Enhancing the spontaneous imbibition rate of water in oil-wet dolomite rocks through boosting a wettability alteration process using carbonated smart brines
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Most fractured carbonate oil reservoirs have oil-wet rocks. Therefore, the process of imbibing water from the fractures into the matrix is usually poor or basically does not exist due to negative capillary pressure. To achieve appropriate ultimate oil recovery in these reservoirs, a water-based enhanced oil recovery method must be capable of altering the wettability of matrix blocks. Previous studies showed that carbonated water can alter wettability of carbonate oil-wet rocks toward less oil-wet or neutral wettability conditions, but the degree of modification is not high enough to allow water to imbibe spontaneously into the matrix blocks at an effective rate. In this study, we manipulated carbonated brine chemistry to enhance its wettability alteration features and hence to improve water imbibition rate and ultimate oil recovery upon spontaneous imbibition in dolomite rocks. First, the contact angle and interfacial tension (IFT) of brine/crude oil systems were measured for several synthetic brine samples with different compositions. Thereafter, two solutions with a significant difference in WAI (wettability alteration index) but approximately equal brine/oil IFT were chosen for spontaneous imbibition experiments. In the next step, spontaneous imbibition experiments at ambient and high pressures were conducted to evaluate the ability of carbonated smart water in enhancing the spontaneous imbibition rate and ultimate oil recovery in dolomite rocks. Experimental results showed that an appropriate adjustment of the imbibition brine (i.e., carbonated smart water) chemistry improves imbibition rate of carbonated water in oil-wet dolomite rocks as well as the ultimate oil recovery.
KeywordsSpontaneous imbibition Carbonated smart water Wettability alteration Enhanced oil recovery Dolomite rocks
Reservoir rock in naturally fractured oil reservoirs consists of two regions with different permeabilities, namely matrix blocks and the fracture network. Oil recovery in these reservoirs strongly depends on the interaction between high conductive fractures and low conductive matrix blocks (Nelson 2001; Haugen 2010; Sahimi 2011).
Three major forces control the drainage of oil from matrix blocks: capillary force, gravity force, and viscous force. During waterflooding, injection water tends to flow quickly into the fractures and bypass the matrix blocks. Preferential flow of water through the fracture network causes a limited differential pressure across the reservoir that results in weak viscous forces for oil production. This leads to poor sweep efficiency and low oil recovery (Guo et al. 1998; Narr et al. 2006; Seyyedi and Sohrabi 2015). However, the two other forces, i.e., gravity and capillary, could be effective depending on the properties of the rock and fluids (i.e., the injection water and the reservoir oil) such as wettability of the rock, water/oil IFT, and the density difference between the displacing and displaced fluids.
In water-wet fractured reservoirs, water is the wetting phase; therefore, the capillary force would be a productive force to bring water spontaneously into the matrix (i.e., spontaneous imbibition) and expel the oil from the matrix into the fracture network. In such reservoirs, if there is a high-pressure high-rate water injection or a strong aquifer, the matrix oil could also, to some extent, be produced by force imbibition.
In oil-wet naturally fractured reservoirs, water is the nonwetting phase; therefore, the capillary force would be an unproductive force. However, gravity and to some extent viscous forces can be effective in oil production from matrix blocks. The lower the capillary force is, the more oil will be produced from the matrix. In addition, when an oil-wet reservoir is subjected to waterflooding and/or in the presence of a strong supporting aquifer, the mechanism of force imbibition would drive out the oil from the matrix blocks into the fracture network.
Previous field studies revealed that the process of imbibing water from the fractures into the matrix is one of the main oil recovery mechanisms in naturally fractured reservoirs (Bourbiaux and Kalaydjian 1990; Hirasaki and Zhang 2004; Narr et al. 2006). Imbibition, which is assisted by capillary and gravity forces, is known as a slow process. For naturally fractured oil reservoirs in which matrix oil is mainly produced by an imbibition mechanism, oil production is small because of the oil-wet nature of matrix blocks (Bourbiaux and Kalaydjian 1990; Babadagli 2003; Narr et al. 2006). In such reservoirs, water spontaneous imbibition is extremely slow or does not occur because of negative capillary pressure. However, force imbibition, if it exists, and/or gravity drainage, if the size of matrix blocks is appropriately high, would cause an improvement in oil production (Hirasaki and Zhang 2004). Therefore, for those oil-wet naturally fractured reservoirs where there is not enough pressure gradient across the matrix blocks to cause force imbibition of water into the matrix or viscous displacement of matrix oil, and also there is not enough gravity force to expel oil from matrix blocks, it would be necessary to alter the wettability of the matrix rock into a water-wet condition in order to improve the spontaneous imbibition rate. Hence, during a water-based EOR process in naturally fractured oil reservoirs with oil-wet rocks, injection water should be able to alter the rock wettability to water-wet conditions to achieve an appropriate ultimate oil recovery.
Wettability alteration of rock surfaces toward water-wet conditions would increase capillary forces, and injection water would imbibe more quickly into the rock (Standnes and Austad 2000a, b; Hirasaki and Zhang 2004; Meng et al. 2018; Pal et al. 2018).
The effectiveness of carbonated water (CW) in improving the water spontaneous imbibition rate and oil recovery in sandstone and limestone rocks has been shown in several studies (Grape 1990; Perez et al. 1992; Sohrabi et al. 2008, 2009, 2011; Fjelde et al. 2011; Seyyedi and Sohrabi 2015). According to these studies, the main mechanisms through which carbonated water enhances oil recovery in carbonate rocks are: (1) wettability alteration which occurs due to the synergic effect of mineral dissolution and potential determining ions, (2) oil swelling, (3) oil viscosity reduction, and (4) oil/brine IFT reduction.
It has been proven previously that the carbonated water is capable of dissolving limestone and dolomite minerals and detaching the oil aggregates from rock surfaces which leads to changes in wettability of carbonate rocks from oil-wet to neutral conditions (Shiraki and Dunn 2000; Oelkers et al. 2008; Seyyedi et al. 2015; Abbaszadeh et al. 2016). However, wettability alteration toward neutral is not enough to achieve the proper rate of water spontaneous imbibition.
In recent years, there has been growing interest in smart water injection as an effective method in wettability alteration and improving spontaneous imbibition rate. Smart water is a brine with modified composition that changes the interfacial properties of the fluids and rock–fluid interfaces. Wettability altered by smart water is described as a symbiotic interaction between the potential determining ions Ca2+, Mg2+, and SO42− and the adsorbed carboxylic organic materials on the carbonate surface (Fathi et al. 2012; Shariatpanahi et al. 2016). This mechanism of wettability alteration has been previously observed in chalk, limestone and dolomite cores (Strand et al. 2006; Zhang et al. 2007; Fathi et al. 2010; Shariatpanahi et al. 2016).
Beside the wettability alteration aspect of smart water, it does not reduce water–oil interfacial tension significantly (Manshad et al. 2016), which is imperative for having a strong capillary force and as a result an effective rate of spontaneous imbibition of water into the matrix.
In this study, we made an attempt to investigate the potential of smart water for improving the wettability alteration feature of carbonated water to enhance its spontaneous imbibition rate in dolomite rocks. To achieve this purpose, first, the contact angle and interfacial tension (IFT) of crude oil/brine systems were measured for several synthetic brine samples with different compositions. The compositions of the solutions were determined so that they contained all the important divalent ions for wettability alteration which are commonly found in injection brines (e.g., Ca2+, Mg2+, and SO42−). Thereafter, two solutions with a significant difference in WAI (wettability alteration index) but approximately equal brine/oil IFT were chosen as imbibing solutions to investigate the effect of wettability alteration on spontaneous imbibition in the same IFTs. In the next step, spontaneous imbibition experiments at ambient pressure and high pressure were conducted to evaluate the ability of carbonated smart water in enhancing spontaneous imbibition rate and the ultimate oil recovery in dolomite rocks.
2 Materials and methods
2.1 Fluid properties
Properties of the utilized crude oil at atmospheric pressure and 75 °F
API gravity, °API
SARA composition, wt%
Composition of the formation brine and the Persian Gulf (PG) water
Total dissolved solids (TDS), ppm
Na+ and K+
Synthetic formation brine
Persian Gulf (PG) water
Different imbibing brine solutions (i.e., smart solutions) used in this study were prepared by dissolving MgSO4, CaCl2, and NaCl in distilled water based on the designed concentrations as will be explained in Sect. 2.3.1. For comparison, we also used Persian Gulf (PG) water with a pH of 6.3 as the imbibing brine in several spontaneous imbibition experiments. Table 2 shows the composition of the utilized PG water. Carbonated solutions were then prepared by dissolving carbon dioxide gas in smart water and seawater at a high pressure using the procedure described in Sect. 2.3.4.
2.2 Core properties
Results of X-ray diffraction analysis of the rock sample using X’Pert 3.0 software
Approximate quantity, wt%
Ca3.00 Mg3.00 C6.00 O18.00
Mg3.00 Cd3.00 C6.00 O18.00
Properties of the core plugs
Core plug ID
Absolute permeability, mD
Pore volume, mm3
2.3.1 Test design and solution preparation
This is the salinity range in which a reduction in CO2 solubility in water is not severe. As the CO2 solubility in water reduces, the strength of CW for wettability alteration, oil swelling, and viscosity reduction reduces (Riazi et al. 2009). At higher total salinities, the carbon dioxide solubility reduces significantly (Weiss 1974; Scharlin 1996).
Experimental conditions designed by Design Expert 7.0, showing the concentration of different ions in the synthetic brine at a total salinity of 7000 ppm
Ion concentration, mol/L
2.3.2 IFT and contact angle measurements
Contact angle measurements were performed using several thin sections cut from eight core plugs after these thin sections were completely saturated with the synthetic formation brine. To assess the extent of wettability alteration, first, the contact angle of a clean brine-saturated thin section (i.e., θinitial) was measured using a drop shape analysis device (DSA-100, Krüss, Germany). The measurement was repeated four times at different positions on the thin section using distilled water and crude oil as the fluid pair. The average of four measured contact angles was reported as the initial contact angle.
In addition, a series of IFT tests were performed using the DSA-100 device to evaluate the interfacial tension between oil and different brine solutions with a precision of 0.01 mN/m. Solutions that give maximum wettability alteration and minimum IFT reduction could be proper candidates for spontaneous imbibition experiments. For water to initiate imbibing into the rock spontaneously, it is necessary to alter the rock wettability to water-wet conditions to get positive capillary forces. On the other hand, IFT should not decrease severely to have enough capillary force and as a result powerful spontaneous imbibition. Therefore, in this study, the solution with the highest WAI and IFT value (called SH solution) was chosen as the solution that was expected to have the best return in spontaneous imbibition experiments. Also, another solution with almost the same IFT value but with a much lower WAI value (named SL solution) was chosen to compare its performance with the SH solution in spontaneous imbibition experiments.
2.3.3 Ambient pressure spontaneous imbibition of brine
After the core samples were cleaned, their pore volume, porosity, and absolute permeability were measured. Then, the core plugs were completely saturated with synthetic formation brine (Table 2), and the initial water saturation (Swi) condition was established by injecting crude oil into the brine-saturated cores. After that, ambient pressure spontaneous imbibition experiments were performed at 104 °F using conventional spontaneous imbibition cells made of glass. The reason for choosing this temperature was to keep the experimental conditions near ambient and also to ensure that a constant temperature is maintained by an oven during the imbibition experiments.
The imbibition brines used in these experiments included three solutions: (a) the solution with the maximum wettability alteration toward water wetness and with the small IFT reduction, (b) the solution with approximately equal IFT to the IFT of the solution in part (a) but with lower ability in wettability alteration (lower WAI), and (c) Persian Gulf (PG) water.
2.3.4 High-pressure spontaneous imbibition of CW
High-pressure spontaneous imbibition experiments were performed to evaluate the effects of dissolved CO2 on the imbibition rate of water and also the effects of smart water on imbibition of CW. Imbibition brine solutions were selected based on the IFT and contact angle results with the details explained in the next section, and then the carbonated form of these brine solutions was also used as imbibition brine in the high-pressure spontaneous imbibition experiments.
For high-pressure spontaneous imbibition experiments, first the core plug was placed in the imbibition cell and the back-pressure regulator (BPR) was set at 2000 psi. Then, the imbibing brine was injected from the bottom of the cell until the first droplets of water came out of the BPR output to ensure that the imbibition cell was completely filled with the imbibing brine. The imbibition cell was designed so there is a space between the inner part of the imbibition cell and the core plug, and therefore, all surfaces of the core plug were in contact with the brine when the brine was injected into the cell. Due to the existence of this space that acts as a fracture around a matrix block, there would be no resistance to the injecting flow, and therefore the pressure gradient that can lead to pushing the oil out from the core will not be applied to the rock. At the time of sampling, the imbibing brine with the volume of the space between the imbibition cell and the core plug was injected into the cell and the outlet fluids were collected. After removing the gas from the collected fluids, oil and water were separated, and the amount of recovered oil was measured. Taking samples was stopped when no oil production was observed after at least 100 h of starting the test.
3 Results and discussion
3.1 Results of contact angle and IFT measurements
The objective of this step was: (1) to find a brine solution with maximum wettability alteration capacity, (2) to find a solution with approximately equal solution/oil IFT, like the one in the first step, but with lower wettability alteration ability, and (3) to compare the performance of both solutions in spontaneous imbibition experiments.
Measured contact angles, calculated WAI, and measured IFTs for solutions with different salinities. Contact angles and IFTs were measured using crude oil as the drop phase and brine as the bulk phase
Total salinity, ppm
Measured solution/crude oil IFT, mN/m
43.6 ± 1.1
144.2 ± 1.2
133.4 ± 0.9
46.8 ± 1.2
143.1 ± 1.3
116.6 ± 0.8
45.2 ± 0.9
146.5 ± 1.1
78.3 ± 1.0
45.0 ± 1.4
140.4 ± 0.7
105.6 ± 1.1
47.6 ± 1.2
141.3 ± 1.2
121.3 ± 1.2
46.5 ± 1.0
141.2 ± 1.3
87.9 ± 1.0
46.7 ± 1.3
143.5 ± 1.0
58.2 ± 0.6
46.4 ± 1.1
139.8 ± 0.9
89.0 ± 1.0
45.8 ± 1.4
139.9 ± 0.6
55.6 ± 0.8
47.5 ± 0.9
142.5 ± 1.1
54.3 ± 0.7
45.0 ± 1.1
143.9 ± 1.0
76.3 ± 1.1
47.6 ± 1.3
142.6 ± 0.8
67.6 ± 0.6
47.9 ± 1.1
145.3 ± 1.2
132.9 ± 0.8
46.9 ± 1.2
145.6 ± 1.4
118.5 ± 1.0
47.3 ± 1.2
141.2 ± 0.9
78.0 ± 1.2
45.5 ± 1.4
141.8 ± 0.9
106.7 ± 1.1
43.8 ± 1.0
144.1 ± 1.1
122.6 ± 1.3
45.1 ± 0.5
141.2 ± 0.7
87.1 ± 0.7
48.1 ± 1.2
140.5 ± 0.8
59.1 ± 0.9
45.3 ± 1.5
146.6 ± 1.2
91.5 ± 0.8
47.2 ± 1.3
143.2 ± 1.1
57.2 ± 0.9
46.2 ± 1.1
143.3 ± 1.0
53.2 ± 0.7
45.9 ± 1.0
144.1 ± 1.3
77.0 ± 0.9
43.3 ± 1.2
139.9 ± 0.8
63.6 ± 1.0
46.5 ± 1.1
144.0 ± 1.2
132.5 ± 0.8
42.8 ± 1.1
139.3 ± 0.9
112.8 ± 1.2
44.2 ± 1.0
139.7 ± 1.0
75.4 ± 1.0
43.1 ± 1.2
143.6 ± 1.2
107.0 ± 1.1
42.4 ± 1.2
145.0 ± 1.4
123.1 ± 1.3
42.4 ± 1.1
141.3 ± 1.2
85.6 ± 0.9
43.7 ± 0.6
143.3 ± 1.2
55.5 ± 1.0
44.1 ± 1.3
144.2 ± 1.4
89.8 ± 1.4
43.6 ± 1.0
142.8 ± 1.3
53.9 ± 1.2
43.1 ± 0.5
146.1 ± 1.3
50.5 ± 1.0
42.1 ± 1.4
143.5 ± 0.9
74.2 ± 1.3
42.4 ± 1.3
142.3 ± 0.9
63.4 ± 0.8
Two solutions with approximately equal crude oil/brine IFT but with a significant difference in wettability alteration index were selected as the imbibition brines. Among the solutions with a salinity of 5000 ppm, solution 10 with a WAI of 0.93 and solution/crude oil IFT of 28.50 mN/m was selected (this solution is called SH), and from the solutions with a salinity of 2000 ppm, solution 8 with WAI of 0.52 and solution/crude oil IFT of 28.99 mN/m was chosen (this solution is called SL).
3.2 Effect of wettability alteration on imbibition rate and oil recovery
Spontaneous imbibition experiments were then performed for SH, SL, and PG solutions to further evaluate the effect of wettability on spontaneous imbibition. The blue, orange, and green curves in Fig. 8 show the recovery factors of the SH, SL, and PG solutions, respectively. The core plugs used for these spontaneous imbibition experiments were C1, C3, and C5, respectively (with specifications shown in Table 4). Although the physical properties of these core plugs were almost the same, for the solution with greater WAI more oil recovery and a higher imbibition rate were achieved. These results reveal the importance of the wettability alteration during the spontaneous imbibition process. In other words, for a good spontaneous imbibition rate and oil recovery, it is required that imbibition brine has the high potential to change wettability to strongly water-wet conditions.
In general, there are two types of forces that mainly control the spontaneous imbibition of water into the core plug: gravity and capillary forces. At first, when the core plug is completely oil-wet and capillary forces are against the spontaneous imbibition, solutions with higher IFT reduction can decrease the amount of counterproductive forces (capillary forces) and as a result, increase the productive forces (productive force in this situation is gravity force) for spontaneous imbibition. In other words, when we have oil-wet matrix blocks, we need to decrease the IFT to increase oil production due to gravity forces. Therefore, as can be seen in Fig. 8, for SL and SH solutions that can decrease IFT enough when it is in oil-wet conditions, the initiation of production of oil droplets could be observed at early stages. However, for PG which is unable to decrease IFT enough, after about 50 h, when it reaches neutral or water-wet conditions and the capillary forces turn to be productive, the first oil droplet can be seen on the core wall.
3.3 Spontaneous imbibition of CO2-enriched brines
Previous studies also show that dissolved CO2, even at low CO2 partial pressure, can reduce the pH of the fully saturated CW (Crawford et al. 1963; Ross 1982). The pH value of carbonated water at a pressure of 2000 psi and temperature of 104 °F is estimated to be around 3 according to Eq. (2). This pH is low enough such that the solution can dissolve minerals of carbonate rocks and also detach carboxylate groups from the rock surface (Seyyedi and Sohrabi 2015; Seyyedi et al. 2015; Abbaszadeh et al. 2016).
In addition, oil swelling and oil viscosity reduction are other mechanisms by which CW could enhance the oil recovery as a result of CO2 diffusion from the water phase to the oil phase (Riazi et al. 2009, 2011; Seyyedi and Sohrabi 2015).
3.4 Spontaneous imbibition of carbonated smart water
In the experiments with results shown in Fig. 9, after reaching a plateau in the oil recovery curve of the carbonated NaCl solution (the orange curve), without changing the core or any other experimental conditions, carbonated brine of the SL solution was injected into the imbibition cell from the bottom to replace the former solution. As shown in Fig. 11 (the green curve), after approximately 110 h, oil production started again, and the final oil production reached 13.5%. This result emphasizes the synergic effect of the potential determining ions and the effect of the dissolution mechanism of CW on wettability alteration (Seyyedi and Sohrabi 2015; Seyyedi et al. 2015; Vaz et al. 2017) which can enhance the imbibition rate and also oil recovery through accelerating and intensifying the process of wettability alteration of the carbonate oil-wet rock to water-wet conditions. Therefore, the positive capillary pressure caused spontaneous imbibition of water into the core and resulted in an additional oil recovery. As can be seen from the CW recovery curve shown in Fig. 11, unlike the plain brine, oil production did not start immediately after the replacement of imbibition brine with smart water. This could be related to the amount and distribution of the residual oil saturation at the beginning of the second stage of the spontaneous imbibition experiment (Viksund et al. 1998; Zhou et al. 2000). In the case of plain brine, because there was no oil recovery during the first stage, oil recovery started faster. However, for the case of CW, since part of CW should have passed through swept zones of the core plug at the beginning of the second stage, it took a longer time to lead to oil recovery.
The most important mechanism that controls the success of the spontaneous imbibition process in oil-wet rocks is wettability alteration. As the strength of the imbibition brine for wettability alteration toward more water-wet condition increases, the amount of imbibed water into the rock and consequently oil recovery would increase.
Using solutions which contain divalent ions (i.e., Mg2+, Ca2+, SO42−) with customized salinity and concentrations, it is possible to increase the wettability alteration strength of imbibing brine. This enhances the amount of imbibing water during spontaneous imbibition of both plain brine and carbonated brine.
Carbonation at high pressures provides high acidic power to the imbibing water which can accelerate the wettability alteration through the dissolution of surface rock and oil aggregates, leading to reinforcement of spontaneous imbibition.
When comparing spontaneous imbibition of smart water and carbonated smart water, it is concluded that although high-pressure carbonation slightly reduces the imbibition rate through IFT reduction, the final oil recovery is significantly higher, because of the incremental power of the acidic brine in wettability alteration, oil swelling, and oil viscosity reduction.
The authors would like to acknowledge the financial support from National Iranian South Oil Company (NISOC). We also thank Petroazma Knowledge-Based Oil Company for its contribution in assembling the experimental rig. Proofreading of the article by Dr. H. Parsaei is hereby appreciated. The co-operation of Mr. M. Abbaszadeh, Ms. S. Shojaei, Mr. B. Dehdari, and Ms. D. Panahpouri during this study is also acknowledged.
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