Hydraulic fracture propagation behavior and diversion characteristic in shale formation by temporary plugging fracturing

Journal Pre-proof Hydraulic fracture propagation behavior and diversion characteristic in shale formation by temporary plugging fracturing Ruxin Zhang, Bing Hou, Peng Tan, Yeerfulati Muhadasi, Weineng Fu, Xiaomu Dong, Mian Chen PII:

S0920-4105(20)30156-X

DOI:

https://doi.org/10.1016/j.petrol.2020.107063

Reference:

PETROL 107063

To appear in:

Journal of Petroleum Science and Engineering

Received Date: 28 February 2019 Revised Date:

10 February 2020

Accepted Date: 11 February 2020

Please cite this article as: Zhang, R., Hou, B., Tan, P., Muhadasi, Y., Fu, W., Dong, X., Chen, M., Hydraulic fracture propagation behavior and diversion characteristic in shale formation by temporary plugging fracturing, Journal of Petroleum Science and Engineering (2020), doi: https://doi.org/10.1016/ j.petrol.2020.107063. 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

Hydraulic fracture propagation behavior and diversion characteristic

2

in shale formation by temporary plugging fracturing

3

Ruxin Zhanga, b, 1, Bing Houb, 1, Peng Tanc, *, Yeerfulati Muhadasib, Weineng Fub, Xiaomu

4

Donga, Mian Chenb

5

a

Texas A&M University, College Station, TX 77843, USA

）

b

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

7

(Beijing), Beijing 102249, China

8

c

CNPC Engineering Technology R&D Company Limited, Beijing 102206, China

10

*

Corresponding Author: Peng Tan

11

Corresponding Author’s Institution: CNPC Engineering Technology R&D Company Limited,

12

Beijing 102206, China

13

Corresponding Author’s E-mail: [email protected]

9

14 15

First Author: Ruxin Zhang

1）

First Author’s Institution: Harold Vance Department of Petroleum Engineering, TAMU 3116,

17

Texas A & M University, College Station, TX 77843-3116, USA; College of Petroleum

18

Engineering, China University of Petroleum (Beijing), Beijing 102249, China

19

First Author’s E-mail: [email protected], [email protected]

20 21

Co-first Author: Bing Hou

22

Co-first Author’s Institution: China University of Petroleum (Beijing), Beijing 102249, China

23

First Author’s E-mail: [email protected]

24 25 2）

1

The authors have equal contribution to this work

27

1

28

Abstract: The exploitation of shale oil and gas has become commercial in the

29

Sichuan basin, China. However, initial fracture closure will result in low production.

30

Therefore, temporary plugging fracturing technology is proposed to create new

31

fractures in alternate directions using a temporary plugging agent that blocks initial

32

fractures, which will lead to a complex fracture morphology. The mechanism of

33

temporary plugging and fracture propagation behavior remains ambiguous, even with

34

many successful operations. Hence, five shale outcrops are used to conduct large-size

35

true tri-axial temporary plugging fracturing simulation experiments to study the issues

3）

mentioned above. The effects of horizontal stress difference and temporary plugging

37

agent amount on plugging effectiveness as well as fracture propagation behavior are

38

discussed. The results reveal that the initial fractures are sealed successfully by a

39

water soluble temporary plugging agent. Two plugging positions, fracture heel and tip,

40

result in three main fracture diversion patterns: fracture diversion at the old fracture

41

heel, fracture diversion inside the old fracture, and a new fracture induced at a new

42

position. Based on the fracturing pressure curve, fracturing pressure in the second

43

fracturing is higher than that of the first fracturing, which indicates effective plugging

44

and fracture diversion. A large horizontal stress difference has prevented fracture

45

diversion, and led to a small diversion angle. However, it has improved the induced

4）

fracture propagation length. Moreover, the temporary plugging agent amount

47

determines the plugging position and fracture diversion pattern. Fracture diversion

48

inside existing fractures is a result of a small amount sealing at the fracture tip. The

49

other two patterns are created by a large amount of plugging at the fracture heel.

2

50

Therefore, in order to achieve successful plugging effectiveness, it is necessary to

51

conduct more experiments to optimize operation parameters according to the specific

52

horizontal in-stress state.

53 54

Keywords: fracture propagation behavior; temporary plugging agent; fracture

55

diversion pattern; horizontal stress difference; 3D scanning

5）

57

1 Introduction

58

In recent years, shale formations have become an important unconventional

59

resource to supplement conventional oil and gas resource in China. Because of the

）0

abundant reserves of shale gas in China, especially in the Sichuan Basin, there is a

）1

huge commercial potential in developing shale gas (Hou et al., 2018). However, it is

）2

difficult to exploit these shale formations due to their reservoir properties, such as

）3

ultra-low porosity and permeability (Wang et al., 2016). Therefore, hydraulic

）4

fracturing is proposed to activate natural fractures and bedding planes to increase the

）5

fracture complexity, which will result in a complex fracture network that can be

））

evaluated quantitatively by stimulated reservoir volume (SRV) (Warpinski et al., 2009;

）7

Cipolla et al., 2009; Tan et al., 2019; Mao et al., 2019). Thus, drainage areas and

）8

channels are increased and the effective permeability of the formation is maximized,

）9

the oil and gas recovery is ultimately improved (Chen et al., 2018; Chen et al., 2019).

70

However, reservoir depletion due to exploitation and pre-existing fracture closure due

3

71

to in-situ stress effect results in a low production from most old wells. Hence, these

72

wells require re-fracturing to reopen primary induced fractures or create new fractures,

73

which will lead to more drainage channels with higher oil and gas production.

74

Conventional re-fracturing operations inject fracturing fluid into old wells to start

75

the second fracturing, resulting in some new fractures (Wright and Conant, 1995;

7）

Siebrits et al., 1998; Aghighi et al., 2009). This is a result of the change in in-situ

77

stress near the wellbore after initial hydraulic fracturing (Warpinsk and Branagan,

78

1989). The in-situ stress decreases faster in the direction parallel to the fracture

79

direction than perpendicular to the fracture direction during exploitation (Elbel and

80

Mack, 1993). Moreover, induced stress is created near the initial fracture by the initial

81

fracturing itself and subsequent production, which will result in a relationship of size

82

between vertical and minimum horizontal stress change (Wright, 1994). Hence, the

83

second induced fracture will be at an angle to the first induced fracture. Siebrits et al.

84

(2000) confirmed that the re-fractures were perpendicular to the initial cracks based

85

on re-fracturing field tests on two old tight gas wells. Although most researchers

8）

investigate the changes of in-situ stress distribution after initial hydraulic fracturing in

87

order to create new fractures during the second fracturing process, conventional

88

re-fracturing operations in unconventional formations always encounter failure in

89

creating new fractures (Eshkalak et al., 2014; Li et al., 2019). The leakage of

90

fracturing fluid to the initial fractures or natural fractures will reduce the energy

91

needed to create new fractures. In some of the conditions, it is difficult for the initial

92

fracture to divert due to poor stress differences (Wang et al., 2015b).

4

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Therefore, in order to create new fractures in old wells, temporary plugging

94

agents are used as an artificial barrier to seal the initial fractures. The artificial barrier

95

prevents fracturing fluids from flowing into the initial fractures, which will result in

9）

enough energy to generate new fractures during the second hydraulic fracturing

97

operation. This stimulation method is called temporary plugging fracturing. The

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mechanisms of this technology in three different scenarios were summarized by Wang

99

et al. (2015a) who has concluded that net pressure was the key factor to determine

100

plugging effectiveness. In the condition of single pre-existent fracture, the plugging

101

agent results in less fluid lost and higher fracture roughness, which will increase the

102

net pressure to induce new fractures; in the condition of multiple pre-existent fractures,

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the plugging agent reduced fluid energy competition among each pre-existent fracture

104

to increase the net pressure; in a heterogenous formation, the main impacting factors

105

are not only the net pressure, but also the in-situ stress and the stress shadow among

10）

pre-existent fractures. Hill and Galloway (1984) established a theoretical model to

107

determine the mechanisms of fracture diverting due to a low-permeability filter cake

108

formed by diverting agent. Many researchers attempted to find effective plugging

109

agents. In addition, Mcleod (1984) recommended different types of agents, such as

110

oil-soluble resin, rock salt, and wax beads, should have different concentrations to

111

achieve their function. Wang et al. (2005) investigated diverting fracturing technology

112

by pumping larger-size proppant or soluble wax balls into the low porosity and

113

permeability formations. Fine pottery clays and oil-soluble resins were found to

114

damage the permeability of the formation. Zhou et al. (2009) declared that degradable

5

115

material should be used because of high plugging strength, automatic and complete

11）

degradation, and negligible damage to the formation. Allison et al. (2011) proposed

117

deformable particles of different sizes to block the initial fractures. Wang et al. (2015a)

118

developed a degradable fiber as the temporary plugging material to seal initial

119

fractures and force fracture diversion. Although the above studies provide various

120

types of temporary plugging materials, many factors determine their temporary

121

plugging effectiveness. Potapenko et al. (2009) optimized the size of proppant and

122

transport velocity to increase the plugging capability of diverting agents. Wang et al.

123

(2015a) proved that the pumping rate, initial fracture width, and bottom hole pressure

124

have an impact on plugging efficiency. Rutqvist et al. (2015) claimed that an

125

increasing net pressure indicates fracture diversion. McCartney and Kennedy (2016)

12）

conducted experiments to study the effect of carrier fluid type and carrier fluid

127

viscosity on fracture diversion results. Wang et al. (2018) demonstrated that the

128

increase of stress difference reduces the effectiveness of temporary plugging. In

129

addition, the initial fracture morphology is a very important factor to determine the

130

effectiveness of temporary plugging fracturing in a shale formation. In an initial single

131

fracture condition, the temporary plugging agent could form a tight cake sealing the

132

initial fracture. However, the temporary plugging agent selectively blocks some initial

133

fractures with different pressures (Wang et al., 2015a). The former is conducive to

134

temporary plugging effectiveness, whereas, the latter increases the risk of temporary

135

plugging failure. In addition, the propagation behavior of new fractures induced via

13）

the second fracturing is affected by nearby initial fractures under complex initial

6

137

fractures conditions. This interaction between initial fractures and newly induced

138

fractures was recently investigated by Wang et al. (2019). Although numerous studies

139

have focused on properties and field applications of temporary plugging materials,

140

few examined the mechanism and the pattern of temporary plugging. Limited

141

experiments were conducted to investigate the mechanism of temporary plugging

142

fracturing in a sandstone formation (Wang et al., 2015a). The few works on shale

143

formations result in an ambiguous understanding on fracture propagation behavior

144

with temporary plugging fracturing.

145

Large-scale true tri-axial hydraulic fracturing simulation experiments could

14）

observe fracture initiation and propagation effectively. Thus, in this study, five

147

experiments were conducted on shale outcrops using an improved experimental

148

apparatus to study the plugging effectiveness of a water soluble temporary plugging

149

agent. The mechanism of temporary plugging fracturing is also investigated. In

150

addition, the effects of horizontal stress difference and temporary plugging agent

151

amount on fracture propagation behavior are discussed. The research puts insight into

152

induced fracture propagation behavior of temporary plugging fracturing in shale

153

formations, and also provides guidance on operation parameters optimization of

154

temporary plugging fracturing.

155

2 Experimental Process and Scheme

15）

2.1 Experimental apparatus

157

A hydraulic sand fracturing physical modelling experimental apparatus was 7

158

designed to conduct the temporary plugging fracturing experiments, as shown in Figs.

159

1-a, b, and c. The experimental equipment is composed of five parts: a true tri-axial

1）0

testing stand, a confining pressure loading system, a servo control system, a data

1）1

acquisition and control system, and an acoustic emission monitoring system. The

1）2

detailed description of this apparatus can be found in Tan et al. (2020).

1）3

The 3D scanner includes three different scanning patterns: fine scanning in hand,

1）4

fast scanning in hand, and fixed full automatic scanning. The scanning precision is 0.1

1）5

mm, 0.3mm, and 0.05mm, respectively. The scanning speed is 15 frames/second, 10

1））

frames/second, and less than 2 seconds, respectively. Moreover, the space dot spacing

1）7

is from 0.2 mm to 2 mm, from 0.5 mm to 2 mm, and 0.16 mm, respectively.

1）8

8

1）9 170

Fig. 1. The experimental apparatus. a. the external structure of true tri-axial frame; b. the internal structure

171

of true tri-axial frame; c. servo control system.

172

2.2 Experimental preparation

173

2.2.1 Sample preparation

174

The shale outcrop samples collected from the Longmaxi Formation in Wulong,

175

Chongqing province in the Sichuan basin, southeastern China were cut into 300 mm ×

17）

300 mm × 300 mm cubes by wire cutting technology without using water, as shown in

177

Fig. 2. In order to simulate the horizontal well, a hole with radius of 10 mm and depth

178

of 180 mm was drilled along the direction of bedding planes in the center of the cubes.

179

60mm was for open-hole section stimulated by foam filler, and the remaining 120 mm

180

was to represent the horizontal wellbore. The wellbore design was presented in Hou et

9

181

al. (2018). Finally, the wellbore was cemented inside the borehole by high-strength

182

epoxy glue. The process of sample preparation is illustrated in Fig. 3.

183 184

Fig. 2. Schematic of shale outcrops collection process: a. field photograph of Longmaxi Formation in

185

Wulong, Chongqing; b. cutting shale outcrop by wire cutting technology; c. the shipment of shale outcrop.

10

18） 187

Fig. 3. Schematic of sample preparation process: a. experimental materials; b. wellbore and shale outcrop

188

bonded by epoxy glue; c. internal structure of samples; and d. developed bedding planes in surface of shale

189

outcrop.

190

Under the confining pressure of 20 MPa and temperature of 122 °C, the average

191

tri-axial mechanical parameters of these shale outcrops were measured as follows:

192

compressive strength, 284.19 MPa; tensile strength, 11.81 MPa; elastic modulus,

193

38.84 GPa; and Poisson’s ratio, 0.16. In addition, the mineralogical composition was

194

analyzed using X-ray diffraction with the average quartz, clay contents, and carbonate

11

195

of 70%, 20%, and 10%, respectively.

19）

2.2.2 Discontinuities description

197

Discontinuities, such as bedding planes and natural fractures, can affect

198

hydraulic fracture initiation and propagation in shale formations (Daneshy, 1974;

199

Beugelsdijk et al., 2000; Olson et al., 2012; Zhang et al., 2019). Therefore, the

200

development of discontinuities (generally expressed by density and distribution) needs

201

to be described clearly at the beginning of the experiment. In order to describe that in

202

the shale samples, the surfaces of each sample were defined as follows, the upper and

203

lower surfaces named P1 and P6, the front and back surfaces named P3 and P4, and

204

the right and left surfaces named P2 and P5, respectively. Taking sample #1 as an

205

example, two obvious bedding planes and one well-developed natural fracture are

20）

shown in Figs. 4-a and b. The observed discontinuities in each shale outcrop are

207

depicted in Fig. 4. However, these are only the discontinuities that are easy to observe

208

but not all the discontinuities present. There are other natural fractures and bedding

209

planes that are not well-developed or inside samples, which will result in invisibility

210

before experiments. Hence, we cannot be sure of the positions of all the

211

discontinuities within the samples leading to the absence of description in Fig. 4.

12

212

213

214

13

215

21） 217

Fig. 4. Schematic of discontinuities in each shale sample. (Natural fractures are marked by red lines, and

218

bedding planes are marked by yellow lines. Discontinuities on fracture surfaces P1, P2, and P3 are marked

219

by solid lines, however, that on fracture surfaces P4, P5, and P6 are marked by dashed lines).

220

2.3 Experimental scheme

221

Longmaxi Formation shale is buried at the depth from 4073.92 to 4080.38 m and

222

is in a strike-fault stress regime: the maximum horizontal stress is from 107.94 to

223

109.12 MPa, the vertical stress is from 102.74 to 103.4 MPa, and the minimum

224

horizontal stress is from 92.32 to 94.42 MPa (Jiang et al., 2017; Zhang et al., 2019).

225

Hence, five experiments are carried out in a similar stress regime with a pump rate of 14

22）

20 mL/min based on the similarity criterion (Clifton and Abou-Sayed., 1979), as

227

shown in Tab. 1. Slick water, viscosity of 5 mPa·s and pH of 6 - 9, is used as the

228

fracturing fluid, as shown in Fig. 5-a. A water soluble temporary plugging agent,

229

diameter of 20 - 100 Mesh, is used in our experiments, as shown in Fig. 5-b. Tests #1,

230

#2, #3, and #5 were conducted to study the effects of the horizontal stress difference

231

on temporary plugging fracturing. Test #4 was used to study the influence of the

232

amount of temporary plugging agent.

233

15

234

Fig. 5. a. low viscosity slick-water (3 mPa·s); b. black temporary plugging agent (20-100 Mesh); c. 500 mL

235

fracturing fluid (480 mL water and 20 mL slick-water) with 50 g black temporary plugging agents; and d.

23）

500 mL fracturing fluid (480 mL water and 20 mL slick-water) with 3 g green fluorescent tracers.

237

Table 1. Summary of experimental parameters

First fracture In-situ stress Pump rate
 /
 /


Test

Second fracture

Temporary plugging

Diversion Diversion

Fracturing

Fracturing agent amount

(mL/min) (MPa)

SRAtotal pressure

SRA1

pressure

angle pattern

SRA2

(g)

(°) (MPa)

(MPa)

1

13/14/12

20

50

21.45

0.25

28.32

0.5

0.75

160

I

2

13/17/12

20

50

33.27

0.5

63.55

0.5

1

180

I

3

15/20/12

20

50

32.52

0.5

34.75

0.5

1

120

I

4

15/17/12

20

25

28.29

0.25

31.65

0.25

0.5

140

II

5

20/24/12

20

50

28.57

0.75

32.75

0.75

1.5

-

III

238

P.S. SRAtotal = SRA1 + SRA2

239

2.4 Experimental procedure

240

1)

Equipment assembly process

241

Shale sample was placed inside the true tri-axial test frame and surrounded by

242

flat jacks, as illustrated in Figs. 1-a and b. Then, the cylinder and top lid

243

assembly was completed.

244 245

2)

Tri-axial stresses loading process In order to simulate horizontal well fracturing in the shale formation, the tri-axial 16

24）

stress loading direction on samples is displayed in Fig. 3-c. The maximum

247

horizontal stress was parallel to the bedding plane direction, whereas, the

248

minimum horizontal stress was loaded along the wellbore direction. In addition,

249

three stresses were loaded at the same time up to the minimum horizontal stress

250

value and the maximum horizontal and vertical stresses were gradually increased

251

to the vertical stress value. Finally, the maximum horizontal stress was slowly

252

loaded to the designed value. This 3D stress loading order would avoid

253

unbalanced loading. It was necessary to hold an approximately 15 to 30 min

254

delay to establish the stress equilibrium before the fracturing test when the

255

stresses reached the set values (Kim and Abass., 1991).

25）

3)

The first fracturing process with fracturing fluid injection

257

After tri-axial stress loading was completed, fracturing fluid and slick water with

258

green fluorescent tracers were injected at the pump rate of 20 mL/min along the

259

wellbore into the sample to start the first fracturing. When the sample was

2）0

broken, the pump was stopped and fracturing fluid was changed to prepare for

2）1

the second fracturing.

2）2

4)

The second fracturing process with temporary plugging agent injection

2）3

In order to start the second fracturing, new fracturing fluid and slick water with

2）4

temporary plugging agent but no fluorescent tracers were injected into the

2）5

sample at the same pump rate of 20 mL/min. Injection was continued until

2））

treatment pressure dropped to a stable value.

2）7

5)

Observation and record process

17

2）8

After each test, the sample was split along induced fractures by hammer and

2）9

chisel to observe and record experimental results. In addition, a 3D scanner was

270

used to describe fracture morphology by scanning the induced fracture surface.

271

3 Experimental Results

272

The results of five experiments revealed that temporary plugging agents

273

successfully plugged the first fractures and facilitated the second fractures to be

274

created, as shown in Figs. 6 – 10. The figures on the left are experimental result

275

pictures, and those on the right figures are 3D scanning images. Based on the

27）

distribution of fracturing fluid and the color of fracture surface, fracture propagation

277

path and final fracture morphology can be inferred. Green fracture surfaces indicate

278

that they are induced in the first fracturing, whereas black bright fracture surfaces

279

suggest that they are created in the second fracturing. In addition, “Stimulated Rock

280

Area (SRA)” is proposed as an evaluation index to quantitative investigate fracture

281

morphology (Hou et al., 2014). The SRA is defined as a sum of induced main fracture

282

area, activated bedding plane area, and activated natural plane area. Each induced

283

fracture plane area was divided into four grades with the value of 1.00 (about 300 mm

284

× 300 mm), 0.75, 0.50 and 0.25 according to the tracer distribution. It can be found

285

that greater SRA value will lead to greater fracturing effectiveness. More detailed

28）

experimental results and analysis are summarized in Tab. 1 and discussed as follow.

18

287

3.1 Fracture initiation and propagation

288

In sample #1, with a horizontal stress difference of 2 MPa and 50 g temporary

289

plugging agent, the first fracture initiates from the open-hole section and then

290

propagates along the direction of the maximum horizontal stress, forming a

291

longitudinal single wing fracture with the SRA1 of 0.25 in the first fracturing process,

292

as shown in Fig. 6-a. When the temporary plugging agents were injected into the

293

sample in the second fracturing process, the first fracture was plug successfully. The

294

second fracture initiates from the open-hole section, but propagates along two

295

opposite directions with the SRA2 of 0.5: one is the direction of a weak plane

29）

resulting in a single wing fracture, and the other is below the direction of the first

297

fracture. The whole fracture morphology is displayed by 3D scanning technology, as

298

shown in Fig. 6-b. This indicates that an angle of 160° exists between the first fracture

299

and second fracture, that is, the diversion angle of the fracture is 160°.

300

In sample #2 with a horizontal stress difference of 5 MPa and 50 g temporary

301

plugging agent induced two fractures. The first and second fracture are longitudinal

302

single wing fractures with the SRA1 of 0.5 and the SRA2 of 0.5, respectively.

303

However, the two different fractures propagate with a diversion angle of 180°, as

304

shown in Fig. 7.

305

The fracture morphologies in the above two experiments are inconsistent with

30）

the common point that the induced fracture should initiate perpendicular to the

307

direction of the minimum stress, and propagate along the direction of the maximum

308

horizontal stress, and form a transverse fracture in the horizontal well under a 19

309

strike-faulting stress regime (Hou et al., 2018). This unusual phenomenon can be

310

explained by two reasons. Firstly, the value of the vertical stress (13 MPa) was close

311

to that of the minimum horizontal stress (12 MPa), which resulted in fracture

312

initiation direction that could be perpendicular to the direction of the minimum

313

horizontal stress or the vertical stress. The former is a transverse fracture, whereas, the

314

latter is a longitudinal fracture. Secondly, invisible natural fractures that existed inside

315

the sample had an impact on fracture initiation, leading to induced fracture

31）

propagation along the direction of the natural fracture instead of the direction of the

317

maximum horizontal stress.

318

Therefore, the vertical stress was increased to 15 MPa in sample #3 to avoid a

319

similar minimum horizontal stress value. In sample #3 with a horizontal stress

320

difference of 8 MPa and 50 g temporary plugging agent, the first fracture initiates

321

from the open-hole section but propagates along the natural fracture direction, which

322

results in the SRA1 of 0.5 in the first fracturing process. After temporary plugging

323

agents were injected during the second fracturing process, the second fracture initiates

324

and propagates perpendicular to the direction of the minimum horizontal stress,

325

forming a transverse fracture with the SRA2 of 0.5 in the opposite side, as shown in

32）

Fig. 8. The diversion angle between the first fracture and the second fracture is 120°.

327

In sample #4 with a horizontal stress difference of 5 MPa and 25 g temporary

328

plugging agent, the first fracture initiates inside the natural fracture and propagates

329

along its direction, which led to the SRA1 of 0.25 during the first fracturing process.

330

The temporary plugging agents plugged the first fracture and promoted the second

20

331

fracture to divert from the direction of the first fracture with an angle of 140°. The

332

second fracture propagates along the new direction, but does not extend to the edge of

333

the sample, which results in a transverse fracture with the SRA2 of 0.25. The whole

334

induced fracture morphology was shown in Fig. 9.

335

In sample #5, the value of vertical stress was increased to 20 MPa and the value

33）

of horizontal stress difference was increased to 12 MPa, in order to avoid the

337

influence of natural fractures. 50 g temporary plugging agent was used. In the first

338

fracturing process, the first fracture initiates from the top of open-hole section. One

339

part of it propagates along the direction of the maximum horizontal stress forming a

340

transverse fracture, but the other part of it diverts in the direction of nearby natural

341

fracture and extends to the edge of sample. Finally, the first fracture resulted in an

342

induced fracture with the SRA1 of 0.75. However, the second fracture initiates from

343

the bottom of open-hole section and propagates perpendicularly to the wellbore,

344

forming a transverse fracture with the SRA2 of 0.75. The two transverse fractures

345

were shown in Fig. 10.

34）

21

347 348

Fig. 6. Fracture morphology with 50 g temporary plugging agent under horizontal stress difference of 2

349

MPa in sample #1 (White dashed lines represent first fracture, and yellow dashed lines represent second

350

fracture). a. the result with wellbore recorded right away after sample opening; b. 3D scanning figure of

351

induced fractures; c. the result without wellbore recorded right away after sample opening; d. the result

352

recorded without wellbore at a long time after sample opening.

353

22

354 355

Fig. 7. Fracture morphology with 50 g temporary plugging agent under horizontal stress difference of 5

35）

MPa in sample #2 (White dashed lines represent first fracture, and yellow dashed lines represent second

357

fracture). a. the result recorded right away after sample opening; b. 3D scanning figure of induced fractures;

358

c. the result of left part recorded right away after sample opening; d. the result of right part recorded right

359

away after sample opening.

3）0

23

3）1 3）2

Fig. 8. Fracture morphology with 50 g temporary plugging agent under horizontal stress difference of 8

3）3

MPa in sample #3 (White dashed lines represent first fracture, and yellow dashed lines represent second

3）4

fracture). a. the result recorded right away after sample opening; b. 3D scanning figure of induced fractures;

3）5

c. the result of left part recorded right away after sample opening; d. the result of right part recorded at a

3））

long time after sample opening.

3）7 3）8

24

3）9 370

Fig. 9. Fracture morphology with 25 g temporary plugging agent under horizontal stress difference of 5

371

MPa in sample #4 (White dashed lines represent first fracture, and yellow dashed lines represent second

372

fracture). a. the result recorded right away after sample opening; b. 3D scanning figure of induced fractures;

373

c. the result recorded at 10 min after sample opening; d. the result recorded without wellbore at 20 min after

374

sample opening.

375

25

37） 377

Fig. 10. Fracture morphology with 50 g temporary plugging agent under horizontal stress difference of 12

378

MPa in sample #5 (White dashed lines represent first fracture, and yellow dashed lines represent second

379

fracture). a. the induced fractures distribution of sample #5; b. 3D scanning figure of induced fractures; c.

380

the first fracture morphology recorded right away after sample opening; d. the second fracture morphology

381

recorded right away after sample opening.

382

3.2 Fracturing pressure curve

383

The fracturing pressure is important in the fracturing operation because of, firstly,

384

it records operational process and pressure change, and secondly, it reflects the

385

existence of the effects of temporary plugging agents. Based on Fig. 11, the whole

38）

fracturing process of sample #1 could be displayed: the first fracturing process took

387

place from 0 to 1800 s, and the second fracturing process was from 2518 to 3557 s.

388

The interval between 1800 and 2518 s indicates the pump is off to change the

389

fracturing fluid.

390

The peak point in the curve represents the fracturing pressure (Zhang et al.,

26

391

2018). However, there are too many peak points in the curve of sample #1 to

392

determine which is the real break point. Therefore, an acoustic emission monitoring

393

system was used to assist us in determining the fracturing pressure in the curve. Two

394

areas of the AE event count concentrations revealed that two fractures were induced at

395

that time based on Fig. 11. In addition, the time of the maximum AE event count was

39）

supposed to be the fracture broken point based on the Time–Pressure–AE event curve

397

(Hou et al., 2018). Hence, the fracturing pressures of the first fracture and the second

398

fracture are 21.45 MPa and 28.32 MPa, respectively. Moreover, the latter pressure was

399

higher than the former one which indicates that the temporary plugging agents

400

exhibited plugging effectiveness. This phenomenon was inconsistent with the

401

conclusion of Wang et al. (2015a). They claimed that plugging old fractures required

402

higher treatment pressure in order to create new fractures. The other high AE event

403

counts were a result of the fracturing fluid flowing along the uneven induced fracture

404

surfaces.

405

The other samples have the similar treatment pressure changing trend in the

40）

fracturing curve as that of sample #1 because of the same fracturing processes.

407

Fracturing pressure of each sample was summarized in Tab. 1. The fracturing pressure

408

of the second fracture was higher than that of the first fracture in all samples, which

409

proved the effectiveness of temporary plugging agents.

27

410 411

Fig. 11. Fracturing pressure curve of samples #1.

412

4 Discussion

413

4.1 Pattern of fracture diversion

414

The temporary plugging agents have plugging effectiveness in all five samples.

415

However, the plugging position in each sample is different, at the heel or tip of

41）

pre-existing fractures, due to the effect of different horizontal stresses and temporary

417

plugging agent amounts. Based on the experimental results, three main patterns of

418

fracture diversion are identified and summarized as shown in Fig. 12.

419




Pattern I – Diversion at induced fracture heel. Temporary plugging agents are

420

congested in the first fracture heel, which results in the second fracture initiating

421

from the heel of the first fracture and diverting into a different direction.

422




Pattern II – Diversion inside the induced fracture. Temporary plugging agents are 28

423

congested in the first fracture tip, which results in the second fracture initiating

424

from the interior of the first fracture and diverting into a different direction .

425




Pattern III – Diversion at other positions. Temporary plugging agents are

42）

congested in the first fracture heel, which results in the second fracture initiating

427

from other positions.

428 429

Fig. 12. Three main temporary plugging patterns resulting in three different fracture morphologies (Red

430

areas represent first fracture, yellow areas represent second fracture, and black circles represent temporary

431

plugging agents).

432

4.2 Influence of horizontal stress difference

433

The horizontal stress difference is defined as the difference between the

434

maximum horizontal stress and the minimum horizontal stress (∆
 
 
 ). In

435

order to study the effect of horizontal stress difference on the result of temporary

43）

plugging fracturing, the samples #1, #2, #3, and #5 were conducted under different

437

horizontal stress differences of 2 MPa, 5 MPa, 8 MPa, and 12 MPa, respectively.

438

The experimental results indicate that the temporary plugging agents worked

29

439

successfully under a small or a large horizontal stress difference. However, a large

440

horizontal stress difference prevented fracture propagation behavior from being

441

influenced by natural fractures and promoted induced fractures to propagate greater

442

distance (Olsen et al., 2012; Hou et al., 2018; Zhang et al., 2019). In the end, a large

443

SRAtotal (SRA1 + SRA2) was created, such as samples #1, #2, #3, and #5. The

444

diversion angle decreased as horizontal stress difference increased, such as in samples

445

#1 and #3. This phenomenon revealed that a large horizontal stress difference

44）

controlled the direction and path of induced fracture propagation. Wang et al. (2015a)

447

declared that a large diversion radius was created by a small horizontal principal stress

448

difference. Hence, it is difficult for a fracture to divert into new direction under a large

449

horizontal stress difference.

450

The fracturing pressure changing trend in our experiment did not follow the

451

common cognition: that is the smaller fracturing pressure, the larger horizontal stress

452

difference is (Guo et al., 2014). The formula created by Haimson and Fairhurst (1967)

453

has also proved that:

454 455

P 

     ()/( ∙ ()/(

(1)

45） 457

In which, σ and σ are the minimum and maximum horizontal stresses,

458

respectively; σ is the tensile strength of the shale outcrops; P is the pore pressure;

459

α is Biot’s constant; and v is Poisson’s ratio.

4）0

This unusual result could be a result of the influence of natural fractures or 30

4）1

bedding planes. If the induced fractures initiate from the interior of these

4）2

discontinuities, the fracturing pressure will be small, because the well-developed

4）3

discontinuities have a weak cement strength that promotes fractures that are easily

4）4

initiated. It is uncertain whether the discontinuities had an impact on the samples #1

4）5

and #2, because the value of vertical stress was very close to that of the minimum

4））

horizontal stress. However, the fracture morphologies of samples #3 and #4 implies

4）7

that the discontinuities affect fracture initiation and propagation. Therefore, it was

4）8

hard to observe the trend of fracturing pressure under different horizontal stress

4）9

differences in our experiments.

470

4.3 Influence of temporary plugging agent amount

471

The temporary plugging agent amount determines the fracture diversion position.

472

Samples #1, #2, #3, and #5 and sample #4 utilized different amount of temporary

473

plugging agent 50 g and 25 g, respectively.

474

The experimental results demonstrat that a large amount of temporary plugging

475

agent will accumulate at the fracture heel, which will result in fracture diversion at the

47）

fracture heel, such as patterns I (samples #1, #2, and #3) and III (sample #5). However,

477

a small amount of temporary plugging agent migrate along the interior of induced

478

fracture and accumulate at the fracture tip, leading to a fracture diverting to the

479

interior, as such as patterns II (sample #4).

480

Patterns I and III could increase single well production, because the temporary

481

plugging agent became an artificial barrier bed that prevented fracturing fluid from

31

482

flowing along the first fracture. Thus, more fracturing fluid energy could be used to

483

create new fractures with a long propagation distance and more drainage paths were

484

created, which resulted in more hydrocarbons flowing into the well. However, the

485

artificial barrier bed in pattern II sealed the fracture tip, which increase the difficulty

48）

of the first fracture propagation. Lots of fracturing fluid energy was lost when fluid

487

flowed along the first fracture. Therefore, little fluid energy was applied to generate

488

new fractures. Even if it was induced, the propagation distance was short which

489

resulted in a small SRA as in sample #4.

490

4.4 Limitation and Future work

491

Although the temporary plugging agent worked successfully in the five

492

experiments and the fracture propagation behavior was observed in temporary

493

plugging fracturing, the limitations still exists due to the experimental apparatus and

494

sample size. Because of the limitation in the diameter of the injection pipeline and

495

wellbore and first fracture width, the diameter of the temporary plugging agent should

49）

be as small as possible. Hence, in order to inject the temporary plugging agents into

497

the interior of induced fracture, a water-soluble temporary plugging agent was chosen

498

in all five experiments. However, such temporary plugging agents have limitations.

499

After a long interaction between temporary plugging agent and slick water, the slick

500

water with solid temporary plugging agent became a high viscosity fluid. The

501

temporary plugging agent lost the ability to plug the first fracture, which resulted in

502

some problems, such as no creation of new fractures , no fracture diversion, and short

32

503

new fracture length. Thus, the soluble velocity and amount of temporary plugging

504

agent requires more research to obtain the optimized value, in order to seal the

505

induced fracture successfully in the second fracturing process.

50）

The effects of horizontal stress difference and temporary plugging agent amount

507

on fracture propagation behavior in temporary plugging fracturing were discussed.

508

However, the influencing factors are more than these two. Pump rate and fracturing

509

fluid viscosity could also have great impacts on the migration distance of the

510

temporary plugging agent, which will affect the fracture diversion pattern. For

511

example, a large pump rate or a high fluid viscosity improves the temporary plugging

512

agent ability which leads to a longer migration inside the first fracture. The temporary

513

plugging agent might accumulate at the first fracture tip, resulting in pattern II.

514

Nevertheless, a low pump rate or a low fluid viscosity results in the temporary

515

plugging agent accumulating at the first fracture heel, such as in patterns I and III.

51）

Therefore, the influence of pump rate and fracturing fluid viscosity should be studied

517

further.

518

Furthermore, the pre-existing fracture morphology affects the plugging

519

effectiveness. It is easy for the temporary plugging agent to block the pre-existing

520

fractures independent of the kind of pattern of fracture diversion, because the

521

pre-existing fracture morphology is simple in the five experiments. However, it is

522

difficult for us to determine the effectiveness of the temporary plugging agent in a

523

complex pre-existing fracture condition. Multiple pre-existing fractures provide many

524

options for the temporary plugging agent to select, leading to randomly blocking some

33

525

of pre-existing fractures. This relationship decreases the temporary plugging agent

52）

amount in some pre-existing fractures, resulting in failed plugging effectiveness. It is

527

a pity that these experiments failed to observe the effects of differences between

528

simple and complex fractures on the plugging effectiveness, because it is difficult to

529

know and control the morphology of the first induced fracture that was created by the

530

first fracturing operation. As a result, more experimental work is needed to study

531

plugging effectiveness in complex pre-existing fracture morphology condition.

532

5 Conclusion

533

This paper studied the fracture propagation behavior during temporary plugging

534

fracturing based on the laboratory experiments conducted on shale outcrop samples.

535

In addition, the effect of horizontal stress contrast and temporary plugging agent

53）

amount on the experimental results was discussed. The main conclusions are

537

summarized as the following:

538

1)

The temporary plugging agent effectively plugs up induced fractures at two

539

different positions, which are its heel or tip, and results in three main fracture

540

diversion patterns: fracture diversion at the old fracture heel, fracture diversion

541

with an old fracture, and a new fracture induced at a new position.

542

2)

A large horizontal stress difference controls fracture propagation path and

543

prevents it from diversion, which leads to a small diversion angle. However, it

544

improves the ability of induced fracture to propagate long distance, resulting in a

545

large SRA.

34

54）

3)

The temporary plugging agent amount determines the plugging position and

547

fracture diversion pattern. Fracture diversion at the inside of old fracture is a

548

result of the small amount plugging up the fracture tip. The other two patterns are

549

created by a large amount plugging up the fracture heel.

550

Acknowledgments

551

The authors are grateful for the Project Support of National Natural Science

552

Foundation of China (No. 51874328 and No. U1762215), PetroChina Innovation

553

Foundation (No. 2018D-5007-0307), and the Mechanism Study on Deflection

554

Fracturing in Shale Gas Wells (No. 20180302-09).

555

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55） 557 558 559 5）0 5）1 5）2 5）3 5）4 5）5 5）） 5）7 5）8 5）9 570 571 572 573 574 575 57）

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38

Highlights 1. Fracture propagation behavior in temporary plugging and diverting fracturing. 2. Fracture diversion patterns and plugging position are summarized. 3. The effects of horizontal stress difference on temporary plugging are discussed. 4. The pressure response to plugging effect in fracturing curve are summarized.

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Hydraulic fracture propagation behavior and diversion characteristic in shale formation by temporary plugging fracturing

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1

Declaration of interest 1. Conflict of Interest Potential conflict of interest exists: We wish to draw the attention of the Editor to the following facts, which may be considered as potential conflicts of interest, and to significant financial contributions to this work: The nature of potential conflict of interest is described below:

✔No conflict of interest exists. We wish to confirm that there are no known conflicts of interest associated with this publication and there has been no significant financial support for this work that could have influenced its outcome.

2. Funding ✔Funding was received for this work. All of the sources of funding for the work described in this publication are acknowledged below: [List funding sources and their role in study design, data analysis, and result interpretation]

1. National Natural Science Foundation of China (No. 51874328 and No. U1762215) 2. PetroChina Innovation Foundation (No. 2018D-5007-0307) 3. The Mechanism Study on Deflection Fracturing in Shale Gas Wells (No. 2018030209).

The first two funding are used for collecting the outcrop sample and conducting rock mechanics testing; The third one is used to conducted temporary plugging and diverting fracturing

2 experiment. No funding was received for this work.

3. Intellectual Property ✔We confirm that we have given due consideration to the protection of intellectual property associated with this work and that there are no impediments to publication, including the timing of publication, with respect to intellectual property. In so doing we confirm that we have followed the regulations of our institutions concerning intellectual property.

4. Authorship All authors should meet all four criteria for authorship 1. Substantial contributions to the conception or design of the work; or the acquisition, analysis, or interpretation of data for the work; AND 2. Drafting the work or revising it critically for important intellectual content; AND 3. Final approval of the version to be published; AND 4. Agreement to be accountable for all aspects of the work in ensuring that questions related to the accuracy or integrity of any part of the work are appropriately investigated and resolved. ✔We confirm that the manuscript has been read and approved by all named authors. ✔We confirm that the order of authors listed in the manuscript has been approved by all named authors.