SPE 166435 Visual Investigation of Oil Recovery by ...

1 downloads 0 Views 3MB Size Report
Visual Investigation of Oil Recovery by Low Salinity Water Injection: Formation of Water Micro-Dispersions and Wettability Alteration. Alireza Emadi1 and Mehran ...
SPE 166435 Visual Investigation of Oil Recovery by Low Salinity Water Injection: Formation of Water Micro-Dispersions and Wettability Alteration 1

Alireza Emadi and Mehran Sohrabi, Centre for Enhanced Oil Recovery and CO2 Solutions, Institute of Petroleum Engineering, Heriot-Watt University Copyright 2013, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in New Orleans, Louisiana, USA, 30 September–2 October 2013. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author (s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract mus t contain conspicuous acknowledgment of SPE copyright.

Abstract Low salinity waterflood (LSW) is a relatively new enhanced oil recovery (EOR) technique which has been reported to improve oil recovery in several laboratory experiments and some field trials. The general assumption among researchers is that LSW shifts wettability towards a more favourable state for oil recovery. Several hypotheses have been introduced in the literature as possible mechanisms involved in oil recovery by LSW e.g. fine migration and flow diversion, multi-component ion exchange (MIE), and rise in pH. However, a consistent theory to explain the process of wettability modification has not yet emerged. This paper presents the results of a comprehensive set of direct visualization (micromodel) experiments which investigate the low salinity effect (LSE) from a novel perspective. The visualization study, using reservoir-condition micromodels, shows that when low salinity brine comes in contact with certain crude oils, a large number of water micro-dispersions form at the oil/water interface within the oil phase. The formation and precipitation of these micro-dispersions can only be seen under high magnifications using our imaging system specifically designed for thin micromodels. The water micro-dispersions do not form when the oil is in contact with a high salinity brine and when they form due to low salinity of the brine, they coalescence as soon as the oil comes in contact with a high salinity brine. In our micromodel tests, when a mixed-wet micromodel and high salinity connate water were utilized, the formation of these micro-dispersions was associated with a slight change in the wettability and redistribution of fluids. We hypothesize that formation of the micro-dispersions results in additional oil recovery through two separate mechanisms; (1) depletion of the oil/water interface from natural surface active materials, resulting in wettability alteration and, (2) swelling of droplets of high salinity connate water. The results of this study introduce water/oil interactions and formation of water micro-dispersions as a potential mechanism for wettability alteration and improved oil recovery in low salinity water injection. Introduction Improved oil recovery by injection of LSW was first reported by Tang and Morrow (1997). Since then, there has been a substantial volume of research on the low salinity effect (LSE) to explore its potential as an enhanced oil recovery technique and to understand the underlying mechanisms. Whilst it is generally accepted that lowering brine salinity can improve basic waterflood performance in certain conditions, a consistent mechanistic explanation has not yet emerged. In part this may be the result of the use of different materials and variations in test procedures in different laboratories. The complexity of the rock minerals, crude oils, and aqueous phase compositions and the interactions among all these phases also contribute to the confusion about the cause of LSE. The variety of circumstances under which LSE may or may not be observed suggests that more than one mechanism may be in play. (Morrow and Buckley 2011; Cissokho et. al. 2009).

1

Now in COREX Uk Ltd

2

SPE 166435

Tang and Morrow (1999) identified necessary conditions for LSE in Berea-sandstone cores, as follows;  significant clay fraction,  presence of connate water,  exposure to crude oil to create mixed-wet conditions. According to Lager et al. (2008, 2009), for low salinity waterflood to be effective formation water should contain divalent cations e.g. Ca2+ and Mg2+. It should be noted that, while these conditions are necessary for the types of sandstones investigated, they are not sufficient; many outcrop sandstones meeting these conditions have not shown LSE recovery (Morrow and Buckley 2011). The general assumption among researchers is that injecting low salinity brine creates a wetting state more favourable to oil recovery e.g. increased water-wetness. Wettability affects the microscopic distribution and flow of oil and water in porous media and thus the residual oil saturation. Evidence for change in wettability, however, is often indirect, such as from changes in relative permeability curves or centrifuge capillary pressure (Morrow and Buckley, 2011). The more accepted hypotheses for mechanisms responsible for wettability alteration are: 1) Multi-Component Ion Exchange (MIE): Experimental observations by Lager et al. (2006) showed that additional oil recovery by low salinity waterflood occurs only if formation water contains divalent cations (Ca2+). Thus, it was suggested that the presence of Mg2+ and Ca2+ plays an important role in the interaction between the clay minerals and surface active components in the crude oil. An adsorption model was suggested in which oil polar compounds are bonded to negatively charged clay surface either through multivalent cation bridges or directly adsorbed onto the mineral surface. When low salinity water is injected, the organo-metallic complex and directly adsorbed polar compounds are replaced by cations present in dilute brine and the system is evolving towards a more water-wet state. 2) Expansion of Electrical Double Layers: Ligthelm et.al. (2009) suggest that by lowering overall salinity level and especially reduction of the multi-valent cations in the brine solution, the electrical diffuse double layers that surround the clay and oil surfaces expand, which in turn yields increased electrical repulsion between the clay particles and the oil blobs. Once the repulsive forces exceed the binding forces, the oil particles maybe desorbed from the clay surfaces. This would result in a reduction in the fraction of rock surface that has been coated by oil and this in turn implies a change in the wetting state towards increased water-wetness. Along with these two predominant mechanisms, several other mechanisms have been proposed by researchers and discussed in the literature. Some of the most important mechanisms are: 1) Migration of Fine Particles: Tang and Morrow (1999) suggest that the low salinity water could release clay fragments, socalled fines, which could be transported along the oil-water interface. The release of clay particles will improve the water wetness of the clay minerals, but perhaps even more importantly, the released clay particles can block pore throats and divert the flow of water into unswept pores to improve the microscopic sweep efficiency. This phenomenon of fine migration during low salinity injection is well-known and explained by DLVO theory of colloids. It is also associated with permeability reduction resulting from pore throat plugging. Boussour et al. (2009) found that although several experimental observations are in agreement with this interpretation, contradictory results with additional oil recovery without permeability reduction and no fine production exist in the literature (Boussour et. al., 2009). 2) Salt-in Effect: The solubility of organic material in water can be drastically decreased by adding salt to the solution, i.e. the “salting out” effect, and the solubility can be increased by removing salt from the water, i.e. the “salting in” effect. RezaeiDoust et. al. (2009) suggest that some organic material will be desorbed from the clay by a “salting in” effect and in this way improving water-wetness of the clay. This mechanism is based on the assumption that recovery improvement is linked to a shift of wettability towards more water-wet conditions. Further tests, however, did not strongly support the impact of the salt-in effect on oil recovery by low salinity waterflood. 3) pH Elevation: McGuire et al. (2005) propose that pH elevation and saponification of surface active agents in the oil can result in generation of natural surfactants and recovery improvement through reduction of interfacial tension. However, other researchers (Boussour et. al. 2009, Lager et al. 2006) have argued that low salinity flooding has reduced residual saturation in cores containing crudes with extremely low acid numbers where alkaline-like waterflooding cannot be effective. Additionally, the oil/brine interfacial tension of the effluent is generally too high for increased recovery to be accounted for by saponification of oil components. Austad et al. (2010) introduced a new mechanism which is based on desorption of oil due to a localized increase in the pH at the clay surface. The localized increase in the pH is caused by

SPE 166435

3

desorption of active cations, especially Ca2+, as the low saline injection water invades the porous medium. The increase in pH will remove adsorbed acidic and basic material from the clay surface and increase the water wetness of the rock. None of the suggested mechanisms have received a general acceptance in the scientific literature so far. There were always evidences against the proposed mechanisms among the experimental facts (Austad et al. 2010, Boussour et. al., 2009). The main body of the experimental work performed on the subject of LSW consists of coreflood experiments, where the change in wettability is inferred through indirect observations (change in kro and krw), or through separate wettability tests. The most direct, but less frequently used, techniques of wettability investigation are spontaneous imbibition and flow visualization tests. While there are a few spontaneous imbibition tests reported in the literature, the use of glass micromodels for the purpose LSW has attracted much less attention. This is mainly due to the assumption in the early literature that presence of significant clay fraction (Tang and Morrow 1999) is required for improved recovery by low salinity waterflooding. However, the recent works show advantages of low salinity waterflooding even in the clean and carbonate systems without or with very low clay content (Pu, et. al. 2008; Yousef et al. 2011). Visualization (micromodel) tests can provide us with valuable direct and real time evidence and analysis of the wettability while the low salinity water is injected under different injection strategies. Additionally, possible interactions between crude oil and low salinity brine (if any exist) can be visually detected and compared to the case of high salinity waterflooding. This can improve our understanding of the pore-scale mechanisms involved in oil recovery by LSW and help develop a theory to predict the performance of LSW. The insights obtained from these micromodel experiments should help us designed better core flood experiments to validate pore scale observations and to quantify the impact of mechanisms observed during visual studies In the Low Salinity Water Injection Joint Industry Project (JIP) at Heriot-Watt University, we are investigating the mechanisms of oil recovery by LSW through a series of visual experiments using our state-of-the-art experimental facilities. In our research approach the physical processes and microscopic mechanisms involved in oil displacement by LSW are first visually studied under reservoir conditions in transparent porous media (micromodels). The micromodel experiments are supported by wettability and fluid characterization experiments and the significance of the observed mechanisms is then further studied and quantified by core flood experiments carried out under simulated reservoir conditions. The results of these experiments are used to evaluate the performance of low salinity water injection and to study the impact of various pertinent parameters and how these parameters can be altered or tuned to maximize oil recovery. The direct visualization (micromodel) results presented in this paper show a unique interaction between low salinity brine and crude oil which results in formation of a large number of water micro-dispersions within the oil phase. We believe that formation of these water micro-dispersions contributes to oil recovery through two mechanisms which are explained in following sections. Experimental Facilities A high-pressure micromodel rig was used to perform the visualization experiments. Details of the micromodel rig can be found elsewhere (Sohrabi et al., 2000). Micromodel is a two-dimensional pore structure, which is etched onto the surface of a glass plate, which is otherwise completely flat. A second un-etched optically flat glass plate is then placed over the first, covering the etched pattern and thus creating an enclosed pore space. This second plate, the cover plate, has an inlet hole and an outlet hole drilled at either ends, allowing fluids to be displaced through the network of pores. Because the structure is only one pore deep, and the containing walls are all glass, it is possible to observe the fluids as they flow along the pore channels and interact with each other. It is also possible to observe how the geometry of the pore network affects the patterns of flow and fluid trapping. In this study, a geometric pattern micromodel (Figure 1a) was used for the first three tests at pressure and temperature of 600 psig and 44 °C and a relatively homogenous rock-look-alike pattern micromodel (Figure 1a) was used for the rest of micromodel tests at pressure and temperature of 2300 psig and 38 °C.

4

SPE 166435

b

a

38 mm

Figure 1: Pictures of the geometric (a) and rock-look-alike (b) micromodels fully saturated with blue dyed water. Pores are shown in blue and un-etched glass in white.

Fluids The brine solutions used in the micromodel tests reported here are all synthetic brines, consisting of NaCl and CaCl2 at different concentrations and ratios. In Tests 1 to 3, the low salinity water and the high salinity water used have a total concentration of 500 and 30,000 ppm, respectively and only consist of NaCl. In experiments 4 and 5 the low salinity water and high salinity water have a total salt concentration of 2000 and 30,000 ppm, respectively and consist of NaCL and CaCl2 with a mixing ratio (weight ratio) of 4 to 1. The crude oil sample used in this study and its basic properties are listed in Table 1.

6 mm

Table 1: Basic properties of the crude oil sample used in this study.

API

Viscosity (cp)

Asphaltene Content (wt/wt%)

Acid Number (mg KOH/g)

92.3 @ 50 °C

1.31

2.36

Gravity 19.1

Results Table 2 shows a list of five micromodel tests that will be discussed here. All the presented tests have been performed at least twice, to make sure about repeatability of the results. Table 2: List of micromodel experiments reported in this paper. Test# Experiment Description Wettability 1 Waterflood using high salinity connate and flood water Water-Wet 2

Waterflood using low salinity connate and flood water

Water-Wet

3

Low Salinity Waterflood in Tertiary Mode: Water-Wet System

Water-Wet

4

Reversibility in Water-Wet System

Water-Wet

5

Low Salinity Waterflood in Tertiary Mode: Mixed-Wet System

Mixed-Wet

Aqueous Phase and Procedure Connate Water: High Salinity NaCl brine 1st Waterflood: High Salinity NaCl brine Connate Water: Low Salinity NaCl brine 1st Waterflood: Low Salinity NaCl brine Connate Water: Low Salinity NaCl brine 1st Waterflood: High Salinity NaCl brine 2nd Waterflood: Low Salinity NaCl brine Connate Water: Blue Dyed High Salinity NaCl/CaCl2 brine 1st Waterflood: Blue Dyed High Salinity NaCl/CaCl2 brine 2nd Waterflood: Low Salinity NaCl/CaCl2 brine 3rd Waterflood: Blue Dyed High Salinity NaCl/CaCl2 brine Connate Water: High Salinity NaCl/CaCl2 brine 1st Waterflood: High Salinity NaCl/CaCl2 brine 2nd Waterflood: Low Salinity NaCl/CaCl2 brine

Test 1: In the first micromodel test, the process of conventional waterflooding was physically simulated in which a hig`h salinity brine was used as both connate and flood water. Micromodel was first saturated with high salinity water and then flooded with oil to establish the initial oil and water distribution (Figure 2a). Micromodel was then flooded with high salinity brine which continued for an extended period of time (Figure 2b). Continuation of waterflood (up to 50 PV’s) after breakthrough did not result in any additional oil recovery or changes of fluid distribution in the system.

SPE 166435

a

5

b Flow Direction

Figure 2: Test 1; fluid distribution in a magnified section of the micromodel, after oil flood (a), and waterflood (b) using high salinity brine.

Test 2: The second test was performed using a procedure similar to that of the first test; however, the high salinity brine was replaced by a low salinity brine which was used as both connate and flood water. One important observation in the test was darkening of the colour of the crude oil when it came in contact with the low salinity water. The very highly magnified pictures of the micromodel revealed that this change of colour was in fact a consequence of formation of very fine particles at the oil/water interfaces. When waterflood continued for an extended time period, these dark particles gradually precipitated at the bottom of isolated oil blobs and the colour of the oil became brighter. The red arrows in Figure 3 illustrate the pores in which precipitation of the dark particles is apparent. Nevertheless, the oil/water distribution remained unchanged during the extended period of waterflood. The fact that formation of the dark particles was not observed when high salinity brine was used with the same oil sample (Test 1) shows that formation of dark particles is a consequence of brine salinity.

Flow Direction Figure 3: Test 2; a highly magnified section of the micromodel which clearly shows formation and precipitation of dark particles (water micro-dispersions) in the oil phase during low salinity waterflood in test 2. The red arrows show the locations in which segregation of dark particles is more apparent.

Test 3: In the third test, to simulate the process of low salinity waterflooding in tertiary mode, the high salinity brine was used as connate water. The micromodel was then flooded by crude oil ( Figure 4a) and subsequently by the high salinity brine until a stable oil/water distribution was achieved in the micromodel (Figure 4b). At this point, injection of the low salinity water started and continued for 50 PV’s. Initially, injection of the low salinity brine resulted in darkening of the oil colour and formation of dark particles in those parts of the crude oil which were closer to the flowing path of water (the red arrows in Figure 4c). However, as the injection of low salinity water continued, the dark particles also appeared in the oil blobs which were further away from the path of flowing water. When injection of low salinity water continued for an extended period of time, the dark particles settled and the oil returned to its original colour (Figure 4d), similarly to the observations made in the second test.

6

SPE 166435

b

c

d

Flow Direction

a

Figure 4: Test 3; fluid distribution in the magnified section of the micromodel, after oil flood (a), waterflood using high salinity brine (b), early times of waterflood using low salinity water (c) and after extended period of waterflood using low salinity water (d). The blue arrow in picture (b) shows the flow path of the injected low salinity water and the red dashed arrows show locations in which formation of dark particles take place. The red circles in picture (d) show the locations in which dark particles have been segregated and accumulated.

Test 4: The objective of the fourth micromodel test was to investigate whether the process of formation of the dark particles in the oil phase during low-salinity waterflood would be reversible if low salinity water injection was followed by a period of high-salinity water injection. To distinguish between the high and low salinity brines in the micromodel, a blue dye agent was added to the high salinity brine. The presence of blue dye agenet in the connate water, made the system strongly water-wet despite presence of Ca2+ ions in the brine. In this test, a procedure similar to that of Test 3 was followed; with the exception that the period of low salinity water injection was followed with another period of high salinity waterflood. Similarly to Test 3, injection of low salinity brine resulted in darkening of the oil and then precipitation of the dark particles in the micromodel. Figure 5 shows a magnified section of the micromodel, in which the formation and precipitation of dark particles at the bottom of oil blobs is clear. As can be seen, when the high salinity brine (blue colour) enters this section the precipitated dark particles rapidly disappear. The sequence of images in Figure 5 shows the disappearance of the dark particles is faster in the area closer to the flow path of injected water and it happens in a slower rate in the areas which are further from flow path of the water. One important observation in this experiment was that when the high salinity brine was injected into the system the dark particles which were not in direct contact with injected water also coalesced and disappeared. On some occasions where high concentration of dark particles existed (red dotted circle in Figure 6a), injection of high salinity brine resulted in formation of a droplet of water (red dotted circle in Figure 6b). Formation of water droplets inside the oil phase, after disappearance of the dark particles, implies that the dark particles contain at least a nucleus of water. A detailed discussion on the nature of the observed dark particles is given in the discussion section of this paper, which provides further evidences that supports this idea. Based on this observation and discussions the dark particles are referred to as ‘water micro-dispersions’ in the rest of this text.

SPE 166435

a

7

b

Flow Direction

c

d

Figure 5: Test 4; a highly magnified section of the micromodel (a) at the end of the period of low salinity waterflood in which formation and precipitation of dark particles (water micro-dispersions) in the oil phase can be clearly seen. The red arrows show the locations in which precipitation of dark particles is more apparent. (b) At arrival of high salinity brine to micromodel (blue colour) which results in disappearance of dark particles in the oil blobs which are closer to flowing path of water (blue arrow). (c) After 25 minutes of high salinity brine injection which results in disappearance of all dark particles in this section of the micromodel. (d) after 1 hour of high salinity brine injection which shows no further changes takes place as a result of high salinity brine injection.

8

SPE 166435

Figure 6: Test 4; (a) the red dotted circle shows formation of a large number of dark particles (water micro-dispersions) during low salinity water injection in a highly magnified section of the micromodel. (b) The red arrow shows coalescence of dark particles and formation of a water droplet in the same section of the micromodel during the subsequent period of high salinity water injection.

Test 5: In all previous experiments, the micromodel wettability was slightly water-wet. The objective of Test 5 was to investigate the effect of low salinity waterflood in a mixed-wet system in tertiary mode. Micromodel glass generally shows water-wet tendency and to make it partially oil-wet, special prepration procedure is required e.g. use of multi-valent ions and aging in oil. The micromodel was first saturated with high salinity brine. The micromodel was then flooded with crude oil to establish the initial water saturation and was subsequently aged for 50 PVs (Figure 7a). Micromodel was then flooded by the high salinity brine until a stable oil/water distribution was achieved in the system (Figure 7b). At this point, injection of the low salinity water started and continued for 100 PV’s. Arrival of the low salinity brine in the micromodel was associated with slight darkening of the crude oil colour throughout the micromodel as can be seen in images b and c of Figure 7. As the injection of low salinity brine continued, the response of this mixed-wet system was different compared to the previous water-wet ones. It should be noted that since the system was mixed-wet both water-wet and oil-wet pores could be seen throughout the micromodel. In the pores with water-wet tendency, the water micro-dispersions were formed and segregated and settled at the bottom of the isolated oil ganglia. No redistribution of fluids or any additional oil recovery from this group of pores could be observed. This was similar to the observations made in Test 3. However, in the slightly oil-wet pores, injection of the low salinity brine had different effects and resulted in redistribution of fluids within the pores and additional oil recovery. In the slightly oil-wet pores, the water micro-dispersions were observed to be attached onto the glass (micromodel) surface and they gradually grew larger as injection of low salinity brine continued. The sequence of images Figure 7f show some of the slightly oil-wet pores in the magnified image of a section of the micromodel in which injection of low salinity brine resulted in formation of large droplets of water within the oil and redistribution of the oil. Injection of low salinity brine also resulted in slight wettability change towards more water-wet conditions in the oil-wet pores. Figure 8 shows a magnified image of a section of the micromodel in which change of curvature of oil/water interfaces shows a slight wettability shift towards more water-wet conditions.

SPE 166435

a

9

c 0 0

b

µ m d

e

f

Figure 7: Test5; a highly magnified oil-wet section of the micromodel, (a) at the end of oil flood, (b) after water breakthrough, during 1st period of waterflood using high salinity brine, (c) at arrival of low salinity brine to micromodel, after 50 PVs of high salinity water injection, (d) during low salinity waterflood after 25 PVs of low salinity water injection, (e) during low salinity waterflood, after 50 PVs of low salinity water injection, and (f) at the end of low salinity waterflood, after 100 PVs of low salinity water injection. The blue arrow in picture (b) shows the flow path of the injected high salinity water and the red dashed circles in picture (f) show the locations in which oil displacement has taken place as the result of low salinity water injection.

Figure 8: Test5; A highly magnified section of the micromodel, (a) after high salinity waterflood, and (b) after the subsequent low salinity waterflood. The red arrows in picture (b) show the oil/water interfaces in which change of curvature form slightly oil-wet to slightly water-wet (or neutral-wet) is apparent.

depicts the additional recovery versus pore volume (PV) of injection of low salinity brine during low salinity waterflood in Test 5. The additional recovery is as a result of a combination of enlargement of water droplets (Figure 7) and wettability change (Figure 8). Figure 9

10

SPE 166435

Recovery (Sorw %)

2.0%

1.5%

1.0%

0.5%

0.0% 0

20

40 60 Injection time (PV)

80

100 ]

Figure 9: Test 5; the recovery improvement versus time of low salinity brine injection. The black bars show the errors of the pixel analysis technique which was used to calculate fluid saturation.

Discussions Formation of Water Micro-Dispersions The results of this series of micromodel tests show that there are certain interactions in the oil phase when it comes in contact with low salinity water. These interactions, which were initially described as formation of dark particles, take place if low salinity water is used either as connate water or as flood water, and may result in re-distribution of fluids in the porous media. The immediate change of colour during low salinity water flood (Tests 3, 4 and 5) or during injection of oil in low salinity brine (test 2) is a good indication that formation of dark particles (or water micro-dispersions) is a fast process. A similar change in colour was never observed when the same oil was flooded (or contacted) with high salinity brine which was the case in Test 1. The generated dark particles disappeared when the period of low salinity waterflood was followed with a period of high salinity waterflood. There are several items of evidences that suggest the dark particles are in fact water micro-dispersions and contain a water core: 1) Formation of small water droplets: As was explained in Test 4, when low salinity water injection was followed by high salinity waterflood, the dark particles disappeared in the system and instead small water droplets formed. Formation of water droplets inside the oil phase, after disappearance of the dark particles, implies that the dark particles are micro-dispersions of water in oil. (Figure 7) 2) Magnified Images: Magnified images taken during Tests 3 and 5 show that dark particles are more like small droplets of fluid rather than solid particles in the oil and their concentration is higher around the oil/water interfaces ( Figure 12). 3) Fluid characterization Tests: A comprehensive set of fluid characterization tests (including ESEM, FTIR and Titration) have been performed to analyze the nature of the generated dark particles. The results confirm that the dark particles observed in the micromodel tests are indeed micro-dispersions of water in oil. The results of the fluid characterization tests will be presented in a subsequent paper. The generated dark particles were segregated at the bottom of oil blobs in the water-wet systems (Tests 2 and 3) or remained attached to the glass surface in the oil-wet systems (Test 5). This means the density of dark particles is more than that of oil. It should be noted that segregation of dark particles was a slow process, in comparison to generation of dark particles, and required extended injection or shut-off period. This might be due to high viscosity of the oil which was used in this study or due to low density difference between oil and dark particles.

SPE 166435

11

Figure 10: A highly magnified section of the micromodel which shows formation of water micro-dispersions at the oil/water interface during low salinity waterflood (Test 5).

Based on the micromodel results and fluid characterization tests, we have developed a hypothesis to explain the formation and coalescence of water micro-dispersions as a result of the salinity change in the aqueous phase. It is known that the surface active molecule in crude oil has two functional groups, namely a hydrophilic (water-soluble) or polar group and a hydrophobic (oil-soluble) or non-polar group. The hydrophobic group is usually a long hydrocarbon chain (C8 –C18), which may or may not be branched, while the hydrophilic group is formed by moieties such as carboxylates, sulfates, sulfonates (anionic), alcohols, polyoxyethylenated chains (non-ionic) and quaternary ammonium salts (cationic). When crude oil is brought in contact with brine or water, these natural surfactants accumulate and form an adsorbed film at water/oil interfaces. Due to the affinity that a surfactant molecule encounters towards both polar (aqueous phase) and non-polar phases (oil phase), thermodynamic stability (i.e. a minimum in free energy or maximum in entropy of the system) occurs when these surfactants are adsorbed at a polar/non-polar (e.g. oil/water or air/water) interface (Brady and Krumhansl 2012, Kanicky et al, 2001). The adsorption of surface-active molecules from a bulk phase to a surface or interface is governed by an equilibrium rate constant, and the adsorption occurs at any concentration. If the concentration of a soluble surfactant is increased gradually, the surface concentration also increases and reaches a maximum level at a specific bulk concentration. This specific concentration is called critical micelle concentration (CMC) above which the individual surfactant monomers aggregate and form ‘supermolecular structures’ in aqueous or oil phase. The simplest aggregate of these surfactant molecules is called a micelle which is typical spherical (about 4–10 nm in diameter) and is made of about 100 surfactant molecules (monomers). More complex structures could be spherical, cylindrical, ellipsoidal, hexagonal-packed or disc-like in shape. It should be noted that aggregation of surfactant molecules is a reversible process and these ‘super-molecular structures’ remain in equilibrium with single surfactant monomers in the bulk of the solution (Goyal and Aswal 2001, Kanicky et al, 2001, Takeo 1999). In aqueous phase, surfactant monomers aggregate with their hydrophilic heads pointing outwards towards the solution and the hydrophobic tails pointing inwards. However, if the bulk phase is non-aqueous, inverse micelles may form with polar heads pointing inwards into a water core and hydrophobic tails pointing outwards into the oil (Goyal and Aswal 2001, Kanicky et al, 2001, Takeo 1999). Figure 11 illustrates a schematic of the three environments (adsorbed film, monomer and, micelle) in equilibrium.

12

SPE 166435

Figure 11: Schematic representation of the three environments (adsorbed film, monomer and, micelle or W/O micro-dispersions) in which surfactant molecules reside in oil phase.

Several parameters, including temperature, pH and ionic strength of the brine can affect the equilibrium between monomer and micelle in a specific water/oil system (Goyal and Aswal 2001, Kanicky et al, 2001, Takeo 1999). The intermolecular forces between surfactant (hydrophilic end) and water molecules are typically weak and can be easily modified by increasing or decreasing salt concentration (Goyal and Aswal 2001). If the ionic strength of the water is lowered (low salinity level), polar components may leave the oil/water interface towards the bulk of the oil phase. This results in formation of a large number of reverse micelles (water micro-dispersions) as was observed in the micromodel tests. When high salinity water is injected into the system again, the polar components leave the bulk of the oil phase and return to the oil/water interface. Therefore, the micro-dispersions become unstable and collapse and their water cores produce droplets of water as was observed in Test 4. Two main mechanisms were observed to contribute to oil recovery during low salinity brine injection in Test 5: 1. Wettability a;teration towards more water-wet conditions in some oil-wet pores (Figure 8), 2. Formation and growth of droplets of water inside the oil phase which eventually results in change of oil distribution and oil displacement (Figure 7). The relation between formation of water micro-dispersions and above mentioned recovery mechanisms is explained in the following sections. Wettability Alteration The wettability preference of the oil/brine/rock system is a function of the state of the equilibrium between the repulsive forces and the binding forces on the oil/brine and rock/brine interfaces. Once the repulsive forces exceed the binding forces, the oil may be desorbed from the rock surface, contributing to the wettability modification toward more water-wet and if the binding forces overcome the repulsive forces, the system may become more oil-wet. Two approaches have been introduced in the literature to explain the wettability alteration process during low salinity water injection (as explained in the Introduction section); (1) double layer expansion due to lower ionic strength of water which strengthen the repulsive forces between oil/brine and rock/brine interfaces and, (2) breaking of water/oil adsorption bonds through Multicomponent Ionic Exhchnage (MIE) which weakens the binding forces between oil/brine and rock/brine interfaces. As was explained in the previous section, injection of low salinity brine results in release of surface active agents from oil/water interfaces and formation of water micro-dispersions. This alters the oil surface charges which itself may change the balance between repulsive and binding forces between the oil and the rock surface. For instance, if the surface active agents that are released from the surface of the oil are positively charged compounds (e.g. basic components), this results in a more negatively charged oil/brine interface. This not only changes the electrical double layers around the oil interfaces (expansion of electrical double layers) but also breaks some of the oil/water bonds which is schematically shown in Figure 12 (Brady and Krumhansl 2012, Hadiaet al. 2012.)

SPE 166435

13

Rock Surface

Rock Surface

Figure 12: Schematic of breaking of water/oil adsorption bonds due to depletion of oil/brine interface from surface active agents (a) elimination of negatively charged organic compounds at the oil/water interface and (b) remobilization of trapped oil.

Swelling of Connate Water Droplets Another mechanism which contributed to oil recovery during the period of low salinity water injection in Test 5 was formation and swelling of existing water droplets in the oil. Detailed study of this phenomenon in the micromodel suggests that the difference in equilibrium between reverse micelles and adsorbed monomers is the driving force for this mechanism. Figure 13 shows a schematic of this recovery mechanism, in which (a) shows distribution of crude oil and high salinity connate water in an oil-wet system. Image (b) shows distribution of fluids after waterflood using low salinity brine in which the oil in the interconnected pore has been displaced, while the distribution of oil in the dead end pore has remained unchanged. In this system, water micro-dispersions form at the interface of low salinity brine and crude oil as soon as low salinity brine is injected into the system and coalesce at the interface of high salinity connate water (C). This results in swelling of the droplet of high salinity connate water and remobilization of the oil through the continuous films attached to the pore walls, or through viscous forces. High Salinity Connate Water

Low Salinity Waterflood

a Coelescence of Water Micro-Dispersion

Formation of Water Micro-Dispersion

c

b Swelling of High Salinity Connate Water

d

Figure 13: Schematic of oil recovery process as a result of swelling of water droplets. Image (a) shows an oil-wet pore after oil flood. Picture (b) shows the same pore after breakthrough of low salinity brine. Injection of low salinity brine results in formation of water micro-dispersions at low salinity water/crude oil interface (picture c). Coalescence of water micro-dispersions at high salinity water/crude oil interface causes swelling of water droplet and remobilization of trapped oil (picture d).

14

SPE 166435

Conclusions 1) The results of this series of micromodel tests reveal certain interactions between crude oil and low salinity water which are associated with formation of water micro-dispersions in the oil phase. 2) The observed water micro-dispersions were not formed in the presence of high salinity water and if they had been formed previously (due to contact with low salinity brine) they would coalesce as soon as they came in contact with high salinity brine. 3) Injection of low salinity water resulted in additional oil recovery only when a mixed-wet system and high salinity connate water were used. Injection of low salinity water in the water-wet micromodel did not cause redistribution of fluids. 4) A hypothesis was introduced here in which formation of water micro-dispersion during low salinity waterflood was attributed to release of surface active components from the oil/water interface. 5) Based on the micromodel observations, two mechanisms were presented by which the release of surface active components from oil/water interface and formation of water micro-dispersions could contribute to oil recovery; (1) wettability alteration and (2) swelling of –high salinity - connate water droplets. 6) Release of surface active agents from the oil/water interface alters the balance between binding and repulsive forces between oil/water and rock/water interfaces and may result in wettability change. 7) Formation of water-dispersions at the oil/low salinity water interface and their coalescence at the oil/high salinity connate water interface also results in swelling of connate water and remobilization of the trapped oil. Acknowledgment This work was carried out as part of the ongoing Low Salinity Water Injection Studies joint industry project (JIP) at the Institute of Petroleum Engineering of Heriot-Watt University and was equally supported by Total Exploration and Production UK, BP, Woodside, and ITF, which is gratefully acknowledged. References Austad, T., RezaeiDoust, A. and Puntervold, T., 2010. “Chemical mechanism of low salinity water flooding in sandstone reservoirs.” Paper SPE 129767 prepared for presentation at the 2010 SPE Improved Oil Recovery Symposium, 24-28 April. Boussour S., Cissokho M., Cordier P., Bertin H., Hamon G. 2009. “Oil recovery by low salinity brine injection: laboratory results on outcrop and reservoir cores.” SPE 124277, 2009. Brady P. V., Krumhansl J. K. 2012. “A surface complexation model of oil-brine-sandstone interfaces at 100 c: low salinity waterflooding.” Journal of Petroleum Science and Engineering 81: 171-176. Cissokho, M., Boussour, S., Cordier, Ph., Bertin, H., and Hamon, G. 2009. “Low salinity oil recovery on clayey sandstone: experimental study.” Paper SCA 2009-05 presented at the 23rd International Symposium of the Society of Core Analysts. Goyal P.S. and Aswal V. K. 2001. “Micellar structure and inter-micelle interactions in micellar solutions: Results of small angle neutron scattering studies.” Current Science 80 (8): 972-979. Hadia, N. J., Hansen, T., Tweheyo, M. T., Torsæter, O. 2012. “Influence of crude oil components on recovery by high and low salinity waterflooding.” Energy & Fuels 26: 4328-4335. Lager, A., Webb, K.J., Black, C.J.J., Singleton, M. and Sorbie, K.S., 2006. “Low salinity oil recovery - an experimental investigation.” Paper SCA2006-36 presented at the International Symposium of the Society of Core Analysts. Lager, A., Webb, K.J. and Black, C.J.J., 2007. “Impact of brine chemistry on oil recovery.” Paper A24 presented at the 14th European Symposium on Improved Oil Recovery, 22-24 April. Lager, A., Webb, K.J., Collins, I.R. and Richmond, D.M., 2008. “LoSalTM enhanced oil recovery: Evidence of enhanced oil recovery at the reservoir scale.” Paper SPE 113976 presented at the 2008 SPE/DOE Improved Oil Recovery Symposium, 1923 April. Ligthelm D., Gronsveld J., Hofman J.P., Brussee N.J., Marcelis F., van der Linde H.A. 2009. “Novel waterflooding strategy by manipulation of injection brine composition”, SPE 119835. Kanicky J. R., Lopez-Montilla J., Pandey, S., and Shah D. O. 2001. “Surface chemistry in the petroleum industry.” in “Handbook of applied surface and colloid chemistry.” K. Holmberg, John Wiley & Sons, Ltd. Makoto, T., 1999. “Disperse Systems”. Wiley-VCH.

SPE 166435

15

McGuire, P. L., Chatham, J. R., Paskvan, F. K., Sommer, D. M. and Carini, F. H. 2005. “Low salinity oil recovery: an exciting new eor opportunity for alaska's north slope.” Paper SPE 93903. Morrow, N., and Buckley, J. 2011. “Improved oil recovery by low-salinity waterflooding.” Journal of Petroleum Technology Vol 63 (5) Pu, H., Xie, X., Yin, P. & Morrow, N.R. 2008. “Application of coalbed methane water to oil recovery by low salinity waterflooding.” Paper SPE 113410. RezaeiDoust, A., Puntervold, T., Strand, S. and Austad, T. 2009. "Smart water as wettability modifier in carbonate and sandstone: a discussion of similarities/differences in the chemical mechanisms." Energy & Fuels 23(9): 4479-4485. Sohrabi, M., Henderson, G. D., Tehrani, D. H. and Danesh, A. 2000. “Visualisation of oil recovery by water alternating gas injection using high pressure micromodels - water-wet system.” Paper SPE 63000. Tang, G.Q. and Morrow, N.R. 1997. “Salinity, temperature, oil composition, and oil recovery by waterflooding.” spe res eng" 12 (4): 269–276. Tang, G.-Q. and Morrow, N.R., 1999. “Influence of brine composition and fines migration on crude oil/brine/rock interactions and oil recovery”. Journal of Petroleum Science and Engineering, 24: 99-111. Yousef, A., Al-Saleh, S., and Al-Jawfi , M. 2011. “New recovery method for carbonate reservoirs through tuning the injection water salinity: smart waterflooding.” Paper SPE 143550.