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Mechanisms of wetting modification by fluoride to mitigate phase trapping
Journal of Natural Gas Science and Engineering 26 (2015) 494e501
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Journal of Natural Gas Science and Engineering journal homepage: www.elsevier.com/locate/jngse
Mechanisms of wetting modification by fluoride to mitigate phase trapping Xuefen Liu*, Pingya Luo, Yili Kang, Lijun You State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, Chengdu 610500, PR China
a r t i c l e i n f o
a b s t r a c t
Article history: Received 25 March 2015 Received in revised form 20 June 2015 Accepted 22 June 2015 Available online 29 June 2015
Wettability alteration has a positive impact on mitigating the damage caused by water trapping. However, the related mechanisms are not quite clear. In this paper, the use of a quaternary ammonium fluoride salt to alter wettability and its potential to mitigate damage caused by aqueous phase trapping in the original water-wet, tight sandstone was investigated. Wettability alteration from water wetting to gas wetting was achieved after the core samples were treated with fluoride. After treatment, the water contact angles were larger than 90 . These contact angles slightly decreased when the temperature rose to 80 C and 100 C. The water surface tension decreased from 71.8 mN/m to 20.7 mN/m with the addition of fluoride and later varied over a small range. The contact angles and surface tension tests indicated that the optimal fluoride concentration was 0.1 wt%. The addition of fluoride slightly increased the viscous shear of the drill-in fluid. The flow back rate of the invading liquid with fluoride (85.1%) was almost double that of the liquid without fluoride (45.2%). With the removal of more water, the gas permeability recovery of cores after the circulation of drill-in fluids with fluoride improved by 20%e30% compared with that of drill-in fluids without fluoride. High performance liquid chromatography (HPLC) tests showed that there was hardly fluoride in the filtrate. The results confirmed that fluoride adsorbed onto the rock when the fluid circulated through the sample. This phenomenon was also proved by scanning electron microscopy (SEM) analysis, which showed that uneven molecular aggregation and amounts of adsorptions were more likely to occur at defect points. The adsorption of fluoride onto the rock surface resulted in a new irregular microstructure with a lower surface free energy, which decreased from 72 mJ/m2 to 12 mJ/m2 after fluoride adsorption. The results showed that the modified structure favors water removal. © 2015 Elsevier B.V. All rights reserved.
Keywords: Water phase trapping Wettability modification Mechanism Fluoride Adsorption Free energy
1. Introduction Aqueous phase trapping damage commonly occurs during drilling and completion operations. The capillary force Pc is responsible for trapping liquid. Pc is a function of surface tension s, contact angle of wetting phase q and capillary radius r, and can be expressed as:
Pc ¼ 2s cos q=r:
(1)
For water-wet reservoirs, the imbibition and entrapment of water by capillary suction is ubiquitous. In the past decades, scholars have extensively researched capillary imbibition in porous media. Li et al. (2006) studied the influence of initial water
* Corresponding author. E-mail address: [email protected] (X. Liu). http://dx.doi.org/10.1016/j.jngse.2015.06.037 1875-5100/© 2015 Elsevier B.V. All rights reserved.
saturation on recovery by spontaneous imbibition in gas/water/ rock systems. Cai et al. (2010) proposed an analytical expression stating that the mass of imbibed liquid is a function of the fractal dimensions of pores and tortuous capillaries, the minimum and maximum hydraulic diameter, porosity, fluid properties, and the fluidesolid interaction. Cai and Yu (2011) further derived a law stating that the average growth in height of a wetting liquid in porous media is a function of the fractal dimension for tortuosity. We can see that wettability is a key parameter affecting fluid flow in porous media. Wettability alteration from oil-wet/mixed-wet to strongly water-wet has long been recognized as an efficient recovery process that enhances water imbibition and expels more oil from the matrix to the fractures in fractured carbonates (Najafabadi et al., 2011; Salehi et al., 2010). However, water wetness in tight sandstone gas reservoirs is unfavorable, as water imbibition and entrapment in capillaries reduces gas deliverability (Xie et al., 2009). Methods have been proposed to mitigate damage
X. Liu et al. / Journal of Natural Gas Science and Engineering 26 (2015) 494e501
caused by aqueous phase trapping to recover gas production. These include hydraulic fracturing (Penny et al., 1983), gas injection and volatile solvent injection (Mahadevan et al., 2007). However, these methods take more time and have temporary effects. According to Jadhunandan and Morrow (1995), liquid saturation in reservoirs can be reduced by altering the rock wettability to intermediate wetting. Li and Firoozabadi (2000) proposed that modifying reservoir wettability from water wetting to gas wetting can mitigate aqueous trapping damage and enhance gas well deliverability. These authors used fluoride agents to obtain gas wetting in Berea sandstone and Kansas chalk. Later laboratory studies conducted by Tang and Firoozabadi (2002), Fahes and Firoozabadi (2007), Kumar et al. (2006), and Adibhatla et al. (2006). Feng et al. (2012) used the emulsion polymerization process to synthesize a type of fluoroacrylate copolymer emulsion. These authors experimentally demonstrated that the fluoropolymer can change the wettability of porous media to gas wetting and suppress the imbibition of water and oil into rock. Sharifzadeh et al. (2013) used a type of monomeric surfactant and conducted the solegel process to prepare a fluorinated polymeric network that behaves as a repellant towards water and oil. They believed that the fluorinated polymer could protect gas condensate reservoirs from undergoing condensate blockage in the near future. Mousavi et al. (2013) prepared fluorinated silica nanoparticles to alter rock wettability in the Near-Wellbore Region in gas condensate reservoirs. The nano-structured fluorinated nanoparticles on the pore surface formed a smooth film coating that behaved as a water and oil repellent by lowering the surface energy, thereby allowing for wettability alteration from liquid wetting to gas wetting. However, the potential reservoirs have absolute permeability values larger than 1 mD and pore radii larger than 1 micro. Thus, a consensus has been reached that fluorinated agents are favorable for obtaining liquid flow through wettability alteration. Micellar solubilization (Austad and Milter, 1997), ion-pair formation (Salehi et al., 2008; Standnes and Austad, 2000), and changes in rock surface charges (Hassan et al., 2015) have been postulated as the mechanisms of wettability alteration. Salinity, surfactant concentration, electrolyte concentration, temperature, etc. also have effects on wettability alteration (Hamouda and Rezaei Gomari, 2006; Gomari, 2009; Gupta and Mohanty, 2011). However, these mechanisms are theoretical and are mainly aimed at hydrocarbon surfactants acting on oil/water/rock systems in carbonate rocks. More experiments to analyze the underlying mechanisms of wettability modification by fluoride are required. In this paper, quaternary ammonium fluoride salt was used as modifier. The contact angles on the rock surface before and after ammonium fluoride treatment were measured. The surface tension of water with a fluoride concentration between 0 and 0.3% was measured as well. The feasibility of using fluoride to mitigate damage induced by the trapped aqueous phase in tight sandstone reservoirs was examined by evaluating the gas permeability, which was assessed by circulating drill-in fluid at the end of the core plug. To ensure that the circulating test was properly done, we prioritized the rheology tests for the drill-in fluid to examine the impact of fluoride on drill-in fluid performance. During the circulation test, the filtrate was collected for high performance liquid chromatography (HPLC) to determine the amount of fluoride adsorption onto the rock. Scanning electron microscopy (SEM) was also applied to image the surface morphology to understand the mechanisms by which fluoride alters wettability. At last, the surface free energy of the rock before and after fluoride adsorption was calculated.
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2. Experimental 2.1. Materials and apparatus Tight sandstone core samples with an in-situ permeability less than 0.1 mD were obtained from a target gas reservoir for use in this study, as shown in Table 1. Quaternary ammonium fluoride salt (purity 99.9%) was applied as a wettability modifier. Distilled water and potassium chloride (KCl) were used for the synthetic solution. The experimental gas consisted of dried N2. The drill-in fluid from the target gas field was used for dynamic circulation tests. The static contact angle (q) for the water-gas-rock system was measured with a goniometry setup (U. S. Patent 5.268.733). A JZHY1-180 tension meter was used to measure the surface tension. A ZNN-D6 six-speed rotational viscometer was used to measure the rheology of the drill-in fluid. The viscometer was calibrated in revolutions per minute (RPM). The fluid dynamic circulation through the core sample was achieved using a mud circulating loop and an instrumental system, as illustrated in Fig. 1. The core holder cell was connected to the fluid container. The rotation of the four rotors induced fluid circulation, which simulated the shear process in the bottom of the hole. The cores and fluids used in the circulation analysis are shown in Table 1. After the core flow test, the filtrate obtained from the circulated fluid was tested using HPLC (LC-20AT, Shimadzu) to determine the fluoride adsorption onto the rock surface. To analyze the surface modification by fluoride, SEM was used for imaging surface morphology. 2.2. Methodology 2.2.1. Contact angles tests Core samples were cut into F25 mm chips, which were then aged in a solution containing fluoride for 24 h at room temperature at 80 C or 100 C. The concentration of fluoride varied between 0 and 0.3 wt%. The cores were removed and an aqueous droplet with a constant volume of 20 ml was directly placed on the surface. Then, a magnified photograph of the droplet was projected onto a dial. 2.2.2. Surface tension tests Generally, the reduction of surface tension s can lead to a relative reduction in the capillary imbibition force, Pc. This is favorable for mitigating damage caused by aqueous phase trapping. The surface tension of the wateregas system with fluoride concentrations ranging from 0 to 0.3 wt% was measured using a tension meter (JZHY1-180) at room temperature. The standard deviation did not exceed ±0.1 mN/m. 2.2.3. Damage evaluation during dynamic circulation of the drill-in fluid First, the drill-in fluid rheology tests were prioritized because rheological properties are of primary concern in the formation of any type of fluid (Olatunde et al., 2012). The fluid was fully stirred using a high-speed blender, and then the fluid rheology was measured using a ZNN-D6 six-speed rotational viscometer. After the measurements, the fluid was placed in a hot roller furnace and aged for 16 h at 120 C. Then, the fluid was fully stirred in a blender. After the temperature dropped to approximately 50 C, the rheology was measured again. Rheological parameters such as viscosity AV, plastic viscosity PV, and yield point YP were calculated. The circulation setup is shown above, in Fig. 1. At first, the gas permeability K0i was tested by varying the differential pressure and constant confining pressure by 10 MPa. The nitrogen gas
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Table 1 Core physical properties and working fluid for dynamic circulating tests. Core#
Length, mm
Diameter, mm
Porosity, %
Permeability, mD
Pore volume, ml
Swi, %
Fluid type
S-6 S-7 S-8 S-9
47.6 48.7 43.4 46.3
25.1 25.1 25.1 25.2
6.74 6.59 7.51 6.99
0.027 0.042 0.031 0.038
1.59 1.59 1.61 1.61
25 25 25 24
Drill-in fluid
Fig. 1. Setup for dynamic circulation tests.
permeability was calculated by Darcy's formula:
2Q P mL Kg ¼ 0 0 101 ; A P12 P22
(2)
where Kg is the gas permeability, mm2; Q0 is the constant gas flow rate obtained at the corresponding differential pressure, ml/min; m is the mean gas viscosity, mPa s; L is the sample length along the flow direction; A is the cross-sectional area of the sample; and P1 and P2 are the upstream pressure and downstream pressure, respectively. The gas flow rate and gas permeability were obtained at each corresponding differential pressure. Based on the average displacement pressure in the target field of 0.54 MPa, the initial differential pressure of 0.5 MPa was selected during displacement and was followed by 1 MPa, 1.5 MPa, 2 MPa, 2.5 MPa and so on. Next, the drill-in fluid was circulated across the core face. Because the temperature of the target reservoir was approximately 80 C and the common drill-in differential pressure in the bottom of the hole was approximately 3.5 MPa, the circulation was conducted at a differential pressure of 3.5 MPa, with a shear rate of 40 Sec1 and a temperature of 80 C for 60 min. During the circulation test, the communicative filtration as a function of time was measured. Once the circulation test completed, a flow back test using nitrogen was conducted in the reverse flow direction until no more fluid flowed back. The displacement volume was also measured. The differential pressure was higher during flow back than during filtration. At last, the gas permeability was examined once again under conditions equivalent to those of K0i, or K1i. The gas permeability recovery was calculated as K1i/K0i. 2.2.4. Measurement of adsorption amount during circulation High performance liquid chromatography using an LC-20AT system was used to measure the residual concentration of fluoride in the filtrate, which could then be used to determine the amount of fluoride adsorbed onto the rock. A Shim-pack CLC-ODS
Drill-in fluid þ0.1% fluoride
chromatographic column (150 mm 6.0 mm 5 mm) was used. The mobile phase was 50:50 (V/V) acetonitrile and water, the UV wavelength used to detect fluoride was 254 nm, the flow rate was 1 mL/min, the column temperature was 40 C, and the injection volume was 10 mL. Under these conditions, standard solutions consisting of single-component fluoride and filtration samples were detected. The standard solutions were prepared from ultrapure water and fluoride. The fluoride concentration was 0.005 wt%, 0.01 wt%, 0.02 wt%, 0.05 wt%, 0.08 wt% and 0.1 wt%. A series of curves with a single peak, which indicated the contribution of fluoride, was obtained from the standard solutions. The peak area was calculated for each concentration. Based on the concentrations and peak areas, we drew a standard curve with the fluoride concentration as the abscissa and the peak area as the ordinate. Generally speaking, the peak area had a linear relationship with the concentration of the detected substance. If the filtrate contained fluoride, there would be corresponding peak in the curve and the peak area could be calculated. Because the peak area is linearly related to the fluoride concentration in the solution, we could employ it to quantify the fluoride contents in the filtration samples. The adsorption amount of fluoride onto the rock surface could be calculated by the differences in concentration in the solutions (Jandera et al., 2001), as shown in Formula (3):
Gi ¼
ðC0 Ci ÞV ; m
(3)
where Gi is the apparent adsorption of fluoride onto the rock surface, mg/g; C0 is the original concentration of fluoride before circulation, wt%; Ci is the concentration of fluoride in the filtrate after circulation, wt%; V is the liquid volume in the adsorption system, L; and m is the quality of the core sample, g. 2.2.5. Surface morphology Scanning electron microscopy was used to observe the adsorption morphology on the rock surface after filtration. After filtration and before the tests, the cores were cut into neat squares. 3. Results 3.1. Contact angle Table 2 shows the contact angles varying with fluoride concentrations ranging from 0 to 0.3 wt% under different conditions. The rock was initially water-wet with a contact angle q of
Table 2 Contact angles varying with concentration at different temperatures. Test condition
Fluoride concentration (wt%)/Contact angle q (degree) 0
0.01
0.05
0.1
0.2
0.3
At room temperature At 80 C At 100 C
Spread
42.2
72
105.1
92.8
92.4
Spread Spread
35 38
65.4 63.2
95.8 85.5
90.6 88.6
93.1 83.7
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approximately zero. With the application of fluoride, the contact angles increased. The maximum contact angle (approximately 105.1 ) was observed when the fluoride concentration reached 0.1 wt%. Then, the contact angle changed slightly. The contact angles decreased as the temperature rose to 80 C or 100 C, as shown in Table 2 and Fig. 2. Despite the decrease in the contact angle, it was still close to 90 . 3.2. Surface tension Fig. 3 presents the variation in water-gas surface tension with fluoride concentrations ranging from 0 to 0.3 wt%. The surface tension decreased quickly as fluoride was added into the solution. After the concentration reached 0.05 wt%, the surface tension of solution varied over a small range. According to the Formula (1) for capillary pressure, Pc is affected by the surface tension s and the contact angle q at a certain pore size. Because the surface tensions were almost constant at given concentrations, wettability alteration was responsible for the changes in capillary force. Fig. 4 was obtained from the results of the contact angle and surface tension tests at room temperature. The capillary force reached a minimal negative value when the fluoride concentration reached 0.1%. Because the capillary force Pc is resistant to water flowing back into the well in water-wet reservoirs, Pc becomes favorable for water removal once the force direction becomes negative. So the fluoride concentration of 0.1% was chosen for later experiments.
Fig. 3. Surface tension at different concentrations.
Fig. 4. Capillary forces at different concentrations.
3.3. Damage evaluation during dynamic circulation 3.3.1. Rheology of drill-in fluid Table 3 shows the fluid rheology of the KCl solution and the drill-in fluid. As fluoride is an organic substance with a short molecular chain, its addition slightly increased the viscous shear of the fluid. This was not necessarily problematic. The drill-in fluid was aged at 120 C for 16 h and then the rheology was measured when the temperature dropped to 50 C. After hot rolling, the apparent viscosity and shear decreased compared to their values before hot rolling, but the impact of fluoride became more obvious. These results confirmed that the quaternary ammonium fluoride was a suitable additive to the drill-in fluid. 3.3.2. Filtration during dynamic circulation and displacement Table 4 shows the cumulative filtration vs. time during circulation and the reversed flow back of the drill-in fluid through core samples. Core samples S-6 and S-7 were contaminated with drill-in fluid without fluoride, while core sample S-8 and S-9 were
contaminated with drill-in fluid with fluoride. The cumulative filtration amount of the invading fluid without fluoride was 0.27e0.28 ml, while the amount of invading fluid with fluoride was 0.30e0.31 ml. There was no obvious fluid invasion when the fluoride was employed, but the total displacement volume and flow back rate of the liquid with fluoride was almost double that of the liquid without fluoride. The average flow back rates were 85.1% and 45.2%, respectively, indicating that fluoride plays a positive role in promoting the flow back rate of the invading fluid. 3.3.3. Gas permeability recovery after flow back Fig. 5(a) shows the gas permeability recovery of cores after circulating drill-in fluids without fluoride. The permeability recovery was approximately 40%e60% of the original value and hardly changed after the differential pressure reached 1.5 MPa. At least 40% of the gas permeability was lost when the core samples were flushed with the original drill-in fluid. Fig. 5(b) displays the gas permeability recovery of cores after circulation with fluoridecontaining drill-in fluids. The gas permeability recovery was clearly higher from cores with fluoride than from cores without fluoride. As more water was removed, the gas permeability was restored to 82e93% of its original value. 3.4. Fluoride adsorption on core surface during filtration
Fig. 2. Contact angles vary with concentration at different temperatures.
Fig. 6 depicts the HPLC chromatogram of the fluoride standard solution, showing a single peak at one concentration at the detected wave of 254 nm. The peak began rising at approximately 1.4 min and gradually increased with concentration. The retention time and operating voltage also increased with concentration, but two additional small peaks emerged at 0.1 wt%. At this point, the peak up time and retention time all increased. These results may have been affected by the impurity of the testing environment. Fig. 7 shows the standard curve obtained from Fig. 6. The peak area was highly proportional to the concentration of fluoride. Fig. 8 depicts the HPLC chromatogram of the filtrate obtained from core
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Table 3 Impact of fluoride on fluid rheology under atmospheric pressure. AV, cp PV, cp YP, Pa YP/PV, (ms)1 Gel, Pa
Fluid composition
3 wt% KCl solution 9.5 3 wt% KCl þ 0.1% fluoride 9.5 Drill-in fluid 105.3 Drill-in fluid þ 0.1% fluoride 105.3 Drill-in fluid 93.5 Drill-in fluid þ 0.1% fluoride 94.5
5.0 4.0 78.4 78.4 73 73
4.59 5.61 27.45 27.45 20.95 21.97
0.92 1.40 0.35 0.35 0.29 0.30
Note
1/1.3 At room temperature 1.5/2 4.1/10.7 4.6/11.2 3.1/7.2 Fluid was aged at 120 C and then measured when the temperature decreased to 50 C 3.6/7.7
Table 4 Cumulative filtration vs. time and flow-back analysis of the drill-in fluid considering fluoride. Fluid type
Drill-in fluid Drill-in fluid þ fluoride
Cumulative filtration, ml Time (min)
1
3
5
7
10
15
20
30
40
50
60
S-6 S-7 S-8 S-9
0.065 0.064 0.068 0.073
0.086 0.084 0.091 0.095
0.095 0.092 0.1 0.11
0.11 0.11 0.12 0.13
0.12 0.12 0.13 0.14
0.14 0.14 0.15 0.16
0.16 0.16 0.17 0.18
0.2 0.19 0.21 0.22
0.23 0.22 0.23 0.26
0.24 0.24 0.28 0.29
0.27 0.26 0.33 0.34
samples. It shows that there was no obvious peak of fluoride at 1.4 min. In other words, the tested sample did not contain fluoride, or the amount of fluoride was below the detection range of the instrument under those conditions. When the fluid was circulated through the core sample, fluoride was adsorbed onto the rock. As the original concentration of fluoride in the drill-in fluid was 0.1 wt % (1000 ppm), the adsorption amount on the rock surface could be calculated using Formula (3). However, because the circulation was done at constant displacing pressure, the invasion volume could not be accurately acquired. Thus, the study shows that fluoride
Displacement, ml
Flow back rate, %
0.13 0.11 0.29 0.28
48.1 42.3 87.8 82.4
adsorbed onto the rock, but no accurate adsorption amount could be determined. 3.5. Surface morphology The SEM results are shown below, in Figs. 9 and 10. Fig. 9 depicts the rock surface morphology after the circulation of the original drill-in fluid. Fig. 10 depicts the rock surface morphology after the circulation of drill-in fluid with fluoride. There were many small and large prolate substances on the surface, but the shapes were
Fig. 5. Permeability recovery after fluid flowing back from cores damaged by drill-in fluid.
Fig. 6. High performance liquid chromatography at series of fluoride concentration.
Fig. 7. The standard HPLC curve for fluoride.
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Fig. 8. HPLC chromatogram of the filtrate obtained from core samples.
aggregation. The adsorption of the fluoride changed the morphology of rock surface and reformed a new irregular microstructure, leading to the changes in the surface properties. 4. Mechanistic analysis of wettability alteration The HPLC and SEM results showed that fluoride was adsorbed onto the core surface, which resulted in an increase in the contact angle. The results obtained in the dynamic circulation test can be better understood by considering the wetting alteration induced by fluoride adsorption onto the surface. A phase interface with a water contact angle above 90 is termed a hydrophobic interface, and in general, a hydrophobic surface is affected by the surface structure as well as surface energy. 4.1. Reformation of surface morphology
Fig. 9. Fresh end core after fluid circulation without fluoride.
essentially similar. The morphology shown in Fig. 10 was significantly different from the surface morphology in Fig. 9, and it is obvious that the fluoride was largely adsorbed onto the rock surface. The fluoride-adsorbed surface presented uneven molecular
Fig. 10. Fresh end core after fluid circulation with fluoride.
Due to isomorphous substitution, large amounts of permanent negative charges, small amounts of variable charges, and hydroxyls are either in or adsorbed onto the molecules of the mineral surface. As the surface tends to be instable, the affinity to adsorb cationic fluoride occurs through Coulomb forces, hydrogen bonds or Van der Waals forces. The HPLC results showed that there was total adsorption of fluoride onto the rock surface. It is obvious that the adsorption was more likely to occur in the defect areas. Thus, as shown by the SEM results, the original surface structure and roughness changed. The molecular aggregation on the surface was not regular, and large adsorptions onto the surface increased the micro-roughness. The adsorption layer of fluoride on the surface can be simplified into micelles and vacancies. This was confirmed by the SEM results. Combined with the contact angle test, the hydrophobic surface can be explained using a model from Wenzel and Cassie (Roach et al., 2008), as shown in Figs. 11 and 12. The micro-bump structure with a larger specific surface area not only improved the area of the gas cushion but also enhanced the repellent abilities of the mineral surface, thus improving water removal and the recovery of gas permeability.
Fig. 11. Hydrophobic surface after fluoride treatment.
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Fig. 12. Two wetting state models: (a) Wenzel (b) Cassie-Baxter.
4.2. Lower surface free energy The adsorption of fluoride onto the rock surface should have resulted in a lower surface free energy. Thus, to quantitatively analyze the surface energy before and after the modification, the contact angle method was used to test the surface free energy (Girifalco and Good, 1957). The calculation formula can be expressed as follows:
rffiffiffiffiffi gs ; cosq ¼ 1 þ 24 gl
(4)
where q is the water contact angle on the rock surface, degrees; 4 is the correction factor with a value of 0.5e1.5, which is determined by molecular size and intermolecular interactions within the system and assigned to be 0.5 in a system composed of perfluoroalkyl and water or 1.0 in a system composed of a polar mineral rock surface and water; gl is the surface tension of the liquid, mN/m; and gs is the solid surface energy, mJ/m2. To quantitatively calculate the surface free energy, the value of q and gl were determined at room temperature. Without fluoride, q and gl were 0 and 72 mN/m, respectively. With fluoride in the system, q and gl were 105.5 and 22.4 mN/m, respectively. According to Formula (4), the rock surface free energies before and after fluoride adsorption were calculated as 72 mJ/m2 and 12 mJ/ m2, respectively. It is known that lower solid surface energies correspond to smaller binding forces between the solid and liquid. Therefore, the spread of the aqueous phase over the newly modified surface was restricted, exhibiting increases in the water contact angle and the gas permeability recovery. 5. Conclusions In this study, wettability alteration by fluoride and its mechanism were experimentally studied. A series of experiments aimed at determining the water contact angles, surface tension, fluid rheology, dynamic circulation of drill-in fluid through core samples, amount of adsorbed fluoride and the micro-morphology of the rock surface after adsorption were conducted. The surface free energy before and after adsorption was also calculated. Based on the results obtained, the following conclusions can be drawn: 1) Rock wettability was modified from water-wetting to hydrophobic oil-wetting after the rock was treated with the quaternary ammonium fluoride salt. The contact angles decreased as the temperature rose to 80 C or 100 C but were still close to 90 ; 2) The surface tension decreased to 20 mN/m with the addition of fluoride and then changed slightly. As the capillary force reached a minimal negative value when the fluoride concentration reached 0.1%, the optimal concentration was selected to be 0.1%; 3) The addition of fluoride slightly increased the viscous shear of the drill-in fluid. The application of fluoride improved the flow
back rate and gas permeability recovery, demonstrating the potential of using fluoride to mitigate damage induced by aqueous phase trapping in tight sandstone reservoirs; 4) When fluoride-containing fluid circulated through the cores, a large amount of fluoride adsorbed onto the rock surface. The adsorption was more likely to occur at points with defects, reforming an irregular structure with a low surface free energy; and 5) The rock surface free energy decreased from 72 mJ/m2 to 12 mJ/ m2 after fluoride adsorption. This structure presented stronger repellent abilities and restricted the spread of the aqueous phase across the surface. Acknowledgments The authors are grateful to (1) the National Basic Research Program (973) project of China under Grant Nos. 2010CB226705 and (2) Longdong University in Gansu. Thanks are also extended to all individuals associated with the project. References Adibhatla, B., Mohanty, K.K., Berger, P., Lee, C., 2006. Effect of surfactants on wettability of near-wellbore regions of gas reservoirs. J. Petrol. Sci. Eng. 52, 227e236. Austad, T., Milter, J., 1997. Spontaneous imbibition of water into low permeable chalk at different wettabilities using surfactants. SPE37236. In: SPE International Symposium on Oilfield Chemistry, Houston, Texas, February 18e21. Cai, J.C., Yu, B.M., 2011. A discussion of the effect of tortuosity on the capillary imbibition in porous media. Transp. Porous Med. 89 (2), 251e263. Cai, J.C., Yu, B.M., Zou, M.Q., Luo, L., 2010. Fractal characterization of spontaneous cocurrent imbibition in porous media. Energy Fuel 24 (3), 1860e1867. Fahes, M., Firoozabadi, A., 2007. Wettability alteration to intermediate gas-wetting in gas-condensate reservoirs at high temperatures. SPE J. 12 (4), 397e407. Feng, C., Kong, Y., Jiang, G., Yang, J., Pu, C., Zhang, Y., 2012. Wettability modification of rock cores by fluorinated copolymer emulsion for the enhancement of gas and oil recovery. Appl. Surf. Sci. 258, 7075e7081. Girifalco, L.A., Good, R.J., 1957. A theory for the estimation of surface and interfacial energies. I. Derivation and application to interfacial tension. J. Phys. Chem. 61 (7), 904e909. Gomari, K.A.R., 2009. Different approaches to understand mechanism of wettability alteration of carbonate reservoirs. SPE 121952. http://dx.doi.org/10.2118/ 121952-MS. Gupta, R., Mohanty, K.K., 2011. Wettability alteration mechanism for oil recovery from fractured carbonate rocks. Transp. Porous Med. 87, 635e652. http:// dx.doi.org/10.1007/s11242-010-9706-5. Hamouda, A.A., Rezaei Gomari, K.A., 2006. Influence of temperature on wettability alteration of carbonate reservoirs. SPE 99848. MS. http://dx.doi.org/10.2118/ 99848-MS. Hassan, M., Arsene, L.K., Steffen, B., Willem-Bart, B., Ramez, N., William, R.R., 2015. Insights into the mechanism of wettability alteration by low-salinity flooding (LSF) in carbonates. Energy Fuel 29, 1352e1367. http://dx.doi.org/10.1021/ ef5023847. Jadhunandan, P.P., Morrow, N.R., 1995. Effect of wettability on waterflood recovery for crude-oil/brine/rock systems. SPE Reserv. Eval. Eng. 10, 40e46. Jandera, P., Buncekova, S., Mihlbachler, K., Guiochon, G., Backovska, V., Planeta, J., 2001. Fitting adsorption isotherms to the distribution data determined using packed micro-columns for high-performance liquid chromatography. J. Chromatogr. A 925 (1), 19e29. Kumar, V., Pope, G.A., Sharma, M.M., 2006. Improving the gas and condensate relative permeability using chemical treatments. In: SPE 100529, Presented at the SPE Gas Technology Symposium, Calgary, Alberta, Canada, May 15e17. Li, K., Firoozabadi, A., 2000. Experimental study of wettability alteration to preferential gas-wetting in porous media and its effects. SPE Reserv. Eval. Eng. 3 (2), 139e149. Li, K.W., Chow, K., Horne, N., 2006. Influence of initial water saturation on recovery by spontaneous imbibitions in gas/water/rock systems and the calculation of relative permeability. SPE Reserv. Eval. Eng. 9, 295e301. Mahadevan, J., Sharma, M., Yortsos, Y.C., 2007. Capillary wicking in gas wells. SPE J. 12 (4), 429e437. Mousavi, M.A., Hassanajili, Sh, Rahimpour, M.R., 2013. Synthesis of fluorinated nano-silica and its application in wettability alteration near-wellbore region in gas condensate reservoirs. Appl. Surf. Sci. 273, 205e214. Najafabadi, N.F., Delshad, M., Sepehrnoori, K., Farhadinia, M.A., 2011. Wettability modification of fractured carbonates using sodium metaborate part II: history match results and sensitivity simulations. Petrol. Sci. Technol. 29 (20), 2160e2175. http://dx.doi.org/10.1080/10916461003681737. Olatunde, A.O., Usman, M.A., Olafadehan, O.A., Adeosun, T.A., Ufot, O.E., 2012.
X. Liu et al. / Journal of Natural Gas Science and Engineering 26 (2015) 494e501 Improvement of rheological properties of drilling fluid using locally based materials. Petrol. Coal 54 (1), 65e75. Penny, G.S., Conway, M.W., Briscoe, J.E., 1983. Enhanced load water-recovery technique improves stimulation results. In: SPE12149, at the Annual Technical Conference and Exhibition, San Francisco, California, October 5e8. Roach, P., Shirtcliffe, N.J., Newton, M.I., 2008. Progress in superhydrophobic surface development. Soft Matter 4 (2), 224e240. Salehi, M., Johnson, S.J., Liang, J.T., 2008. Mechanistic study of wettability alteration using surfactants with applications in naturally fractured reservoirs. Langmuir 24 (24), 14099e14107. Salehi, M., Johnson, S.J., Liang, J.T., 2010. Enhanced wettability alteration by surfactants with multiple hydrophilic moieties. J. Surfactants Deterg. 13 (3), 243e246.
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Sharifzadeh, S., Hassanajili, Sh., Rahimpour, M.R., 2013. Wettability alteration of gas condensate reservoir rocks to gas wetness by solegel process using fluoroalkylsilane. J. Appl. Polym. Sci. 128 (6), 4077e4085. http://dx.doi.org/10.1002/ APP.38632. Standnes, D.C., Austad, T., 2000. Wettability alteration in chalk: 2. Mechanism for wettability alteration from oil-wet to water-wet using surfactants. J. Pet. Sci. Eng. 28 (3), 123e143. Tang, G.Q., Firoozabadi, A., 2002. Relative permeability modification in gas/liquid systems through wettability alteration to intermediate gas wetting. SPE Reserv. Eval. Eng. 5 (6), 427e436. Xie, X., Liu, Y., Sharma, M., Weiss, W.W., 2009. Wettability alteration to increase deliverability of gas production wells. J. Nat. Gas Sci. Eng. 1 (1), 39e45.
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Mechanisms of wetting modification by fluoride to mitigate phase trapping Xuefen Liu*, Pingya Luo, Yili Kang, Lijun You State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, Chengdu 610500, PR China
a r t i c l e i n f o
a b s t r a c t
Article history: Received 25 March 2015 Received in revised form 20 June 2015 Accepted 22 June 2015 Available online 29 June 2015
Wettability alteration has a positive impact on mitigating the damage caused by water trapping. However, the related mechanisms are not quite clear. In this paper, the use of a quaternary ammonium fluoride salt to alter wettability and its potential to mitigate damage caused by aqueous phase trapping in the original water-wet, tight sandstone was investigated. Wettability alteration from water wetting to gas wetting was achieved after the core samples were treated with fluoride. After treatment, the water contact angles were larger than 90 . These contact angles slightly decreased when the temperature rose to 80 C and 100 C. The water surface tension decreased from 71.8 mN/m to 20.7 mN/m with the addition of fluoride and later varied over a small range. The contact angles and surface tension tests indicated that the optimal fluoride concentration was 0.1 wt%. The addition of fluoride slightly increased the viscous shear of the drill-in fluid. The flow back rate of the invading liquid with fluoride (85.1%) was almost double that of the liquid without fluoride (45.2%). With the removal of more water, the gas permeability recovery of cores after the circulation of drill-in fluids with fluoride improved by 20%e30% compared with that of drill-in fluids without fluoride. High performance liquid chromatography (HPLC) tests showed that there was hardly fluoride in the filtrate. The results confirmed that fluoride adsorbed onto the rock when the fluid circulated through the sample. This phenomenon was also proved by scanning electron microscopy (SEM) analysis, which showed that uneven molecular aggregation and amounts of adsorptions were more likely to occur at defect points. The adsorption of fluoride onto the rock surface resulted in a new irregular microstructure with a lower surface free energy, which decreased from 72 mJ/m2 to 12 mJ/m2 after fluoride adsorption. The results showed that the modified structure favors water removal. © 2015 Elsevier B.V. All rights reserved.
Keywords: Water phase trapping Wettability modification Mechanism Fluoride Adsorption Free energy
1. Introduction Aqueous phase trapping damage commonly occurs during drilling and completion operations. The capillary force Pc is responsible for trapping liquid. Pc is a function of surface tension s, contact angle of wetting phase q and capillary radius r, and can be expressed as:
Pc ¼ 2s cos q=r:
(1)
For water-wet reservoirs, the imbibition and entrapment of water by capillary suction is ubiquitous. In the past decades, scholars have extensively researched capillary imbibition in porous media. Li et al. (2006) studied the influence of initial water
* Corresponding author. E-mail address: [email protected] (X. Liu). http://dx.doi.org/10.1016/j.jngse.2015.06.037 1875-5100/© 2015 Elsevier B.V. All rights reserved.
saturation on recovery by spontaneous imbibition in gas/water/ rock systems. Cai et al. (2010) proposed an analytical expression stating that the mass of imbibed liquid is a function of the fractal dimensions of pores and tortuous capillaries, the minimum and maximum hydraulic diameter, porosity, fluid properties, and the fluidesolid interaction. Cai and Yu (2011) further derived a law stating that the average growth in height of a wetting liquid in porous media is a function of the fractal dimension for tortuosity. We can see that wettability is a key parameter affecting fluid flow in porous media. Wettability alteration from oil-wet/mixed-wet to strongly water-wet has long been recognized as an efficient recovery process that enhances water imbibition and expels more oil from the matrix to the fractures in fractured carbonates (Najafabadi et al., 2011; Salehi et al., 2010). However, water wetness in tight sandstone gas reservoirs is unfavorable, as water imbibition and entrapment in capillaries reduces gas deliverability (Xie et al., 2009). Methods have been proposed to mitigate damage
X. Liu et al. / Journal of Natural Gas Science and Engineering 26 (2015) 494e501
caused by aqueous phase trapping to recover gas production. These include hydraulic fracturing (Penny et al., 1983), gas injection and volatile solvent injection (Mahadevan et al., 2007). However, these methods take more time and have temporary effects. According to Jadhunandan and Morrow (1995), liquid saturation in reservoirs can be reduced by altering the rock wettability to intermediate wetting. Li and Firoozabadi (2000) proposed that modifying reservoir wettability from water wetting to gas wetting can mitigate aqueous trapping damage and enhance gas well deliverability. These authors used fluoride agents to obtain gas wetting in Berea sandstone and Kansas chalk. Later laboratory studies conducted by Tang and Firoozabadi (2002), Fahes and Firoozabadi (2007), Kumar et al. (2006), and Adibhatla et al. (2006). Feng et al. (2012) used the emulsion polymerization process to synthesize a type of fluoroacrylate copolymer emulsion. These authors experimentally demonstrated that the fluoropolymer can change the wettability of porous media to gas wetting and suppress the imbibition of water and oil into rock. Sharifzadeh et al. (2013) used a type of monomeric surfactant and conducted the solegel process to prepare a fluorinated polymeric network that behaves as a repellant towards water and oil. They believed that the fluorinated polymer could protect gas condensate reservoirs from undergoing condensate blockage in the near future. Mousavi et al. (2013) prepared fluorinated silica nanoparticles to alter rock wettability in the Near-Wellbore Region in gas condensate reservoirs. The nano-structured fluorinated nanoparticles on the pore surface formed a smooth film coating that behaved as a water and oil repellent by lowering the surface energy, thereby allowing for wettability alteration from liquid wetting to gas wetting. However, the potential reservoirs have absolute permeability values larger than 1 mD and pore radii larger than 1 micro. Thus, a consensus has been reached that fluorinated agents are favorable for obtaining liquid flow through wettability alteration. Micellar solubilization (Austad and Milter, 1997), ion-pair formation (Salehi et al., 2008; Standnes and Austad, 2000), and changes in rock surface charges (Hassan et al., 2015) have been postulated as the mechanisms of wettability alteration. Salinity, surfactant concentration, electrolyte concentration, temperature, etc. also have effects on wettability alteration (Hamouda and Rezaei Gomari, 2006; Gomari, 2009; Gupta and Mohanty, 2011). However, these mechanisms are theoretical and are mainly aimed at hydrocarbon surfactants acting on oil/water/rock systems in carbonate rocks. More experiments to analyze the underlying mechanisms of wettability modification by fluoride are required. In this paper, quaternary ammonium fluoride salt was used as modifier. The contact angles on the rock surface before and after ammonium fluoride treatment were measured. The surface tension of water with a fluoride concentration between 0 and 0.3% was measured as well. The feasibility of using fluoride to mitigate damage induced by the trapped aqueous phase in tight sandstone reservoirs was examined by evaluating the gas permeability, which was assessed by circulating drill-in fluid at the end of the core plug. To ensure that the circulating test was properly done, we prioritized the rheology tests for the drill-in fluid to examine the impact of fluoride on drill-in fluid performance. During the circulation test, the filtrate was collected for high performance liquid chromatography (HPLC) to determine the amount of fluoride adsorption onto the rock. Scanning electron microscopy (SEM) was also applied to image the surface morphology to understand the mechanisms by which fluoride alters wettability. At last, the surface free energy of the rock before and after fluoride adsorption was calculated.
495
2. Experimental 2.1. Materials and apparatus Tight sandstone core samples with an in-situ permeability less than 0.1 mD were obtained from a target gas reservoir for use in this study, as shown in Table 1. Quaternary ammonium fluoride salt (purity 99.9%) was applied as a wettability modifier. Distilled water and potassium chloride (KCl) were used for the synthetic solution. The experimental gas consisted of dried N2. The drill-in fluid from the target gas field was used for dynamic circulation tests. The static contact angle (q) for the water-gas-rock system was measured with a goniometry setup (U. S. Patent 5.268.733). A JZHY1-180 tension meter was used to measure the surface tension. A ZNN-D6 six-speed rotational viscometer was used to measure the rheology of the drill-in fluid. The viscometer was calibrated in revolutions per minute (RPM). The fluid dynamic circulation through the core sample was achieved using a mud circulating loop and an instrumental system, as illustrated in Fig. 1. The core holder cell was connected to the fluid container. The rotation of the four rotors induced fluid circulation, which simulated the shear process in the bottom of the hole. The cores and fluids used in the circulation analysis are shown in Table 1. After the core flow test, the filtrate obtained from the circulated fluid was tested using HPLC (LC-20AT, Shimadzu) to determine the fluoride adsorption onto the rock surface. To analyze the surface modification by fluoride, SEM was used for imaging surface morphology. 2.2. Methodology 2.2.1. Contact angles tests Core samples were cut into F25 mm chips, which were then aged in a solution containing fluoride for 24 h at room temperature at 80 C or 100 C. The concentration of fluoride varied between 0 and 0.3 wt%. The cores were removed and an aqueous droplet with a constant volume of 20 ml was directly placed on the surface. Then, a magnified photograph of the droplet was projected onto a dial. 2.2.2. Surface tension tests Generally, the reduction of surface tension s can lead to a relative reduction in the capillary imbibition force, Pc. This is favorable for mitigating damage caused by aqueous phase trapping. The surface tension of the wateregas system with fluoride concentrations ranging from 0 to 0.3 wt% was measured using a tension meter (JZHY1-180) at room temperature. The standard deviation did not exceed ±0.1 mN/m. 2.2.3. Damage evaluation during dynamic circulation of the drill-in fluid First, the drill-in fluid rheology tests were prioritized because rheological properties are of primary concern in the formation of any type of fluid (Olatunde et al., 2012). The fluid was fully stirred using a high-speed blender, and then the fluid rheology was measured using a ZNN-D6 six-speed rotational viscometer. After the measurements, the fluid was placed in a hot roller furnace and aged for 16 h at 120 C. Then, the fluid was fully stirred in a blender. After the temperature dropped to approximately 50 C, the rheology was measured again. Rheological parameters such as viscosity AV, plastic viscosity PV, and yield point YP were calculated. The circulation setup is shown above, in Fig. 1. At first, the gas permeability K0i was tested by varying the differential pressure and constant confining pressure by 10 MPa. The nitrogen gas
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Table 1 Core physical properties and working fluid for dynamic circulating tests. Core#
Length, mm
Diameter, mm
Porosity, %
Permeability, mD
Pore volume, ml
Swi, %
Fluid type
S-6 S-7 S-8 S-9
47.6 48.7 43.4 46.3
25.1 25.1 25.1 25.2
6.74 6.59 7.51 6.99
0.027 0.042 0.031 0.038
1.59 1.59 1.61 1.61
25 25 25 24
Drill-in fluid
Fig. 1. Setup for dynamic circulation tests.
permeability was calculated by Darcy's formula:
2Q P mL Kg ¼ 0 0 101 ; A P12 P22
(2)
where Kg is the gas permeability, mm2; Q0 is the constant gas flow rate obtained at the corresponding differential pressure, ml/min; m is the mean gas viscosity, mPa s; L is the sample length along the flow direction; A is the cross-sectional area of the sample; and P1 and P2 are the upstream pressure and downstream pressure, respectively. The gas flow rate and gas permeability were obtained at each corresponding differential pressure. Based on the average displacement pressure in the target field of 0.54 MPa, the initial differential pressure of 0.5 MPa was selected during displacement and was followed by 1 MPa, 1.5 MPa, 2 MPa, 2.5 MPa and so on. Next, the drill-in fluid was circulated across the core face. Because the temperature of the target reservoir was approximately 80 C and the common drill-in differential pressure in the bottom of the hole was approximately 3.5 MPa, the circulation was conducted at a differential pressure of 3.5 MPa, with a shear rate of 40 Sec1 and a temperature of 80 C for 60 min. During the circulation test, the communicative filtration as a function of time was measured. Once the circulation test completed, a flow back test using nitrogen was conducted in the reverse flow direction until no more fluid flowed back. The displacement volume was also measured. The differential pressure was higher during flow back than during filtration. At last, the gas permeability was examined once again under conditions equivalent to those of K0i, or K1i. The gas permeability recovery was calculated as K1i/K0i. 2.2.4. Measurement of adsorption amount during circulation High performance liquid chromatography using an LC-20AT system was used to measure the residual concentration of fluoride in the filtrate, which could then be used to determine the amount of fluoride adsorbed onto the rock. A Shim-pack CLC-ODS
Drill-in fluid þ0.1% fluoride
chromatographic column (150 mm 6.0 mm 5 mm) was used. The mobile phase was 50:50 (V/V) acetonitrile and water, the UV wavelength used to detect fluoride was 254 nm, the flow rate was 1 mL/min, the column temperature was 40 C, and the injection volume was 10 mL. Under these conditions, standard solutions consisting of single-component fluoride and filtration samples were detected. The standard solutions were prepared from ultrapure water and fluoride. The fluoride concentration was 0.005 wt%, 0.01 wt%, 0.02 wt%, 0.05 wt%, 0.08 wt% and 0.1 wt%. A series of curves with a single peak, which indicated the contribution of fluoride, was obtained from the standard solutions. The peak area was calculated for each concentration. Based on the concentrations and peak areas, we drew a standard curve with the fluoride concentration as the abscissa and the peak area as the ordinate. Generally speaking, the peak area had a linear relationship with the concentration of the detected substance. If the filtrate contained fluoride, there would be corresponding peak in the curve and the peak area could be calculated. Because the peak area is linearly related to the fluoride concentration in the solution, we could employ it to quantify the fluoride contents in the filtration samples. The adsorption amount of fluoride onto the rock surface could be calculated by the differences in concentration in the solutions (Jandera et al., 2001), as shown in Formula (3):
Gi ¼
ðC0 Ci ÞV ; m
(3)
where Gi is the apparent adsorption of fluoride onto the rock surface, mg/g; C0 is the original concentration of fluoride before circulation, wt%; Ci is the concentration of fluoride in the filtrate after circulation, wt%; V is the liquid volume in the adsorption system, L; and m is the quality of the core sample, g. 2.2.5. Surface morphology Scanning electron microscopy was used to observe the adsorption morphology on the rock surface after filtration. After filtration and before the tests, the cores were cut into neat squares. 3. Results 3.1. Contact angle Table 2 shows the contact angles varying with fluoride concentrations ranging from 0 to 0.3 wt% under different conditions. The rock was initially water-wet with a contact angle q of
Table 2 Contact angles varying with concentration at different temperatures. Test condition
Fluoride concentration (wt%)/Contact angle q (degree) 0
0.01
0.05
0.1
0.2
0.3
At room temperature At 80 C At 100 C
Spread
42.2
72
105.1
92.8
92.4
Spread Spread
35 38
65.4 63.2
95.8 85.5
90.6 88.6
93.1 83.7
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approximately zero. With the application of fluoride, the contact angles increased. The maximum contact angle (approximately 105.1 ) was observed when the fluoride concentration reached 0.1 wt%. Then, the contact angle changed slightly. The contact angles decreased as the temperature rose to 80 C or 100 C, as shown in Table 2 and Fig. 2. Despite the decrease in the contact angle, it was still close to 90 . 3.2. Surface tension Fig. 3 presents the variation in water-gas surface tension with fluoride concentrations ranging from 0 to 0.3 wt%. The surface tension decreased quickly as fluoride was added into the solution. After the concentration reached 0.05 wt%, the surface tension of solution varied over a small range. According to the Formula (1) for capillary pressure, Pc is affected by the surface tension s and the contact angle q at a certain pore size. Because the surface tensions were almost constant at given concentrations, wettability alteration was responsible for the changes in capillary force. Fig. 4 was obtained from the results of the contact angle and surface tension tests at room temperature. The capillary force reached a minimal negative value when the fluoride concentration reached 0.1%. Because the capillary force Pc is resistant to water flowing back into the well in water-wet reservoirs, Pc becomes favorable for water removal once the force direction becomes negative. So the fluoride concentration of 0.1% was chosen for later experiments.
Fig. 3. Surface tension at different concentrations.
Fig. 4. Capillary forces at different concentrations.
3.3. Damage evaluation during dynamic circulation 3.3.1. Rheology of drill-in fluid Table 3 shows the fluid rheology of the KCl solution and the drill-in fluid. As fluoride is an organic substance with a short molecular chain, its addition slightly increased the viscous shear of the fluid. This was not necessarily problematic. The drill-in fluid was aged at 120 C for 16 h and then the rheology was measured when the temperature dropped to 50 C. After hot rolling, the apparent viscosity and shear decreased compared to their values before hot rolling, but the impact of fluoride became more obvious. These results confirmed that the quaternary ammonium fluoride was a suitable additive to the drill-in fluid. 3.3.2. Filtration during dynamic circulation and displacement Table 4 shows the cumulative filtration vs. time during circulation and the reversed flow back of the drill-in fluid through core samples. Core samples S-6 and S-7 were contaminated with drill-in fluid without fluoride, while core sample S-8 and S-9 were
contaminated with drill-in fluid with fluoride. The cumulative filtration amount of the invading fluid without fluoride was 0.27e0.28 ml, while the amount of invading fluid with fluoride was 0.30e0.31 ml. There was no obvious fluid invasion when the fluoride was employed, but the total displacement volume and flow back rate of the liquid with fluoride was almost double that of the liquid without fluoride. The average flow back rates were 85.1% and 45.2%, respectively, indicating that fluoride plays a positive role in promoting the flow back rate of the invading fluid. 3.3.3. Gas permeability recovery after flow back Fig. 5(a) shows the gas permeability recovery of cores after circulating drill-in fluids without fluoride. The permeability recovery was approximately 40%e60% of the original value and hardly changed after the differential pressure reached 1.5 MPa. At least 40% of the gas permeability was lost when the core samples were flushed with the original drill-in fluid. Fig. 5(b) displays the gas permeability recovery of cores after circulation with fluoridecontaining drill-in fluids. The gas permeability recovery was clearly higher from cores with fluoride than from cores without fluoride. As more water was removed, the gas permeability was restored to 82e93% of its original value. 3.4. Fluoride adsorption on core surface during filtration
Fig. 2. Contact angles vary with concentration at different temperatures.
Fig. 6 depicts the HPLC chromatogram of the fluoride standard solution, showing a single peak at one concentration at the detected wave of 254 nm. The peak began rising at approximately 1.4 min and gradually increased with concentration. The retention time and operating voltage also increased with concentration, but two additional small peaks emerged at 0.1 wt%. At this point, the peak up time and retention time all increased. These results may have been affected by the impurity of the testing environment. Fig. 7 shows the standard curve obtained from Fig. 6. The peak area was highly proportional to the concentration of fluoride. Fig. 8 depicts the HPLC chromatogram of the filtrate obtained from core
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Table 3 Impact of fluoride on fluid rheology under atmospheric pressure. AV, cp PV, cp YP, Pa YP/PV, (ms)1 Gel, Pa
Fluid composition
3 wt% KCl solution 9.5 3 wt% KCl þ 0.1% fluoride 9.5 Drill-in fluid 105.3 Drill-in fluid þ 0.1% fluoride 105.3 Drill-in fluid 93.5 Drill-in fluid þ 0.1% fluoride 94.5
5.0 4.0 78.4 78.4 73 73
4.59 5.61 27.45 27.45 20.95 21.97
0.92 1.40 0.35 0.35 0.29 0.30
Note
1/1.3 At room temperature 1.5/2 4.1/10.7 4.6/11.2 3.1/7.2 Fluid was aged at 120 C and then measured when the temperature decreased to 50 C 3.6/7.7
Table 4 Cumulative filtration vs. time and flow-back analysis of the drill-in fluid considering fluoride. Fluid type
Drill-in fluid Drill-in fluid þ fluoride
Cumulative filtration, ml Time (min)
1
3
5
7
10
15
20
30
40
50
60
S-6 S-7 S-8 S-9
0.065 0.064 0.068 0.073
0.086 0.084 0.091 0.095
0.095 0.092 0.1 0.11
0.11 0.11 0.12 0.13
0.12 0.12 0.13 0.14
0.14 0.14 0.15 0.16
0.16 0.16 0.17 0.18
0.2 0.19 0.21 0.22
0.23 0.22 0.23 0.26
0.24 0.24 0.28 0.29
0.27 0.26 0.33 0.34
samples. It shows that there was no obvious peak of fluoride at 1.4 min. In other words, the tested sample did not contain fluoride, or the amount of fluoride was below the detection range of the instrument under those conditions. When the fluid was circulated through the core sample, fluoride was adsorbed onto the rock. As the original concentration of fluoride in the drill-in fluid was 0.1 wt % (1000 ppm), the adsorption amount on the rock surface could be calculated using Formula (3). However, because the circulation was done at constant displacing pressure, the invasion volume could not be accurately acquired. Thus, the study shows that fluoride
Displacement, ml
Flow back rate, %
0.13 0.11 0.29 0.28
48.1 42.3 87.8 82.4
adsorbed onto the rock, but no accurate adsorption amount could be determined. 3.5. Surface morphology The SEM results are shown below, in Figs. 9 and 10. Fig. 9 depicts the rock surface morphology after the circulation of the original drill-in fluid. Fig. 10 depicts the rock surface morphology after the circulation of drill-in fluid with fluoride. There were many small and large prolate substances on the surface, but the shapes were
Fig. 5. Permeability recovery after fluid flowing back from cores damaged by drill-in fluid.
Fig. 6. High performance liquid chromatography at series of fluoride concentration.
Fig. 7. The standard HPLC curve for fluoride.
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Fig. 8. HPLC chromatogram of the filtrate obtained from core samples.
aggregation. The adsorption of the fluoride changed the morphology of rock surface and reformed a new irregular microstructure, leading to the changes in the surface properties. 4. Mechanistic analysis of wettability alteration The HPLC and SEM results showed that fluoride was adsorbed onto the core surface, which resulted in an increase in the contact angle. The results obtained in the dynamic circulation test can be better understood by considering the wetting alteration induced by fluoride adsorption onto the surface. A phase interface with a water contact angle above 90 is termed a hydrophobic interface, and in general, a hydrophobic surface is affected by the surface structure as well as surface energy. 4.1. Reformation of surface morphology
Fig. 9. Fresh end core after fluid circulation without fluoride.
essentially similar. The morphology shown in Fig. 10 was significantly different from the surface morphology in Fig. 9, and it is obvious that the fluoride was largely adsorbed onto the rock surface. The fluoride-adsorbed surface presented uneven molecular
Fig. 10. Fresh end core after fluid circulation with fluoride.
Due to isomorphous substitution, large amounts of permanent negative charges, small amounts of variable charges, and hydroxyls are either in or adsorbed onto the molecules of the mineral surface. As the surface tends to be instable, the affinity to adsorb cationic fluoride occurs through Coulomb forces, hydrogen bonds or Van der Waals forces. The HPLC results showed that there was total adsorption of fluoride onto the rock surface. It is obvious that the adsorption was more likely to occur in the defect areas. Thus, as shown by the SEM results, the original surface structure and roughness changed. The molecular aggregation on the surface was not regular, and large adsorptions onto the surface increased the micro-roughness. The adsorption layer of fluoride on the surface can be simplified into micelles and vacancies. This was confirmed by the SEM results. Combined with the contact angle test, the hydrophobic surface can be explained using a model from Wenzel and Cassie (Roach et al., 2008), as shown in Figs. 11 and 12. The micro-bump structure with a larger specific surface area not only improved the area of the gas cushion but also enhanced the repellent abilities of the mineral surface, thus improving water removal and the recovery of gas permeability.
Fig. 11. Hydrophobic surface after fluoride treatment.
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Fig. 12. Two wetting state models: (a) Wenzel (b) Cassie-Baxter.
4.2. Lower surface free energy The adsorption of fluoride onto the rock surface should have resulted in a lower surface free energy. Thus, to quantitatively analyze the surface energy before and after the modification, the contact angle method was used to test the surface free energy (Girifalco and Good, 1957). The calculation formula can be expressed as follows:
rffiffiffiffiffi gs ; cosq ¼ 1 þ 24 gl
(4)
where q is the water contact angle on the rock surface, degrees; 4 is the correction factor with a value of 0.5e1.5, which is determined by molecular size and intermolecular interactions within the system and assigned to be 0.5 in a system composed of perfluoroalkyl and water or 1.0 in a system composed of a polar mineral rock surface and water; gl is the surface tension of the liquid, mN/m; and gs is the solid surface energy, mJ/m2. To quantitatively calculate the surface free energy, the value of q and gl were determined at room temperature. Without fluoride, q and gl were 0 and 72 mN/m, respectively. With fluoride in the system, q and gl were 105.5 and 22.4 mN/m, respectively. According to Formula (4), the rock surface free energies before and after fluoride adsorption were calculated as 72 mJ/m2 and 12 mJ/ m2, respectively. It is known that lower solid surface energies correspond to smaller binding forces between the solid and liquid. Therefore, the spread of the aqueous phase over the newly modified surface was restricted, exhibiting increases in the water contact angle and the gas permeability recovery. 5. Conclusions In this study, wettability alteration by fluoride and its mechanism were experimentally studied. A series of experiments aimed at determining the water contact angles, surface tension, fluid rheology, dynamic circulation of drill-in fluid through core samples, amount of adsorbed fluoride and the micro-morphology of the rock surface after adsorption were conducted. The surface free energy before and after adsorption was also calculated. Based on the results obtained, the following conclusions can be drawn: 1) Rock wettability was modified from water-wetting to hydrophobic oil-wetting after the rock was treated with the quaternary ammonium fluoride salt. The contact angles decreased as the temperature rose to 80 C or 100 C but were still close to 90 ; 2) The surface tension decreased to 20 mN/m with the addition of fluoride and then changed slightly. As the capillary force reached a minimal negative value when the fluoride concentration reached 0.1%, the optimal concentration was selected to be 0.1%; 3) The addition of fluoride slightly increased the viscous shear of the drill-in fluid. The application of fluoride improved the flow
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