Wettability modification by fluoride and its application in aqueous phase trapping damage removal in tight sandstone reservoirs

Journal of Petroleum Science and Engineering 133 (2015) 201–207

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Wettability modification by fluoride and its application in aqueous phase trapping damage removal in tight sandstone reservoirs Xuefen Liu n, Yili Kang, Pingya Luo, Lijun You, Yun Tang, Lie Kong State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, Chengdu 610500, PR China

art ic l e i nf o

a b s t r a c t

Article history: Received 17 March 2014 Received in revised form 14 May 2015 Accepted 12 June 2015 Available online 19 June 2015

External fluid invading into reservoir could induce formation damage in form of phase trapping in tight sandstone reservoirs (in-situ permeability o0.1 mD). Aqueous phase trapping damage occurs commonly in drilling and completion operations. Once aqueous phase trapping damage happens, it could hardly be removed, as a result of which gas production will not be promising. The objective of this study is to experimentally investigate the wettability alteration by quaternary ammonium fluoride salt and its potential to mitigate aqueous phase trapping damage in original water-wet, tight sandstone gas reservoirs. Wettability alteration from water wetting to gas wetting was achieved as water contact angles on core chip surface treated by 0.1 wt% fluoride were larger than 90° at 27 °C. There was hardly change in contact angles when temperature rose up to 80 °C and 100 °C respectively. The results of contact angle and surface tension tests indicated that the optimal fluoride concentration is 0.1 wt%. Atomic Force Microscope (AFM) analysis revealed that large amounts of fluoride adsorbed on mica surface, forming an irregular micro-nanometer structure. The modified structure enhanced hydrophobicity of surface and promoted the flowback of the invading fluid foreign to reservoir. Fluid rheology tests were carried out by viscometer and the results showed good compatibility between fluoride and drill-in fluid. The result of the core flow test indicated that both the flow back rate and gas relative permeability were significantly improved by 40% and 20% respectively. & 2015 Elsevier B.V. All rights reserved.

Keywords: Tight sandstone Formation damage Aqueous phase trapping Wettability modification Atomic Force Microscope

1. Introduction Increasing world demand on energy prompts an increased emphasis toward unconventional resources. Tight sandstone gas accounts a major portion of the current exploitation market among unconventional gas production (Abdelaziz et al., 2011; Wisam and Jennifer, 2014). However, tight sandstone gas reservoirs are exposed to many production problems and formation damage due to unfavorable geologic status, i.e., low permeability (o 0.1 mD), narrow throats, remarkable amounts of potential capillary suction energy and extra-low initial water saturation (Bennion et al., 2004; Gupta,2009). As a result, fluid invading into the reservoir can be easily entrapped within porous medium during drilling and completion operations, making reservoirs suffer from phase trapping damage (Bennion et al., 1996; Cai et al., 2012; Mahadevan et al., 2007). Provided the reservoir is water-wet and the fluid invading into the reservoir is water-based, it could be recognized as aqueous phase trapping damage (Bennion et al., 1996; You and Kang, 2009). n

Corresponding author. Tel.: þ 86 28 8303 2118. E-mail address: [email protected] (X. Liu).

http://dx.doi.org/10.1016/j.petrol.2015.06.013 0920-4105/& 2015 Elsevier B.V. All rights reserved.

Recently, there have been many studies focused on factors affecting aqueous phase trapping damage (Abass et al., 2007; Bennion et al., 1992, 2004; Holditch, 1979), damage laboratory evaluation (Bennion et al., 1991), consequence and prevention or treatment of aqueous phase trapping damage (Bahrami et al., 2012; Bennion and Thomas, 2005; Bennion et al., 1994, 2000; Jamaluddin et al., 2000; Wang et al., 2012). Capillary imbibition and entrapment of the invading aqueous are the main reasons of aqueous phase trapping damage. The entrapment of liquid within pore throats is attributed to the unfavorable capillary force, Pc ¼2s cos θ/r (Cai et al., 2014). Once aqueous phase trapping damage occurred, gas relative permeability can be substantially reduced by approximately 95% of the original value (Bennion et al., 1996) and the damage could hardly be removed, leading to a disappointing gas production (Xie et al., 2009). In general, most of tight sandstone gas reservoirs are water-wet due to special physicochemical properties of silicate minerals existing on the surface. Li and Firoozabadi (2000) proposed that modifying reservoir wettability from water wetting to gas wetting can mitigate aqueous phase trapping damage and improve gas production, which provided a new idea for controlling aqueous trapping damage. Water capillary imbibition behavior in tight sandstone gas reservoirs can be inhibited by wettability alteration (Liu et al., 2009;

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2.2. Apparatus and methodology

Fig. 1. Molecular structure of quaternary ammonium fluoride salt FW-134.

You and Kang, 2013). Wettability modification can be achieved by certain ionic compound (Bera et al., 2012). Fluoride was selected as the modifier due to its better aqueous stability and lower surface free energy (Al-Anazi et al., 2007; Fahes and Firoozabadi, 2005; Liu et al., 2006; Panga et al., 2006; Tang and Firoozabadi, 2002). Li and Liu (2008) reported an earlier field application of wettability modification by fluoride. Micellar solubilization and ion-pair formation have been postulated as mechanisms of wettability alteration in some literatures (Anderson, 1986; Austad and Milter, 1997; Bera et al., 2011; Li and Horne, 2003; Li et al., 2004; Salehi et al., 2008, 2010; Seiedi et al., 2011; Standnes and Austad, 2000; Wu and Firoozabadi, 2009; Wu et al., 2006). Nevertheless the previous mechanism studies focused mostly on hydrocarbon surfactant. More underlying experiments on wettability modification by fluoride are required. In this study, wettability alteration is achieved by quaternary ammonium fluoride salt (purity 99.9%) with both hydrophobic groups and hydrophilic groups (Fig. 1). Firstly, contact angles and surface tensions with fluoride concentration between 0% and 0.3% were measured and the optimal concentration for lower capillary viscosity force was finally determined. Contact angles of waterbased drill-in fluid at different temperatures with optimal fluoride concentration were also measured. Secondly, Atomic Force Microscope (AFM) was applied to image surface morphology to understand mechanisms of the wettability alteration by fluoride. Finally, core flow test by circulating drill-in fluid at the core plug's end was performed to examine the feasibility of controlling aqueous phase trapping damage in tight sandstone gas reservoir. In order to ensure the flow test done in the right way, we gave the priority to rheology test to examine the performance of drill-in fluid and its compatibility with fluoride. The methodology is described as follows.

2. Experiment section 2.1. Materials In this study, tight sandstone core samples with permeability less than 0.1 mD from target gas reservoir were used for contact angle test and core flow test, shown in Table 1. Mica was used for imaging surface morphology by AFM. Quaternary ammonium fluoride salt was applied as wettability modifier. Distilled water, potassium chloride (KCl) and sodium chloride (NaCl) were used for synthetic solution. Drill-in fluid from target gas field was used for core flow test. Dried N2 (purity 99.99%) was used as power source.

2.2.1. Measurement of contact angle The static contact angle (θ) for the water–gas–rock system was measured by a goniometry setup (U. S. Patent 5.268.733). Core samples were cut into chips of Φ25 mm  L50 mm and aged in solution with fluoride concentration between 0% and 0.3% at 27 °C. Aqueous droplet with constant volume of 20 μl was placed in direct contact with the core surface and then the magnified photograph of the droplet was projected on dial. Furthermore, photographs of drill-in fluid filtrate on core chips before and after treatment at 27 °C, 80 °C, and 100 °C were taken as well. 2.2.2. Measurement of surface tension Generally, the reduction of surface tension (s) can lead to a relative reduction in capillary imbibitions force, Pc ¼2s cos θ/r. This is favorable for mitigating aqueous phase trapping damage. Surface tension of water–gas system with fluoride concentration from 0 to 0.3 wt% was measured by tension-meter (JZHY1-180) at 27 °C. The standard deviation does not exceed 70.1 mN/m. 2.2.3. Surface morphology of mica treated by fluoride Atomic Force Microscope (AFM) was adopted to obtain the apparent absorption morphology of mica at 27 °C. Mica was selected for two reasons. On one hand mica has similar structure with Illite which is the main component of clay mineral in tight sandstone. On the other hand mica surface is relatively smooth for obtaining the adsorption imaging. Mica was cut into square plate by 10 mm  10 mm  2 mm and was saturated by aqueous solution (0.1 wt% fluoride) for 10 min. After that the mica plate was cleaned by distilled water and dried by N2 flush. The tests were performed in10 μm  10 μm scanning area with 1.489 Hz scanning speed under tapping mode. 2.2.4. Drill-in fluid rheology The priority was given to drill-in fluid rheology tests as the rheological property is of primary concern in the formation for any type of fluid (Olatunde et al., 2012). Thus, rheology was measured by viscometer prior to core flow test to testify the compatibility between fluoride and water-based drill-in fluid. Rheological parameters, such as viscosity AV, plastic viscosity PV and yield point YP, were calculated. The viscometer is calibrated in revolutions per minute (RPM). 2.2.5. Core flow test The system used for core flow test, including mud circulating loop and instrumental system, is illustrated by Fig. 2. The core holder cell is equipped on the fluid container. The rotation of the four rotors induces the circulation of fluid. Core and fluid for flow tests are shown in Table 1 above. Firstly gas permeability K0i was measured by flowing dry nitrogen gas through core samples at constant confining pressure of 10 MPa and varying differential pressure. Then the drill-in fluid was circulated across the face of the core for 60 min at differential pressure ΔP ¼ 3.5 MPa, rate of shear V¼ 40 s  1 and T ¼80 °C. During the circulation, the communicative filtration as a function of

Table 1 Core physical properties and working fluid for core flow test. Core#

Length, mm

Diameter, mm

Porosity, %

Permeability, mD

Pore volume, ml

Swi,%

Weight, g

Fluid type

S2-7 S2-15 D-82 A-57

49.6 38.7 63.4 63.3

25.1 25.1 25.3 25.2

3.74 3.79 15.51 15.99

0.017 0.012 0.051 0.058

0.921 0.725 4.929 5.054

20 20 21 23

69.13 70.14 71.22 70.08

Drill-in fluid Drill-in fluid þ 0.1%fluorid

X. Liu et al. / Journal of Petroleum Science and Engineering 133 (2015) 201–207

203

Table 3 Comparisons of contact angle varying with time. Conditions

Time of progress

Water, at 27 °C

Without fluoride

0.1 wt%fluoride

Fig.2. Setup for core flow tests.

time was measured. Once the circulation had been completed, flowback test was conducted by introducing nitrogen at differential pressure ΔP = 5 MPa for 3 h in the reversed flow direction and the displacement volume was measured. Finally, the gas permeability K1i was reexamined at the condition equivalent to that of K0i and permeability recovery was calculated by K1i/K0i.

Drill-in fluid filtrate

Without fluoride, at 27 °C

0.1 wt% fluoride, at 27 °C

3. Results

0.1 wt% fluoride, at 80 °C

3.1. Contact angle Table 2 shows the contact angles varying with fluoride concentration from 0 to 0.3 wt%. The initial wettability of the rock was water-wet and the contact angle θ was approximately zero. The maximum value of contact angle (approximately 105°) was observed when fluoride concentration reached 0.1 wt% and contact angle varied slightly after that. Table 3 shows contact angles vs. time. There was hardly change in θ when temperature rose up to 80 °C and 100 °C respectively.

20.0

3.2. Surface tension

15.0

3.3. Surface morphology of mica sample by AFM AFM was used as a supplementary technique to investigate the

σcosθ/ (mN/m)

Table 2 presents the water–gas surface tension of solution with fluoride concentration ranging from 0 to 0.3 wt%. The tension of solution with fluoride varied in a small range (21–24 mN/m) and was significantly lower than that of distilled water. Since the surface tensions are almost constant at given concentrations, wettability alteration is responsible for capillary force change. As shown in Fig. 3, the capillary force Pc reached a minimal negative value when the fluoride concentration equaled to 0.1%. As the capillary force Pc is resistant to water flowing back in water-wet reservoirs, capillary force will turn to be favorable to water removal once the force direction is changed to be negative. So the later study gave priority to the fluoride concentration of 0.1%.

0.1 wt% fluoride, at 100 °C

15.32

10.0 7.00 5.0 -0.94

-0.77

0.2

0.3

0.0 -5.0 -5.66 -10.0

0

0.1

0.4

Concentration/ (wt %) Fig. 3. Capillary forces with different concentrations. (a) The original one. (b) The treated one.

mechanism of wettability alteration by imaging the surface changes in morphology and composition. The morphological

Table 2 Contact angle and surface tension of the fluoride solution varying with concentration at 27 °C. Concentration, wt%

0.3 0.2 0.1 0.05 0.01 Distilled water

Contact angle θ, ° (at initial time)

Surface tension s, mN/m

θ1

θ2

θ3

Mean value

s1

s2

s3

Mean value

90.5 92.5 102.3 70.4 40.0 –

86.3 95.5 110.5 70.5 42.2 –

100.5 90.3 102.5 75.3 45.0 –

92.4 92.8 105.1 72.0 42.4 –

22.5 23.4 22.4 21.1 20.3 72

22.7 23.9 22.4 22.3 21 71

23 23.7 22.5 23.3 20.8 72.3

22.7 23.7 22.4 22.2 20.7 71.8

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Fig. 4. Surface morphology of mica scanned by AFM. (a) Height image with a selected path. (b) Profile based on the selected path.

Fig. 5. Height images of the treated mica surfaces by AFM.

0.35

Table 4 Rheology of fluid (3 wt%KCl) with fluoride. cumulative filtration (ml)

0.30

Fluid composition

AV, cp PV, cp YP, Pa YP/PV, (ms)  1

Gel, Pa/Pa

3 wt%KCl 3 wt%KClþ 0.05%fluoride 3 wt%KClþ 0.1%fluoride 3 wt%KClþ 0.1%fluoride þ2% NaCl 3 wt%KClþ 0.1%fluoride þ5% NaCl 3 wt%KClþ 0.1% fluorideþ 10%NaCl

9.5 9.5 9.5 8.0

5.0 5.0 4.0 4.0

4.59 4.59 5.61 4.09

0.92 0.92 1.40 1.02

3.6/3.6 3.6/3.8 4.1/4.1 2.0/2.0

7.0

4.0

3.07

0.77

2.6/2.6

0.05

6.5

4.0

2.56

0.64

2.6/2.6

0.00

0.25 0.20 Core sample S2-7 Core sample S2-15 Core sample D-82 Core sample A-57

0.15 0.10

0

10

20

30 time (min)

40

50

60

Fig. 6. Cumulative filtration of the drill-in fluid vs. time. (a) Core sample S2-7. (b) Core sample S2-15.

Table 5 Rheology of drill-in fluid with fluoride. Fluid composition

AV, cp PV, cp YP, Pa YP/PV, (ms)  1

Gel, Pa/Pa

Drill-in fluid Drill-in fluid þ0.1% fluoride Drill-in fluid þ0.1% fluorideþ 2%NaCl Drill-in fluid þ0.1% fluorideþ 5%NaCl Drill-in fluid þ0.1% fluorideþ 10%NaCl

105.3 105.3 101.5

28.5 28.5 28.0

78.44 78.44 75.12

2.75 2.75 2.68

86.0/95.0 86.5/95.0 80.0/84.5

93.0

26.0

68.47

2.63

80.0/83.0

91.5

27.0

65.90

2.44

70.0/75.0

images of the original and treated mica surface were analyzed. Fig. 4(a) shows the morphology of the original mica with relatively smooth surface. Fig. 4(b) shows the morphology of the mica surface treated by fluoride. The mean and the highest adsorption height were 10–20 nm and 60 nm respectively. The surface presented uneven molecular aggregation and large

Table 6 Flow-back analysis of drill-in fluid in core samples considering fluoride. Working fluid

Drill-in fluid

Drill-in fluid þ0.1 wt%fluoride

Core sample Cumulative filtration, ml Displacement, ml Flow back rate, % Average flowing-back rate, %

S2-7 0.28 0.125 44.8 46.6

D-82 0.30 0.253 81.6 85.2

S2-15 0.27 0.132 48.4

A-57 0.31 0.275 88.8

adsorptions were more likely to occur at points with defect. Fig. 5 shows the surface height image (a) and the profile based on a selected path in 1D (b) after adsorption. The mean aggregation diameter was about 200 nm. Few parts of the aggregation diameter reached 800 nm. The adsorption of the fluoride

X. Liu et al. / Journal of Petroleum Science and Engineering 133 (2015) 201–207

1.0 Core sample S2-7 porosity 3.74% permeability 0.017mD

0.8

permeability re covery

permeability recovery

1.0

0.6 0.4 0.2 0.0

0

1

2

3

4

Core sample S2-15 porosity 3.79%

0.8

permeability 0.0123mD 0.6 0.4 0.2 0.0

5

205

0

1

2

3

4

5

differential pressure (MPa)

differential pressure (MPa)

Fig. 7. Permeability recovery of cores after circulating drill-in fluids without fluoride. (a) Core sample A-57. (b) Core sample D-82.

1.2

1.0 permeability recovery

permeability recovery

Core sample D-82

Core sample A-57 porosity 15.99 % permeability 0.0581mD

1.5

0.9 0.6 0.3 0

0

1

2

3

4

5

porosity 15.51 % permeability 0.0511mD

0.8 0.6 0.4 0.2 0.0

0

1

differential pressure (MPa)

2

3

4

5

differential pressure (MPa)

Fig.8. Permeability recovery of cores after circulating drill-in fluids with fluoride.

3.4. Drill-in fluid rheology

Fig. 9. Simplified graph of the adsorbed layer.

The rheology of solution of 3 wt% KCl with fluoride shown in Table 4 indicated better compatibility between fluoride and salt. Table 5 shows that adding fluoride into drill-in fluid had little effect on the fluid’s rheology. Parameters such as apparent viscosity (AV) and yield point (YP) had a slightly decrease with the concentration of NaCl at 2 wt%, 5 wt%and 10 wt%, respectively. The results confirmed that the quaternary ammonium fluoride salt is available in drill-in fluid. 3.5. Core flow test

Fig. 10. Two wetting state models: (a) Wenzel. (b) Cassie–Baxter.

increased the surface roughness and decreased the defect areas on mica surface (Ai et al., 2005). It can be seen that the adsorption of fluoride on the surface reformed an irregular micro-nanometer structure, as a result of which the surface properties would be changed.

3.5.1. Filtration and flow back Fig. 6 shows the cumulative filtration vs. time during circulation of the drill-in fluid. Core sample S2-7 and S2-15 were contaminated by drill-in fluid without fluoride, while core sample D-82 and A-57 were contaminated by drill-in fluid with fluoride. The cumulative amount of invading fluid without fluoride was 0.27–0.28 ml, while that of invading fluid with fluoride was 0.30– 0.31 ml. When the fluoride was employed, there was no obvious fluid invasion even at differential pressure of 5.0 MPa. Table 6 shows the total displacement volume and flow back rate. Flow back rate of invading liquid with fluoride was double that of

Fig. 11. Schematic diagram of probable interaction happening at mineral surfaces.

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Fig. 12. Water flow ability and gas permeability recovery will be improved as a result of wettability alteration from water wetting to gas wetting, by fluoride adsorption on mineral surface.

without fluoride, that was 85.2% and 46.6% respectively, indicating that fluoride would play a positive role in promoting the flow back of the invading fluid to reservoir. 3.5.2. Permeability recovery Fig. 7 shows the permeability recovery of cores after circulating drill-in fluids without fluoride. The permeability recovery was about 40–60% of the original value and it hardly changed after the differential pressure reached 2 MPa. At least 30% of gas permeability was lost when the core samples damaged by the original drill-in fluid without fluoride. Fig. 8 displays the permeability recovery of cores after circulating drill-in fluids with fluoride. For the core sample A-57, the permeability exceeded the initial permeability at any given differential pressure. For the sample D-82, permeability restored 80% of the original value when differential pressure increased to 2 MPa, though damage still existed. When differential pressure increased from 4 to 5 MPa, permeability had a slight decrease. This may be related to adsorption instability induced by displacement.

4.2. Lower surface free energy Phase interface with water contact angle above 90° is termed hydrophobic. In general, a more hydrophobic surface is affected by the surface roughness and lower surface energy. There are large amounts of permanent negative charges and small amounts of variable charges and hydroxyls in or absorbed on the mineral molecules because of isomorphous substitution. As the surface tends to be instable, the affinity to adsorb cationic fluoride would occur through Coulomb force, hydrogen bond or Van der Waals force, shown in Fig. 11(a) and (b). Fluorine is an element with the strongest electro-negativity and the lowest surface free energy among element ever discovered. The main chains are wrapped by the connected fluorine atoms and exhibit a huge repulsion to each other. The surface free energy of minerals would decrease as fluorine gather at the mineral surface and a hydrophobic surface would reform (Wang and Chen, 2005; Zhao et al., 2007). As a result, the spread of aqueous phase on the new surface will be restricted, exhibiting an increase in contact angle and gas permeability recovery (Fig. 12).

4. Discussions

5. Conclusions

It has been proved that the adsorption of fluoride on the solid– liquid interface is the reason for the increase in contact angle. And the results obtained in core flow test can be better understood by considering wettability alteration by fluoride adsorbing at surface. The reformed surface morphology and lower surface free energy are the main reasons for wettability alteration.

According to the experimental results, the following conclusions can be drawn:

4.1. Reformation of surface morphology Wettability of solid is mainly affected by its surface structure and roughness. The adsorption layer of fluoride on mineral surface can be simplified as micelle and vacancy, shown in Fig. 9. This simplification confirms the mica surface structure observed by AFM and the hydrophobic model proposed by Wenzel and Cassie (Roach et al., 2008), as shown in Fig. 10. The micro-bump structure with a larger specific surface area and rougher surface not only improved the area of gas cushion but also enhanced repellent ability of the mineral surface, as a result of which gas permeability improved.

1. Wettability could be modified from water wetting to gas wetting by the quaternary ammonium fluoride salt, with the optimal concentration of 0.1 wt%. 2. The adsorption of fluoride on rock surface may occur and then reform a new irregular nano-micro structure with low surface free energy, restrictingapp:addword:restrict the aqueous phase spread at the mineral surface and increasing the flow ability of liquid and gas. 3. There is a good compatibility between fluoride and drill-in fluid. Fluoride can maintain fluids' rheology and present better tolerance for salinity and temperature. 4. The flow back rate and gas relative permeability were significantly improved by 40% (from 46.6% to 85.2%) and 20% (from 60% to 80%) respectively, displaying the potential to mitigate aqueous phase trapping damage in tight sandstone gas reservoirs.

X. Liu et al. / Journal of Petroleum Science and Engineering 133 (2015) 201–207

Acknowledgments This work is financially supported by the National Basic Research Program (973) Projects of China under Grant no. 2010CB226705 and by National Science and Technology Major Special Projects of China under Grant no. 2008ZX05022. Thanks are also extended to all individuals associated with the project.

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