showed superior performance with lower hydrocarbon losses to the underflow as compared to demulsifiers DMO A and DMO B at all the dosages studied. The direct correlation was observed between the RSN values and dewatering/solids removal performance while the IFT does not correlate to the dewatering/solids removal efficacy of the EO-PO block copolymer demulsifiers. The influence of operating conditions such as pH and mixing were also studied on dilbit dewatering, solids removal efficiency and naphtha/bitumen losses to underflow.

The decrease in pH by addition of acidic chemistry in presence of

demulsifier was not assisting to enhance demulsifier performance. The results also showed that over or under mixing are pushing more hydrocarbons to the underflow due to existence of unresolved bitumen emulsion.

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1. INTRODUCTION Clark hot water method is employed to extract bitumen from mined oil sands [1-3]. The liberated bitumen under aeration rises to the top of the flotation vessel as bitumen froth, which usually comprises of 60 wt% bitumen, 30 wt% water, and 10 wt% solids [4-5]. Further reduction of water and solids is promoted by decreasing the bitumen froth viscosity with aromatic or aliphatic hydrocarbon solvents. In the paraffinic process, a ratio of diluent to bitumen (D/B) above two is preferred and the dilbit stream consist of an overall water and solids contents below 0.1 wt% [6-8]. Alternatively in the naphtha based froth treatment processes at D/B of 0.6 to 0.75, the dilbit usually comprises around 2 to 5 % and 0.3 to 1 % of water and solids, respectively by weight [9]. The residual water in diluted bitumen product exists as stable water-in-oil (W/O) emulsion, while the residual solids occur as dispersed clay particles. These emulsions are highly stable due to occurrence of interfacial active organic components such as asphaltenes, resins, naphthenic acids, waxes and clays [10-14]. These indigenous substances may possibly gather at the oil/water interface and hinders the water droplets coalescence [15-18]. To meet transportation and refinery processes specifications, the further elimination of water and solids from the dilbit product is desired [19]. Few researchers reported that asphaltenes and resins stabilize the emulsions by forming interfacial films at the oil/water interfaces that inhibits coalescence of water droplets [20-23]. Both asphaltenes and resins are amphiphilic in nature. Asphaltenes are defined as the crude oil fraction soluble in toluene but insoluble in pentane, hexane and heptane. On the other hand resins are insoluble in methanol but soluble in both aromatic and aliphatic solvents. Some studies pointed out that only a minute fraction of asphaltenes participates in development of interfacial films at oil/water interface and hence stability of emulsion [24-28]. Masliyah et al. identified that asphaltenes fraction stabilizing emulsions was more polar with higher oxygen to carbon ratio and a lower hydrogen to carbon ratio compared with fraction solubilized in oil phase [29]. 2|Page ACS Paragon Plus Environment

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Chemical demulsification is the most common, cost-effective and technically feasible approach to resolve water-in-oil emulsions [30-34]. The demulsification efficiency of demulsifier is mainly controlled by its hydrophilic-hydrophobic ability and capability to destroy the interfacial film [35]. Chemical demulsifiers should exhibit superior interfacial activity compared to the indigenous species that stabilizing the water-in-oil emulsions. But the mechanism of chemical demulsification remains to be established [36]. Several publications revealed that the purpose of a demulsifier is to alter the interfacial rheology and disrupt the interfacial films [37-39]. Daniel David et al. proposed demulsification mechanism, according to which demulsifiers interrupt the asphaltene aggregates network at the oil/water interface and hence allow coalescence of water droplets [35]. Zhang et al. reported that the asphaltenes film at oil/water interface becomes less rigid in presence of a EO-PO block copolymer [40].

As a consequence the chemical

demulsifiers alters water / oil interfacial properties and hence allows coalescence of water droplets. Pensini et al. probed demulsification mechanism with Brewster angle and atomic force microscopy [41]. They reported that the infiltration of the EO-PO block copolymers into the asphaltene film changed the asphaltene interfacial mobility and morphology. Harbottle et al. reported that the asphaltenes interfacial microstructure at the oil/water interface can either be liquid-like or solid-like, depending on original whole concentration of asphaltenes [42]. They found droplets coalesce rapidly when the interfacial film is conquered by the viscous constituent. However, droplet coalescence stops when the interfacial microstructure changes to a solid-like state by the ascendancy of elastic influence. The presence of EO-PO block copolymers reverse the development of asphaltene film from solid to liquid-like, by competing for oil/water interfacial area. Alternatively, demulsifiers can as well link water droplets that cause flocculation and also increases coalescence and phase separation [43, 44]. The key performance indictors (KPIs) for effective bitumen froth treatment are dewatering and demineralization of the diluted bitumen, and reduction in the bitumen / diluent losses to tailings. Generally, the demulsifier formulations are designed by incorporating numerous EO-PO block copolymers with numerous chemical structures 3|Page ACS Paragon Plus Environment

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and an extensive distribution of molecular weights to meet / exceed the KPIs. Each component of the final package has a different partitioning ability and interfacial activity. In this article we studied the properties and performance of three newly developed demulsifiers “DMO A”, “DMO B” and “DMO C”. The first objective of the work was to explore the relationship between demulsification proficiency and EO-PO block copolymers properties such as relative solubility number (RSN) and dynamic interfacial tension (IFT).

In addition to the demulsifier’s properties, the operating conditions also impact demulsifier’s performance in bitumen froth treatment. The oil-water emulsion stability can be affected by operating conditions such as pH [45-48] and mixing [49, 50]. It has been stated in literature that addition of acidic chemistry to crude oil-water emulsion shows different effects on demulsification of oil-water emulsions from different origins [47]. Poteau et al. (2005) reported that pH has a significant impact on interfacial properties of asphaltenes at the oil/water interface due to charged asphaltenes functionalities [46]. The second objective of the research was to study the influence of the operating parameters such as pH and mixing on demulsification efficiency.

2. MATERIALS AND METHODS 2.1 Materials. The bitumen froth and naphtha samples were received from the mineable oil producers from Athabasca region in 1-gallon metal paint cans and 1L glass jars, respectively. The bitumen froth was heated to 85°C for 2h and then mixed well by a hand held stirrer for 15 min. About 85 g of bitumen froth was transferred in 180 mL graduated glass bottles that were sealed, cooled to room temperature and stored at 4°C in a refrigerator. To determine composition of bitumen froth by a Dean Stark extraction method, about 30 g of homogenized bitumen froth was placed in an extraction thimble and then extracted with xylenes. The solids remained in the extraction thimble and the water was gathered in the side trap. The amount of bitumen was calculated with a filter paper method, while


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the amount of water and solids were calculated by weight. The composition of bitumen froth averaged around 56.15 ± 0.06 % bitumen, 32.32 ± 0.27 % water and 11.53 ± 0.22 % solids by weight. The fine solids content (≤ 45 µm) of each bitumen froth sample was measured by sieve analysis based on the dried solids obtained from the Dean Stark analysis and averaged around 34.03 ± 1.82 % by weight. The naphtha was also homogenized at room temperature using a paint shaker for 5 minutes. Depending on the amount of froth in each bottle, the quantity of naphtha needed to provide diluent-to-bitumen ratio of 0.7 (containing 33.4 g diluent) was weighed into a new set of 180 mL graduated glass bottles that were also stored at 4°C. Before starting the tests, the froth and naphtha were removed from the refrigerator and left to reach room temperature. Xylenes, toluene and ethylene glycol dimethyl ether used for Dean Stark extraction, interfacial tension (IFT) and relative solubility number (RSN) measurements, respectively were obtained from the Fisher Scientific.

2.2 Demulsifiers. Baker Hughes Research and Development Centre in Sugar Land, Texas supplied the demulsifiers for this work. Three demulsifier formulations DMO A, DMO B and DMO C were prepared and studied in the Baker Hughes oil sands laboratory in Leduc, Alberta. RSN values of demulsifiers DMO A, DMO B and DMO C were measured at 8.71, 9.10, and 9.45, respectively. The details of the RSN determination method can be found in reference [51].

2.3 Demulsification Tests. The bitumen froth and diluent samples were placed at 80 °C in a water bath. The diluent bottles at 80 °C were treated at 15, 25, and 50 ppm with EO-PO block copolymer demulsifiers. Two undosed bottle tests were kept as baseline in each experiment. After 10 min, the dosed naphtha bottles were shaken on the horizontal shaker table for 1 min and then added to the corresponding bitumen froth bottles. The diluted froth samples were then mixed for 6 min at frequency 180 shakes/min, on a horizontal shaker table. After agitating, the diluted froth sample bottles were transferred to a water bath at 80 °C and allowed to settle under gravity. Diluted


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bitumen froth samples were collected at the 1/3 height from the surface at 15 and 30 min retention time, respectively, from each bottle and the water content was obtained by a Karl Fisher titration. A reference point was the average water content in the two control tests. The dewatering efficiency of demulsifiers for each dosage was calculated from: dewatering efficiency ሺ%ሻ=

൫Wo - Wd ൯ Wo

×100

(1)

where W o is the water content in the control, and W d is the water content on the addition of the EO-PO block copolymer.

2.4 Solids Analysis. The known amount of dilbit samples collected from 1/3 height from the surface at 30 min settling time from each graduated glass bottle were transferred into weighed Teflon centrifuge tubes. The tubes were then set in titanium 50.2 Ti rotor after balancing the weights and centrifuged at 15,000 rpm for 30 minutes using a Beckman Coulter Optima L-90K ultracentrifuge. After 30 minutes, the top oil from the centrifuge tubes was carefully removed with plastic pipettes. The centrifuge tubes containing solids were filled with toluene, sonicated until the solids completely dispersed and then centrifuged again for 30 min at 15,000 rpm. The sonication and centrifugation steps were repeated till the supernatant had no black colour of the bitumen. The solids were dried at 115°C for 2 hours in an oven. The tubes containing dry solids were re-weighed to calculate the percent solids in diluted froth samples. The solids removal efficiency of demulsifiers for each dosage was calculated from: solids removal efficiency ሺ%ሻ=

൫So - Sd ൯ So

×100

(2)

where So is the solids content in the control, and Sd is the solids content on the addition of the EO-PO block copolymers. The results reported are the average of three measurements.


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2.5 IFT Measurement. IFT work was conducted with a Teclis Tracker H automated drop tensiometer. The oil and water phases were 60 wt% toluene-diluted bitumen and deionized (DI) water, respectively. Demulsifier was injected in toluene diluted bitumen. The testing was conducted at 25.0 ± 1.0 °C. Prior to testing, the diluted bitumen samples were treated with 50 ppm of demulsifiers. A new oil droplet was made at the tip of an inverted needle immersed in the deionized water, at start of each measurement. The instrument determined the dynamic IFT by a technique of consecutive estimation to fit a formula of the Young–Laplace equation to the oil droplet shape. The TRACKER H employs a computer controlled syringe pump to sinusoidally alter the volume of oil droplet and measure simultaneously the IFT change. The software calculates the dilatational modulus by equating the oil droplet deformation to the IFT change. The volume oscillations were accomplished at an amplitude of ten percent of volume of oil droplet.

2.7 Underflow preparation. The underflow was prepared to measure the effect of demulsifiers DMO A, DMO B and DMO C on bitumen and diluent losses to tailings. After 30 min of settling, the bottles were removed from the water bath and the diluted bitumen phase was removed cautiously above the free water at oil/water interface. The fluid left in the bottle is called the underflow.

2.8 Hydrocarbon Losses Measurement. Diluent losses to the underflow were measured by the use of the Baker Hughes proprietary method. Bitumen losses to the underflow were calculated by the Dean Stark extraction method.

The underflow

prepared in Section 2.7 was displaced to an extraction thimble and constantly extracted with xylenes. The amount of bitumen lost to the underflow was evaluated using a filter paper method.

3. RESULTS AND DISCUSSION 3.1 Correlation between the demulsifier’s properties and performance 7|Page ACS Paragon Plus Environment

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To measure the performance of chemical demulsification, the typical KPI’s are the water content and the solids content in the diluted bitumen product, and bitumen/diluent losses to the tailings.

The lower the value of the KPIs acquired, the better the

performance of the bitumen froth treatment.

3.1.1 Correlation between the demulsifier’s properties and dewatering efficiency Demulsification of the froth samples was performed at 0, 15, 25 and 50 ppm using demulsifiers DMO A, DMO B and DMO C. The water contents in the diluted froth samples collected from 1/3 height from the surface were analyzed at 15 min and 30 min settling time using a Karl Fisher Titration.

Figures 1 and 2 show the influence of

demulsifier dosage on dilbit water content at 15 and 30 min settling times, respectively. The results indicate that the dilbit dewatering improves both with dosage and the settling time in presence of all the demulsifiers. DMO C performed the best among the three demulsifiers on dilbit dewatering over the dosage range studied.

Figure 1. Influence of demulsifier dosage on dilbit dewatering at 15 min settling time


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Figure 2. Influence of demulsifier dosage on dilbit dewatering at 30 min settling time The dewatering efficiency (calculated using equation 1) of demulsifiers at 30 min settling time is plotted against demulsifier dosage in Figure 3. Figure 3 shows that the dewatering efficiencies of DMO A, DMO B and DMO C for the dilbit collected from 1/3 height from the oil surface are 43.8 %, 54.2 %, and 63.6 %, respectively, at the 50 ppm dosage and 30 min of settling time. In other words, the dewatering efficiency of DMO C is 19.8 % and 9.4 % higher than DMO A and DMO B, respectively at the 50 ppm dosage and 30 min of settling time. The RSN values of demulsifiers DMO A, DMO B and DMO C are 8.71, 9.10, and 9.45, respectively. The results point out that the dewatering efficiency is directly linked to the RSN value of the EO-PO block copolymers [52, 53]. Kailey and Feng found that the demulsification improves with an increase in RSN value of the EO−PO block copolymers [52]. Several researchers have made an effort to relate demulsification performance with IFT [55-57]. To find the link between the dewatering efficiencies of EO-PO block copolymers and their IFT, the IFT between DI water and 60 wt% toluene-diluted bitumen was considered with and without the addition of demulsifiers DMO A, DMO B and DMO C. 9|Page ACS Paragon Plus Environment

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IFT is plotted against time for toluene diluted bitumen samples treated with 50 ppm of demulsifiers in Figure 4. The IFT values decrease with time in presence of all three demulsifiers. The lowest IFT values were obtained in presence of demulsifier DMO A, however the demulsifier DMO C assisted to achieve the highest dewatering efficiencies at the dosage range studied. The higher IFT values of demulsifier DMO C is not an unexpected result, as IFT results often do not relate to demulsification efficiency as water droplet coalesce is dynamic in nature, which is influenced by hydrodynamic film stability of the water droplet surface [32, 54].

In the existence of EO-PO block copolymers, the IFT value is subtle to the interfacially active molecules density at the oil/water interface. The extension of the area at the interface will result in decrease of the concentration of interfacial active molecules per unit area at the interface and a consequent rise in IFT. In the existence of EO-PO block copolymers, IFT gradients are created which compete with these variants.

This

phenomenon is termed as dilatational elastic modulus (defined by equation 3) and it measures the interfacial resistance to change in area at the interface.

ε=

dλ d ln A

(3)

where Ɛ is the dilatational elastic modulus, λ is the IFT, and A is the interfacial area. Several investigators found out that demulsifiers which lower the elastic modulus of the oil/water interface will achieve superior demulsification performance [32, 54].

The

dilatational elastic modulus is plotted against frequency in Figure 5. The dilatational elastic modulus is lowest in case of demulsifier DMO C, indicating that the demulsifier DMO C is best among the three demulsifiers to dislocate the interfacial tension gradients and hydrodynamic forces that repelling coalescence of water droplets. The results explain why the demulsifier DMO C assisted to achieve the highest dewatering efficiencies at the dosage range studied.

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Figure 3. Dewatering efficiency vs. EO-PO block copolymer dosage at 30 min settling time.

Figure 4. IFT vs. time for 60 wt% toluene-diluted bitumen samples treated with 50ppm of demulsifier DMO A, DMO B and DMO C.


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Figure 5. Dilatational elastic modulus vs. frequency between water and toluene diluted bitumen treated with 50 ppm of EO-PO block copolymer DMO A, DMO B and DMO C.

3.1.2 Correlation between the demulsifier’s properties and demineralization efficiency

The solids content of the dilbit samples collected from the 1/3 height from the oil surface at 30 min settling time were determined by high speed centrifugation at 15,000 rpm. Figure 6 shows the correlation between the demineralization efficiency (calculated using equation 2) and demulsifier dosage for all three demulsifiers DMO A, DMO B and DMO C. The demineralization efficiency of all the demulsifiers improved with the dosage. For instance, at 30 min settling time, the demineralization efficiencies of demulsifier DMO C are 23.0 %, 31.1 % and 40.8 % at 15, 25 and 50 ppm dosages, respectively. Furthermore, DMO C performed superior for solids removal from the dilbit among the three demulsifiers at all the dosages. Figure 6 shows that the average demineralization efficiencies of DMO A, DMO B and DMO C for the dilbit collected from 1/3 height from the oil surface are 19.9 %, 37.3 %, 12 | P a g e ACS Paragon Plus Environment

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and 40.8 %, respectively, at the 50 ppm dosage and 30 min of settling time. In other words, the demineralization efficacies of DMO C are 6.6% and 8.7% higher than DMO A and DMO B. Demulsifier DMO C showed higher dewatering and demineralization efficiencies among the three demulsifiers considered in this work, which point out that the water and solids removal efficiencies of the demulsifiers are directly correlated to each other. Like dewatering efficiencies, the solids removal efficiencies of demulsifiers DMO A, DMO B and DMO C are directly related to the RSN values. DMO C has highest RSN value and achieved best demulsification efficiency among the three demulsifiers considered for this work. Several researchers reported earlier that the demulsification efficacy increases with RSN value of the EO−PO block copolymers [52, 60].

Figure 6. Correlation between demineralization efficiency and demulsifier dosage at 30 min settling time

3.1.3 Correlation between the demulsifier’s properties and hydrocarbon losses to underflow The naphtha losses to underflow were measured using the Baker Hughes proprietary method. The naphtha losses are quantified as a percentage of the naphtha collected by 13 | P a g e ACS Paragon Plus Environment

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the Baker Hughes method to the initial amount of naphtha added to the test sample. The values presented in this section are indications only and cannot be correlated to the actual system because the test system cannot simulate the downstream processing equipment used by mining operators, such as hydrocyclones and the naphtha recovery units that further reduce the hydrocarbon losses to tailings.

Therefore, the data

presented shows higher losses than would be expected in the commercial plant. The key point to consider is that comparisons can be made between the different demulsifiers to confirm the same, better, or worse performance on naphtha losses to the underflow. The naphtha losses to the underflow with the increase in demulsifier dosage are shown in Figure 7. The naphtha loss to underflow is increased with dosage in presence of all the demulsifiers. However, “DMO C” showed superior performance with lower naphtha losses to the underflow as compared to demulsifiers DMO A and DMO B at all the dosages studied at 30 min settling time. For instance, at 30 min settling time the naphtha losses to the underflow in presence of DMO C at dosages 15, 25 and 50 ppm are 1.82 %, 1.90 % and 2.21 %, respectively by weight. While in presence of demulsifier DMO A the naphtha losses to the underflow are 1.86 %, 2.17 % and 2.44 %, by weight at dosages 15, 25 and 50 ppm, respectively at 30 min settling time. The relative comparison between the demulsifiers DMO A and DMO C show that the DMO C improved the naphtha losses by 2.0 %, 15.3 % and 12.9 %, compared to DMO A at 15, 25 and 50 ppm dosages, respectively at 30 min settling time.


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Figure 7. Correlation between percent naphtha loss to the underflow and demulsifier dosage at 30 min settling time

The results reveal that DMO C performs significantly better on reducing the naphtha losses to the underflow by controlling the interface as compared to DMO A and DMO B. DMO C showed improvement of 9.4 % and 12.9 % by weight as compared to demulsifiers DMO A and DMO B, respectively at 50 ppm dosage and 30 min of settling time. The correlation between bitumen losses to the underflow and demulsifier dosage is shown in Figure 8. The bitumen loss to underflow is increased with dosage in presence of all the demulsifiers. However, “DMO C” showed superior performance with lower bitumen losses to the underflow as compared to demulsifiers DMO A and DMO B at all the dosages studied at 30 min settling time. The increases of hydrocarbon losses with dosage are linked to increase of solids removal efficiencies in all the demulsifiers. Among three demulsifiers, DMO C showed higher solids removal efficiencies and hence the naphtha/bitumen losses to the 15 | P a g e ACS Paragon Plus Environment

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underflow. It has been described in the literature that the hydrocarbon components in bitumen has strong affinity for biwettable clay surfaces [58, 59]. The strong adsorption of hydrocarbons on clay minerals surfaces causes higher hydrocarbon losses in processing of mineable oil sands. Sparks et al. reported that in naphtha-based froth treatment processes certain solids fractions are linked with substantial quantities of toluene insoluble organics, which adsorbed onto biwettable/hydrophobic solids surfaces.25 The particle size of these organic rich solids can vary from less than 44 µm to greater than 100 µm. The particles of size greater than 100 µm usually occurs as agglomerates of small particles bound together by humic matter. During the bitumen froth treatment processes, these agglomerates carry any associated bitumen/naphtha into the tailings, which influences overall hydrocarbon recoveries. The organic material coated particles of size less than 44 µm persist in diluted bitumen stream in the course of bitumen froth treatment processes, which cause problems in downstream/refinery processes.

Figure 8. Correlation between percent bitumen loss to the underflow and demulsifier dosage at 30 min settling time


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3.2 Influence of the operating conditions on demulsifier’s performance The influence of operating conditions such as pH and mixing were studied on bitumen froth treatment KPIs such as dilbit dewatering, demineralization and hydrocarbon losses to underflow.

3.2.1 Influence of the pH on dilbit dewatering, demineralization and hydrocarbon losses to underflow To study the influence of pH on KPIs such as dilbit dewatering, demineralization, and hydrocarbon losses to the underflow, an acidic chemistry BHI-AC was selected for this work. BHI-AC is an inhibited acid that has been used in various oil sands applications and was believed to be the best choice for this study. The demulsification tests were carried out by keeping the dosage of DMO C constant at 25 ppm and varying the dosage of BHI-AC from 0 to 10,000 ppm. Figure 9 shows the influence of BHI-AC dosage on percent water content in dilbit at 30 min settling time, while using 25 ppm of demulsifier DMO C. BHI-AC.

The percent water content in dilbit increased with the dosage of

These results conclude that the acidic chemistry is not aiding in dilbit

dewatering.


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Figure 9. Influence of BHI-AC dosage on percent water content in dilbit in the presence of 25 ppm of DMO C at 30 min settling time

After the demulsification tests the bottom layer was centrifuged at 4000 rpm to separate the constituents into oil, water, and solids. The oil was carefully removed using plastic pipette and pH of water collected in a vial after filtering through the filter paper was measured using pH meter. Figure 10 shows the pH vs. BHI-AC dosage in the presence of 25 ppm of DMO C at 30 min settling time. The pH decreases with the increase of BHI-AC dosage. The results illustrate that as the pH decreases; the dilbit appeared to contain higher water content than the blank sample. Thus, decreasing the pH by the use of acid addition is not assisting in dilbit dewatering.

Figure 10. pH as a function of BHI-AC dosage in the presence of 25 ppm of DMO C at 30 min settling time

The dilbit solids content are plotted against BHI-AC dosage, at 30 min of settling time in Figure 11. Figures 8 and 10 illustrate that as the water content in the dilbit increases, the solid content also increases.

Several researchers reported that pH affects


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interfacial film and emulsion stability [46-48]. Poteau et al. illustrates that pH strongly impacts interfacial properties of asphaltenes at the oil/water interface [46]. Fortuny et al. studied the impact of pH on stability of water-in-oil emulsions using microwaves and found that the demulsification efficiency deteriorates at high pH [48]. Strassner reported that Venezuelan crude water-in-oil emulsions are highly stable at pH < 6 or ≥ 13, while unstable at pH > 10 [47]. Several publications reported that pH impacts stability of water-in-oil emulsions by the ionization of polar functional groups of asphaltenes, which influence electrostatic repulsive interactions to an extent that stops the cohesion of interfacial film [22, 61].

Figure 11. Influence of BHI-AC on dilbit demineralization in the presence of 50 ppm of DMO C at 30 min settling time

Figures 12 and 13 show the influence of BHI-AC dosage on diluent and bitumen losses to underflow at 30 min of settling time. Both diluent and bitumen losses increase with the increase in dosage of BHI-AC. The results point out that the decrease in pH by acid addition is ineffective in destabilizing water- in- oil emulsions, in actual fact it shows the 19 | P a g e ACS Paragon Plus Environment

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negative impact on demulsifiers performance. Strassner reported in literature that addition of acidic chemistry to crude oil/water emulsion shows different effects on demulsification of oil/water emulsions from different origins [47]. It has been reported in literature that pH influences interfacial properties of asphaltenes at the oil/water interface [46]. The asphaltenes polar groups become charged at both high and low pH, which increases their hydrophilicity and hence surface activity. The accumulation of asphaltenes at oil/water interfaces, impact both interfacial tension and elastic modulus. The charged asphaltenes tend to accumulate more easily at the oil/water interface especially in the high-pH range since asphaltenes consist of more acidic functionalities. As a result the water-in-oil emulsion becomes more stable, which impacts coalescence of water droplets.

Figure 12. Influence of BHI-AC on diluent losses in presence of 50 ppm of DMO C at 30 min settling time


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Figure 13. Influence of BHI-AC on bitumen losses in presence of 50 ppm of DMO C at 30 min settling time

3.2.2 Influence of the mixing on hydrocarbon losses to underflow

dewatering,

demineralization

and

For the demulsifier to work efficiently, it needs to create close contact with the oil/water emulsion to influence the oil/water interface. Both diffusion and dispersion of demulsifier can be enhanced by mixing, which increases the possibility of collisions and hence coalescence between water droplets in oil/water emulsion. Hence adequate mixing time needs to be provided to thoroughly mix the demulsifier into the emulsion and promote coalescence of water droplets by influencing the oil/water interface. In addition the mixing intensity should not deteriorate the demulsifiers performance by further tightening of the water-in-oil emulsion.


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Figure 14. Influence of mixing time on dilbit dewatering at 30 min settling time

Demulsification of froth samples were performed with DMO C at 0, 15, 25 and 50 ppm dosage. After demulsifier addition to the diluted froth, six mixing times 3, 6, 8, 10, 12 and 18 min were selected to conduct this work. The water contents of the dilbit were examined at 30 min settling time using a Karl Fischer Titration and plotted against the DMO C dosage as shown in Figure 14. Figure 14 indicates that at all the dosages studied herein, the percent water content in the diluted bitumen decreased up to 8 min mixing time and then increased afterwards with further increase in mixing time at 30 min settling time.

The results showed that the optimal demulsification performance with

DMO C was achieved at 8 min mixing time. The agitation over 8 min increasing the percent water content in the dilbit, pointing towards over mixing that emulsifying the diluted froth. The agitation less than 6 min points towards the under mixing as it is not aiding to get the best results.


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Figure 15. Influence of mixing time on dilbit demineralization at 30 min settling time

Figure 15 shows the influence of mixing time on dilbit demineralization at 30 min settling time. The percent solids content in dilbit at all the dosages studied, decreases with mixing time up to 8 min and then increased after that with further increase in mixing time. These results point out that there is direct correlation between the dilbit dewatering and demineralization. The percent solids content in dilbit increased with increase in percent water content. The impact of mixing speed and time in demulsification performance is still not fully understood. It has been studied earlier that there is a significant variance in the time needed to achieve a uniform concentration by adding either concentrated demulsifier drop wise or dilute before injecting into a bigger volume of fluid [49]. The demulsification performance increases with demulsifier dosage up to an optimum level and then deteriorates with further increase in concentration [49, 62]. Czarnecki et al found that high local concentrations can built up rag layers in oil sands processes [63]. To achieve best performance, both the mixing conditions at the feed point and local concentration of additive are important. High local concentrations can form on demulsifier addition, if 23 | P a g e ACS Paragon Plus Environment

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feed rate exceeds the local mixing rate as the demulsifier molecules don’t get enough time to disperse in continuous phase. This phenomenon is termed as meso-mixing [64]. Laplante et al. revealed that better mixing improves demulsification efficiency [49]. They found that increase in mixing time and/or mixing intensity aids to achieve the comparable demulsification efficiency at lower dosage of demulsifier. Thus good mixing conditions considerably increase the demulsification efficiency.

Figure 16. Influence of mixing time on diluent losses to the underflow


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Figure 17. Influence of mixing time on bitumen losses to the underflow

Figure 16 and 17 illustrate the influence of mixing time on diluent and bitumen losses to the underflow, respectively. At all the dosages, the diluent loss to underflow is noticeably increased with agitation after 10 min. The results indicate that over or under mixing are pushing more hydrocarbons to the underflow due to existence of unresolved bitumen emulsion.

4. Conclusions

The properties and performance of three demulsifiers DMO A, DMO B and DMO C were investigated. The demulsifiers were characterized by the RSN value and IFT measurements. Among the three demulsifiers considered, water and solids efficiencies were in the order of DMO C > DMO B > DMO A from 0 to 50 ppm dosage at 30 min of retention time. The demulsifier DMO C also showed higher performance with lower diluent and bitumen losses to the underflow as compared to demulsifiers DMO A and 25 | P a g e ACS Paragon Plus Environment

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DMO B at all the dosages studied. The direct correlation was observed between the RSN values and dewatering/demineralization performance while the IFT does not correlate to the water/solids removal efficiency of the demulsifiers. The influence of operating conditions such as pH and mixing were also studied on diluted bitumen dewatering, demineralization and bitumen/naphtha losses to underflow. The decrease in pH by addition of acidic chemistry in presence of demulsifier is not assisting to enhance demulsifier performance. The results also show that over or under mixing are pushing more hydrocarbons to the underflow due to existence of unresolved bitumen emulsion.

AUTHOR INFORMATION Corresponding author

*Phone: (780) 980-5978. Fax: (780) 980-5989. E-mail: [email protected]

ACKNOWLEDGEMENT The authors would like to thank R&D team at the Baker Hughes Research & Development Center, Sugar Land, TX for providing the valuable support. In particular, I thank Jonathan Heironimus for IFT work and Jason Thomas for his support through this work. The permission from Baker Hughes to submit this work for publication is really appreciated.

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Properties and Performance of Newly Developed Demulsifiers in Oil

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