Crude oil surface active species : Consequences for enhanced oil

Subscriber access provided by READING UNIV

Review

Crude oil surface active species : Consequences for enhanced oil recovery and emulsion stability Maurice Bourrel, and Nicolas Passade-Boupat Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.7b02811 • Publication Date (Web): 09 Nov 2017 Downloaded from http://pubs.acs.org on November 10, 2017

Just Accepted “Just Accepted” manuscripts have been peer-reviewed and accepted for publication. They are posted online prior to technical editing, formatting for publication and author proofing. The American Chemical Society provides “Just Accepted” as a free service to the research community to expedite the dissemination of scientific material as soon as possible after acceptance. “Just Accepted” manuscripts appear in full in PDF format accompanied by an HTML abstract. “Just Accepted” manuscripts have been fully peer reviewed, but should not be considered the official version of record. They are accessible to all readers and citable by the Digital Object Identifier (DOI®). “Just Accepted” is an optional service offered to authors. Therefore, the “Just Accepted” Web site may not include all articles that will be published in the journal. After a manuscript is technically edited and formatted, it will be removed from the “Just Accepted” Web site and published as an ASAP article. Note that technical editing may introduce minor changes to the manuscript text and/or graphics which could affect content, and all legal disclaimers and ethical guidelines that apply to the journal pertain. ACS cannot be held responsible for errors or consequences arising from the use of information contained in these “Just Accepted” manuscripts.

Energy & Fuels is published by the American Chemical Society. 1155 Sixteenth Street N.W., Washington, DC 20036 Published by American Chemical Society. Copyright © American Chemical Society. However, no copyright claim is made to original U.S. Government works, or works produced by employees of any Commonwealth realm Crown government in the course of their duties.

Page 1 of 32

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 BOURREL - Page 1

1

Crude oil surface active species: Consequences for enhanced oil

2

recovery and emulsion stability

3

Maurice Bourrel, Nicolas Passade-Boupat

4

Total SA

5

Total E&P – PERL Pôle Economique 2 – BP 47 – 64170 Lacq, France

6

CRUDE OIL SURFACE ACTIVE SPECIES: Consequences for enhanced oil recovery and emulsion stability

ACS Paragon Plus Environment

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 2 of 32 BOURREL - Page 2

1

Abstract

2

The physical-chemistry of the brine-crude oil interface is immensely complex, due to the

3

complexity of the crude itself, and access to the detailed phenomena occurring at this interface is

4

extremely difficult. Understanding these phenomena is however of paramount importance since

5

they are underlying issues encountered in several domains of the oil industry: Reservoir flooding,

6

oilfield emulsion production, so-called “flow assurance”, oil sands processing, emulsion

7

formation in refineries….

8

These problems have prompted a number of studies in academic and industrial research

9

laboratories. A large body of data has been generated, particularly in the areas of oilfield

10

emulsion production and dewatering of bitumen extracted from oil sands by water processing.

11

In a first part questions raised and experimental observations made in reservoir flooding are

12

presented. Some new results in this area are also offered, that may shed some light on

13

phenomena previously described in studies directed towards the dewatering of bitumen removed

14

from oil sands. The spontaneous formation of water microdroplets in the oil phase when gently

15

contacted to water is an example.

16

I a second part, the literature on oilfield emulsion production problems is briefly reviewed, with

17

the limited aim of extracting some features that could be in resonance with reservoir flooding.

18

Roughly, two main types of vision of the mechanisms ruling the partitioning of asphaltenes,

19

resins and naphthenic acids between the interfacial pseudo-phase and the water and oil phases

20

are encountered:

21

•

the complex formation model

22

•

the competition model between these species.

23

Experimental results supporting these models are given. 2573154_File000000_45054302.docx Consequences for enhanced oil recovery and emulsion stability


Page 3 of 32

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


1

Interestingly, both visions can be reconciled in a recently proposed model inspired by analogy

2

with protein film structure. This model incorporates also the experimental observations on the

3

reversibility/irreversibility of asphaltene adsorption at the interface.

4 5

More specifically, it is observed that the knowledge, tools, technologies developed in both areas

6

of reservoir flooding and oilfield emulsion production complement each other. The effect of

7

asphaltene concentration on interfacial properties is another example.

8 9

2573154_File000000_45054302.docx Consequences for enhanced oil recovery and emulsion stability


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


1

Introduction

2

The purpose of this paper is first to present some issues encountered in Enhanced Oil Recovery

3

(EOR) by chemical flooding where the crude oil/brine interface is involved, and then to review,

4

though not extensively, some results reported in the literature treating oilfield production

5

problems where the oil/brine interface plays also a key role. The hope is that some concepts and

6

approaches developed in this area, as well as the immense body of results obtained in the

7

characterization of the oil/water interface, would be helpful to address some EOR issues. The

8

aim of this paper is limited to extract from that literature the relevant information for that

9

purpose. Extensive reviews can be found elsewhere [1-4].

10 11

Brine/crude oil interfacial effects in reservoir flooding

12

Injection of water in reservoirs to maintain the pressure during production is old practice.

13

It can be improved by addition of alkali (caustic, sodium carbonate, ammonia…) to water,

14

triggering the in-situ production of water-in-oil (W/O) or oil-in-water (O/W) emulsions by

15

saponification of acidic species, for example, depending on the type of indigenous surfactants,

16

pH, ionic strength. W/O emulsions increase the oil phase viscosity, and thus the pressure drop ;

17

in the case of O/W emulsions, oil droplets can block some water channels either by interception

18

or by straining [ 5 ], thus reducing the water production by a so-called “conformance” or

19

“diversion” effect.

20

A typical example of the effect of O/W emulsion production during coreflooding is shown in

21

Figure 1 [ 6 ], .



Page 5 of 32

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


1 2 3 4 5 6 7 8

Figure 1: High viscosity oil; brine salinity: 10 g/L NaCl; core: unconsolidated sandstone; the amount of fluid injected is expressed in pore volume (PV) units; OOIP: original oil in place in the core. 3 fluids are successively injected: blue curve: water (yielding 45% recovery of OOIP), red curve: polymer solution at 55.3 cP (+22% oil recovery), green curve: polymer + NaOH solution at 63 cP (+30% oil recovery). Viscosity of polymer solution measured at 7 s-1.

9

It is interesting to note the strong pressure increase when the polymer is injected (from 4 to

10

6 PV), accompanied by oil production, then followed by a decrease, due to water channeling and

11

oil production stopping. On the contrary, when alkali is added to the polymer (from 6 to 8 PV),

12

the pressure decreases right away, despite a strong production of oil, under the form of low

13

viscosity O/W emulsion [ 7 ]. Indeed, it is very likely that the O/W emulsion is created thanks to

14

the saponification of naphthenic acids, or more generally of acidic species of the crude [ 8, 9 ].

15

The hydrophilicity of such naphthenates is known to be very sensitive to salinity. If the salinity is

16

sufficiently increased, the formation of W/O emulsion is expected. This has been reported by

17

Cooke et al. [ 8 ], who carried out series of corefloods at different salinities. They observed the



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


1

formation of a viscous W/O emulsion bank, providing excellent areal sweep efficiency. With the

2

particular oil used, the recovery was found maximum at a salinity on the order of 90 g/L NaCl.

3

To adjust the optimal salinity to the reservoir conditions, it is common practice to add synthetic

4

surfactants to the alkali slug [10, 11].

5

Zhang et al. [ 12 ] compared the oil recovery obtained by injection of alkali only or an alkali-

6

surfactant mixture. They observed a significant pressure drop (~ 180 cm H2O) attributed to W/O

7

emulsion formation with alkali, and an increase of 35% in oil recovery. Addition of 300 ppm

8

surfactant (commercial C5460, Stepan, Canada) decreased the pressure down to ~ 50 cm H2O,

9

by decreasing the emulsion formation, whereas the increase in oil production dropped to only

10

23%. Interestingly, the interfacial tension was measured at ~ 10-1 mN/m with alkali, and at ~ 10-3

11

mN/m with the alkali-surfactant mixture: Despite lower interfacial tension, the surfactant showed

12

to be detrimental to oil recovery because of the decrease in pressure drop. High pressure drop,

13

i.e. high apparent viscosity of the fluids in the core, provides adequate mobility control, more

14

important in the present case than a lowering of interfacial tension.

15

The question arises then as to know if W/O emulsion formation is always desirable for

16

improving oil recovery. A limit is indeed foreseen: Too viscous emulsions will be difficult to

17

propagate in the porous medium, and will give rise to injectivity issues.

18

This has been recently reported by Sun et al. [ 13 ] who observed an unacceptable pressure drop

19

when pure brine (no alkali) was injected (Figure 2), due to coarse W/O emulsion formation.

20

Adding a demulsifier to the brine promoted a large decrease in pressure drop.

21



Page 7 of 32

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


1 2 3 4 5

Figure 2: Effect of adding a demulsifier DEM to brine on the pressure drop. DEM was selected from bottle test. After [ 13 ].

6

Interestingly, and contrary to what obtained by Zhang et al. [ 12 ], in the case at hand oil

7

recovery with the demulsifier was 12% higher than without.

8

Oil/brine interface properties during reservoir flooding are not easy to monitor [14, 15] but they

9

are key for controlling in-situ emulsion formation, as seen above. They are also important to

10

control the snap-off mechanism.

11

Snap-off is the moment when oil continuous filaments break to become oil drops dispersed in

12

continuous water. At that point capillary forces increase strongly. Oil production becomes very

13

difficult and it is crucial to delay that event as much as possible.

14

Alvarado [ 14 - 16 ] has emphasized the relevance of the rheological properties of the W/O

15

interface, and more specifically of the elasticity, to control snap-off.



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


1

Figure 3 shows the effect of the brine salinity on the shear elastic modulus (SEM) of crude oil/brine

2

interface [ 16 ] and SEM is measured over time and is found to increase and reach a plateau when the

3

interface ages. Plateau values are given in Figure 3.

4 5 6 7 8

Figure 3: Effect of brine salinity (Na2SO4) on the plateau value of the shear elastic modulus of WG oil/brine interface. Similar behavior has been observed by Chávez et al. [[ 17 17 ] in a different range of salinity (NaCl).

9

Decreasing the brine salinity increases significantly the interface shear elastic modulus. In

10

parallel, observations in micromodels have shown that snap-off is retarded when the salinity is

11

lowered [ 16 ]. Finally, corefloods run on Berea sandstones yielded improved oil production

12

when salinity was decreased [ 16 ].

13

Such incremental oil recovery, sometimes obtained at the lab scale by injection of low salinity

14

brine (typically a few g/L) compared to high salinity (typically 100 g/L and above), has

15

prompted a strong interest in the oil industry since 20 years [ 18 ]. A number of laboratories are

16

involved to identify the mechanisms controlling the low salinity effect, in order to be able to

17

select reservoirs eligible to that technology, based on scientific grounds. Several mechanisms

18

have been listed and investigated, but so far none of them seems both necessary and sufficient to

19

predict the occurrence of the effect. 2573154_File000000_45054302.docx Consequences for enhanced oil recovery and emulsion stability


Page 9 of 32

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


1

As seen above, the sensitivity of the rheological properties of the water-oil interface to salinity

2

has received attention. The impact of various components of the crude oil has been investigated [

3

19, 20 ]. Naphthenic acids are found to decrease the elastic modulus, while asphaltenes do the

4

reverse (see Figure 13 below and discussion).

5

Sohrabi and co-workers [ 21 ] have observed the water-oil interface when a crude oil is carefully

6

contacted with low salinity water. Water particles stabilized by indigenous oil amphiphilic

7

species, so-called “micro-dispersions”, appear spontaneously on the oil side of the interface

8

where they accumulate. These micro-dispersions were believed to play a role in the oil recovery

9

by low salinity waterflooding.

10

To illustrate the relevance of the micro-dispersions, the particles were removed from the oil

11

phase and imbibition experiments were carried out in cores containing the original oil on the one

12

side, and the oil deprived of the particles on the other side. The results are reported in Figure 4.

13 14 15 16 17 18 19

Figure 4: Oil production over time during spontaneous imbibitions experiments. LS with (without) particles stand for Low Salinity on original oil (on treated oil) in the core. “High salinity” brine imbibition is carried out on original oil. The red arrow shows the recovery difference between the oils with and without microdispersions. The blue arrow indicates the effectiveness of introducing low salinity brine compared to high salinity brine in this system. After [ 21 ]. 2573154_File000000_45054302.docx Consequences for enhanced oil recovery and emulsion stability


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


1 2

As can be seen, low salinity is more effective than high salinity to produce oil, including from

3

the kinetic point of view. The effect of removing the particles is also clearly apparent in the case

4

at hand.

5

According to the authors, reservoir containing crude oils displaying micro-dispersions when the

6

oil is contacted with low salinity brine are potential good candidates for the low salinity process.

7

We have run such oil-water contact experiments with 5 crude oils, differing by their viscosity

8

and their acido-basicity [ 22 ]. The acido-basic character is determined by measuring the

9

equilibrium pH of water, at different initial pH, contacted with the crude.

10

The results are shown in the photographs of Figure 5 [ 23 ].

11 12 13 14 15

Figure 5: Interface observation 48h after contact. T = 50°C. Left tubes: 242 g/L Nacl. Right tubes: 2g/L NaCl. The viscosity is indicated below each couple of tubes.

16

Some brownish or greyish material (not characterized) appears on the oil side of the interface in

17

every low salinity tube, in various quantities, small for crude C, which is the more viscous. It is



Page 11 of 32

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


1

to be noted that the kinetics of formation of these -likely- micro-dispersions varies from one

2

crude oil to another. As expected nothing happens at high salinity.

3

In an attempt to identify the driving force for the transfer of water into the crude (diffusion and

4

stranding, interfacial turbulence…) a “synthetic crude” has been prepared, Toluene containing

5

2% asphaltenes, which has then be contacted to water in a capillary tube. The asphaltenes are

6

heptane extracted from a heavy oil sand bitumen, of the acido-basic type. The interface is

7

observed continuously by optical microscopy. A picture is shown in Figure 6 [ 23 ].

8 9 10 11 12 13

Figure 6: Water-oil interface after gentle contact in a square capillary tube. Optical microscope observation. The particules are on the micrometer size. Oil: Toluene + 2% asphaltenes ; water: 2g/L NaCl. Room temperature. The oil phase is at the top of the photograph

14

Water particles appear spontaneously and grow in the oil phase. Their amount increases with the

15

asphaltene concentration. It can be conjectured that such a phenomenon occurs also at the water-

16

crude oil interface during contact angle or interfacial tension measurements (see below [ 35 ]).

17 18

Another situation where surface active species contained in crude oils enter into play is indeed

19

when surfactant formulations are designed for chemical EOR applications. This is generally 2573154_File000000_45054302.docx Consequences for enhanced oil recovery and emulsion stability


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


1

carried out by observing the phase behavior of surfactants-brine-oil mixture, looking for Type I –

2

Type III – Type II transition in Winsor’s nomenclature [ 24 ]. This can be achieved by scanning

3

any of the formulation parameter: Salinity, pH, temperature, surfactant structure… [ 25 ]. Type

4

III systems, where a microemulsion phase is in equilibrium with both excess oil and water

5

phases, is looked for, since it is the state where ultra-low interfacial tensions (below 10-2 mN/m)

6

are encountered.

7

Figure 7 displays the phase behavior observed in pipettes when salinity is varied [ 26 ].

8 9 10 11 12

Figure 7: Effect of salinity (NaCl) on phase behavior. Water-Oil ratio: 1; 0.75% C16-17[PO]7SO4, 0.25% C15-18IOS, 2% SBA with WT Crude Oil with and without sodium carbonate. From [ 26 ]

13

One of the criteria to evaluate the quality of a surfactant formulation for EOR is the rate of

14

separation of the phases in pipettes [ 26 ] : The quicker the separation, the easier the transport in

15

porous media (coarse stable emulsions are to be avoided-see Figure 2). Co-surfactants (short 2573154_File000000_45054302.docx Consequences for enhanced oil recovery and emulsion stability


Page 13 of 32

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


1

chain amphiphilic molecules such as alcohols) are often used to facilitate phase separation. In

2

alkali free system, coarse emulsions appear which slow down equilibrium. Adding Na2CO3 to

3

the brine allows the phases to separate much quicker, with a clear Type III system appearing at

4

34 g/L NaCl (so called optimum salinity).

5

It is conjectured that naphthenic acids are converted to naphthenates by the alkali. These

6

naphthenates participate then to the water-oil interface, create disorder, increase the fluidity of

7

the interface and facilitate phase separation [ 25 ].

8 9

Brine/crude interfacial effects in oilfield emulsion production

10

Producers of conventional oil have to face several challenges. Preventing coarse emulsion

11

formation or selecting the best demulsifier are two of them. Similarly, the extraction of bitumen

12

from oil sands by the water process produces water-in-oil emulsions, the dewatering of which is

13

very challenging. It is thus mandatory to understand the mechanisms underlying emulsion

14

formation, and therefore to focus on the brine-crude oil interface.

15

As pointed out by P. Kilpatrick [ 1Error! Reference source not found. ], many hundreds of

16

papers have addressed that topic, and a large body of work has been devoted to characterize

17

interfacial films and emulsions encountered both in conventional oil production and in oil sands

18

exploitation. It is not the aim of this paper to execute an exhaustive review of this literature, but

19

rather to extract some features that could be in resonance with oil recovery issues.

20

The interfacial film at the boundary between crude oil and water comprises a number of

21

compounds: Asphaltenes (A), resins (R), naphthenic acids (NA), maltenes (M) and possibly

22

synthetic surfactants (S). It can be conveniently considered as a pseudo-phase, allowing transfers

23

of species to the bulk oil and water phases to reach equilibrium. Two main types of vision of the



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


1

mechanisms ruling the partitioning of asphaltenes and naphthenic acids between the interfacial

2

pseudo-phase and the oil and water phases are encountered in the literature:

3 4 5

•

A-R/NA complex formation model

It is well described in Figure 8 [ 27 ].

6 7 8 9 10

Figure 8: Dominant contributors to asphaltene solubility, state of aggregation, and the resulting impact on interfacial activity.

11

A and R aggregate depending on relative amounts and solvent aromaticity, forming a complex

12

[A-R]. Then, a particular combination favors the adsorption of [A-R] at the interface, promoting

13

emulsion stabilization: Very strongly solvated asphaltenes partition preferentially in the oil



Page 15 of 32

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


1

phase, while weakly solvated asphaltenes precipitate. Similar view is shared by other authors

2

[ 28 ].

3 4

•

A, R/NA (and Surfactant S) competition model

5

A and R/NA (and S) are considered as independent species, each with its own partitioning

6

coefficient between pseudo-phases. The partitioning coefficient of A, particularly, depends on

7

solvent aromaticity. Also, the adsorption dynamics matters [ 29 - 32 ].

8 9

One of the outcomes of both models is to discuss the reversibility of the asphaltene adsorption at

10

the interface, very often considered as responsible of the stability of W/O emulsions in

11

production.

12

On the one side, the characterization of asphaltenic films has addressed their physical properties,

13

and mobilized a number of techniques: Rheological/mechanical properties, dynamic interfacial

14

tension, surface pressure isotherms… and indeed analytics. The effect of additives has been

15

thoroughly investigated.

16

On the other side, emulsion stability has been extensively studied through water separation

17

measurements: Bottle tests, centrifugation, electrical field…, often with the purpose of finding

18

appropriate demulsifier.

19

Some studies have established a correlation between both aspects, which are briefly reviewed in

20

what follows.

21 22

A very powerful and popular technique to investigate the fundamentals of brine-crude interface

23

consists in measuring the shape change of a drop of oil in water, or the reverse, under

24

solicitation. Micro-pipettes or drop tensiometers are tools of choice to measure film 2573154_File000000_45054302.docx Consequences for enhanced oil recovery and emulsion stability


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


1

“mechanical” properties, dilatational rheology, dynamic interfacial tension and film

2

compressibility.

3

In their pioneering work, Yeung et al. have shown the formation of a rigid film at the water-oil

4

interface [ 33 ]. A drop of water is blown in a diluted bitumen solution (Figure 9).

5 6 7 8 9 10

Figure 9: a) Drop of water in oil after blowing from a micropipette. b) Deflating the drop after 3mn. The continuous phase is heptol (1:1 mixture, by volume, of n-heptane and toluene) containing 0.1% bitumen.

11

When the droplet is deflated and its area compressed, the surface crumples abruptly, revealing a

12

rigid cortical structure. Crumpling was observed for bitumen concentration ranging from

13

0.001 to 1%. Crumpling is indeed a signature of the surface active species present in the crude,

14

which can be characterized by a “crumpling ratio” Ac/Ao. Ac is the drop area at crumpling and

15

Ao is the initial drop area [ 34 ]. When the deflation is repeated for bitumen concentrations above

16

1%, up to 10%, the interface loses its rigidity and remains spherical (Figure 10a). 2573154_File000000_45054302.docx Consequences for enhanced oil recovery and emulsion stability


Page 17 of 32

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


1 2 3 4 5

Figure 10: Deflating a water drop in a 10% bitumen solution. No interfacial crumpling is observed. The arrow in Figure 10c points to several droplets that have just come off the interface.

6

As noted by the authors in a companion paper [ 35 ], at some point during deflation, small

7

surface protusions resembling goose bumps begin to appear on the droplet surface (Figure 10b).

8

On further reduction, they result in formation of micrometer-sized water droplets that eventually

9

detach from the original mother drop (Figure 10c). Such a process is irreversible. Furthermore, it

10

is noted that after several minutes of the deflation experiment, the initially clear oil phase



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


1

becomes polluted with small roughly 1µm water droplets that are clearly visible in the

2

background in Figure 10.

3

According to the authors, the absence of micrometer droplets in the conditions of Figure 9 would

4

be due to the mechanical resistance to shear, due to the rigid film formation, which does not form

5

in conditions of Figure 10. No explanation is given however as to why the film appears at low

6

bitumen concentration and does not appear at high bitumen concentration.

7

Besides, the formation of micro-droplets is attributed to the area reduction possible in Figure 10.

8

It can be hypothesized that the “micrometer-sized water droplets” observed here are similar to

9

the “micro-dispersions” described above in Figure 5 and Figure 6. As indicated, the amount of

10

particles created increases with the asphaltene concentration. It is then possible that, at high

11

bitumen concentration, the rate of micro-droplets formation is higher than the rate of interfacial

12

film building.

13

Another concern is the role of interface area reduction in micro-droplets formation. No change in

14

the macroscopic interface area is achieved in Figure 5 and Figure 6. Moreover, some micro-

15

droplets are already visible in the background of Figure 10a. This factor, i.e. the interface area

16

reduction, thus may not be first order in the advent of the micro-droplets in the oil phase.

17

Investigating the effect of Naphthenic Acids on the critical bitumen concentration for rigid film

18

formation, Wu [ 36 ] observed that at high enough bitumen concentration, the flexibility of the

19

interface was due to the NA presence. At low bitumen concentration, the NA content was not

20

high enough to provide interfacial flexibility.

21

The deflation experiment has been nicely exploited by Yarranton et al. [ 37 ] to evaluate the

22

interfacial film compressibility, in relation with the adsorption of indigenous surface active

23

species, and of synthetic surfactants [ 38 ].



Page 19 of 32

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


1

The surface pressure, difference between the interfacial tension of the system with surface active

2

molecules and the interfacial tension of the pure solvent, is calculated from interfacial tension

3

measured at each film ratio A/Ao, where A is the area of the drop as the fluid is withdrawn from

4

the drop in steps (step wise compression of the interface) after a specified aging time. Crumpling

5

may occur at some point. A typical result is shown in Figure 11 [ 38 ].

6 7 8 9 10

Figure 11: a) Surface pressure for diluted bitumen (10%) in 25:75 heptol versus aqueous surfactant (AOT) solution. b) Emulsion stability for the same solutions (60°C). Emulsions contained 40% aqueous phase. After [ 38 ].

11

The interfacial compressibility was calculated from the slope of the curves in Figure 11(a): The

12

steeper the curve, the lower the compressibility with no additive. The surface pressure isotherm

13

exhibits an abrupt change of slope when the drop area decreases (low film ratio), i.e. the

14

compressibility becomes very small (film very rigid). Ultimately, the film crumples. When 500

15

ppm of AOT surfactant are added to the water drop, the surface pressure isotherm becomes flat:

16

The film becomes highly compressible, and no crumpling is observed. The absence of a

17

crumpling point indicates a “reversibly adsorbed” film, where the additive can leave the interface

18

during compression. Comparing these results to those obtained with pure AOT, the authors 2573154_File000000_45054302.docx Consequences for enhanced oil recovery and emulsion stability


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


1

concluded that AOT replaces asphaltenes on the interface. Interestingly, emulsion stability has

2

been studied on the same systems. Since the addition of AOT eliminates the crumpling point,

3

AOT is expected to decrease the stability of emulsions. This is clearly confirmed in Figure 11(b).

4 5

As mentioned earlier, the stability of oilfield emulsions is generally considered to be due in part

6

to a barrier to coalescence attributed to adsorbed asphaltenes at the interface.

7

The rigidity of the interface, besides by film compressibility, can be assessed by measuring its

8

rheological properties. Oscillatory drop shape analysis is a convenient technique, measuring the

9

dilatational rheological properties.

10

Bouriat et al. [ 39 ] have shown that asphaltenes dissolved in cyclohexane build at the water-oil

11

interface a two dimensional network by a universal process of aggregation. This network exhibits

12

a glass transition zone and behaves as a gel near its gelation point. Same results were obtained

13

with a crude oil [ 40 ].

14

They then extracted with water some indigenous species from this crude oil. This water was then

15

put in contact with cyclohexane to measure the rheological properties of the interface.

16

Interestingly, the water soluble species produced the same type of rheological behavior: That of a

17

gel near the gelation point [ 41 ]. They also demonstrated that such a behavior can be displayed

18

by other chemical compounds, like surfactants dissolved in water [ 42 ]. The correlation between

19

the interface rheological properties and emulsion stability was investigated: The higher the gel

20

strength and the glass temperature of the gel, the higher the stability of the emulsion [ 43 ].

21

As seen above, surface active species coming either from the oil phase or from the aqueous

22

phase, possibly in competition, can contribute to the interfacial mechanical properties and, as a

23

consequence, to emulsion stability. A further example is provided in Figure 12 [ 44 ].



Page 21 of 32

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


1 2 3 4 5

Figure 12: Assessment of skin formation at Na Naphthenates solution droplet surfaces in 0.1% heptol (50/50)-diluted bitumen as a function of Na Naphthenate concentration. After [ 34 ].

6

Na Naphthenates commercially available are dissolved in the water phase. When their

7

concentration increases, the crumpling ratio is reduced: It is apparent that large concentrations

8

mitigate the development of interfacial rigidity. According to the authors, high crumpling ratios

9

indicate that large, asphaltene-like molecules are adsorbed, potentially irreversibly, at the

10

interface. Alternatively, low crumpling ratios indicate low adsorption of indigenous molecules,

11

the Na Naphthenates having fast adsorption-desorption kinetics, thus reversibly adsorbed,

12

dominate at the interface.

13

Regarding the discussion on the reversibility of asphaltene adsorption, it must be noted however

14

that very often in the experimental conditions aiming at characterizing the mechanical properties

15

of the interface such as above, the interfacial film is not yet formed when “additives” come into

16

play. Disrupting a rigid skin once formed could be kinetically very slow, as seen in Langmuir

17

trough experiments [ 44 ].



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


1

A model capturing most of the features of the above-discussed interfacial film has recently been

2

proposed by L. Ligiero [ 45 ], inspired by analogy with protein film structure [ 46 ], and

3

represented in Figure 13.

4 5 6 7 8

Figure 13: Schematic of a water/crude oil interface with interconnected elastic islands and holes filled with unconnected species that are more able to adsorb/desorb from the interface.

9

The interfacial film is viewed as irregular, with holes in its structure.

10

Additives may occupy holes in the structure, and exchange with volumic phases. This would be

11

the case for demulsifiers, to promote coalescence between water drops dispersed in the oil.

12

Coalescence occurs if a hole is created in the interfacial films surrounding the water pools.

13

According to Kabalnov and Wennerström [ 47 ], this can be achieved provided that the created

14

hole is able to overcome the energy penalty involved in reversing the interfacial curvature

15

(Figure 14).



Page 23 of 32

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


1 2 3 4 5 6 7

Figure 14: a) Plausible conformation of indigenous materials (asphaltenes-asphaltene-resin aggregates) and synthetic additives at the water-oil interface when two water drops approach each other and the formation of a “hole” takes place. Additives are phenolic resin and cross-linked polyurethane. b) Schematic representation of the hole, showing the region of near-zero interfacial curvature. From [ 48 ].

8

At near-zero interfacial spontaneous curvature, the bending energy is small, and thus the energy

9

penalty for creating the hole. This “optimal” condition can be achieved by using appropriate

10

demulsifier additives, that is, by adapting its relative interactions energies with the oil and water

11

phases.



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


1

Figure 15 provides an example: The additive is a phenolic resin containing ethylene oxide (EO)

2

and propylene oxide (PO) in the molecule [ 48 ].

3 4 5 6

Figure 15: Effect of EO + PO content and temperature on the performance of the phenolic resins in bottle tests.

7

An increase in the length of the EO + PO headgroup confers hydrophilicity to the phenolic

8

resins. The results shown in Figure 15 clearly indicate that there is an optimal structure of the

9

resin molecule for optimum performance.

10

Indeed, the optimal molecular structure of the additive depends on the composition of the system

11

(type of oil, salinity, pH…) and on temperature, since its relative interactions with oil and water

12

depend on the system: In Figure 15, the optimal % (EO + PO) is not the same at 30°C and 50°C.

13

This is in complete accordance with the rules for formulating optimized surfactants for chemical

14

EOR [ 25, 50 ] (see Figure 7). Salinity, which decreases the interactions of the surfactant

15

hydrophile with water, can be used for example as a scanning parameter to locate the optimal

16

conditions of a given surfactant [ 50 ].

17

Indeed, the rigidity of the interfacial network described in Figure 13, and the coalescence rate of

18

emulsions, depends on solvent quality, asphaltene type and acidic species combined in so-called

19

“Interfacial Material”, pH, salinity, temperature… 2573154_File000000_45054302.docx Consequences for enhanced oil recovery and emulsion stability


Page 25 of 32

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


1

These factors have been thoroughly studied in the literature, both on emulsion breaking and

2

interfacial film properties [ 2, 4, 32 ]. Figure 16 shows the effect of modifying the solvent quality

3

by changing the heptane-toluene ratio in heptol on emulsion stability [ 27 ].

4 5 6 7 8

Figure 16: Effect of aromaticity (% toluene in heptol mixtures) on emulsion stability of 0.5 wt% asphaltenes in heptol mixed with water. AH and ANS are two types of asphaltenes. After [ 27 ].

9

It can be seen that the oil aromaticity is a primary factor in determining the stability of

10

asphaltene-stabilized emulsions, and that there is a range of aromaticity where maximum

11

stability is observed. These results support the model depicted in Figure 8: Approaching the

12

onset of precipitation increases the chemical potential of asphaltenes and thus their adsorption.

13

Similar conclusion can be reached from the results obtained on interfacial film characterization

14

presented in Figure 17 [ 37 ].



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


1 2 3 4 5

Figure 17: Effect of solvent on surface pressure isotherms for 10 kg/m3 asphaltenes after 60 mn of aging at 23°C and with 30s intervals between compression steps. After [ 37 ].

6

The films in 50/50 heptol show somewhat lower initial compressibility (higher elasticity)

7

compared to 25/75 heptol (75% toluene). According to the authors, a possible explanation is that

8

asphaltenes are more likely to become irreversibly adsorbed in a poorer solvent, leading to less

9

compressible films.

10

The chemical potential of asphaltenes in the solvent is indeed influenced by the presence of other

11

compounds, such as resins, maltenes, naphthenic acids… which interact with them as depicted in

12

Figure 8.

13

The effect of the Resin-Asphaltene ratio is shown in Figure 18 [ 27 ].



Page 27 of 32

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


1 2 3 4 5

Figure 18: Effect of adding resins (varying R/A) from different crudes (AH, SJV, AB, ANS) on emulsion stability. 0.5% asphaltenes (extracted from AH) in 70/30 heptol, mixed with water. After [ 27 ].

6

For R/A ratio ≥ 3, the propensity of the model oils to emulsify decreases to a significant extent.

7

The magnitude of the effect depends on the nature of the resins.

8

Hemmingsen et al. [ 51 ] have investigated the effect of naphthenic acids on emulsion stability.

9

They found that removing them from the crude oil increased the emulsion stability. This could be

10

due, according to the authors, either to the penetration of the acids in the interfacial asphaltenic

11

film, or to an interaction between acids and asphaltenes, improving their solubility in the oil

12

phase. Both mechanisms would concur to decrease the emulsion stability.

13



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


1

Conclusions

2

Problems related to the physical-chemistry of the crude oil/brine interface are faced in two

3

domains of the oil industry: Reservoir flooding and oilfield emulsion production. They have

4

prompted a number of studies in academic and industrial laboratories, especially in the area of

5

conventional oilfield emulsion production and oil sands exploitation.

6

In this paper, some issues encountered in reservoir flooding, believed to be related to water-oil

7

interface physical-chemistry, are listed. They could potentially benefit from the techniques,

8

approaches and knowledge developed for addressing emulsion production problems. The

9

literature on that matter is briefly reviewed, and some features that could be in resonnance with

10

oil recovery issues are identified.

11

Reciprocally, some new results obtained in the framework of reservoir flooding are presented,

12

which shed some light on phenomena observed in studies directed towards oilfield emulsion

13

production.

14 15

Acknowledgments

16

The authors gratefully acknowledge the contribution of P. Bouriat, C. Dicharry, J. Duboué, F.

17

Dubos, A. Feucherolles, A. Klimenko, L. Ligiero, V. Molinier, E. Santanach-Carreras and G.

18

Virenque.

19

They also thank TOTAL management for permission of publishing this work.

20 21



Page 29 of 32

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


1

References

2 3

[1]

Kilpatrick, P.K. Water-in-Crude Oil Emulsion Stabilization: Review and Unanswered Questions. Energy and Fuels 2012, 26, 4017-4026.

4 5

[2]

Langevin, D. ; Argillier, J.F. Interfacial behavior of asphaltenes. Adv. in Coll. Interf. Sci. 2016, 233, 83-93.

6 7

[3]

Ligiero, L. Crude oil/water interface characterization and its relation to water-in-oil emulsion stability. Feb 2017. Ph. Dissertation. Univ. of Pau (France).

8 9 10

[4]

Clingenpeel, A.C. ; Rowland, S.M. ; Corilo, Y.E. ; Zito, P. ; Rodgers, R.P. Fractionation of Interfacial Material Reveals a Continuum of Acidic Species That Contribute to Stable Emulsion Formation. Energy and Fuels 2017, to appear.

11 12

[5]

Soo, H. ; Radke, C.J. The Flow Mechanism of Dilute, Stable Emulsions in Porous Media. Ind. Eng. Chem. Fundam. 1984, 23, 342-347.

13 14 15

[6]

Bourrel, M. ; Levitt, D. ; Santanach-Carreras, E. The potential of Chemical EOR for heavy oils: Investigation through sandpack corefloods and micromodels. 2nd Foro Venezolano de Crudos Pesados. Maturin-2013.

16 17 18

[7]

Levitt, D. ; Jouenne, S. ; Bondino, I. ; Gingras, J.P. ; Bourrel, M. The Interpretation of Polymer Coreflood Results for Heavy Oil. Paper SPE 150566, SPE Heavy Oil Conference, Kuwait City, 2011.

19 20

[8]

Cooke, C.E. ; Williams R.E. ; Kolodzie, P.A. Oil Recovery by Alkaline Waterflooding. J. Pet. Techn. Dec 1974. 1365-1374.

21 22

[9]

Samanta, A. ; Ojha, K. ; Mandal, A. Interactions between Acidic Crude Oil and Alkali and their Effects on Enhanced Oil Recovery. Energy and Fuels 2011, 25, 1642-1649.

23 24 25

[ 10 ] Nelson, R.C. ; Lawson, J.B. ; Thigpen, D.R. ; Stegemeir, G.L. Cosurfactant-Enhanced Alkaline Flooding. Paper SPE/DOE 12672, SPE/DOE 4th Symposium on EOR, Tulsa, 1984.

26 27 28

[ 11 ] Rudin, J. ; Bernard, C. ; Wasam, D.T. Effect of Added Surfactant on Interfacial Tension and Spontaneous Emulsification in Alkali/Acidic Oil Systems. Ind. Eng. Chem. Res. 1994, 33, 1150-1158.

29 30 31

[ 12 ] Zhang, H. ; Dong, M. ; Zhao, S. Which One is More Important in Chemical Flooding for Enhanced Court Oil Recovery, Lowering Interfacial Tension or Reducing Water Mobility? Energy and Fuels 2010, 24, 1829-1836.

32 33 34

[ 13 ] Sun, M. ; Mogensen, K. ; Bennetzen, M. ; Firoozabadi, A. Demulsifier in Injected Water for Improved Recovery of Crudes That Form Water/Oil Emulsions. SPE Reservoir Evaluation and Engineering. Nov 2016, 664-672. 2573154_File000000_45054302.docx Consequences for enhanced oil recovery and emulsion stability


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


1 2

[ 14 ] Guillen, V.R. ; Carvalho, M.S. ; Alvarado, V. Pore Scale and Macroscopic Displacement Mechanisms in Emulsion Flooding. Transp. Porous Med. 2012, 94, 197-206.

3 4

[ 15 ] Moradi, M. ; Kazempour, M. ; French, J.T. ; Alvarado, V. Dynamic Flow response of crude oil-in-water emulsion during flow through porous media. Fuel 2014, 135, 38-45.

5

[ 16 ] Alvarado, V. Private communication, 2014.

6 7 8

[ 17 ] Chávez-Miyauchi, T.E. ; Firoozabadi, A. ; Fuller, G.G. Nonmonanotonic Elasticity of the Crude Oil-Brine Interface in Relation to Improved Oil Recovery. Langmuir 2016, 32, 2192-2198..

9 10

[ 18 ] Tang, G. ; Morrow, N. Salinity, Temperature, Oil Composition, and Oil Recovery by Waterflooding. Paper SPE-3668, SPE Reservoir Engineering 1997, 12(4), 269-276.

11 12 13

[ 19 ] Alvarado, V. ; Garcia-Olvera, G. ; Hoyer, P. ; Lehmann, T.E. Impact of Polar Components on Crude Oil-Water Interfacial Film Formation: A Mechanism for LowSalinity Waterflooding. Paper SPE-170807-MS, SPE ATCE, Amsterdam 2014.

14 15 16

[ 20 ] Garcia-Olvera, G. ; Reilly, T.M. ; Lehmann, T.E. ; Alvarado, V. Effects of asphaltenes and organic acids on crude oil-brine interfacial visco-elasticity and oil recovery in lowsalinity waterflooding. Fuel 2016, 185, 151-163.

17 18 19

[ 21 ] Sohrabi, M. ; Mahzari, P. ; Farzaneh, S.A. ; Mills, J.R. ; Tsolis, P. ; Ireland, S. Novel Insights into Mechanisms of Oil Recovery by Low Salinity Water Injection. Paper SPE172778-MS, SPE Middle East Conference, Manama 2015.

20 21 22

[ 22 ] Passade-Boupat, N. ; Rondon-Gonzales, M. ; Brocart, B. ; Hurtevent, C. ; Palermo, T. Risk assessment of calcium naphthenates and separation mechanisms of acidic crude oil. Paper SPE 155229, SPE Oilfield Scale Conference. Aberdeen, 2012.

23 24

[ 23 ] Duboué, J., Klimenko, A., Santanach Carreras, E., M. Bourrel, F. Lequeux To be published.

25

[ 24 ] Winsor, P.A. Solvent Properties of Amphiphilic Compounds. Butterworths (1954).

26 27

[ 25 ] Bourrel, M. ; Schechter, R.S. Microemulsions and Related Systems: Formulation, Solvency and Physical Properties. Surfactant Science Series, vol. 30. Dekker 1988.

28 29 30

[ 26 ] Levitt, D.B., Jackson A.C., Heinson C., Britton L.N., Malik T., Dwarakanath, V., Pope, G.A., Identification and Evaluation of High Performance EOR Surfactants, SPE-100089PA

31 32 33

[ 27 ] Mc Lean, J.D. ; Kilpatrick, P.K. Effects of Asphaltene Aggregation in Model HeptaneToluene Mixtures on Stability of Water-in-Oil Emulsions. J. Coll. Int. Sci. 1997, 196, 2334.



Page 31 of 32

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


1 2

[ 28 ] Ostlund, J.A. ; Nydén, M. ; Auflem, I.H. ; Sjöblom, J. Interactions between Asphaltenes and Naphthenic Acids. Energy and Fuels 2003, 17, 113-119.

3 4

[ 29 ] Czarnecki, J. ; Moran, K. On the Stabilization Mechanism of Water-in-Oil Emulsions in Petroleum Systems. Energy and Fuels 2005, 19, 2074-2079.

5 6 7

[ 30 ] Ortiz, D.P. ; Baydak, E.N. ; Yarranton, H.W. Effect of surfactants on interfacial films and stability of water-in-oil emulsions stabilized by asphaltenes. J. Coll. Int. Sci. 2010, 351, 542-555.

8 9

[ 31 ] Jeribi, M. ; Almir-Assad, B. ; Langevin, D. ; Hénaut, I. ; Argillier, J.F. Adsorption Kinetics of Asphaltenes at Liquid Interfaces. J. Coll. Int. Sci. 2002, 256, 268-272.

10 11 12

[ 32 ] Poteau, S. ; Argillier, J.F. ; Langevin, D. ; Pincet, F. ; Perez, E. Influence of pH on Stability and Dynamic Properties of Asphaltenes and Other Amphiphilic Molecules at the Oil-Water Interface. Energy and Fuels 2005, 19, 1337-1341.

13 14 15

[ 33 ] Yeung, A. ; Dabros, T. ; Czarnecki, J. ; Masliyah, J. On the interfacial properties of micrometer-sized water droplets in crude oil. Proc. R. Soc. Lond. A. 1999, 455, 37093723.

16 17 18

[ 34 ] Moran, K. ; Czarnecki, J. Competitive adsorption of sodium naphthenates and naturally occurring species at water-in-crude oil emulsion droplet surfaces. Coll. and Surf. A: Physicochem. Eng. Aspects 2007, 292, 87-98.

19 20

[ 35 ] Dabros, T. ; Yeung, A. ; Masliyah, J. ; Czarnecki, J. Emulsification through Area Contraction. J. Coll. Int. Sci. 1999, 210, 222-224.

21 22 23

[ 36 ] Wu, X. Investigating the Stability Mechanism of Water-in-Diluted Bitumen Emulsions through Isolation and Characterization of the Stabilizing Materials at the Interface. Energy and Fuels. 2003, 17, 179-190.

24 25

[ 37 ] Yarranton, H.W. ; Sztukowski, D.M. ; Urrutia, P. Effect of interfacial rheology on model emulsion coalescence. I. Interfacial rheology J. Coll. Int. Sci. 2007, 310, 246-252.

26 27 28

[ 38 ] Ortiz, D.P. ; Baydak, E.N. ; Yarranton, H.W. Effect of surfactants on interfacial films and stability of water-in-oil emulsions stabilized by asphaltenes. J. Coll. Int. Sci. 2010, 351, 542-555.

29 30 31

[ 39 ] Bouriat, P. ; El Kerri, N. ; Graciaa, A. ; Lachaise, J. Properties of a Two-Dimensional Asphaltene Network at the Water-Cyclohexane Interface Deduced from Dynamic Tensiometry. Langmuir 2004, 20, 7459-7464.

32 33 34

[ 40 ] Flesinski, L. Etude de la stabilité des émulsions et de la rhéologie interfaciale des systèmes pétrole brut/eau : influence des asphaltènes et des acides naphthéniques. Déc. 2011. Ph. Dissertation. Univ. of Pau. France.

35

[ 41 ] Flesinski, L.; Bouriat, P.; Dicharry, C., Passade-Boupat, N. 2011. Unpublished. 2573154_File000000_45054302.docx Consequences for enhanced oil recovery and emulsion stability


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


1 2 3

[ 42 ] Anton, N. ; Vandamme, T.F. ; Bouriat, P. Dilatational rheology of a gel point network formed by nonionic soluble surfactants at the oil-water interface. Soft matter 2013, 9, 1310-1318.

4 5 6

[ 43 ] Dicharry, C. ; Arla, D. ; Sinquin, A. ; Graciaa, A. ; Bourriat, P. Stability of water/crude oil emulsions based on interfacial dilatational rheology. J. Coll. Int. Sci. 2006, 297, 785791.

7 8

[ 44 ] Zhang, L.Y. ; Lopetinsky, R. ; Xu, Z. ; Masliyah, J. Asphaltene Monolayers at a Toluene/Water Interface. Energy and Fuels 2005, 19, 1330-1336.

9 10

[ 45 ] Ligiero, L. Crude oil/water interface characterization and its relation to water-in-oil emulsion stability. Feb. 2017. Ph. Dissertation. Univ. of Pau. France. To be published.

11 12 13

[ 46 ] Mackie, A.R. ; Gunning, A.P. ; Wilde, P.J. ; Morris, V.J. Orogenic Displacement of Protein from Air/Water Interface by Competitive Adsorption. J. Coll. Int. Sci. 1999, 210, 157-166.

14 15

[ 47 ] Kabalnov, A.S. ; Wennerström, H. Macroemulsion stability: The oriented wedge theory revisited. Langmuir 1996, 12, 276-288.

16 17

[ 48 ] Peña, A.A. ; Hirasaki, G.J. ; Miller, C.A. Chemically Induced Destabilization of Waterin-Crude Oil Emulsions. Ind. Eng. Chem. Res. 2005, 44, 1139-1149.

18 19

[ 49 ] Bourrel, M. ; Graciaa, A. ; Schechter, R.S. ; Wade, W.H. The relation of Emulsion Stability to Phase Behavior and Interfacial Tension. J. Coll. Int. Sci. 1979, 72, 161-163.

20 21

[ 50 ] Goldszal, A. ; Bourrel, M. Demulsification of crude oil emulsions: correlation to microemulsion phase behavior. Ind. Eng. Chem. Res. 2000, 39, 2746-2751.

22 23 24

[ 51 ] Hemmingsen, P.V. ; Kim, S. ; Pettersen, H.E. ; Rodgers, R.P. ; Sjöblom, J. ; Marshall, A. Structural Characterization and Interfacial Behavior of Acidic Compounds Extracted from a North Sea Oil. Energy and Fuels 2006, 20, 1980-1987.



Crude oil surface active species : Consequences for enhanced oil

Recommend Documents