Pore structure alteration induced by CO2–brine–rock interaction during CO2 energetic fracturing in tight oil reservoirs

Journal Pre-proof Pore structure alteration induced by CO2–brine–rock interaction during CO2 energetic fracturing in tight oil reservoirs Sihai Li, Shicheng Zhang, Yushi Zou, Xinfang Ma, Yao Ding, Ning Li, Xi Zhang, Dane Kasperczyk PII:

S0920-4105(20)30234-5

DOI:

https://doi.org/10.1016/j.petrol.2020.107147

Reference:

PETROL 107147

To appear in:

Journal of Petroleum Science and Engineering

Received Date: 6 January 2020 Revised Date:

8 February 2020

Accepted Date: 1 March 2020

Please cite this article as: Li, S., Zhang, S., Zou, Y., Ma, X., Ding, Y., Li, N., Zhang, X., Kasperczyk, D., Pore structure alteration induced by CO2–brine–rock interaction during CO2 energetic fracturing in tight oil reservoirs, Journal of Petroleum Science and Engineering (2020), doi: https://doi.org/10.1016/ j.petrol.2020.107147. This is a PDF file of an article that has undergone enhancements after acceptance, such as the addition of a cover page and metadata, and formatting for readability, but it is not yet the definitive version of record. This version will undergo additional copyediting, typesetting and review before it is published in its final form, but we are providing this version to give early visibility of the article. Please note that, during the production process, errors may be discovered which could affect the content, and all legal disclaimers that apply to the journal pertain. © 2020 Published by Elsevier B.V.

1

Pore Structure Alteration Induced by CO2–Brine–Rock Interaction

2

During CO2 Energetic Fracturing in Tight Oil Reservoirs

3

Sihai Li a, b, Shicheng Zhang a, Yushi Zou a*, Xinfang Ma a, Yao Ding c, Ning Li a, Xi Zhang b, Dane Kasperczyk b

4

a

State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing, China

5

b

CSIRO Energy, Private Bag 10, Clayton South, VIC 3169, Australia

6

c

School of Electronics Engineering and Computer Science, Peking University, Beijing 100871, China

7

ABSTRACT: CO2 energetic fracturing is an important technique for developing tight oil resources

8

by creating complex fractures and enhancing formation pressure. The physical properties of host

9

rocks may be changed by CO2–brine–rock interaction in the soaking stage of CO2 energetic

10

fracturing. However, the pore structure alteration behavior and mechanism during CO2 energetic

11

fracturing are still unclear. To address this problem, this work conducted static soaking experiment

12

under

13

comprehensively characterize the pore structure. The results show that CO2–brine–rock interaction

14

generated many large pores (10~50 µm) due to the dissolutions of carbonate and feldspar, numerous

15

tiny intragranular pores (1~6 µm) and some microfractures in clays. The
 distribution could be

16

applied to characterize the pore size distribution of tight sandstones when the pores saturated with

17

brine. Some secondary clay particles and debris dispersed into the brine caused by CO2–brine–rock

18

interaction. These particles may block extremely small pore throats during flowing back. These

19

blockages weakened the exchange between the small and the large pores, characterized by

20

single-peak and insignificant three-peak
 distributions transformed into apparent dual-peak


21

distributions. After soaking the rock with CO2-saturated brine for 168 h at 20 MPa and 80 °C, the

22

maximum pore throat radius increased four-fold, and the average pore throat radius increased by

23

86.5% from 0.089 µm to 0.166 µm, indicating a significant increase in the pore connectivity.

24

Increasing the soaking pressure or CO2 concentration can transform small pores into larger pores and

25

can open bedding planes significantly, thus increasing the porosity and permeability of tight

26

sandstones.

27

Keywords: CO2–Brine–Rock Interaction; Pore Structure; CO2 energetic fracturing; Tight oil

28

1 Introduction

reservoir

temperature-pressure

conditions

and

employed

multiple

techniques

to

29

Driven by economic development and the improvement of living standards, fossil fuels demand

30

is growing rapidly (Khan et al., 2019). Crude oil will continue to be an important energy source in

31

the next few decades. In China, there has been a decrease in conventional crude oil production,

32

which has led to unconventional tight oil resources being vigorously developed. These tight oil

33

resources are within reservoirs with ultralow in-situ permeability of between 0.01 mD and 0.1 mD.

34

The ultralow permeability is enhanced by using horizontal-well drilling and multistage fracturing

35

that injects massive water-based fluids to create a permeable fracture network (Bhattacharya and

36

Nikolaou, 2016; Zou et al., 2016). Although water-based fracturing fluids have the advantage of

37

creating high conductivity fractures for oil production, they may cause damaging formation, wasting

38

water resources and polluting groundwater (Myers, 2012; Buono et al., 2018). Moreover, field

39

practice indicated that massive-scale hydraulic fracturing in some tight oil reservoirs tends to

40

generate two-wing symmetric fractures as these reservoirs have a low brittleness and lack of natural

41

fractures and bedding planes. To avoid these drawbacks, CO2 fracturing technologies have attracted

42

much attention in recent years (Li and Zhang., 2018; Middleton et al., 2015). In particular, CO2

43

fracturing has recently been applied to stimulate tight oil/gas reservoirs in Changqing and Jilin

44

Oil-fields achieving a significant increase in production from many wells (Meng et al., 2019; Ding et

45

al., 2018). CO2 fracturing has advantages over water-based fracturing, such as creating complex

46

hydraulic fractures, enhancing formation pressure, reducing oil viscosity and formation damage, and

47

saving water resources (Sinal and Lancaster, 1987; Reynolds and Buendia, 2017; Li et al., 2019a).

48

In the process of CO2 fracturing, CO2 is injected into reservoirs to create complex fractures for

49

oil/gas to efficiently flow to the wellbore. After injecting CO2 into a reservoir, it dissolved in the

50

reservoir brine forming a dilute carbonic acid solution. Although the carbonic solution is a weak acid

51

under reservoir temperature-pressure conditions, a strong geochemical reaction can occur between

52

the acidic brine and the host rock (Yu et al., 2012; Zou et al., 2018). This interaction between the

53

CO2-saturated brine and reservoir rock, that is CO2–brine–rock interaction, can partially dissolve the

54

skeletal grain minerals and cement of the host rock (Gaus, 2010; Liu et al., 2012). The mineral

55

dissolutions can generate macropores or even microfractures that result in altering the properties of

56

host rock (Alam et al., 2014). The host rocks of tight oil reservoirs are typically sedimentary rocks,

57

which contain unstable minerals (e.g., calcite, dolomite, K-feldspar, and albite). In fact, most of tight

58

oil reservoirs in China are featured by low formation pressure, high oil viscosity and a brine

59

saturation of up to 60% (Hu et al., 2018; Zou et al., 2015). CO2 energetic fracturing, characterized by

60

delayed or even no flow back after fracturing, is an efficient technique to develop tight oil resources

61

by creating complex fractures in the reservoir, increasing formation pressure, and reducing oil

62

viscosity (Hu et al., 2018; Liu et al., 2014). The soaking process of CO2 energetic fracturing provides

63

enough time for the reactions between CO2-enriched brine and unstable minerals. Thus, the

64

importance of CO2–brine–rock interaction should not be overlooked when using CO2 energetic

65

fracturing in tight oil reservoirs.

66

The pore structure of tight sandstones has a significant impact on the flow capacity of oil and

67

the production rate. The pore structure is defined by the geometry, size, distribution, and connectivity

68

of pores and throats (Fu et al., 2015). Previous studies have indicated that CO2–brine–rock

69

interaction may alter the mineralogical and pore-scale properties of conventional sandstone and

70

carbonate formations during CO2 flooding or CO2 capture and storage (Saeedi et al., 2016; Adebayo

71

et al., 2017; Kweon and Deo, 2017; Huo et al., 2017; Han et al., 2018; Jayasekara et al., 2019). In

72

addition, several studies investigated the effects of CO2–brine–rock interaction on the pore-scale

73

properties of unconventional shale reservoirs. Alemu et al. (2011) investigated the pore-scale

74

geochemical reactivity between shale and CO2-saturated brine during CO2 geological storage. Pan et

75

al. (2018) investigated the influences of temperature and pressure of CO2 treatment on the pore

76

structure of shale with low-pressure CO2 adsorption and low-pressure nitrogen adsorption. Our

77

previous study studied the effects of CO2–brine–rock interaction on the porosity, permeability,

78

tensile strength, and friction coefficient of marine shale during supercritical CO2 fracturing (Zou et

79

al., 2018). Zhang et al. (2018) studied the impacts of CO2–brine–rock interaction on the mineral

80

compositions and wettability of Lucaogou tight sandstone during CO2 injection. Zhou et al. (2019)

81

investigated the chemical effect of supercritical CO2 on the variation rules of porosity and

82

permeability of intersalt dolomitic shale oil reservoirs. They found that the mixed solution of

83

supercritical CO2 and distilled water can remarkably improve the reservoir porosity and permeability

84

and avoid salt crystallization damage. Luo et al. (2019) investigated the effect of supercritical

85

CO2-water-shale interactions on shale pore structure and found that the specific surface area and pore

86

volume of two types of shale increased after the reaction. Most of the abovementioned studies

87

focused on the mineral composition, porosity/permeability, wettability of host rock after CO2

88

injected into shale reservoirs. However, the pore structure alteration behavior and mechanism

89

contingent to CO2–brine–rock interaction during CO2 energetic fracturing in tight oil reservoirs is

90

still unclear. Furthermore, the pressure and CO2 concentration difference at the far-field and

91

near-wellbore zones may produce the behavior of pore structure differently, which to date, is poorly

92

studied.

93

This paper studied the pore structure alteration induced by CO2–brine–rock interaction during

94

CO2 energetic fracturing in the Chang-7 tight oil reservoir. A series of static soaking experiments

95

were conducted under reservoir temperature-pressure conditions, with independently changing the

96

soaking pressure, soaking time, and CO2 concentration. Multiple testing methods, including X-ray

97

diffraction (XRD), scanning electron microscopy (SEM), low field nuclear magnetic resonance

98

(LFNMR), mercury injection capillary pressure (MICP) measurement, and gas porosity/permeability

99

testing were employed to reveal the mineralogical and pore structural property variations. In the end,

100

some conclusions are drawn based on the changes in the pore structural properties.

101

2 Experimental Methods

102

2.1 Experimental Apparatus

103

A high temperature-pressure soaking device was utilized to conduct static soaking experiments

104

(Fig. 1). The cooling unit was used to transfer CO2 into the liquid state, which is required for

105

pressurization with the CO2 plunger pump. The inlet pressure of the CO2 pump should be larger than

106

1.2 MPa, and the outlet pressure can be up to 50 MPa. A polyfluoroethylene seal assembly capable of

107

resisting to CO2 was placed in the middle part of the piston in the fluid separation vessel. The heating

108

pipelines were used to heat CO2 and transform it into the supercritical state. Other parameters of the

109

soaking device can be found in Li et al., 2019b.

110 111

Fig. 1. Schematic diagram of the high temperature-pressure soaking device (after Li et al., 2019b).

112

2.2 Sample and Synthetic Brine Preparation

113

Tight sandstone samples were over cored from Chang-7 tight oil reservoir with a depth of

114

2072.5~2072.8 m in Ordos Basin, China. Three types of samples, including granular sample, thin

115

slice sample, and cylindrical sample, were prepared for the static soaking experiments (Fig. 2). Initial

116

crude oil in these samples was completely extracted for three weeks. For mineral composition testing,

117

a total of 12.000 g granular sample was prepared (Fig. 2a). The size of the granular sample ranges

118

from 0.85 mm to 1.18 mm, which could increase the contact area and thus enhance the dissolution

119

degree of unstable minerals as well as collect these particles conveniently. Two thin slice samples

120

with a diameter of 25 mm and a thickness of 2 mm were prepared for studying mineral dissolution

121

through SEM (Fig. 2b). Six cylindrical samples with 25 mm in diameter and 30 mm or 50 mm in

122

length were used for the testing of porosity, permeability, pore size distribution, and pore throat

123

distribution (Fig. 2c). A synthetic brine was prepared for the static soaking experiments with

124

deionized water matching the composition (wt. %) of Chang-7 formation brine: 2.0% KCl, 1.56%

125

NaCl, 0.05% MgCl2, and 0.22% CaCl2.

126 127

Fig. 2. Three types of tight sandstone sample: (a) granular; (b) thin slice; (c) cylindrical.

128

2.3 Experimental Scheme and Procedure

129

Static soaking experiments were conducted at the temperature of Chang-7 formation (80 °C).

130

After CO2 energetic fracturing in tight oil reservoirs, the well is often soaked for several days or

131

weeks to enhance formation pressure and reduce oil viscosity (Liu et al., 2014). In the CO2 energetic

132

fracturing process, the high fluid pressure and high concentration of CO2 in the hydraulic fracture

133

gradually diffuses to the far-field zone. To simulate the enhanced pressure in the near-fracture areas

134

and the reservoir pressure, the soaking pressure was set as 20 MPa and 30 MPa, respectively. To

135

mimic the CO2 concentrations in the reservoir, CO2-saturated brine and CO2-undersaturated brine

136

were used during the soaking experiments. Notably, the CO2-saturated brine and CO2-undersaturated

137

brine correspond to the geochemical environment of the near-fracture zones and far-field zones,

138

respectively. To match CO2 energetic fracturing durations, the soaking time for the cylindrical

139

sample was 24/72/168 h, and the soaking time for the granular and thin slice samples was 72 h. The

140

parameters of static soaking experiments were listed in Table 1. Noted that granular sample G-1

141

(6.000 g) and cylindrical sample C7-1-3 were used for testing the initial mineral composition and

142

initial pore throat distributions, and cylindrical sample C7-2-3 was used as a blank comparison

143

control to correct the effect of the sample itself on the experimental results. Granular samples G-1

144

and G-2 were collected at the same depth of a reservoir core, so were the cylindrical samples C7-1-1,

145

C7-1-2, and C7-1-3, as well as the samples C7-2-1, C7-2-2, and C7-2-3. Table 1 The parameters of static soaking experiments

146

147

Sample No.

Temperature (°C)

Pressure (MPa)

Reaction time (h)

Soaking fluid

G-1/C7-1-3

/

/

/

/

G-2/S-1

80

20

72

CO2-saturated brine

C7-1-1

80

20

24/72/168

CO2-saturated brine

C7-1-2

80

30

24/72/168

CO2-saturated brine

C7-2-1

80

20

24/72/168

CO2-saturated brine

C7-2-2

80

20

24/72/168

CO2-undersaturated brine

C7-2-3

80

20

168

Synthetic brine

Note: G, S, and C represents the granular, thin slice, and cylindrical sample, respectively.

148

To simulate the actual water saturation of Chang-7 formation, the sample should be deoiled,

149

dried, saturated with synthetic brine, and then displaced with crude oil at each soaking stage

150

(24/72/168 h). It is extremely hard to control the water saturation of different samples and the same

151

sample at the different soaking stage to the same value. Such a time-consuming sample preparation

152

process might damage the sample and affect the experimental results. Therefore, before the static

153

soaking experiment, the samples listed in Table 3 were saturated with the synthetic brine as an

154

approximation at 25 MPa for 24 h after being held under vacuum for 24 h. In the case of soaking

155

with the CO2-saturated brine, pour 100 mL synthetic brine into the CO2 reaction tank and place the

156

samples into the tank simultaneously. Next, the CO2 reaction tank was heated to the given reservoir

157

temperature (80 °C) in the oven. Once the set temperature had been reached, supercritical CO2 was

158

injected into the tank continually using the syringe pump until meeting the target pressure (either 20

159

MPa or 30 MPa). In the case of soaking with the CO2-undersaturated brine, the cylindrical sample

160

was placed into the CO2 reaction tank and filled with synthetic brine. Then, supercritical CO2 was

161

injected into the tank using the syringe pump until it reached the given pressure. However, after CO2

162

was left to dissolve into the brine for 2 h, CO2 injection was stopped, and synthetic brine was

163

continuously injected into the CO2 reaction tank to maintain stable pressure. After soaking for

164

24/72/168 h, the cylindrical samples were removed from the CO2 reaction tank and immersed in the

165

soaked synthetic brine before conducting the LFNMR test to measure the
 distribution. After

166

completing the static soaking experiments, the granular, thin slice, and cylindrical samples were

167

flushed with deionized water and then thoroughly dried for 48 h at 100 °C. After the drying process,

168

a series of physical parameters were measured, including mineral composition, mineral dissolution,

169

porosity, and permeability. To measure pore throat distribution and observe precipitates and pore size,

170

sample C7-1-1 was cut into cylindrical sample C7-1-1-C (30 mm in length) and thin slice C7-1-1-S,

171

respectively (Fig. 3).

172 173

Fig. 3. Schematic diagram of cutting sample C7-1-1 after the soaking treatment: (a) the cutting

174

positions in sample C7-1-1; (b) the SEM positions on the thin slice C7-1-1-S.

175

2.4 Analytical Techniques and Methods

176

Multiple analytical techniques were employed to measure the changes in mineralogical and pore

177

structural properties induced by CO2–brine–rock. The mineral compositions were measured by XRD

178

analysis of powder particles ( 150 μm) from the granular samples. SEM was conducted on the thin

179

slice samples to measure mineral dissolutions, secondary minerals precipitates, and changes in pore

180

size. LFNMR was employed to test the pore size distribution of cylindrical samples with a 0.35 T

181

SPEC-35 permanent magnet core analyzer (Beijing SPEC Technology Development Company). The

182

porosity was tested with a helium porosimeter and the permeability was measured by the PDP-200

183

pulse decay permeameter. Finally, MICP was used to measure the pore throat distribution.

184

2.5 Background of NMR theory

185

NMR uses the transverse relaxation time
 to characterize the pore size distribution of porous

186

media (Morriss et al., 1997). Apparent transverse relaxation time
 of fluid confined in pores is a

187

combination of three relaxation mechanisms: bulk relaxation
 , surface relaxation
 , and

188

diffusion relaxation
 (Coates et al., 1999; Dunn et al., 2002).

189













  

(1) 

190

When the spins of hydrogen proton satisfies the fast diffusion regime characterized by   ≪ 1,

191

where  is the pore size and  is the diffusion coefficient, the surface relaxation rate (1/
 ) is

192

equal to the surface relaxivity (ρ) multiplied by the surface to volume ratio (/) (Brownstein et al.,

193

1979).

194 195







(2)

Provided that the bulk relaxation rate (1/
 ) and diffusion relaxation rate (1/
 ) are much

196

smaller than the surface relaxation rate (1/
 ), they can be neglected in the right-hand side of Eq. (1)

197

(Dunn et al., 2002). In this case, the apparent
 distribution can indicate the distribution of pore

198

size. Specifically, the relaxation time
 is related to pore size, and the
 area to the volume of

199

pores.

200

3 Experimental Results

201

The solubility of CO2 in the synthetic brine at 80 °C and 20 MPa was 1.04 mol/kg and was 1.16

202

mol/kg at 30 MPa and 80 °C (Duan and Sun, 2003). Carbonic acid was formed after CO2 dissolving

203

in the synthetic brine as given in Eq. (3), causing a decrease in the pH value. Under the reservoir

204

temperature was 80 °C, the pH values were 3.07 and 3.02 at 20 MPa and 30 MPa, respectively, as

205

calculated using the software package PHREEQC. Thus, it provides geochemical conditions for

206

altering rock mineralogical and pore structural properties that include pore size distribution, pore

207

throat distribution, porosity, and permeability.

208

CO  H O → H %  HCO' &

209

3.1 Mineral Composition

(3)

210

Before and after soaking the granular samples for 72 h at 20 MPa and 80 °C, the average

211

mineral compositions measured were shown in Fig. 4. The concentration of calcite, dolomite,

212

K-feldspar, and albite decreased while the concentration of quartz and clay increased slightly. Most

213

notably, the carbonate concentration decreased from 19.2% to 13.3% and the feldspar concentration

214

decreased from 14.5% to 12.7% (Fig. 4a). The concentration of the illite and chlorite declined

215

approximately 2% and the kaolinite concentration increased approximately 4% after the soaking

216

experiments. Previous studies have found similar results on mineral composition change behavior

217

(Gaus, 2010; Yu et al., 2012; Liu et al. Pan et al., 2018; Li et al. 2019b). The changes in mineral

218

compositions result from the chemical reactions between these unstable minerals and CO2-saturated

219

brine at reservoir temperature-pressure conditions, which are governed by Eqs. (4)-(9) (Mandalaparty

220

et al., 2011; Kweon and Deo, 2017).

221 222

Fig. 4. Mineral compositions before and after soaking with CO2-saturated brine: (a) rock mineral

223

compositions; (b) clay mineral compositions.

224

CaCO& )Calcite/  H % → Ca%  HCO&'

225

CaMg)CO& / )Dolomite/  2H % → Ca% Mg %  2HCO' &

(5)

226

2KAlSi& O8 9K-feldspar?  2H %  9H O → 2K %  4HB SiOB  Al Si OC )OH/B )Kaolinite/

(6)

227

NaAlSi& O8 )Albite/  CO  5.5H O → Na%  HCO&'  2HB SiOB  0.5Al Si OC )OH/B )Kaolinite/(7)

228

Illite  8H %  0.25Mg %  0.6K %  2.3Al&%  3.5SiO )aq/  5H O

(8)

229

Chlorite  16H %  2.3Al&%  3SiO )aq/  5Fe%  12H O

(9)

(4)

230

Before conducting the soaking experiments, numerous SEM images were captured and Energy

231

Dispersion Spectrum (EDS) analyses were employed to confirm the mineral type with the un-soaked

232

thin slice sample. After the soaking treatment, the morphology of minerals changed significantly due

233

to the chemical reactions, which could be confirmed by comparing the SEM-EDS results with the

234

initial ones. Fig. 5 shows the dissolution of calcite, dolomite, albite, and K-feldspar after soaking for

235

72 h at 20 MPa. Calcite was dissolved completely because of its low initial concentration (3.5%) and

236

chemical instability, while dolomite was partially dissolved exhibiting a porous honeycomb

237

morphology. The intense dissolution of the carbonate minerals can be attributed to their being easily

238

corroded by acids. The well-crystallized K-feldspar was unevenly dissolved, exhibiting incomplete

239

crystal texture with some pockets, whereas albite was etched limitedly, showing a relatively

240

well-crystallized texture. The dissolution degree of carbonate was stronger than that of feldspar and

241

the corrosion degree of albite is much weaker than that of K-feldspar.

242 243

Fig. 5. The dissolution of calcite, dolomite, K-feldspar, and albite after soaking for 72 h. (The red

244

boxes refer to the corroded minerals, the dotted yellow lines refer to the boundary of etched

245

minerals.)

246

Figure 6 shows the images of quartz and clays after soaking for 72 h at 20 MPa and 80 °C.

247

Quartz was not been corroded by the acidic CO2-saturated brine and remained as a complete crystal

248

texture (Fig. 6a). However, previous studies indicated that quartz could be corroded with a higher

249

temperature of 100 °C or longer soaking time of 168 h (Lin et al., 2008; Li et al., 2019b). Numerous

250

tiny intragranular pores with a diameter of approximately 6.0 µm were formed in clays as shown in

251

Fig. 6b, which is probably because that chlorite embedded in the clays was dissolved. The illite was

252

eroded generating extremely small intragranular pores with a diameter of approximately 1.0 µm and

253

some microfractures with a width of 1.6 µm (Fig. 6c). Moreover, some secondary kaolinite particles

254

were formed beside the K-feldspar and albite due to the dissolutions of these two minerals (Figs. 6d,

255

e).

256

257

Fig. 6. SEM images of quartz and clays after soaking for 72 h: (a) uncorroded quartz, (b) dissolution

258

pores in clays, (c) chemical-induced pores and microfracture in illite, kaolinite generated from the

259

dissolution of (d) K-feldspar and (e) albite.

260

3.2 Pore Size Distribution

261

Previous studies have found that tight sandstone has a relatively weak surface relaxation rate (ρ)

262

and the diffusion coefficient () of water is large (Dunn et al., 2002). This indicates that water

263

confined in tight sandstone pores support the fast diffusion regime. The bulk relaxation time

264

(approximately 1000 ms) is much larger than the apparent
,PQ (the logarithmic mean of


265

distribution), as shown in Figs. 7 and 8, and therefore it is reasonable to employ the
 distribution

266

of brine confined in tight sandstone pores to characterize its pore size distribution.

267

Figure 7 shows the
 distribution before and after soaking with CO2-saturated brine at 20

268

MPa and 30 MPa, under the temperature of 80 °C. Based on the bimodal
 distribution, the pores

269

of tight sandstone samples can be divided into two categories: small pores (
  10 ms), and large

270

pores (
 > 10 ms). The large pores were mainly generated by the dissolution of calcite and

271

dolomite, feldspar, and albite, while the small pores were mainly generated by the dissolution of clay

272

minerals (Figs. 5 and 6). As shown in Fig. 7a, under 20 MPa and 80 °C, the number of large pores in

273

sample C7-1-1 increased with soaking time within 72 h and kept steady after 72 h whereas the

274

number of small pores decreased with increasing soaking time. As shown in Fig. 7b, the number of

275

small pores in sample C7-1-2 stopped to decrease and kept steady after soaking for 72 h at 30 MPa

276

and 80 °C, and that of large pores kept increasing with the soaking time. This is attributed to that

277

increasing the soaking pressure could reduce the pH value of CO2-saturated brine and increase the

278

penetration depth of the carbonic acid into the small pores, which may increase the chemical reaction

279

rate and the dissolution degree of small pores. Therefore, increasing the soaking pressure is

280

conducive to enlarging the pore size and transforming small pores to large pores, resulting in

281

increasing the number of large dissolution pores.

282 283

Fig. 7.
 distributions before and after soaking with CO2-saturated brine at 20 MPa and 30 MPa,

284

respectively: (a) 20 MPa (sample C7-1-1); (b) 30 MPa (sample C7-1-2).

285

Figure 8 shows the
 distribution before and after soaking with CO2-saturated and

286

CO2-undersaturated brine at 20 MPa and 80 °C. As shown in Fig. 8a, the number of large pores of

287

sample C7-2-1 increased with the soaking time after 72 h, which differs from sample C7-1-1 that has

288

a higher permeability under identical soaking conditions (Fig. 7a). This result indicates that the time

289

to reach the maximum dissolution degree for the tight sandstone is shorter for the tight sandstone

290

with relatively higher permeability. As shown in Fig. 8b, the number of large pores increased slightly

291

after soaking for 72 h with CO2-undersaturated brine. Moreover, the increment in the pore volume of

292

large pores after soaking with CO2-undersaturated brine (C7-2-2) is smaller than that with

293

CO2-saturated brine (C7-2-1). This difference is explained by the acidity of CO2-undersaturated brine

294

that gradually weakens due to the interaction with unstable mineral and without sufficient CO2

295

dissolved in the brine. The results indicate that insufficient CO2 in the far-field areas may enlarge the

296

pore size limitedly, and it needs a longer duration to reach the maximum dissolution degree.

297 298

Fig. 8.
 distributions before and after soaking with CO2-saturated and CO2-undersaturated brine,

299

respectively: (a) CO2-saturated brine (sample C7-2-1); (b) CO2-undersaturated brine (sample

300

C7-2-2).

301

There are two distribution variations of
 before and after the soaking treatment (Figs. 7 and

302

8). First, the right endpoints of the
 distribution curves shifted to the left approximately 70~220

303

ms after the soaking treatment. This offset can be attributed to the secondary clay minerals that

304

disperse in the brine and adhere to the pore wall, which can speed up the relaxation time (Matteson et

305

al., 2000). Second, the single peak
 distributions and insignificant three-peak
 distributions

306

transformed into apparent dual-peak
 distributions after the soaking treatment. The fluid exchange

307

between the small pores and the large pores was weakened to some extent and can explain the visible

308

dual-peak
 distributions (Ghomeshi et al., 2018; Anand and Hirasaki, 2007). Fig. 9 shows the

309

images of throat blockage captured by SEM at different depths (x) in sample C7-1-1. The throat

310

block is made by the secondary reticulated halloysite and debris, resulting from the chemical CO2–

311

brine–rock interaction. The most likely reason is that CO2 carries these particles to the throat when

312

CO2 is released from the reaction tank after the soaking treatment. The evident throat blockage could

313

explain the reason for the weakened exchange between large pores and small pores. Previous studies

314

also found that the formation of clay minerals and mobilized minerals could cause intragranular and

315

intergranular pore blockage (Wang et al., 2010; Massarotto et al., 2010).

316 317

Fig. 9. Throat blockage at different depth (x) in the sample C7-1-1 after soaking for 168 h at 20 MPa

318

and 80 °C: (a) x=2.5 mm; (b) x=7.5 mm; (c) x=12.5 mm.

319

3.3 Pore Throat Distribution

320

Figure 10 shows the capillary pressure curve and the pore throat distribution of the initial

321

sample C7-1-3 and the soaked sample C7-1-1-C. For the initial sample C7-1-3, shown in Fig. 10a,

322

both the intrusion and extrusion curves moved to the lower left after soaking for 168 h at 20 MPa and

323

80 °C. Specifically, the maximum mercury saturation value increased from 91.06% to 95.49%, and

324

the discharge pressure decreased from 2.75 MPa to 0.67 MPa, indicating that both the pore volume

325

and the pore throat were enlarged after the soaking treatment. The pore throat distribution for the

326

soaked sample C7-1-1-C increased from 0.004~0.250 µm to 0.004~1.000 µm (Fig. 10b). The

327

maximum pore throat radius increased four-fold, and the average pore throat radius increased by

328

86.5% from 0.089 µm to 0.166 µm, indicating a significant increase in the pore connectivity.

329 330

Fig. 10. Capillary pressure curve and pore throat distribution before and after soaking for 168 h: (a)

331

capillary pressure curve, (b) pore throat distribution.

332

Figure 11 shows the internal dissolutions and pore size enlargement in sample C7-1-1 after

333

soaking for 168 h. The chemical reactions between unstable minerals and CO2-saturated brine were

334

intensive near the sample surface (x=0 mm), forming some large pores with a diameter of

335

approximately 53 µm (Fig. 11a). The pore size is also enlarged to approximately 10~35 µm with

336

depth ranges from 0.25 mm to 1.25 mm. The results indicate that the whole sample was sufficiently

337

eroded after the soaking treatment. Moreover, the amplitude of pore size enlargement at the

338

near-surface positions was higher than that inside the sample.

339 340

Fig. 11. Pore size enlargement at different depth (x) in sample C7-1-1 after soaking for 168 h: (a) x=0

341

mm; (b) x=2.5 mm; (c) x=5.0 mm; (d) x=7.5 mm; (e) x=10.0 mm; (f) x=12.5 mm.

342

3.4 Porosity and Permeability

343

Figure 12 shows the changes in porosity and permeability after soaking for 168 h. As shown in

344

Fig. 12a, the porosity of sample C7-1-1 increased by 2.59% from 11.95% to 12.26% under the

345

soaking pressure of 20 MPa, while the porosity of sample C7-1-2 increased by 11.33% from 12.45%

346

to 13.86% under the soaking pressure of 30 MPa. Correspondingly, the permeability increased by

347

36.43% and 425.72% under the soaking pressure of 20 MPa and 30 MPa, respectively (Fig. 12b).

348

The significant increase in permeability after soaking for 168 h at 30 MPa and 80 °C is because two

349

bedding planes were opened in sample C7-1-2 (Fig. 12b). The experimental results show that higher

350

soaking pressure may trigger more active chemical interactions between unstable minerals and

351

CO2-saturated brine, resulting in the higher enhancement of porosity and permeability or even

352

facilitate the activation of bedding planes. In the cases of soaking with CO2-saturated brine in sample

353

C7-2-1 and CO2-undersaturated brine in sample C7-2-2, the porosity increased by 3.22% and

354

10.81%, respectively; while the permeability increased by 42.02% and 117.24%, respectively. The

355

results indicate that the porosity and permeability increased more significantly after soaking with

356

CO2-saturated brine in comparison to that with CO2-undersaturated brine.

357 358

Fig. 12. Changes in porosity and permeability of cylindrical samples after soaking for 168 h.

359

4 Discussion

360

4.1 Relationship between T2 distribution and pore size distribution

361

NMR technology can effectively and non-destructively quantify the physical properties of rock

362

matrix, pore fluid saturation and pore sizes (Kleinberg et al., 1994; Yao and Liu, 2012; Yan et al.,

363

2020). The shape of
 distribution is not only affected by pore size distribution but also related to

364

fluid diffusion mechanism, bulk relaxation, and diffusion relaxation. Two critical conditions should

365

be met when applying the results obtained to characterize the pore size distribution: fast diffusion

366

regime should be supported, and the bulk relaxation rate and diffusion relaxation rate could be

367

neglected. Should these conditions be met, the surface relaxation
 has a good correlation with the

368

pore size. Noted that two factors within the brine can influence the bulk relaxation including

369

dispersed clay particles and paramagnetic materials (e.g., Mg2+, Ca2+, and Fe2+). Surface relaxation

370

can be varied by changes in the pore wall properties due to variation in the mineral composition after

371

the soaking treatment. Therefore, it is necessary to check whether the diffusion of fluid meets the

372

critical conditions before relating
 distribution to pore size distribution. For example, it is not

373

feasible to characterize pore size distribution by
 distribution when the pores saturated with

374

high-viscosity oil or heavy oil. In such conditions, the bulk relaxation rate (1/
 ) cannot be

375

neglected in the right hand of Eq. (1). Additionally, the high-viscosity oil has a large hydration radius,

376

and thus its diffusion coefficient is small, which means it may not support the fast diffusion regime

377

considered in this paper.

378

The NMR signal amplitude of the cylindrical samples saturated with the synthetic brine before

379

and after the soaking treatment was shown in Fig. 13. The NMR signal amplitude decreased by 11.24%

380

on average after soaking for 168 h. It indicates that the amount of brine confined in the pores

381

decreased after the soaking treatment because the NMR signal amplitude depends on the amount of

382

brine (hydrogen proton) in the pores. This probably can be attributed to two reasons. On one hand,

383

the primary and secondary clays may swell and expel some brine out of the enlarged pores,

384

especially for the secondary clays (Figs. 6 and 9). The swelling of clays could be confirmed by the

385

blank comparison experiment on sample C7-2-3, in that the NMR signal amplitude decreased 251

386

after soaking for 168 h with the synthetic brine at 20 MPa and 80 °C (Fig. 13). Therefore, it is better

387

to add clay anti-swelling agents into the fracturing fluid, especially for the water-based fracturing

388

fluids. Moreover, when the fluid pressure decreased to the atmospheric pressure, CO2 may escape

389

from the brine and expel some brine out of the pores, shown in Fig. 14c. Because CO2 uniformly

390

dissolved in the brine during the soaking stage, it will escape from the brine uniformly when flowing

391

back occurred. Then we may get the point that the brine expelled out of the large and small pores

392

may be proportional to the volume of these pores. In other words, the volume ratio of brine in the

393

large and small pores could be considered unchanged after CO2 escaped out of the brine. Therefore,

394

the
 distributions shown in Figs. 7 and 8 can still represent the pore size distribution, but with a

395

proportional decrease in the NMR signal amplitude. If the NMR testing could be conducted on the

396

samples in a non-magnetic core holder under high pressure after the soaking experiment, it is

397

possible to minimize the impacts of gas CO2 by re-dissolving the CO2 into the brine.

398 399

Fig. 13. NMR signal amplitude of the cylindrical samples saturated with the synthetic brine before

400

and after the soaking treatment.

401

4.2 Mechanism of pore structure alteration

402

The schematic diagram of the pore structure alterations before and after the soaking treatment

403

was shown in Fig. 14. After the soaking treatment, unstable minerals were variably dissolved thereby

404

enlarging the size of pores and throats. Meanwhile, there were some secondary mineral precipitates

405

dispersed in the brine and some feldspar (i.e., K-feldspar and albite) debris fall into the pores. When

406

the shut-in valve opened (i.e., back flow occurred), CO2 escapes from the brine and carries these

407

mineral precipitates and debris to the low fluid pressure areas. When these tiny particles encountered

408

an extremely small pore throat, they will gather at the throats and block them. The blockage may

409

weaken the exchange between pores, which can be confirmed by the significant dual-peak


410

distributions as shown in Figs. 7 and 8 (Ghomeshi et al., 2018; Anand and Hirasaki, 2007). Although

411

the throat blocked by mineral precipitates and debris particles, the gas permeability of tight

412

sandstones samples increased by 36% to 426% after the soaking treatment. This is because clay

413

minerals (e.g., kaolinite and halloysite) lost water during the drying process before the gas

414

permeability testing, which may partially weaken the blockage of pore throat (Fig. 9). Moreover, the

415

enlarging of the size of pores and throats, indicating the enhancing of the connectivity between the

416

pores, are conducive to increasing the permeability of the tight sandstone, which can be confirmed by

417

the results of SEM, NMR, MICP, and gas permeability testing.

418 419

Fig. 14. Schematic diagram of the pore structure alterations after the soaking treatment: (a) before

420

soaking; (b) after soaking and before flow back; (c) after flow back (pore pressure equal to

421

atmospheric pressure).

422

Similar to tight oil reservoirs, shale reservoirs generally contain unstable minerals and primary

423

brine, which are necessary conditions for CO2-brine-rock interaction. The study by Pan et al. (2018)

424

indicated that the number of micropores and mesopores (0.3-20 nm) in a marine shale decreased

425

significantly after CO2-brine-rock interaction, while the number of macropores increased leading to

426

improving the porosity and permeability. However, an opposite variation trend of pore structure was

427

also discovered in a terrestrial shale. Luo et al. (2019) found that the pore volume of the micropores

428

(<2 nm) and mesopores (2-50 nm) increased after the interactions, while the change of the pore

429

volume of macropores (>50 nm) exhibited opposite behaviors for two different shales. They also

430

pointed out that the increase in the pore volume of micropores is due to the dissolution of the clay

431

minerals and carbonate minerals, which is different from the pore structure alteration behavior of

432

Chang-7 tight sandstone. In this study, we found that both the number of large pores (approximately

433

10-50 µm) and small pores (approximately 1-10 µm) increased significantly after soaking with

434

CO2-saturated brine. The size of dissolution pores generated in the Chang-7 tight sandstone is

435

approximately two to three orders of magnitude larger than the shales. That is because the size of

436

unstable mineral grains of Chang-7 tight sandstone is on the micron scale, which is much larger than

437

that of nanoscale shales. Other than the pore size, the variation behavior of pore size distribution of

438

the shales and Chang-7 sandstone also exhibit different behavior. The abovementioned two studies

439

suggest that the pore structure alteration behavior is closely related to the primary mineralogical and

440

physical properties of shale, including the type and content of unstable minerals, pore size

441

distribution, pore throat distribution, and reservoir conditions (e.g., temperature, pressure, and

442

salinity). Therefore, the pore structure alteration behavior caused by CO2-brine-rock interaction in

443

various rocks may exhibit different or even opposite trends.

444

4.3 Utilizing the chemical effect of CO2 in field CO2 fracturing

445

In the case of CO2 energetic fracturing in the tight oil reservoirs, massive CO2 could be injected

446

into the reservoir. The well often soaked for several days or weeks for enhanced oil recovery by

447

enhancing formation pressure and reducing oil viscosity or even realizing the mixing of CO2 with

448

crude oil. During CO2 energetic fracturing, CO2–brine–rock interaction may enlarge the pore size of

449

host rock by dissolving unstable minerals (i.e., calcite, dolomite, K-feldspar, albite, chlorite, and illite)

450

and enhancing the connectivity of the pores. On the other hand, the pore throat may be blocked when

451

flowing back occurred after the soaking stage. The blockage herein will hinder oil flow to the

452

wellbore. Thus, the pore-enlarging effect and throat-blockage effects should be systematically

453

investigated to comprehensively evaluate their influences on the oil flow in the rock matrix.

454

Specifically, two engineering parameters, including the time for the soaking stage and the back-flow

455

rate, should be optimized to achieve the optimal improvement of pore structure or permeability after

456

the soaking treatment.

457

CO2–brine–rock interaction may facilitate the activation of bedding planes during the soaking

458

stage, which can be seen from the CT image of C7-2-2 illustrated in Fig. 12b. Our previous studies

459

have found that the tensile strength of bedding planes of Chang-7 tight sandstone decreased by 46.8%

460

after soaking for 168 h (Li et al., 2019b). Inspired by the reduction in the tensile strength of the

461

bedding plane due to CO2–brine–rock interaction, we previously introduced an intermittent

462

CO2-hybrid fracturing method for stimulating tight reservoirs (Li et al., 2019b). The motivation of

463

the design is to enhance the stimulated reservoir volume in tight reservoirs by fully utilizing the

464

physical and chemical effects of CO2.

465

The Chang-7 tight oil reservoir has a low brittleness, and the natural fractures are relatively

466

undeveloped (Hu et al., 2018). Besides, it contains some bedding planes with a relatively high tensile

467

strength (approximately 4-7 MPa). Field practice indicated that massive-scale hydraulic fracturing in

468

Chang-7 tight oil reservoir tends to create two-wing symmetric fractures. Besides, the Chang-7

469

reservoir has a low formation pressure coefficient (approximately 0.77~0.84) and its water saturation

470

ranges from 40% to 60% (Hu et al., 2018). CO2 fracturing in the reservoir with a low formation

471

pressure coefficient could significantly enhance the formation pressure and oil production. Although

472

the absolute value of pore-scale properties might be slightly greater than the actual situation due to

473

the pore spaces completely saturated with synthetic brine, the experimental results could also exhibit

474

an approximated behavior of pore structure alteration. Moreover, well-factory and three-dimensional

475

large well cluster drilling are useful methods to minimize the drilling and fracturing costs. Especially

476

for the large well cluster drilling, it can arrange up to 20 wells on the same platform. Thus, we further

477

introduce an advanced intermittent CO2-hybrid fracturing design to stimulate these wells placed on

478

the same platform without consideration of gas source, equipment performance, logistics, and

479

economic costs. The operation of the advanced intermittent CO2-hybrid fracturing includes three

480

stages: (1) fracturing wells with pure CO2 one by one in sequence to create complex fractures in the

481

near-wellbore area and soaking the well after it is fractured, (2) injecting a water-/CO2-based slurry

482

into these fractured wells in sequence to create new fractures and further extend the fractures and

483

prop them, (3) soaking the well for several days or weeks to enhance oil recovery. The soaking

484

operation subsequent to the fracturing in the first stage could weaken the bedding planes or cemented

485

natural fractures. Then, the fracturing in the second stage may further activate more weaken bedding

486

planes or natural fractures. The soaking operation in the third stage may help to further enhance the

487

low formation pressure and reduce oil viscosity. The advantage of applying the advanced intermittent

488

CO2-hybrid fracturing design to stimulate multiple wells in the same platform is that it may save

489

substantial time, labor, and equipment costs. Although there are still many challenges to overcome

490

before applying the novel CO2-hybrid fracturing design in the field, it provides a potential and

491

efficient way to enhance the recovery of tight oil resources.

492

5 Conclusions

493

This paper investigated the pore structure alterations caused by CO2–brine–rock interaction

494

during CO2 energetic fracturing for Chang-7 tight oil reservoirs. Static soaking experiments were

495

conducted on three types of samples (granular, thin slice, and cylindrical samples) under reservoir

496

temperature-pressure conditions. Multiple techniques, including XRD, SEM, LFNMR, MICP, and

497

gas porosity/permeability testing, were employed to gain insights into the pore structure alteration

498

behavior and mechanism during CO2 energetic fracturing. The experimental results may provide new

499

insights into the pore structure alteration behavior and mechanism during CO2 energetic fracturing in

500

tight oil reservoirs. The findings are summarized as follows:

501

(1) CO2–brine–rock interaction generated many large dissolution pores with a diameter of

502

10~50 µm due to the dissolution of carbonate and feldspar. Numerous tiny intragranular pores with a

503

diameter of 1~6 µm and some microfractures were created in clays. The maximum pore throat radius

504

increased four-fold, and the average pore throat radius increased by approximately 86.5% from 0.089

505

µm to 0.166 µm, indicating a significant increase in the pore connectivity.

506

(2) The
 distribution of the brine confined in the pores of tight sandstone could be applied to

507

characterize the pore size distribution because the fast diffusion regime is supported and the surface

508

relaxation is significantly smaller than the bulk relaxation. After soaking with CO2-saturated brine,

509

massive newly generated secondary clay particles (e.g., kaolinite and halloysite) adhere to the pore

510

wall and disperse in the brine thus increasing the relaxation time. These clay particles may block

511

extremely small pore throats during flowing back, which can be illustrated by the single peak and

512

insignificant three-peak
 distributions transformed into apparent dual-peak
 distributions.

513

(3) Insufficient CO2 in the far-field areas of the reservoir may enlarge the pore size limitedly.

514

Increasing both soaking pressure and CO2 concentration may trigger more severe geochemical

515

interaction between CO2-saturated brine and unstable minerals, transforming more small pores

516

(
  10 ms) into the large pores (
 > 10 ms) and thereby significantly increasing the porosity and

517

permeability of tight sandstones. Especially, when the soaking pressure is increased to 30 MPa, some

518

macro bedding planes were opened resulting in a 426% increase in permeability.

519

Declaration of Competing Interest

520 521

The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper.

522

Acknowledgements

523 524 525 526

The first author is grateful for the support of China Scholarship Council (No. 201906440137) for supporting his study at CSIRO. This paper was supported by the National Natural Science Foundation of China (No. 51704305), the Major National Science and Technology Projects of China (No. 2016ZX05049-006, 2017ZX05039002-003).

527

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Highlights: 1. CO2 energetic fracturing was proposed to develop low pressure tight oil reservoirs. 2. Low field nuclear magnetic resonance was used to measure pore size distribution. 3. The alterations in mineralogy, pore size and throat distributions were elucidated. 4. The pore structure alteration mechanism was clarified using multiple techniques.

Author Contribution Statement Sihai Li: Conceptualization, Methodology, Investigation, Writing - Original Draft. Shicheng Zhang: Resources, Supervision. Xinfang Ma: Funding acquisition. Yushi Zou: Formal analysis, Project administration. Yao Ding: Methodology, Validation. Xi Zhang: Review & editing. Dane Kasperczyk: Review & editing.

Declaration of interests ☒ The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper. ☐The authors declare the following financial interests/personal relationships which may be considered as potential competing interests:

The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper.