CO2 and CH4 Wettabilities of Organic-Rich Shale - Energy & Fuels

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CO2 and CH4 wettabilities of organic-rich shale Bin Pan, Yajun Li, Hongqian Wang, Franca Jones, and Stefan Iglauer Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.7b01147 • Publication Date (Web): 22 Nov 2017 Downloaded from http://pubs.acs.org on December 2, 2017

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180 160 140 298 K, Advancing, CO₂

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Contact angle [⁰]

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298 K, Receding, CO₂ 298 K, Advancing, CH₄

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298 K, Receding, CH₄ 323 K, Advancing, CO₂ 323 K, Advancing, CO₂

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323 K, Advancing, CH₄ 323 K, Receding, CH₄

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343 K, Advancing, CO₂ 343 K, Receding, CO₂

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20 0

5

10

15 Pressure [MPa]

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ACS Paragon Plus Environment

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CO2 and CH4 wettabilities of organic-rich shale

1

2

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Bin Pana,b,c, Yajun Lia*, Hongqian Wanga, Franca Jonesd, Stefan Iglauerc

3 4

a

5 6

China University of Petroleum (East China), School of Petroleum Engineering, No. 66,Changjiang West Road, Qingdao, China , 266580

b Subsurface Fluidics and

7

Porous Media Laboratory, University of Calgary, Department of Chemical and Petroleum

Engineering, AB, Canada, T2N 1N4

8

c

Curtin University, Department of Petroleum Engineering, 26 Dick Perry Avenue, 6151 Kensington, Australia

9

d

Curtin University, Department of Chemistry, Nanochemistry Research Institute, PO Box U1987, Perth WA, 6845

10

Abstract

11

CO2 and CH4 wettabilities of organic-rich shale are important physico-chemical

12

parameters which significantly influence CO2 sequestration and CH4 production.

13

However, there is a serious lack of understanding of these aspects as the data available

14

is scarce. Thus, we evaluated organic-rich shale CO2- and CH4-wettabilities (i.e.

15

brine/shale/gas systems) through advancing and receding brine contact angle

16

measurements as a function of pressure, temperature, salinity and ion type (as these can

17

vary significantly in underground formations). The results indicated that the brine

18

contact angles for both CO2/CH4-brine-shale systems increased with pressure and

19

salinity, but decreased with temperature. However, these effects were much less

20

significant for CH4. Furthermore, the brine contact angles for CO2-brine-shale system

21

reached 180° (i.e. the shale was completely wetted by CO2) when the pressure reached 1


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30 MPa at 343 K and 9 MPa at 298 K. The brine contact angles for the analogue CH4

23

systems was much lower, 50-90°, only indicating weakly water-wet to intermediate-

24

wet conditions. Finally, the brine contact angles for CO2-brine-shale system were also

25

larger for divalent ions (Ca2+, Mg2+) than for monovalent ions (Na+, K+), while ion type

26

had no significant influence on CH4 wettability. However, a similar CO2/CH4 density

27

resulted in a similar wettability. Consequently CH4 could not be used as a proxy for

28

predicting CO2 storage capacities unless they have similar densities.

29 30

Key words: CO2 wettability, CH4 wettability, organic-rich shale.

31

32

1. INTRODUCTION

33

34

Global warming and the greenhouse effect are primarily caused by anthropogenic

35

CO2 emissions. To reduce these emissions, carbon geo-sequestration (CGS) has been

36

identified as an important solution.1,2 In CGS, CO2 is captured from large-point-source

37

emitters, purified, compressed, and injected into geological formations at depths of or

38

greater than 800 m, including saline aquifers,3-5 (depleted) oil and gas reservoirs,4,6-8 or 2


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un-mineable coal seams,4,9 where CO2 is stored in a supercritical (sc) state.1 However,

40

the scCO2 density is, approximately, only 50%-80% of formation brine density, which

41

leads to CO2 upwards migration.10 Four main sequestration mechanisms in CGS are: (a)

42

structural trapping,11,12 (b) residual trapping,13-15 (c) dissolution trapping,5,16,17 and (d)

43

mineral trapping.18,19 Another way is to store CO2 in clay-rich formations by CO2

44

adsorption trapping.20-22 In CCS, the advancing brine angle is related to residual

45

trapping, while the receding brine angle is related to structural trapping.23

46

In addition, due to the improvement of hydraulic fracturing and horizontal drilling

47

technologies, shale gas has been recognized as a promising energy resource, which

48

can be exploited commercially.24-26 Shale gas primarily contains methane, which

49

generally exists in organic-rich pores of low permeability shale formations.27,28 Such

50

shale gas recovery can potentially be improved by CO2 injection, while

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simultaneously CO2 is sequestered (adsorption trapping).22,29-36 In such a scenario,

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CO2- and CH4 rock wettabilities play very important roles as they determine fluid

53

spreading and fluid dynamics in the reservoir.12,13,30,37-39

54

However, organic content in shale can vary dramatically,40-42 and thus the

55

coverage of shale surfaces with organics is expected to vary substantially. Moreover,

56

only a few research papers reported CO2 wettability of shale4,22,37,43-45, and available

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data is scarce.

58 59

Furthermore, some scholars used CH4 as a proxy for predicting structural CO2 storage capacities, assuming that CO2 and CH4 wettabilities are similar.46-48 This

3


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assumption, however, has not yet been systematically verified, and it is clear that CO2

61

and CH4 have fundamentally different physical and molecular properties.23 Moreover,

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as the best of our knowledge, the brine contact angles of CH4-brine-shale system have

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not been reported, although they are of key importance in shale gas production, see

64

above.37-39

65

Thus, we measured the advancing and receding brine contact angles of CO2/CH4-

66

brine-shale systems as a function of pressure, temperature, salinity and ion type in

67

order to aid shale gas production and CO2 geo-storage capacity predictions.

68

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2. EXPERIMENTAL SECTION

70

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2.1. Materials.

72

CO2 (purity = 99.7 mol%), CH4 (purity = 99.7 mol%) and de-gassed brines (0 wt%,

73

1 wt%, and 5 wt% NaCl, CaCl2 and MgCl2 dissolved in deionized water; stirred for 2

74

hr and vaccumed for 12 hr at ambient temperature) were used in all experiments; This

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brine composition was chosen to simulate Shengli shale formation water (which mainly

76

contains Na+, Ca2+ and Mg2+ cations,49,50) and the salinities range with formation

77

depth.51

78

The shale sample examined was acquired from well FY-1 in the Shengli shale play

79

formation, Jiyang depression, China. Geological and geo-chemical properties of the

4


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shale sample are listed in Table 1. The shale sample was thoroughly characterized by

81

quantitative X-ray diffraction (XRD), total organic content (TOC), scanning electron

82

microscopy-energy dispersive X-ray spectroscopy (SEM-EDS) and surface roughness

83

tests (Tables 1 and 2 and Figure 1).

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Table 1. Geological and geo-chemical properties of the shale sample examined. Lithology

laminar-mixed limestone and mudstone

Depth (m)

3178

TOC (mg/kg)

30000

Vitrinite reflectance (%)

0.76

Matrix density (g/cm3)

2.73

Porositya (%)

8.21

Average pore throat radiusb (nm) Average Permeabilityc (mD)

5 10-6

Chemical compositiond (wt%) Calcite

49

Quartz

19

Illite

16

Ankerite

10

Pyrite

3 5


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Albite a

Porosity measured by NMR,52 using MacroMR12-110H-1 at ambient conditions.

b

c

3

Pore throat radius measured by gas adsorption and mercury intrusion.53

Permeability measured by gas pulse method.54

d

Chemical composition measured with a Bruker AXS XRD instrument.

86

87

Table 2. EDS analysis of the shale sample. Element

Atomic Concentration (%)

Oxygen

53.9

Silicon

13.2

Carbon

28.1

Aluminum

4.0

Magnesium

0.8

88 89

90

(b)

(a)

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91

92 93

(c)

94 95

(d)

96 97

(e) 7


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Figure 1. SEM and atomic force microscopy images of the shale sample used in the

99

experiments. (a-c) SEM images; (d) 3D topography; (e) deflection signal, (d) and (e):

100

different heights are shown in different colours (black is 0 nm, white is 4000 nm).

101

102

The shale sample consisted mainly of calcite (49 wt%), quartz (19 wt%) and illite

103

(16 wt%) and a few other minor minerals, Table 1. The SEM images, Figure 1a-c,

104

showed that organic matter filled some of the pores; microfractures and inorganic pores

105

were also identified. The EDS analysis in Table 2 showed that the total atomic carbon

106

concentration on the surface was 28.1 mol%. Surface topography of the sample was

107

measured via atomic force microscopy (instrument model AFM DSE 95-200), Figure

108

1d,e, and the sample was relatively rough when compared to single cystals (e.g. a

109

smooth alpha-quartz had a RMS surface roughness of 40 nm)55 and a root-mean-square

110

(RMS) surface roughness of 490 nm was measured.

111

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2.2. Contact angle measurement.

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For the contact angle experiments, a cuboid sample was cut with a high speed

114

diamond blade (to 17 mm x 12 mm x 3 mm dimensions). The sample was then cleaned

115

with acetone and exposed to air plasma for 3 min to remove any organic surface

116

contaminants.56 Subsequently, the advancing brine contact angle (𝜃𝑎 ) and the receding

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brine contact angle (𝜃𝑟 ) were measured by a Krüss DSA 100 instrument, using the tilted

118

plate method.57 The cleaned substrate was placed into the pressure cell at a pre-set 8


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temperature (298 K, 323 K or 343 K) and the system was flooded with CO2 or CH4 for

120

10 min at ambient pressure. Subsequently the gas pressure was increased to prescribed

121

values (0.1 MPa, 5 MPa, 10 MPa, 20 MPa and 30 MPa). After pressure stabilization

122

was achieved, a droplet (average volume of ~6 ±1 µL) of brine was dispensed onto the

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surface of the shale substrate through a needle. 𝜃𝑎 was measured just before the

124

leading edge of the droplet started to move and 𝜃𝑟 was measured simultaneously at

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the trailing edge of the droplet. A high resolution video camera recorded the dispensing

126

process as a movie, and 𝜃𝑎 and 𝜃𝑟 were measured on the images extracted from the

127

movies. To obtain reliable and reproducible results, all experiments were conducted

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with vacuumed brines and repeated 3 times (All the experimental data were listed in

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SI-Table 1 Supporting Information). Brines were not equilibrated with CO2 or CH4, as

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it was shown earlier that this has only an insignificant influence on θ during the θ

131

measurement.55,58 The standard deviation of these measurements was ± 3° based on

132

replicate measurements.

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2.3. Zeta potential measurement.

135

For the zeta potential experiments, a Zetasizer Nano instrument (Malvern, UK) was

136

used to measure the zeta potentials of a powder suspension prepared from the examined

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shale sample. The shale suspension was prepared as follows: the shale rock sample was

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crushed to very fine particles of less than 10 micrometer size. 0.2 wt% shale powder

139

was then added to NaCl, CaCl2 and MgCl2 brines, respectively (0.1 g shale powder into

9


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50 mL brine). Each dispersion was mixed with a magnetic stirrer for 15 min at a speed

141

of 4×100 rpm at 323 K. The solution was subsequently equilibrated for 12 hr. and

142

transferred to a measurement cell. The cell temperature was set to 323 K (at ambient

143

pressure), and the zeta potential was measured at least ten times for each solution and

144

the arithmetic average was taken. The standard deviation of these measurements was

145

±1 mV based on replicate measurements. The pH values ranged from 6.72-8.81

146

(measured by RHA-SHKY pH Meter Model 8601), Table 3.

147 148 149

Table 3. The pH values of different solutions at 323 K and ambient pressure. (Note that 0.2 wt% shale powder was added to each solution)

150

wt% NaCl

pH

wt% CaCl2

pH

wt% MgCl2

pH

1

8.81

1

7.4

1

8.06

2

8.55

2.5

6.99

2.5

7.89

5

8.19

5

6.72

5

7.62

151

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3. RESULTS AND DISCUSSION

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3.1. Influence of pressure.

155

As pressure and temperature are expected to vary with storage depth,59 both, the

156

advancing (𝜃𝑎 ) and the receding (𝜃𝑟 ) brine contact angles of the CO2/CH4-brine-shale 10


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157

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systems were measured at various pressures and temperatures, Figure 2. For the CO2-brine-shale system, the brine contact angles of 𝜃𝑎 and 𝜃𝑟 at

159

ambient conditions (T = 298 K and 0.1 MPa) were measured as 73° and 72°,

160

respectively, which indicated intermediate-wet conditions. Note all the relationships

161

between contact angles and wet state in this work were based on literature standard.12

162

However, at 20 MPa and 343 K, 𝜃𝑎 and 𝜃𝑟 were measured as 130° and 120°,

163

respectively, indicating weakly CO2-wet conditions. At even higher pressure, 30MPa,

164

all brine contact angles reached 180°, i.e. a completely CO2-wet state. In this case, the

165

brine droplet did not stay on the shale substrate and it rolled away immediately once it

166

dropped onto the tilted surface of the shale substrate.

167

On the contrary, for the CH4-brine-shale system, 𝜃𝑎 and 𝜃𝑟 at ambient

168

conditions (T = 298 K and 0.1 MPa) were 54° and 46°, respectively, which indicated

169

strongly to weakly water-wet conditions. 𝜃𝑎 and 𝜃𝑟 at 20 MPa and 343 K were 74°

170

and 70°, respectively (an increase by 42° and 38° when the pressure increased from

171

0.1 MPa to 20 MPa), and this indicated intermediate-wet conditions.

172

Although, the brine contact angles of both, CO2 and CH4, increased with

173

pressure (due to lower density differences between fluids,23,60,61 and stronger

174

intermolecular interactions between CO2/CH4 and the rock surface,23,61-64), consistent

175

with literature data for CO2 on quartz,55,56,61,65,66 mica,65,67 shale,4,44,68 sandstone,44

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coal,69 and for CH4 on coal,70,71 the CH4–shale system was far more water-wet than

177

the analogue CO2 system, consistent with data measured on coal.70,71 To further

11


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explore and quantify the reason why the brine contact angles for CO2 and CH4 at the

179

same thermo-physcial conditions were different, we plotted advancing and receding

180

brine contact angles versus the CO2 and CH4 densities, respectively, Figure 3. When

181

the CO2 and CH4 densities were close, the brine contact angles matched. Specifically,

182

when CO2 density was 38 kg/m3, its advancing and receding brine contact angles were

183

70° and 60°, respectively; when CH4 density was 35 kg/m3, its advancing and

184

receding brine contact angle were 65° and 59°. When CO2 and CH4 density reached

185

133 and 135 kg/m3, the CO2- and CH4- advancing brine contact angles were 90° and

186

91°, respectively. These results clearly showed that when the fluid densities were

187

similar, their wettabilities were also similar, consistent with measurements for N2, Ar,

188

SF6 and He on quartz.66 Extrapolations from CH4 behavior to CO2 behavior thus need

189

to be avoided unless they have similar densities.

190

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180 160 140 298 K, Advancing, CO₂

Contact angle [⁰]

120

298 K, Receding, CO₂ 298 K, Advancing, CH₄

100

298 K, Receding, CH₄ 323 K, Advancing, CO₂ 323 K, Advancing, CO₂

80


60

343 K, Advancing, CO₂ 343 K, Receding, CO₂

40


20 0

5

10

15 Pressure [MPa]

191

20

25

30

192

Figure 2. Effect of pressure and temperature on the brine contact angles of the

193

CO2/CH4-5 wt% NaCl brine-shale system. 180 160 140

Contact angle [⁰]

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120 100

Advancing, CO₂

80

Receding, CO₂

60

Advancing, CH₄

40

Receding, CH₄

20 0 0

100

200

300

400

500

Density

600

700

800

900

1000

[kg/m3]

194 195

Figure 3. Effect of fluid density on the brine contact angles of the CO2/CH4-5 wt%

196

NaCl brine-shale system (CO2 and CH4 density were taken from literature data.72,73) 13


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3.2. Influence of temperature.

199

𝜃𝑎 and 𝜃𝑟 decreased with temperature, Figure 2. This is consistent with

200

molecular dynamics simulations for CO2 on quartz,62 and some experimental data for

201

CO2 on quartz,61,66 and mica,67,74 where 𝜃𝑎 and 𝜃𝑟 decreased with temperature.

202

Specifically, for the CO2-brine-shale system, when temperature increased from 298 K

203

to 343 K at 10 MPa pressure, 𝜃𝑎 decreased by 60° from 180° to 120° and 𝜃𝑟

204

decreased by 80° from 180° to 100°, thus changing from completely CO2-wet to weakly

205

CO2-wet. For the CH4-brine-shale system, when temperature increased from 298 K to

206

343 K at 10 MPa pressure, 𝜃𝑎 decreased by 12° from 79° to 67°, and 𝜃𝑟 decreased

207

by 12° from 65° to 53°, thus the shale substrate became more water-wet. Note that the

208

temperature had a stronger influence on CO2 wettability than on CH4 wettability.

209

However, other researchers found an opposite trend for the effect of temperature on

210

CO2 wettability,37,69,75,76 or no temperature influence.77 A recent study reported that

211

temperature influences contact angles through density and Van der Waals forces.31 For

212

CO2-wet surfaces, Van der Waals forces (solid-CO2) decrease with increasing

213

temperature (causing CO2 to detach more from the surface, which renders the surface

214

more water-wet); however, hydrogen bonds are increasingly broken on water-wet

215

surfaces with increasing temperature (thus reducing the water-wetness of the surface).

216

Therefore, here in our work, a CO2-wet shale surface became more water-wet with

217

temperature increase. Furthermore, we did not find any previous report on the effect of

218

temperature on CH4 wettability. 14


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220

3.3. Influence of salinity and salt type.

221

The effect of salinity on the brine contact angles was investigated at 298 K and 10

222

MPa, Figure 4. Salinities tested ranged from (0 to 5) wt%.

180 Advancing, CO₂

160

Receding, CO₂ Advancing, CH₄

140

Contact angle [°]

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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Receding, CH₄

120 100 80 60 40 20 0

1

2

3

4

5

Salinity [% wt]

223 224

Figure 4. Effect of salinity on the advancing and receding brine contact angles of the

225

CO2 and CH4-NaCl brine-shale systems at 298 K and 10 MPa.

226

227

For the CO2-brine-shale system, 𝜃𝑎 increased by 90° and 𝜃𝑟 by 97° when NaCl

228

salinity increased from 0 to 5 wt% at 298 K and 10 MPa. For the CH4-brine-shale

229

system, 𝜃𝑎 increased by 15° and 𝜃𝑟 by 8° when NaCl salinity increased from 0 to 5

230

wt% at the same thermodynamic condition, consistent with literature data for CO2 on

231

quartz,61 mica,67,74,78 shale37 and other rock minerals.65,75,79 Thus salinity had a larger

232

influence on CO2 wettability than on CH4 wettability. Furthermore the brine contact 15


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233

angles for divalent cations were higher than those for monovalent cations (Figure 5),

234

following the order MgCl2 > CaCl2 > NaCl, consistent with literature data for CO2 on

235

quartz,61 mica,78 coal,80 and shale.37 However, these ion types only had an insignificant

236

influence (2°) on CH4 wettability (which is within experimental error). Note that

237

literature data for the effect of salinity and salt type on CH4 wettability is scarce. 110 100 90 80

Contact angle [°]

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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70 60

343 K, Advancing, CO₂

50

343 K, Receding, CO₂

40

298 K, Advancing, CH₄

30

298 K, Receding, CH₄

20 10 0 Na⁺

Ca²⁺

Mg²⁺

Ion type

238 239

Figure 5. Effect of salt type on the advancing and receding brine contact angles at 10

240

MPa and 1 wt% salt concentration.

241

16


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10

Zeta Potential [mV]

5 0 -5 -10

NaCl CaCl₂

-15

MgCl₂ -20 0

1

2

3

4

5

Concentration of different brines [wt%]

242

(a)

243

244

10 5

Zeta Potential [mV]

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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0 -5

NaCl

-10

CaCl₂ -15

MgCl₂

-20 0

0.5

1

1.5

Ionic strength [mol/kg]

245

(b)

246

247

Figure 6. Shale zeta potentials as a function of (a) salt concentration and (b) ionic

248

strength of the brine (in which the shale was dispersed) at 323 K. The error bars show

249

the standard error of the measurements. 17


Page 19 of 39

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Energy & Fuels

250

251

The effect of salinity and ion type on the brine contact angles can be explained

252

with the diffuse double layer theory with specific adsorption of ions included.37,81,82 It

253

is clear that at higher pH values more protons are released from the surface OH

254

groups, which results in a more negative surface charge (= more negative zeta

255

potential). However, we cannot measure zeta potentials at high pressures (due to

256

instrument limitations), thus we measured and reported zeta potentials at ambient

257

pressure (Figure 6). Note that efforts were made to correlate such (ambient condition)

258

zeta potential measurements to real reservoir conditions.80 Trendwise, the contact

259

angles followed the same trends with temperature and salinity at ambient and high

260

pressure, while the zeta potentials also followed the same trend at ambient pressure;

261

thus it was assumed that zeta potentials probably also follow a similar trend at high

262

pressures.

263

Furthermore, with the addition of NaCl, CaCl2 or MgCl2 into the shale suspension,

264

the zeta potential increased, Figure 6. Mechanistically, this increase in zeta potential is

265

caused by adsorption of divalent ions onto the shale surface, which leads to a more

266

positive charge.83,84 However, sodium ions are not so strongly adsorbed, so here the 85,86

1 n 2 As the ionic strength ( I   ci zi , where I is the ionic 2 i 1

267

effect is less significant.

268

strength, c is the concentration and z is the ion charge) increased, the surface charge

269

was more and more screened which resulted in more positive zeta potentials. This

270

charge screening effect is stronger for Mg2+ and Ca2+ than for Na+ (due to their higher 18


Energy & Fuels

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

Page 20 of 39

271

ionic strength).23 At very high ionic strengths charge reversal occurred for Mg2+ and

272

Ca2+, presumably due to specific adsorption of the divalent ions on the clay or the

273

calcitic shale surface.83,84 The ranking Mg2+ > Ca2+ based on the de-wetting ability and

274

zeta potential is probably caused by the stronger adsorption for Mg2+ than Ca2+ onto the

275

shale surface, consistent with other experimental results (where the zeta potential for

276

Mg2+ solutions was more positive than that for Ca2+ solutions).87 In addition, one study

277

investigated the effect of individual ionic concentration on zeta potential in calcite

278

solutions and found that Ca2+ can only change zeta potentials from negative to positive

279

values at high concentrations, while small additions of Mg2+ into the calcite solution

280

can readily achieve a positive zeta potential,88 consistent with our results. Mg2+ has a

281

stronger effect on calcite surface charge due to ionic adsorption88; and recall that the

282

calcite content in our shale sample was high (49 wt%). However, some other study

283

reported that Ca2+ had stronger adsorption ability than Mg2+ on shale,26 and note that

284

the primary composition in its shale sample was quartz.26 The discrepancy of divalent

285

ion adsorption capacity here probably was due to the composition of the shale sample.

286

Furthermore, this charge reversal has been previously associated with higher contact

287

angles.86,89,90 Moreover, once the zeta potential approaches zero, the surface polarity

288

decreases and the affinity of the shale surface for water decreases so that the brine

289

contact angle increases.23,89,91-93

290

291

3.4. Influence of total organic carbon content.

19


Page 21 of 39

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

292

Energy & Fuels

We furthermore investigated which influence the total organic carbon content (TOC)

293

has on the brine contact angle of brine-CO2-shale, Table 4. However, only a few

294

studies reported the CO2-wettability of shale, 22,37,43,44 thus data is scarce.

295

296

Table 4. The effect of TOC on shale wettability. Chemical

Mineral

TOC

NaCl

T

P

𝜃𝑟

𝜃𝑎 Reference

Composition

wt%

Calcite

mg/kg

MPa

°

°

49

0.1

60

70

Quartz

19

10

107

125

Illite

16

20

120

130

Ankerite

10

30

180

180

Other

6

Illite

33

0.1

20

30

Quartz

31

10

21

24

Literature data37,44

30000

810

wt%

5

5.85

K

343

This work

343

Analcite

15

15

25

40

Other

21

20

40

48

297

298

Clearly the high TOC shale was much more CO2-wet. Precisely, 𝜃𝑎 increased by

299

18° from 30° to 48°, and 𝜃𝑟 increased by 10° from 20° to 30°, when the pressure

300

increased from 0.1 MPa to 20 MPa for the low TOC shale; while 𝜃𝑎 increased by 110°

301

from 70° to 180°, and 𝜃𝑟 increased by 120° from 60° to 180°, when pressure increased 20


Energy & Fuels

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

Page 22 of 39

302

from 0.1 MPa to 30 MPa for the high TOC shale. It is thus clear that higher TOC and

303

thus a more hydrophobic surface leads to higher CO2-wettability, consistent with data

304

measured for CO2 on other hydrophobic surfaces, i.e. alkylated mica,74 quartz,94 silica,95

305

coal,69,96 and minerals aged in crude oil.97,98 Furthermore, one recent study reported the

306

effect of TOC on shale wettability (TOC ranged from 0.16 wt% to 23.4 wt%), and a

307

consistent conclusion with ours was reached.22 However, our result was inconsistent

308

with another recent report where CO2 wettability of organic-rich shale had no

309

relationship with organic matter content, which may be attributed to the remaining

310

mineral composition or the spatial distribution of the organics in the shale.43

311

312

4. CONCLUSION.

313 314

Organic-rich shale formations are an important fuel resource and they are also

315

potential CO2 sinks.34,35,46,99,100 In this context, CO2 and CH4 wettabilities are important

316

parameters as they determine the security and capacity of CO2 sequestration and shale

317

production respectively.12,13,30,37-39 However, their wettabilities in organic-rich shale

318

formation are poorly understood. We thus measured them as a function of pressure,

319

temperature, salinity, and ion type in order to aid CO2 geo-storage and CH4 production

320

schemes. Following conclusions were reached:

321

322

The brine contact angles of both, CO2 and CH4, increased with pressure, consistent

323

with literature data,4,44,55,56,61,65-71 while the CH4–shale system was far more water-wet

21


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Energy & Fuels

324

than the analogue CO2 system, consistent with data measured on coal,70,71 However, a

325

similar CO2/CH4 density resulted in a similar wettability, consistent with literature

326

data.66 Thus, extrapolations from CH4 behavior to CO2 behavior need to be avoided

327

unless they have similar densities. The brine contact angles for CO2 and CH4 decreased

328

with temperature, consistent with literature data,61,62,66,67,74 while the temperature had a

329

stronger influence on CO2 wettability than on CH4 wettability. Higher salinity resulted

330

in higher brine contact angles, consistent with literature data,37,61,65,67,74,75,78,79 while the

331

brine contact angles for divalent cations were higher than those for monovalent cations,

332

consistent with literature data.37,61,78,80 However, the ion type only had an insignificant

333

influence (2°) on CH4 wettability. The effect of salinity and ion type on the brine contact

334

angles can be explained with the diffuse double layer theory with specific adsorption

335

of ions included.37,81,82 Higher TOC led to higher CO2 wettability, consistent with one

336

recent report,22 and other literature data.69,74,94-98

337 338

Especially noteworthy is that we reported CH4 wettability of shale here for the first time, which is of key importance to shale gas production.

339

340

 SUPPORTING INFORMATION

341

342

SI-Table 1. Advancing and receding brine contact angles (°) of CO2/CH4-brine -

343

shale for all cases measured in this work. T/k

P/MPa

Advancing for CO2

Receding for CO2 22


Energy & Fuels

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

298

Page 24 of 39

0.1

76

74

77

73

72

74

5

90

90

89

88

87

86

10

180

180

180

180

180

180

20

180

180

180

180

180

180

30

180

180

180

180

180

180

0.1

73

72

73

71

70

68

5

88

87

88

85

84

84

10

130

132

133

110

111

108

20

180

180

180

180

180

180

30

180

180

180

180

180

180

0.1

70

71

70

60

60

58

5

80

82

79

70

71

71

10

125

125

125

107

108

109

20

130

130

130

120

118

121

30

180

180

180

180

180

180

T/k

P/MPa

Advancing for CH4

298

0.1

54

55

56

46

46

45

5

65

65

64

59

60

60

10

79

82

81

65

65

65

15

92

93

95

79

82

81

20

96

94

96

84

85

86

0.1

52

50

51

42

43

44

5

63

64

63

50

51

50

10

67

65

67

58

60

57

15

81

83

80

75

74

75

20

91

90

92

78

80

81

0.1

50

50

49

40

39

38

5

63

62

60

51

48

49

10

67

64

64

53

52

53

15

67

68

69

60

61

62

20

74

75

77

70

71

70

323

343

323

343

Receding for CH4

344 345 346



AUTHOR INFORMATION

347

348

Corresponding Author

349

*E-mail: [email protected]. 23


Page 25 of 39

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Energy & Fuels

350

ORCID

351

Bin Pan:0000-0003-3482-5660

352

Yajun Li: 0000-0001-6693-017X

353

Franca Jones: 0000-0002-8461-8291

354

Stefan Iglauer: 0000-0002-8080-1590

355

Notes

356

The authors declare no competing financial interest.

357

358



ACKNOWLEDGMENTS

359

360

This project was supported by the National Science and Technology Major Project

361

(2016ZX05023-001, 2017ZX05049-006), 973 Program (2014CB239103) and the

362

Chinese Scholarship Council.

363

364



ABBREVIATIONS

365

366

CO2

carbon dioxide

367

N2

nitrogen

24


Energy & Fuels

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

368

Ar

argon

369

SF6

sulfur hexafluoride

370

He

helium

371

NaCl

sodium chloride

372

CaCl2

calcium chloride

373

MgCl2 magnesium chloride

Page 26 of 39

374

375



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