Effect of Anionic Surfactant on Wettability of Shale and Its Implication

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The Effect of Anionic Surfactant on The Wettability of Shale and its Implication on Gas Adsorption/Desorption Behavior Hesham Abdulelah, Syed M. Mahmood, and Ahmed Al-Mutarreb Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.7b03476 • Publication Date (Web): 17 Jan 2018 Downloaded from http://pubs.acs.org on January 18, 2018

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Title: The Effect of Anionic Surfactant on The Wettability of Shale and its Implication on Gas Adsorption/Desorption Behavior Authors: Hesham Abdulelah 1, Syed Mahmood 1, * and Ahmed Al-Mutarreb 1 Affiliations: 1

Shale Gas Research Group (SGRG), Institute of Hydrocarbon Recovery, Department of Petroleum Engineering, Universiti Teknologi PETRONAS, 32610 Seri Iskandar, Perak Darul Ridzuan, Malaysia; [email protected] (H.A) Corresponding Author: AP.Dr. Syed Mahmood Associate Professor Shale Gas Research Group (SGRG), Institute of Hydrocarbon Recovery, Department of Petroleum Engineering, Universiti Teknologi PETRONAS, 32610 Seri Iskandar, Perak Darul. T: +605 368 7103 E: [email protected]

ACS Paragon Plus Environment

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Abstract

During the fracking process in shale, an interaction occurs between shale and fracking fluid which contains a cocktail of chemicals. One of the chemicals used in fracking fluid is often surfactant, which is generally used as a viscofier. However, surfactants also have the potential of significantly influencing the wettability and thus gas desorption – key factors affecting ultimate gas recovery from shale reservoirs. Even though a few studies discussed the ability of surfactants to wettability in shale, the implication of that change in adsorption/desorption behavior has never been experimentally investigated beyond hypothetical inferences. In this study, the influence of the wettability change by anionic surfactant on gas adsorption/desorption behavior in shale was investigated through a series of experiments. Baseline wettability readings of two shale samples were established by measuring the contact angles (BG-1=22.7°, KH-1= 35°) between a drop of pure water placed on their polished surfaces, indicating that the affinity of pure water for the BG1 surface was greater than that for KH-1. This difference can be attributed to the higher clay content and lower total organic carbon found in BG-1 as compared to KH-1. To investigate the impact of the interaction between shale and surfactants on wettability during the fracking process, the contact angles were measured again, this time with 1 wt% solution of internal olefin sulfate surfactant. The surfactant-induced wettability changes of the two shale samples were investigated by measuring the contact angles again (BG-1=3.5°, KH-1= 19.2°) between a drop of surfactant solution and their polished surfaces. The effect of wettability changes on gas adsorption/desorption was then evaluated utilizing the United States bureau of mines’ modified method. Experiments were conducted on the two shale samples in two ways: after pure water treatment, and after surfactant treatment. The results suggest that due to the wettability alteration of the two shale samples by IOS surfactant towards more water-wet during the treatment, the


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methane adsorption/desorption characteristics were influenced. In BG-1 sample, IOS solution dramatically changed its wettability to become completely water-wet. Therefore, the volume of desorbed methane dropped by nearly 54%. A similar but less pronounced influence was found in KH-1 sample, where its desorbed methane dropped by 10% due to wettability alteration towards more water-wet. These reductions in the amount of desorbed gas suggest that prior to selecting a surfactant for addition to fracking fluid, its effect on wettability and gas desorption should be investigated to optimize shale gas recovery potential.

Keywords: Shale, Wettability Alteration, Adsorption, Desorption, Anionic Surfactants.

1. INTRODUCTION The oil & gas industry is undergoing a transformation in hydrocarbon recovery from a scarcity of resources to an abundance due to what is dubbed as “shale oil & gas” revolution. Shale reservoirs, due to their ultra-low permeability, are classified as “unconventional resources.” Despite the current glut caused by the production from shale reservoirs, it is anticipated that they will continue to play an important role in fulfilling the energy demand in the future. The production of gas from shale requires horizontal drilling and fracking (hydraulic fracturing) to enhance transmissibility. With rapid technological advances in extended-reach and multi-lateral horizontal drilling, and in advanced fracking, it is likely that shale gas will be the largest constituent in gas production in future.1-3 Shale is composed of fine grains, rich in clay, could have significant organic content, and can entrap a large amount of gas.4 The gas in shale gas reservoirs usually exists in three states: free gas, dissolved gas, and adsorbed gas; however, a significant proportion of it exists in the


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adsorbed state.5-6 Extremely low matrix permeability, very fine grains, micro/mesopores and large surface areas cause a high proportion of gas to remain adsorbed in shales.7 Fracking, a critical need for shale gas production, involves pumping a large volume of water at high pressures to create highly conductive vertical fractures. The proppants are added to the pumped water to keep the fractures propped open. In addition, a cocktail of chemicals is routinely added in a fracking operation out of hundreds of chemicals that could be possibly added to perform more specialized functions. Surfactants such as “Lauryl Sulfate” are also added to increase the viscosity of the fracture fluid.8 However, the addition of this chemical could influence water retention and gas desorption. The fracking fluid loss (water retention in the reservoir) and its impact on gas production, therefore, needs to be carefully investigated. Only 610% on average of the fracking fluid is recovered after flow back from the shale reservoirs in the United States; the remaining is supposedly imbibed by surrounding shale matrix, microfractures, and other fracture networks. A variety of mechanisms are involved in the imbibition 9. An increase in water saturation was found to reduce the adsorption capacity of methane in clay pores in a simulation study. It has also been reported that liquid imbibition in shale reservoir could block gas flow leaving high residual gas trapped, however, the implication of lost water is still open to debate.10-12 Surfactants are added in the hydraulic fracturing fluid to minimize the water imbibition by either reducing the interfacial tension or alter the shale wettability.13-15 There have been several experimental studies on shale investigating the effect of surfactant. Treatment with a nonionic surfactant solution has shown to change wettability from water-wet to intermediate-wet and lowered water imbibition.11, 16 In a separate study, surfactant was shown to alter the surface tension between gas and water, and capillary blocking in shale was claimed to have reduced.17 Another study on Marcellus and Collingwood shale showed that treating with a


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mixture of cationic–anionic surfactant solution increased alteration of wettability at a very low concentration.13, 15 Above studies were performed in the context of the effect of surfactant on alteration of interfacial tension, wettability, and water imbibition. It is also important to study the role of surfactant in changing the gas adsorption/desorption characteristics in shale. This study focusses on the effect of anionic surfactant on adsorption/desorption behavior to fill this gap, though wettability change was investigated as well. One of the most popular methods to measure gas desorption in the laboratory is the USBM modified direct method in which the desorbed gas is collected into an inverted burette (calibrated with small intervals) and volume is measured vs time over an extended period. This particular method is the most common method in the industry to measure the quantity of shale gas.18-19 This study adopts the same method with some modifications (customized desorption canister) to investigate desportion/adsorption of Methane from shale under two wettability scenarios. Shale samples, collected from Batu Gajah and Kroh outcrop formations in Malaysia, were fully characterized for mineralogy, pore system, and total organic matter and were used to investigate the effect of an anionic surfactant (ENORDET O332, Internal Olefin Sulfonate) on methane adsorption/desorption behavior.


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2. EXPERIMENTAL SECTION 2.1. Shale Samples. Two representative samples collected for this study were from shale formations of “Batu Gajah” (BG-1) in the State of Perak and “Kroh” (KH-1) in State of Kedah, Malaysia. Both formations were reported to be potential shale outcrops.20 The samples were collected after removing the upper 60 cm layer of the outcrop. The locations from which these samples were collected are presented in the geological map 21, shown in Figure 1.

Figure 1. Geological map of Peninsular Malaysia showing the locations of shale samples collected for this study


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2.2.

Surfactants. ENORDET O332, an anionic surfactant – Internal Olefin

Sulfonate (IOS), was thankfully obtained gratis from Royal Dutch Shell and was used for contact angle measurements and for treatment of the two crushed samples in some tests. IOS was in a liquid state and was reported by the supplier to be of 28.03% active material (AM) and 0.7 g/cm3 density at 23º C. It has two alkyl groups on tails 15 to 18 carbon atoms.22 The surfactant concentrations (1 wt %) used in this study was presumably well above its CMC (Critical Micelle Concentration).23 In this study, the CMC of ENORDENT O332 was obtained using IFT-700 at 25º C utilizing pure water (0.5 ppt salinity) and found to be 0.05 wt%. The chemical structure of ENORDET O332 (Internal Olefin Sulfonate) is shown in Figure 2.

Figure 2. Chemical Structure of ENORDET O332 (Internal Olefin Sulfonate) 2.3. Mineralogy. The mineralogy measurements of the two shale samples were conducted using Powder X-Ray Diffractometer (XRD, Model: XPert3, PANalytical). The samples were scanned 3º to 65º using a wavelength, λ (CuKα = 1.5418 Å) with a step scan mode (step size 0.026º). The measurement was performed twice in each sample and the results were identical. X-ray diffraction (XRD) was used since it is one of the best available methods for studying the mineralogy of rocks.24 The data form XRD was then analyzed using the US Geological Survey’s (USGS)


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ROCKJOCK program that determines the quantitative mineralogy from such data.25 The elemental analysis was performed using energy-dispersive spectrometry (EDS) using ZEISS Microscope at an accelerating voltage of 20 kV. To provide a visual confirmation about the mineralogy, the field emission scanning electron microscopy (FE-SEM) images were obtained using Zeiss microscope (FESEM, Model: Zeiss Supra 55VP, ZEISS) at magnifications of 10K and 50K at an accelerating voltage of 5 kV. Total Organic Matter (TOC) Measurement. The total organic matter (TOC) of the two samples were measured by TC analyzer (TC Analzer, Model: Multi N/C® 3100, Analytik Jena) by drying powdered samples of the shales at 60o C for 24 hours to get rid of the moisture. To remove the inorganic carbon, 2 grams of each sample was treated with HCL of 37% concentration, followed by washing with distilled water and then drying at 60o C for 12 hours. A small sample (0.63 g) of each shale was loaded into Multi N/C® 3100 to evaluate its total organic matter content (TOC). The measurement was repeated twice in each sample and the TOC results and the deviation between the results were 0.09%, and 0.08% in KH-1 and BG-1; respectively. The average TOC of both measurements was used.


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2.4.

Pore System. A knowledge of pore size distribution is necessary to understand

the mechanism of gas desorption process. Previously, mercury injection capillary pressure (MICP) was used to characterize pore system in rock samples including shales. These methods were later found to be erroneous in showing the pore size distribution of shales.26 Brunauer-Emmett-Teller (BET) method using Surface Area and Pore Size Analyzer (ASAP, Model: ASAP 2020, Micrometrics) is now the standard for revealing the pore structure in shales utilizing low pressure nitrogen adsorption.27 Therefore, BET was used in this study to decipher the pore structure of the two shale samples utilizing nitrogen gas. Prior to the measurements, two samples with a grain size < 0.2 mm were prepared and degassed in Surface Area and Pore Size Analyzer at 80 °C under a vacuum of 10-6 Pa for more than 6 hours (until a constant weight was achieved) to remove moisture.

2.5.Contact Angle Measurement. Several established methods are available to measure the wettability of rock surfaces. However, measuring the contact angle of a liquid droplet placed carefully on the rock surface is the most conclusive and least ambiguous technique.15 It reveals the level of wetting during the in interaction between solid and liquid. Generally, contact angles lower than 90° indicate high wettability whereas contact angles greater than 90° indicate low wettability.


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The fundamental theory of this method is Young’s equation, where the contact angle of a drop of liquid on solid surface is governed by three interfacial tensions28: γ#$ = γ#& + γ&$ cosθ

(1)

Where γ#$ , γ#& , and γ&$ are interfacial tensions between solid/vapor, solid/liquid, and liquid/vapor phases.28 In this study, shale was the solid phase, the air was the vapor phase, and water/IOS solutions were the liquid phases.

The contact angle between the polished shale surfaces and water/IOS solution were obtained at a temperature of 26°C and pressure of 1 bar using Vinci’s Interfacial Tension Meter (IFT, Model: IFT 700, Vinci Technology). During each contact angle measurement, twenty images of the drop were captured using high-resolution DSLR camera. Each measurement was repeated twice (i.e. total 40 images) where the deviation of resulted contact angles was +/- 0.1 degrees. The average of the two measurements was used.


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Adsorption/Desorption Tests. Figure 3 shows the experimental set-up used for adsorption/desorption studies. The method of evaluation of gas adsorption/desorption was based on U.S Bureau of Mines (USBM) modified direct method. This method assumes that the methane release rate from a shale sample follows the diffusion equation for spherical particles.29 In the last few years, many researchers have used this method to assess the adsorption/ desorption behavior of shale gas.18, 30-31 The basic principle of the measurement of the desorbed gas is the water-level change in an inverted graduated cylinder

Figure 3. Schematic of Adsorption and Desorption Experimental Set-up. The main components of the system are: - 1) Methane gas cylinder 2), canister cell 3), 1000 ml inverted graduated tube 4), water pan 5), pressure gauge 6), two valves and 7) computer.


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Shale samples (BG-1 and KH-1) were dried then crushed and sieved to a size of 22.38 mm. A 100 gram of this crushed sample was immersed in pure water for 48 hours. The excess water on the external rock surfaces was wiped off by sliding motion of fingers. Prior to loading the shale sample, the adsorption column was leak tested by applying positive pressure for an hour. After successful leak testing, the shale was placed in the adsorption column (canister cell) which was then capped. The temperature of 26°C was maintained throughout the measurements. The test was started by closing the valve 6b and opening the valve 6a and exposing the canister to methane at steadily increasing pressure until a pressure of 20 bar was attained. The pressure across the canister cell was recorded versus time by the computer. As the pressure would lower due to adsorption, it was restored manually to 20 bars again until no more pressure drop occurred. At this point, it was assumed that the adsorption process has completed and no more gas is able to adsorb. On average, 2 days were required to achieve pressure equilibrium in the cell. Once adsorption was complete, the desorption process was started by closing valve 6a (which may have already been closed) and opening valve 6b. The initial gas produced was discharge to the atmosphere until the pressure inside the column lowered to the atmospheric pressure. This step was carried out to eliminate the free methane gas which was in the matrix and in the fractures (but not adsorbed) of the shale sample in the canister. The hose was then inserted into the water filled inverted tube so that the gas being desorbed can be accurately measured.


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A similar procedure was used for measuring the adsorption/desorption of samples treated with anionic surfactant solution (IOS) except that instead of immersing the shale samples in pure water, the samples were immersed in 1 wt% IOS surfactant solution.

3. RESULTS AND DISCUSSION 3.1. Shale Composition. Total organic matter of the two samples is shown in Table 1. The measurements were performed using TC analyzer (TC Analzer, Model: Multi N/C® 3100, Analytik Jena) and showed that the KH-1 has a richer organic matter than BG-1. Table 1. TOC Results of the samples Sample ID BG-1

TOC (%) 2.17

KH-1

12.1

The mineralogy of the two samples was investigated by using advanced Powder XRay Diffractometer (XRD, Model: XPert3, PANalytical). The qualitative data obtained from XRD was then interpreted using the USGS’s ROCKJOCK program. The quantitative mineralogy results obtained from this program using the standardless analysis option are presented in Table 2.


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Table 2. Quantitative Mineralogy Results obtained from ROCKJOCK interpretation of XRD data

Calcite

Total NonClay (%)

Kaolinite

Smectite

Illite

Muscovite

Biotite

Dickite

Total Clay (%)

BG-1

29.3

12.8

1.3

43.4

6.3

12.7

23.1

5

9.3

0.1

NA

56.6

KH-1

66.4

7.2

0.8

74.5

2.8

9.7

9.7

1.9

NA

0.9

0.5

25.5

Chlorite

Kspar

Clay Minerals (Weight %)

Quartz

Non-Clay Minerals (Weight %)

Sample ID

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

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Figure 4 is the ternary diagram visually depicting the quantitative mineralogy data shown in Table 3. It can be seen more clearly in this diagram that the KH-1’s mineralogy is quartz-rich while BG-1 is clay-rich.

Figure 4.Tenary Digram of BG-1 & KH-1 Shale Samples To support the XRD results, the elemental analysis performed by EDS using ZEISS Microscope at an accelerating voltage of 20 kV. In table 4, a correlation with Table 3’s XRD results exists such that a relatively higher quantity of silicon (the main component of quartz) was found in KH-1 compared to BG-1. The most common form


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of crystalline silica (silicon dioxide, SiO2) is quartz which is found in almost every type of rock. Although the amount of Si and O may seem in similar range in BG-1 and KH-1, this does not reflect the actual mineralogy in the two samples, which was determined by XRD. This is explained by to the fact that EDS due of its sample requirement used a very small heterogenous random chip from each sample that does not represent the mineralogy in the whole sample. The main goal for EDS test was to prove the existence of elements rather than the amount to support XRD data. It is also interesting to note that a higher percentage of carbon is observed in KH-1 than in BG1. The carbon percentages correlate with the total organic content (TOC) in Table 2, where KH-1 was found to be richer in TOC than BG-1.

K

S

Ti

Mg

Cl

7.52

3.25

0.075 0.1

1.05

1.4

0.1

18.3

0.9

0.8

0.8

0.1

-

-

Ca

Fe

14.82 9.25

Al

46.27 16.2

Si

BG-1 o

C

O

Table 3. EDS results for shale samples

Sample ID

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

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T

40.6 KH-1 t

36.5

1.7

0.1

To visually validate the finding of XRD and EDS analyses, FE-SEM images were obtained and shown in Figure 5 and Figure 6. The FE-SEM imaging provides a visual appreciation of small pores, clay and organic matter.32


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B

A

Fracture

C

Clay

D

Quartz

Figure 5. Field emission scanning electron microscope (FE-SEM) images of BG-1 shale sample. Clay and fracture existence confirmed as shown in both 10K (A) and 50K (B) images. Presence of quartz is evident in 10K (C) and 50K (D) images.


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The images confirm that KH-1 sample is quartz rich while BG-1 is clay-rich. In addition, it indicates the existences of fractures, mesopores and macropores.

B

A

Mesopores

Clay

C

D

Quartz

Macropores

Figure 6. Field emission scanning electron microscope (FE-SEM) images of KH-1 shale sample. Clay and mesorpores (2-50 nm) are displayed in both 10K (A) and 50K (B) images. Quartz was found to be dominant mineral as observed in 10K (C) and 50K (D) images, which a show the existence of macropores (> 50 nm).


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Pore System. Investigation for pore system was carried out utilizing BET low pressure gas (N2) adsorption. Two samples with grain size < 0.2 mm were placed in Surface Area and Pore Size Analyzer (Model: Micrometrics ASAP 2020) at 80 °C under vacuum of 106

Pa for more than 6 h (until a constant weight was achieved) to remove moisture. As per

the International Union of Pure and Applied Chemistry (IUPAC), pores are classified into three categories; micropores (50nm).33-35 This classification has been accepted and used for describing pore system in shale.36 Figure 7 shows the pore size distribution in BG-1 and KH-1. Though the pore diameters in both samples ranged between 2.0 to 180 nm, a wide majority fell in the mesorpores region (2- 50 nm); only a small fraction exceeded this range. It is generally known that organic matter in shale is associated with micropores. However, nitrogen gas cannot access to some of the micropores existing in the organic matter. As a result, the surface area of shales of high TOC measured by low pressure nitrogen adsorption would not take into consideration the surface area of the inaccessible mircropores in the organic matter, thus showing low surface area.37-38 In our case, the BET showed KH-1 is to have a lower surface area than BG-1 ( Figure 7) which is possibly because KH-1 has higher TOC thus its surface area is likely to have been underestimated. It is also important to mention that mesopores and miropores are generally associated with TOC and illite and they positively affect methane adsorption capacity or adsorption quantity of shale.39-40 Moreover, the surface area in clay rocks was reported to linearly correlate with methane sorption capacity in the literature.41


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Figure 7. Pore size distribution in BG-1 & KH-1 shale samples defined by Incremental pore area vs pore width using BET low-pressure gas (N2) adsorption analyses. 3.2.Wettability. The wettability of the shale samples using pure water water and with 1 wt% IOS surfactant solution was determined at a pressure of 1 bar and temperature of 26°C using Vinci’s Interfacial Tension Meter (IFT 700, Vinci Technology) following the technique described earlier. For each measurement, a drop of liquid was carefully placed on the polished and dried external surfaces of the shale samples. The liquid drops were either pure water or 1 wt% IOS surfactant solutions, and the shale samples were BG-1 and KH-1. The measurements were made at a temperature of 26°C and pressure of 1 bar. The following section compares the liquid wettability of pure water vs surfactant solution for both shale samples. The pictorial views of the droplets of pure water and 1 wt% IOS solution on BG-1 and KH-1 shale samples are shown in Figures 8 and 9 respectively, whereas quantitative contact angle measurements are summarized in Table 4.


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Table 4. Contact angle measurements of the two samples with water and IOS droplet

Contact Angle, θ° Water droplet IOS droplet

Sample ID

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

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% Difference

BG-1

22.7

3.5

85%

KH-1

35

19.2

45%

The contact angle of a drop of pure water on the surface of BG-1 shale sample was 22.7˚ (Figure 8a), thus the surfaces showed considerable affinity towards water i.e. water was preferably the wetting phase in the air/water/BG-I system. In a parallel experiment, a drop of 1 wt% IOS solution was carefully placed on the surface of BG1 shale sample and the contact angle was measured to be 3.5˚ as shown in Figure 8b.

A

B

Figure 8. The affinity of pure water and 1wt% IOS surfactant solution on the polished dried surface of BG-1. A) the contact angle of pure water/air/BG-1 surface (22.7°). B) the contact angle of 1 wt.% IOS surfactant solution/air/BG-1 surface (3.5°). Dashed white and green lines are the borders of BG-1 surface and water/IOS droplet; respectively.


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Comparing the two contact angles suggests that BG-1 shale sample has a greater affinity towards the 1 wt% IOS surfactant solution as compared to the pure water. This suggests that it is possible for a surfactant solution to have 85% higher affinity toward the surface as compared to the pure water. The higher affinity of this surfactant solution will allow a greater imbibition to the shale thus possibly reducing the adsorbed gas capacity and freeing some gas for production. Measuring the IOS contact angle with the rock surface instantaneously without allowing enough time to fully treat the sample is a more realistic approach to represent the case of surfactant coming into contact with shale surfaces during the fracking process where, it might be argued, that enough time is not available for treatment to complete. The contact angle of a drop of pure water on the surface of BG-1 shale sample was 22.7˚ (Figures 8a), whereas it was 35˚ in case of KH-1 sample (Figure 9a). The sample thus exhibited somewhat water-wet behavior.


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The same set of contact angle measurements were also performed on KH-1 sample. The contact angle of the drop of pure water on the surface of KH-1 shale sample was 35˚ (Figure 9a), thus the surfaces showed a considerable affinity towards water i.e. water was preferably the wetting phase in the air/water/KH-I system. A

B

Figure 9. The affinity of pure water and 1wt% IOS surfactant solution on the polished dried surface of KH-1. A) the contact angle of pure water/air/KH-1 surface (35°). B) the contact angle of 1 wt.% IOS surfactant solution/air/KH-1 surface (19.2°). Dashed white and green lines are the borders of KH-1 surface and water/IOS droplet; respectively. In a parallel experiment, a drop of 1 wt% IOS solution was carefully placed on the surface of KH-1 shale sample and the contact angle was measured to be 19.2˚ as shown in Figure 8b. Comparing the two contact angles suggests that KH-1 shale sample has a greater affinity towards the 1 wt% IOS surfactant solution as compared to the pure water. Comparing the results of the pure water/air/shale contact angles, the higher affinity of BG-1 sample to water (22.7˚) compared to the KH-1 sample (35˚) was possibly due to the fact that BG-1 sample is clay rich, whereas KH-1 was quartz rich as per the XRD results.


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Energy & Fuels

The clay tends to have a higher affinity to water compared to quartz. Some previous studies reported that clays in the shale play a major role in the amount of water imbibed. This was explained by the fact clay minerals tend to attract the water in a process called clay hydration. In this process, water molecules get absorbed into charged regions of clay minerals through the existing the interlayer spaces in clay minerals.1, 3 In contrast, it is widely accepted that quartz possess a hydrophobic nature inhibiting water adherence to its surface.42-44 By the same token, BG-1’s TOC (2.17%) was lower than KH-1 (12.1%), another factor the encourages higher affinity towards the water in BG-1, since organic contents inherently have a much lower affinity towards water. The strong affinity to water observed in both samples could be explained by the fact that the mesopores, which are generally associated with clay dominated their pore systems as shown in Figure 7. Both samples also showed higher affinity with but different to 1 wt% IOS when the IOS/air/shale contact angles were measured in comparison to the pure water/air/shale contact angles. This observation agrees very well with previously reported behavior that addition of anionic surfactant at concentrations above its CMC results in alteration of shale wettability towards the water–wet.15 However, this difference was more evident in case of BG-1 where the measured contact angle (22.7˚) with water was shifted to almost complete wetting condition (3.5˚) while using IOS solution, a shift of 85%. The KH-1 only showed a shift of 45%.


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A possible explanation for increasing the affinity towards IOS solution as compared to pure water in both sample is due to the electrostatic interaction between the surface of shale and surfactants. The surface charge of shales is mixed charge because they contain negative surface charged minerals and positive surface-charged minerals. Therefore, the adsorption of anionic surfactants e.g: IOS, may occur in two ways. One mechanism of anionic surfactants adsorption in shale is achieved by the electrostatic interactions between the headgroup of the surfactant and positively charged minerals. The other mechanism takes place due to the electrostatic interactions between the weak tail of surfactant and the negatively charged minerals. In the case of KH-1, the higher percentage of existing quartz in its composition, which has a negative surface charge might have repelled the negatively charged headgroups of anionic surfactants, hence lowering its affinity to IOS solution. A similar finding was reported, where quartz was found to have less affinity to anionic surfactant solution due to the repulsion forces between its negative surface charge and the head-group of anionic surfactant.15


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3.3.Adsorption/Desorption Results. Shale gas capacity -- the volume of gas that a certain amount of shale can adsorb/desorb -- is expressed in volume/mass (cc/gram in this study) and is measured by the USBM modified direct method which is commonly used in industry.18, 45The two shale samples (BG-1 and KH-1) were tested for adsorption/desorption in two situations: (1) the water-treated samples were immersed in pure water for 48 hours, (2) IOS-treated samples were immersed in 1 wt% IOS surfactant solution for 48 hours. The goal was to quantify the effect of wettability alteration on methane adsorption and desorption characteristics. on these shale samples. The testing procedure for each test was USBM modified direct method as detailed in materials and methods section. Figure 10a shows the desorption results of BG-1 as desorbed gas (cc/g) vs square root of time (min0.5) for both water-treated and IOS-treated cases.

A

B

Figure 10. Desorbed gas (cc/g) vs sqrt time (min0.5) in BG-1 and KH-1 samples.


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Figure 10a shows that the methane desorbed from the water-treated BG-1 shale sample was 0.94 cc/gram. In contrast, the desorption was 0.43 cc/gram from the IOStreated BG-1 shale sample. Therefore, the IOS treatment resulted in a reduction of 54% in desorption. It is also interesting to note that the initial desorption rate before inflexion was higher for the water-treated sample than the IOS-treated sample, however, the implication of this observation is not entirely clear. Figure 10b shows the desorption results of KH-1 as desorbed gas (cc/g) vs square root of time (min0.5) for both water-treated and IOS-treated cases. As Figure 10b suggests, the methane desorbed from the water-treated BG-1 shale sample was 1.22 cc/gram. In contrast, the desorption was 1.10 cc/gram from the IOS-treated BG-1 shale sample. Therefore, the IOS treatment resulted in a reduction of about 10% in desorption. It is also interesting to note that the initial desorption rate before inflexion was almost equal for both water-treated sample and the IOS-treated sample, however, the implication of this observation is not entirely clear. The comparison of the methane capacity of the two samples, Figure 10 shows that KH-1 has higher methane capacity than BG-1. This may possibly be attributed to the fact that the KH-1 had a higher TOC (12.1%) than the BG-1 (2.17%). In term of pore system, TOC is generally associated with the existence of mesopores and micropores, which positively impact methane adsorption capacity.39-40


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The bar graph in figure 11 shows that the IOS surfactant has reduced the amount of desorbed gas significantly in one case (54% reduction of desorbed gas in BG-1) and considerably in the other case (10% reduction of desorbed gas in KH-1). The level of change in desorption due to surfactant treatment correlates well with the level of change in wettability (Table 5) of the two samples. This change in wettability towards more water-wet apparently increases capillary-induced water retention which inhibits gas release. These observations suggest that before selecting a surfactant to be added to the fraking fluid cocktail, its impact on wettability and gas desorption should be carefully investigated in the laboratory to optimize gas recovery potential. A similar finding was reported in a simulation study where water was found to reduce methane adsorption in clay pores.12

Figure 11. Gas capacity (cc/100 g) in BG-1 and KH-1 for water-treated and IOS-treated cases


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4. CONCLUSION This study was conducted in order to investigate the effect of anionic surfactant on the wettability of two shale samples (BG-1 and KH-1). The goal of this work is to further understand the implication of the interaction between shale and surfactant during the fracking process on gas production. Since gas desorption mechanism in shale contributes significantly to the overall gas recovery process, the implication of wettability change resulted from anionic surfactant-shale interaction on the gas adsorption/desorption behavior was experimentally evaluated in this study. Both samples were characterized for their mineralogy, pore system and organic matter content to allow correlation of these properties with wettability and the gas adsorption/desorption behavior. The wettability alteration of the shale samples was achieved through using 1 wt% concentration of IOS solution. The wettability was inferred from the contact angle measurement of a drop of liquid on the polished external surface of these shale samples in air. The USBM direct method (the canister test) was adopted to measure the adsorption/desorption volumes. As a result of this study briefly described above, the following observations and conclusion may be drawn: •

The affinity of water on the external surfaces of both shale samples (BG-1 and KH-1) was lower than the affinity of 1 wt% IOS surfactant solution on the same surfaces. This suggests that the drop of surfactant solution was more wetting as evidenced by their much lower contact angles with the shale surfaces.

•

The difference in contact angles in all cases was due to the differences in mineralogy and TOC. The contact angles in case of water/air/shale system were lower in BG-1 than in KH-1 presumably because BG-1 had lower TOC and higher clay content than KH-1 which had higher TOC and more quartz. In case of BG-1 that had lower TOC and


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Energy & Fuels

higher clay content, the IOS showed greater affinity as compared to the affinity of water. The contact angle between IOS/air/ BG-1 system was lower as compared to the contact angles of water/air/ BG-1 systems. A similar behavior was observed in case of KH-1 (having higher TOC and higher quartz content) in which the IOS also showed greater affinity as compared to the affinity of water. The contact angle between IOS/air/KH-1 system was lower as compared to the contact angles of water/air/KH-1 system. •

When comparing the affinity of the two shale samples towards IOS, BG-1 showed a greater affinity (contact angle = 3.5°) than KH-1 (contact angle = 19.2°). This could presumably be because the BG-1 was rich in clay whereas the KH-1 was quartz. Quartz has a negatively charged surface that repels the negatively charged head group of the IOS causing lesser affinity towards its surface.

•

The affinity change due to IOS treatment was more drastic in BG-1 sample and resulted in 50% reduction in its methane adsorption capacity. KH-1, on the other hand, had only 10% reduction in its methane adsorption capacity because it had a lesser change of affinity.

•

The findings of this study ultimately revealed that the interaction between IOS surfactant a shale have reduced the gas recovery in both samples.

•

The results also alert that before selecting a candidate surfactant for addition to the fracking fluid, its impact on wettability change should be carefully evaluated to optimize gas desorption in order to improve gas recovery potential from shale gas reservoirs.


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ACKNOWLEDGMENT We acknowledge the Shale Gas Research Group (SGRG) in UTP and Shale PRF project (cost center #0153AB-A33) for the financial support. We also thank AP. Dr. Eswaran Padmanabhan for providing the shale samples and also SHELL for providing the surfactant. REFERENCES 1.

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Effect of Anionic Surfactant on Wettability of Shale and Its Implication

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