Oil Removal from Produced Water during Laboratory- and Pilot-Scale

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Oil removal from produced water during laboratory and pilot scale gas flotation - the influence of interfacial adsorption and induction times Mona Eftekhardadkhah, Svein Viggo Aanesen, Karsten Rabe, and Gisle Øye Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.5b02110 • Publication Date (Web): 27 Oct 2015 Downloaded from http://pubs.acs.org on October 29, 2015

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Oil removal from produced water during laboratory and pilot scale gas flotation - the influence of interfacial adsorption and induction times Mona Eftekhardadkhaha, Svein Viggo Aanesenb, Karsten Rabec and Gisle Øyea,*

a

Ugelstad Laboratory, Department of Chemical Engineering, Norwegian University of

Science and Technology (NTNU), N-7491 Trondheim, Norway b

Statoil Research Centre Porsgrunn

c

Schlumberger Norge AS

*Corresponding author: [email protected] Phone: (+47) 73 59 41 35, Fax: (+47) 73 59 40 80

Abstract The significance of interfacial chemistry for the oil removal efficiency during flotation was demonstrated in a series of laboratory flotation and pilot scale compact flotation unit (CFU) tests. Three crude oils with different physicochemical properties were used in the investigations. The differences in drop size distributions and densities of the oils could not fully account for the observed oil removal. However, taking the time for drainage and rupture (i.e. induction time) of the thin aqueous film separating the drops and bubbles into consideration resulted in good agreement with the oil removal. Moreover, it was demonstrated in a modified CFU setup that water soluble hydrocarbons adsorbed onto the bubbles and reduced the oil removal. This was most likely due to increased induction times caused by the adsorbed components.

Keywords: Crude oil removal, produced water treatment, flotation, compact flotation unit, drop size distributions, drainage time, thin films

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1. Introduction Huge amounts of produced water are generated during petroleum production. Worldwide, the water to oil ratio is currently estimated to be ~4:1 1, and the water volumes are expected to increase as the fields mature. Complex mixtures of dissolved and dispersed components are typically present in the produced water. Water-soluble crude oil compounds, dissolved salts and production chemicals comprise the dissolved species, while various solids (typically from the reservoir, scale products and corrosion products) and oil are dispersed in the water. The polluting components must be minimized to allowed levels, and the threshold of oil in the produced water is limited by legislation if the water is to be discharged. Current regulations at the Norwegian Continental Shelf require that the oil content is less than 30 ppm prior to discharge to sea 2. If the produced water is to be re-injected on the other hand, the threshold of dispersed components is largely determined by operational considerations such as the permeability of the reservoirs 3. Removal of the residual oil from the produced water is essential also in this case.

Hydrocyclones and flotation units are typical produced water treatment equipment placed downstream gravity separators

3, 4

. The fundamental principle for both these

technologies is based on Stokes Law: v=

2 R 2 ( ρ 2 - ρ1 ) g 9 η

(1)

where the removal of oil drops (v) is proportional to the drop radius squared (R2) and the density difference between oil and water ( ρ 2 - ρ1 ) and inversely proportional to the viscosity of the water ( η ). g is the gravitational constant. In the case of gas flotation, which will be focused on here, addition of gas to the produced water will 2 ACS Paragon Plus Environment

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increase the density difference between the continuous and dispersed phases upon formation of oil−gas agglomerates 5, 6.

Two methods of introducing gas bubbles have been used in field applications: induced or dissolved gas flotation 7. During induced gas flotation, the gas becomes dispersed in the flotation vessel by revolving impellers or ejectors. The resulting bubbles normally have diameters in the range of 1000 µm 8. During dissolved gas flotation, the gas is initially dissolved in pressurized water and the bubbles are released by pressure reduction as the water enters the flotation vessel. In this case the diameter of the bubbles can range from 20 to100 µm 8. The main differences between the two approaches are average bubble size, mixing conditions and the hydraulic loading rate 9.

Gas flotation also involves various sub-processes which are not accounted for by Stokes Law (eq. 1). Efficient oil removal during induced gas flotation will for example depend on the collision frequency between bubbles and drops, the attachment efficiency between these and the stability of the resulting bubble−drop agglomerates 10,11,12

. The collision frequency mainly depends on the hydrodynamic conditions.

However, quick drainage and rupture of the thin aqueous film formed upon close approach between drops and bubbles are also important requirements for successful flotation

12

. Furthermore, the oil drops should spread over the gas bubbles once the

thin film is broken

13,14

. These phenomena are strongly influenced by the interfacial

properties of both oil drops and gas bubbles. Optimal oil removal can only be ensured if the mechanisms governing these processes are understood and appropriately responded to.


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The properties of crude oil-water interfaces have been extensively investigated in petroleum systems

15,16,17,18,19,20,21

. However, little attention has been given to the

water-gas interfaces. Therefore, in a series of recent papers, we investigated the interfacial properties of gas bubbles in produced water 22,23,24. Here it was shown that water soluble crude oil components adsorbed rapidly onto bubble surfaces. Both the acidic and basic components had affinity for the bubble surfaces, but no correlations to the total acid and base numbers of the crude oils were found. Furthermore, statistical models were developed for predicting the solubility and surface affinity of the dissolved hydrocarbons. This demonstrated that detailed knowledge about the crude oil fractions and the water phase could give good predictions of the interfacial properties of gas bubbles. Subsequently, the induction time (i.e. the time of film drainage and rupture) was measured upon the approach of a single bubble and a single crude oil drop in a drop-bubble micromanipulator system

25

. The adsorption of

hydrocarbons onto gas bubbles clearly influenced the induction time and the attachment between bubbles and drops.

The objective of the current work was to investigate if the removal of dispersed oil from produced water by gas flotation could be influenced by the interfacial phenomena outlined above. Pilot scale flotation studies were carried out in a compact flotation unit (CFU). Both the dissolved and the induced gas flotation modes were tested. A special split-flow setup was designed to study how the adsorption of water soluble components onto the gas bubbles affected the oil removal in the CFU. In addition a series of laboratory scale induced gas flotation experiments were carried out. Three crude oils with a range of physicochemical properties were used in the investigations. Previous measurements of interfacial properties and induction


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times for the thin aqueous films between drops and bubbles were used to evaluate the observed oil removal.


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2. Experimental

Crude oils The investigated crude oils were denoted A, C and E. Detailed physicochemical characterization of the oils has been reported elsewhere

26

, while some of the

properties are summarized in Table 1 for convenience. The oils ranged from the light crude oil A with low viscosity and low resin and asphaltene content to the relatively heavy crude oil C with higher resin and asphaltene content. Furthermore, the oils had a broad span of induction times, previously determined in a drop-bubble micromanipulator setup 25.

Preparation of o/w emulsions for laboratory scale flotation Dilute emulsions were prepared by dispersing crude oil in synthetic brine using an Ultra-Turrax at 20 000 rpm for 2 min. The brine composition is given in Table 2. The emulsions contained approximately 800 ppm oil and were prepared in three parallels. The drop size distributions of the emulsions were determined using a Nikon LV 100D microscope. The emulsions were poured into a glass cuvette (Hellma, 110OS, 10 mm) immediately after preparation, and images were taken from the upper part of the cuvette. The drop sizes were determined using the Image-Pro Plus 5.0 software, and 10 to 20 images were analyzed for each sample.

Laboratory flotation experiments The laboratory scale flotation setup is shown in Figure 1. The glass column was 2.5 cm in diameter and 25 cm high. Air was introduced into the emulsion at a fixed flow rate of 1 litre/min through a porous filter (40-90 µm pore size) at the bottom of the


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column. Approximately 10 ml sample was collected 1, 3, 5 and 10 min after the flotation started. The sampling was done by a pipette about 4 cm above the bottom of the column. The collected samples were thoroughly mixed with dichloromethane in order to extract the crude oil into the solvent. The organic phase was collected from a separation funnel and the amount of crude oil components was determined by UV spectroscopy using the absorbance at 260 nm and pre-made calibration curves for each crude oil dissolved in dichloromethane (20 to 120 ppm). Finally, the oil removal efficiency (ORE) was calculated by the following equation: ORE =

C0 − Ct C0

(2)

where C0 is the initial amount of crude oil in the emulsion and Ct is the oil concentration after t min of gas flotation (t = 1, 3, 5 and 10 min). The average of three repeated experiments with standard deviation is reported.

Real scale flotation experiments Real scale flotation experiments were carried out in a compact flotation unit (CFU) at Schlumberger Norge PWMS’s test facilities in Porsgrunn, Norway. The standard setup of the rig is illustrated in Figure 2. In addition to the CFU it included gas saturation and degassing vessels filled with totally about 7000 litres of water. The pressure in the gas saturation vessel was adjusted depending on whether the rig was run in induced, dissolved or combined induced-dissolved gas flotation mode. An injection pump and oil-water mixer was used to introduce the oil into the aqueous phase downstream the saturation vessel. Chemicals can also be added to the water stream by an injection pump, but no chemicals were added in these investigations. The gas injection shear valve was placed just upstream the CFU, while sampling


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was done at the inlet and outlet of the CFU. After treatment in the CFU, the fluids entered the degassing vessel and were recycled back to the saturation vessel.

Initially, a series of experiments with different flow rates and gas injection modes were carried out. The saturation vessel was kept at atmospheric pressure during the induced gas flotation experiments, while gas was injected to the produced water stream through the gas injection shear valve. During the dissolved gas flotation experiments, the gas saturation vessel was pressurized to dissolve gas into the produced water. No gas was then introduced through the shear valve. In the combined mode, the gas was partly dissolved in the water in the saturation vessel and partly injected through the shear valve. Additional parameters during the tests can be summarized as follows: o

•

Temperature was kept at 50 C

•

The flow rate of produced water was adjusted to 4 or 6 m3/hr

•

The salinity was fixed at 3,5% NaCl

•

Nitrogen was used as the gas phase (10% of produced water rate gas injection in induced gas flotation tests)

•

The concentration of the oil at the inlet of the CFU was between 100 and 200 ppm, depending on the test

The oil-in-water concentrations were determined at the inlet and outlet of the CFU by online monitoring facilities (Advanced Sensors) and the oil removal efficiency was calculated as the difference. A series of samples were also collected at the same sampling points. These were analysed for drop size distributions by a Malvern Laser Diffraction 2000 instrument and the surface tension by a maximum bubble pressure tensiometer (Krüss BP100, Hamburg, Germany). 8 ACS Paragon Plus Environment

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The standard setup of the rig was used in a series of experiments to check the reproducibility in the different flotation modes. Furthermore, series of experiments were run with fixed and varied pressure drops across the gas injection shear valve in order to study the effect of drop size distributions and density differences on the oil removal.

In another series of experiments the aim was to study if adsorption of water soluble components onto gas bubbles influenced the oil removal efficiency. A modified setup of the rig was designed, as illustrated in Figure 3. Here, the produced water flow was divided into two flow lines (a) and (b) before the oil-water mixer. The oil was injected into flow line (a) while the gas was injected into flow line (b) in induced gas mode at point Xb. Dissolved organic components were also introduced into flow line (b) just upstream the gas injection point (Xb). This exposed the gas bubbles to the dissolved organic components. By varying the flow rates in line (a) and (b), the exposure time was controlled from Xb to point Z, where the two flow lines were merged again. After the drops and bubbles were mixed, the fluids entered the CFU. The total flow rate of produced water was 4 or 6 m3/hr. The corresponding split flow rates and the exposure times of the bubbles to the dissolved organic components are summarized in Table 3.

The dissolved organic components were either butyric acid (model compound) or the water soluble components from crude oil A. The latter were prepared by mixing the crude oil and brine (50-50 wt%) overnight and subsequently separating the phases by centrifugation. More details about the procedures can be found elsewhere 22. The


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oil removal efficiency was determined in the same way as above, using 100 ppm oil at the inlet of the CFU. Only crude oil E with one parallel of each experiment was used as the dispersed oil in this series.


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3. Results and Discussion

3.1 Laboratory scale flotation The oil removal efficiency as a function of time for the three crude oil emulsions is shown in Figure 4. The largest difference in removal efficiency was observed shortly after the aeration started. Low removal (about 53 %) was then seen for crude oil A, while crude oil C had the highest removal (about 78 %). After 10 minutes of flotation the oil removal was almost identical for oil A and E (about 92 %), while it was somewhat higher for oil C (about 98 %). The fast rise of gas bubbles largely determined the number of drop-bubble collisions and the drop and bubble size distributions were anticipated to be important for the oil removal. Assuming that the bubble size distribution was similar in all the experiments, only the differences in drop sizes between the crude oils were considered. This means that the oil removal efficiency should be promoted by increased drop sizes, in accordance with Stokes Law (eq.1). The crude oil A emulsion had the smallest Sauter mean diameter, as seen in Table 4. This agreed quite well with the relatively low oil removal for this sample, particularly at the shortest time. Somewhat higher and fairly similar drop sizes were seen in the emulsions with crude oils C and E. However, since the total oil removal was very similar for crude oils A and E, the drop sizes alone could not satisfactorily explain the results. The density difference between the oil and water is another factor in Stokes Law (eq.1) that will influence the oil removal. As seen in Table 1, crude oil C had the highest density of the oils (i.e. lowest density difference to water). This should


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oppose good oil removal. However, the highest oil removal was seen in the emulsion with this oil. Clearly, the density differences could not fully explain the results either. In an attempt to resolve this, the attachment process between oil drops and bubbles was taken into consideration. As mentioned above, the drainage and rupture of the aqueous film formed upon close approach of drops and bubbles are important for this process. The induction times (i.e. characteristic times of aqueous film drainage and film rupture) were previously determined for the same crude oils as used here

25

and are listed in Table 4. The longest induction time (8 seconds) was seen for crude oil A, while it was considerable shorter for crude oil C (1 second) and E (4 seconds). Particularly at short flotation times there was good agreement between induction times and oil removal, as the oil removal improved when the induction time became shorter. The best overall oil removal was also seen for the oil with shortest induction time. Notably, the time for an oil drop to cover a gas bubble was also determined previously

25

and was highest for crude oil C. This suggested that the coverage time

was less important for the oil removal than the induction time, at least for the flow rates considered here. It should also be noted that the induction times referred to here were measured under static conditions, and therefore they are probably much longer than the induction times for the highly dynamic conditions present during the flotation experiments. Nevertheless, the values are believed to indicate relative magnitudes between the different oils.

3.2 Pilot scale flotation 3.2.1 Flotation modes and repeatability


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Figure 5 shows the concentration of crude oil at the inlet of the CFU (A) and the corresponding oil removal efficiency (B) for two parallel measurements in different (induced, dissolved and induced-dissolved) flotation modes. None of the repeated measurements were carried out directly after each other, and normally performed at different days. Overall, the reproducibility was very good. The maximum variation between repeated measurements of oil concentration at the CFU inlet was 14%, but usually the variation was less. For the oil removal efficiency, the variation normally was less than 11%. The exception was the dissolved flotation at 4 m3/h, where the repeated measurements differed by a factor 2.7. The injected oil dosage was kept constant at 200 ppm during all the experiments. This was somewhat lower than the oil concentration measured at the inlet of the CFU, Figure 5A. The difference also increased slightly as the flow rate was increased from 4 to 6 m3/h. This was attributed to accumulation of background oil during the experiments. It was also seen that the oil removal efficiency was higher at the highest flow rate, Figure 5B. This could be due to several factors. Poor mixing might have resulted in some pipeline separation and less dispersion of gas at the lowest flow rate. In addition, the relative velocities between the phases were lowest at the lowest flow rate, which could have reduced the collision frequency between the bubbles and drops. It is evident from Figure 5B that the oil removal efficiency depended on the gas injection mode. The removal was lower during the dissolved air flotation than during the induced gas flotation. Different attachment mechanisms between oil drops and gas bubbles might explain this

27

. During induced gas flotation the bubbles

normally become fully or partially encapsulated by the oil drops after rupture of the aqueous film between them. Full encapsulation of the bubbles would provide the 13 ACS Paragon Plus Environment

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strongest linkage between the two phases and would prevent detachment of the oil by shear forces. If the drops were too small to provide full encapsulation, an oil lens at the aft of the bubble might be formed, while negative spreading coefficient might result in point contact between the drop and bubble. Shear forces could then easily detach the oil from the bubbles. During dissolved gas flotation, on the other hand, gas bubbles nucleate on the surface of drops and grow to sufficient size to aid flotation. The nucleation and growth will occur as long as the partial pressure is lower in the gas phase than in the liquid phase. In order for this mechanism to be effective, sufficient gas must be released from the solution. This would usually coincide with a fairly high pressure drop at the inlet of the flotation cell. Furthermore, the amount of released gas would depend on the pressure and temperature difference between the upstream piping and the operating conditions of the flotation cell. Based on these considerations, the lower oil removal observed during dissolved gas flotation was attributed to low pressure in the gas saturation vessel, resulting in low pressure drop and insufficient release of gas for efficient flotation. It is anticipated that the removal efficiency would improve upon increasing the pressure in the gas saturation vessel. It is also emphasised that it was not attempted to optimize the conditions to give maximum oil removal in these investigations.

3.2.2 Fixed and not-fixed drop size distributions The influence of drop size and densities of the crude oils upon oil removal efficiency was investigated by performing two series of experiments. In the first series, the drop size distributions were varied by keeping the pressure drop across the shear valve constant when the oil was injected into the water phase. This resulted in skewed distributions with tails towards the larger drops for all the crude 14 ACS Paragon Plus Environment

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oils, Figure 6. Crude oil A had the smallest drops, with a peak in the distribution around 13 µm and maximum drop sizes around 60 µm. Crude oil E had the peak in the similar range as crude oil A, but it contained more of the larger drops. The largest drops, with maximum in the size distribution around 22 µm and drop sizes up to 105 µm, were seen for crude oil C. The oil removal for the oils during different flotation modes are shown in Figure 7. Overall, no systematic trends in the removal efficiency were observed between the oils. However, the removal of crude oil C was slightly better than the other oils during induced gas flotation (in agreement with the laboratory scale flotation). During dissolved gas flotation, on the other hand, the removal of crude oil C was the poorest. The overall low removal in this mode was attributed to the low pressure in the saturation vessel, as explained above. Nevertheless, the differences in drop size distributions alone could not explain the observations. In the second series of experiments, the drop size distributions were kept similar for the oils by adjusting the pressure drop across the oil injection shear valve. In this way the influence of the density differences between oil and water on flotation efficiency could be studied. Figure 8 shows the resulting oil removal efficiency for the crude oils. The variation between the oils was relatively small, but at least during the induced flotation the removal of the lightest oil (crude oil A) was generally lower than for the other oils. This meant that the density difference was not an important factor for the oil removal here. As during laboratory scale flotation, considering induction times could help to give a reasonable explanation of the observations. The induction time was considerably longer for crude oil A than for the two other oils (Table 4). Since the drop size distributions were similar for all the oils, faster drainage and


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rupture of the aqueous film and the same retention time in the CFU would lead to higher number of drops attached to the gas bubbles for crude oils C and E.

3.2.3 Adsorption of water soluble crude oil components at bubble-water interfaces It was previously established that water soluble crude oil components start to adsorb at fresh bubble surfaces within ms

22,23,24

. Furthermore, it was demonstrated

that the adsorbed components can prolong the drainage time of the thin aqueous film between bubbles and drops

25

. Therefore it was of interest to explore whether

this effect could influence pilot scale flotation as well. However, surface tension measurements of samples taken at the inlet and outlet of the CFU during the measurements outlined above did not show significant amounts of interfacially active components present in the water. This was attributed to the short recycling time and the low oil-water ratio during the experiments. Consequently, the rig was modified with a split flow-line setup where dissolved components were added in one of the flow lines, as explained in the experimental section. The contact times between bubbles and dissolved components were varied from 0.4 to 1.5 s, Table 3. Experiments with butyric acid and water soluble crude oil components injected into flow line (b) were carried out. In addition reference experiments without any added dissolved components were performed. The resulting oil removal efficiencies at different total flow rates and flow-spilt conditions are shown in Figure 9. The best removal of oil was seen when no dissolved components were injected. This was most clearly seen at the highest total flow rate. When butyric acid or dissolved crude oil components were injected, these components likely adsorbed onto the bubbles and reduced the oil removal by giving rise to increased induction times. The suggested mechanisms are illustrated in Figure 10. Since the initial coverage of 16 ACS Paragon Plus Environment

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bubbles by dissolved components typically occured within 300 to 600 ms

23

, the

exposure times obtained here (0.4 to 1.5 s) were considered to be so long that complete coverage of the bubbles was likely in all cases. This could explain the lack of systematic trends in oil removal as the exposure time was altered.

Conclusions The removal efficiency of three crude oils in produced water was investigated by laboratory and pilot scale flotation experiments. The differences in oil removal during induced, dissolved and mixed flotation modes were discussed in terms of different mechanisms for drop – bubble attachment. The oil removal efficiencies in neither laboratory nor pilot scale experiments could solely be explained by the differences in drop size distributions and densities of the oils. However, good agreement between the oil removal and the drainage and rupture of the thin aqueous film (induction time) separating drops and bubbles were seen. It was also shown that water soluble hydrocarbons that adsorbed onto bubbles reduced the oil removal efficiency, probably because the adsorption increased the induction times. Overall, the produced water with the heaviest crude oil, largest drop sizes and shortest induction time tended to give best separation.

Acknowledgments The authors are grateful to the industrial sponsors (ConocoPhillips Skandinavia, ENI Norge, Schlumberger Norge PWMS, Statoil Petroleum and Total E&P Norge) of the joint industrial program “Produced Water Management: Fundamental Understanding of the Fluids” for financial support.


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Tables

A

C

E

Density (50 oC,g/cm3)

0.78

0.91

0.81

Viscosity (50 oC, cP)

1.5

70.4

4.2

Saturates (wt%)

80.0

25.6

67.7

Aromatics (wt%)

18.0

49.6

27.1

Resins (wt%)

1.9

10.9

4.4

Asphaltenes (wt%)

0.1

13.9

0.8

TAN (mg/g)

0.4

0.5

0.3

TBN (mg/g)

0.6

1.3

1.1

IFT (mN/m)

8.9

4.2

17.4

Table 1: The physicochemical data for the crude oils

Concentration Ions (ppm) Cl-

62810

Na+

35393

Ca2+

3253

Mg2+

909

HCO3- 218 SO4 2-

49

Table 2: The ionic composition of the brine


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Total PW flow rate 4 m3/h Flow split

Total PW flow rate 6 m3/h

Line (a)

Line (b)

Exposure time

Line (a)

Line (b)

Exposure time

(m3/h)

(m3/h)

Xb-Z (s)

(m3/h)

(m3/h)

Xb-Z (s)

30% line (b)

2.8

1.2

1.5

4.2

1.8

1.0

50% line (b)

2.0

2.0

0.9

3.0

3.0

0.6

70% line (b)

1.2

2.8

0.6

1.8

4.2

0.4

Table 3: The flow split conditions and the exposure times between the gas bubbles and the dissolved components

Crude oil A

Crude oil C

Crude oil E

Sauter mean diameter ( µm )

5.5 ± 0,3

8.5 ± 0.2

8.1 ± 0.2

Induction time (s)

8.00 ± 3.04

1.01 ± 0.34

4.11 ± 1.47

Table 4: The Sauter mean diameters and the induction times for the crude oil samples


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Figures

Flotation column Gas flow meter Filter (gas disperser)

Figure 1: The laboratory flotation setup

Figure 2: Schematic flow diagram of the standard setup of the CFU rig


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Figure 3: Schematic flow diagram of the modified setup of the CFU rig

100

90

Oil removal efficiency (%)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

80

70

60

Crude oil A Crude oil E Crude oil C

50

40 0

2

4

6

8

10

12

Gas flotation time (min)

Figure 4: The oil removal efficiency as a function of gas flotation time


Energy & Fuels

First parallel Second parallel

A) 300

Oil Concentration in inlet CFU (ppm)

Ind

Diss

Ind+Diss

250

200

150

100

50

0 4

6

4

6

4

6

3

Flow rate (m /hr)

First parallel Second parallel

B) 60

Ind

Diss

Ind+Diss

50


1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 22 of 26

40

30

20

10

0 4

6

4

6

4

6

3

Flow rate (m /hr)

Figure 5: The reproducibility of the oil concentration detected at the inlet of the CFU and the calculated oil removal efficiency. (Ind: induced gas flotation; Diss: dissolved gas flotation). The measurements were performed with crude oil E.


Page 23 of 26

10 Crude oil C Crude oil E Crude oil A

8

Volume (%)

6

4

2

0 0

20

40

60

80

100

Droplet diameter (µm)

Figure 6: The drop size distributions for the crude oils at the inlet of the CFU. Each distribution is the average of at least 4 different measurements (Malvern Laser Diffraction)

25 Ind

Diss

20


1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

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Crude oil A Crude oil E Crude oil C

15

10

5

0

4

4

6

6

3

PW flow rate (m /hr)

Figure 7: The oil removal efficiency for the crude oils when the drop size distributions varied 23 ACS Paragon Plus Environment

Energy & Fuels

25 Ind

Diss


20 Crude oil A Crude oil E Crude oil C 15

10

5

0

4

6

4

6 3

PW flow rate (m /hr)

Figure 8: The oil removal efficiency for the crude oils when the drop size distributions were similar (DV(50)=20 micron)

35 PW-A Butyric acid No additives

30


1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 24 of 26

25

20

15

10

5

0

30% (b)

50% (b) 3

4 m /hr

70% (b)

30% (b)

50% (b)

70% (b)

3

6 m /hr

Figure 9: The influence of interfacially active components adsorbed onto bubbles on oil removal efficiency. The x-axis shows the amount of flow through flow line b at different total flow rates. 24 ACS Paragon Plus Environment

Page 25 of 26

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

Figure 10: The mechanism at bubble surfaces without (a) and with (b) injection of dissolved compounds


Energy & Fuels

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 26 of 26

References: (1) Duhon, H. Oil and Gas Facilities 2012, 29-31. (2) OSPAR Commission: Discharges, Spills and Emissions from Offshore Oil and Gas Installations; London, 2010. (3) Judd, S.; Qiblawey, H.; Al-Marri, M.; Clarkin, C.; Watson, S.; Ahmed, A.; Bach, S. Sep. Sci. Technol. 2014, 134, 241-246. (4) Arnold, K; Stewart, M. Surface Production Operations Design of Oil Handling Systems and Facilities. 3rd edition; Gulf Professional Publishing, 2008:Burlington MA, 2008; pp 482-609. (5) Rubio, J.; Souza, M.L., Smith. Miner. Eng. 2002, 15, 139-155. (6) Melo, M. V.; Sant’Anna Jr, G. L.; Massarani, G. Environ. Technol. 2003, 24, 867-876. (7) Moosai, R.; Dawe, R.A. W Indian J. Eng. 2002, 25 (1), 25-41. (8) W. T. Strickland Jr. Soc. Pet. Eng. J., 1980, 10, 175-190. (9) Moosai, R.; Dawe, R. A. Sep. Sci. Technol. 2003, 33, 303-314. (10) Nguyen, A.V.; Ralston, J.; Schulze, H.J. Miner. Eng. 1998, 53 (4), 225-249. (11) Ralston, J.; Fornasiero, D.; Hayes, R. Int. J. Miner. Process. 1999, 56, 133-164. (12) Min, M. A.; Nguyen, A. V. Miner. Eng. 2013, 40, 67-80. (13) Grattoni, C.; Moosai, R.; Dawe, R. A. Colloid Surface A. 2003, 214, 151-155. (14) Oliveira, R. C. G.; Gonzalez, G.; Oliveira, J.F. Colloid Surfaces A. 1999, 154, 127-135. (15) Freer, E.M.; Radke, C.J. J. Adhesion. 2004, 80, 481-496. (16) Bauget, F.; Langevin, D.; Lenormand, V. J.Colloid Interf. Sci. 2001, 239, 501-508. (17) Jeribi, M.; Almir-Assad, B.; Langevin, D.; Henaut, I.; Argillier, J.F. J. Colloid Interface Sci. 2002, 256, 268-272. (18) Poteau, S.; Argillier, J.F.; Langevin, D.; Pincet, F.; Perez, E. Energ. Fuel. 2005, 19, 1337-1341. (19) Varadaraj, R.; Brons, C. Energ. Fuel. 2007, 21, 199-204. (20) Farooq, U.; Simon, S.; Tweheyo, M.T.; Øye, G.; Sjöblom, J. J. Disper. Sci. Technol. 2013, 34, 701-708. (21) Gaweł, B.; Lesaint, C.; Bandyopadhyay, S.; Øye, G. Energ. Fuel. 2015, 29, 512-519. (22) Eftekhardadkhah, M.; Øye, G. Energ. Fuel. 2013, 27, 5128-5134. (23) Eftekhardadkhah, M.; Reynders, P.; Øye, G. Chem. Eng. Sci. 2013, 101, 359-365. (24) Eftekhardadkhah, M.; Øye, G. Ind. Eng. Chem. Res. 2013, 52, 17315-17321. (25) Eftekhardadkhah, M.; Øye, G. Environ. Sci. Technol. 2013, 47, 14154-14160. (26) Gaweł, B.; Eftekhardadkhah, M.; Øye, G. Energ. Fuel. 2014, 28, 997-1003. (27) Rawlins, C. H. SME Annual Meeting & Exhibit. 2011 Feb. 27-Mar. 2, Denver, CO.


Oil Removal from Produced Water during Laboratory- and Pilot-Scale

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