A pilot investigation of pyrolysis from oil and gas extraction from oil shale by in-situ superheated steam injection

Journal Pre-proof A pilot investigation of pyrolysis from oil and gas extraction from oil shale by in-situ superheated steam injection Zhiqin Kang, Yangsheng Zhao, Dong Yang, Lijun Tian, Xiang Li PII:

S0920-4105(19)31203-3

DOI:

https://doi.org/10.1016/j.petrol.2019.106785

Reference:

PETROL 106785

To appear in:

Journal of Petroleum Science and Engineering

Received Date: 1 July 2019 Revised Date:

3 December 2019

Accepted Date: 4 December 2019

Please cite this article as: Kang, Z., Zhao, Y., Yang, D., Tian, L., Li, X., A pilot investigation of pyrolysis from oil and gas extraction from oil shale by in-situ superheated steam injection, Journal of Petroleum Science and Engineering (2020), doi: https://doi.org/10.1016/j.petrol.2019.106785. 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. © 2019 Published by Elsevier B.V.

1

A pilot investigation of pyrolysis from oil and gas

2

extraction from oil shale by in-situ superheated steam

3

injection

4

Zhiqin Kanga,c,*, Yangsheng Zhaoa,b,c,1, Dong Yanga,c, Lijun Tiand, Xiang Lia,c

5

a

6

Technology, Taiyuan 030024, China

7

b

8

c

9

Exploitation, Taiyuan 030024, China

Key Laboratory of In-situ Property-improving Mining of Ministry of Education, Taiyuan University of

Mining Technology Institute, Taiyuan University of Technology, Taiyuan 030024, China The In-situ Steam Injection Branch of State Center for Research and Development of Oil Shale

10

d

11

*Corresponding author. E-mail address: [email protected] (Z. Kang).

12

1

13

Abstract: Oil shale is a critical strategic energy with huge reserve. The research and

14

development of an economically feasible in-situ retorting technology for oil and gas

15

extraction from oil shale is of great significance. Thus, this paper experimentally studied the

16

large oil-shale samples pyrolysis by in-situ superheated steam injection (MTI) implemented

17

from 2014 to 2016. The structure of the large-scale in-situ pyrolysis test system, the

18

experimental procedure, and the results are presented here. The steam fracturing-connection

19

was used during the initial stage, and the pressure of the superheated steam for fracturing was

20

~2 times higher than the strata stress. The variation of temperature and pressure during

21

pyrolysis was controlled by the variation in steam seepage. The operating steam pressure

22

during pyrolysis was lower than 1/4 of the strata stress. The energy utilization of the

23

superheated steam for the pyrolysis reaction was 42.7%. The average temperature of the fluid

Datong Coal Mine Group, Datong 03700, China.

Prof. Zhao organized this research work and instruct other co-authors on their experimental design.

1

24

that was discharged from the production wells was around 170°C, which can be recycled to

25

achieve a heat-utilization coefficient of 13.19% in commercial operations. The oil-recovery

26

rate in the pyrolysis area exceeded 95%, and the overall oil-recovery rate reached up to 70.7%

27

of the tested large oil-shale samples. The gas production rate and the effective energy rate of

28

the injected steam are correlated with an exponential function. Our pilot tests indicate that the

29

in-situ retorting technology of oil shale by MTI shows great potential for commercial

30

operation in oil-shale formation.

31

Key Words: oil shale; in-situ pyrolysis; superheated steam injection; experimental

32

investigation; oil-recovery rate

33 34

1. Introduction

35

Petroleum is acknowledged as the most important energy source, chemical raw material, and

36

strategic resource globally. Oil shale is a fine-grained organic-matter-rich sedimentary rock

37

(Han et al., 2014; Jia et al., 2013; Zhao et al., 2017a). Most organic matter in oil shale

38

contains a substance that cannot be dissolved in common organic solvents, whereas organic

39

matter can be converted to oil and is termed “kerogen” , which is composed of complex

40

polymeric organic compounds, has a large aliphatic hydrocarbon content and a low arene

41

content (Tao et al., 2013; Lai et al., 2017; Qing et al., 2009). The organic content from

42

kerogen of oil shale ranges from 3% to 15% (Aboulkas and Nadifiyine, 2008; Bhargava et al.,

43

2005; Fuhr et al., 1988). The mineral matrix in oil shale is usually higher than the

44

organic-matter content and consists mainly of quartz, kaolin, clay, mica, carbonate, and pyrite

45

(Hu et al., 2014; Pan et al., 2016). Furthermore, as a large amount of clay minerals appear, the

46

oil shale tends to form a noticeable schistosity. 2

47

The organic matter in oil shale is very sensitive to variations in temperature as it will undergo

48

a violent thermal decomposition reaction and produce a large amount of shale oil and gas

49

when the temperature increases from 350 to 550°C (Doǧan and Uysal, 1996; Li and Yue,

50

2003; Zhang et al., 2016). Global oil-shale reserves consist of ~ 400 billion tons of converting

51

shale oil, which is ~2.5 times than that of global crude oil reserves, and thus they are

52

considered to be an important supplemental resource to oil (Dyni, 2006; Liu et al., 2017;

53

Wang et al., 2012).

54

Currently, the ground retorting processing and underground retorting processing of two

55

approaches are employed to produce shale oil (Crawford et al., 2008; Fan et al., 2010; Jiang

56

et al., 2007; Liu et al., 2009; Opik et al., 2001; Qian et al., 2008). Over the past decade,

57

ground retorting technology and engineering have become gradually more diverse and mature

58

(Golubev, 2003; Han et al., 2009; Shi et al., 2012). However, these methods face significant

59

challenges, such as slag occupation, environmental pollution, and cost inefficiencies

60

(Kaljuvee et al., 2004; Nei et al., 2009; Raukas and Punning, 2009; Selberg et al., 2009).

61

Unlike ground retorting, underground retorting technology refers to the extraction of oil and

62

gas from oil-shale seam by in-situ heating, and it has become recognized as an effective

63

approach to obtain large-scale commercial production from oil shale. Well-known in-situ

64

heating technologies include Shell’s in-situ Conversion Process (ICP) technology (Brandt,

65

2008; Brandt, 2009; Hascakir et al., 2008), ExxonMobil’s’ ElectrofracTM technology (Hoda et

66

al., 2010; Yeakel et al., 2007), gas (overheated air, CO2, or hydrocarbon) injection to heat

67

oil-shale beds (Bauman and Deo, 2012; Crawford and Killen, 2010; Zhao et al., 2013),

68

microwave and other radiation heat technologies (Al-Gharabli et al., 2015; Mokhlisse et al., 3

69

2000). Many of these technologies are either terminated or still in the stage of demonstration

70

due to some technical defects. Therefore, it is critical and urgent to develop an economically

71

feasible in-situ retorting technology for oil and gas extraction from oil shale.

72

Oil shale in-situ retorting technology by superheated steam injection, i.e., MTI technology

73

(Zhao et al., 2010), which can be used to exploit oil-shale deposits rapidly (Wang et al.,

74

2018c; Wang et al., 2019b). The process of MTI technology is described as follows: (1) The

75

arrangement and drilling of wells on the ground to oil-shale beds and the connection of

76

injection well and production well by fracturing. (2) The injection of superheated steam (T >

77

500°C) into the oil-shale beds from a ground pipe network system and injection wells,

78

deposit heating to produce oil and gas products due to organic-matter decomposition. (3) The

79

discharge of oil and gas products carried by low-temperature steam (or condensate water)

80

from production wells to the surface, and then into a separation system to obtain final oil and

81

gas products, and recycling of condensed water after purification. A sketch of the MTI

82

technology and its main technical principle is shown in Fig. 1. After its proposal in 2005, the

83

technology has been used to perform oil-shale pyrolysis weightlessness tests, pyrolysis

84

permeability tests, pyrolysis-cracking mesoscopic tests, high-temperature and pressure-tank

85

pyrolysis tests, and large-sample (300 mm × 300 mm × 300 mm) fracturing tests of samples

86

collected from seven districts (Fushun, Yan’an, Daqing, Huadian, Nongan, Bagemaode, and

87

Jimusaer) (Dong et al., 2018; Geng et al., 2017; Kang et al., 2011; Kang et al., 2017; Wang et

88

al., 2018a; Wang et al., 2019a; Zhao et al., 2017b; Kang, et al., 2009). These experiments

89

examined the composition and characteristics of the extracted oil and gas, and the feasibility

90

of wastewater reuse. The results revealed basic scientific principles and technique parameters 4

91

of in-situ retorting technology by superheated steam injection (MTI).

92 93

Fig. 1. Schematic of oil shale in-situ retorting technology by superheated steam injection (MTI).

94

However, the following questions remain unsolved. (1) Does injected high-temperature steam

95

flow only along the main fracture channel to form a short circuit that results in the failure of

96

industry implementation? (2) What are the rock temperature, pressure, and fluid-migration

97

mechanisms under the stratum stress during the recovery process? (3) How can energy and

98

water consumption be quantified in the mining process? (4) What are the fluid enthalpy and

99

temperature characteristics that are discharged from the production wells? To answer these

100

questions, we performed a large-scale laboratory pilot test. In this paper, we introduce the

101

laboratory pilot test procedures and present results from oil-shale pyrolysis by injecting

102

superheated steam. This was the first pilot test on large-scale oil-shale sample pyrolysis by

103

in-situ superheated steam injection throughout the world. The findings from this work could

104

provide a significant contribution for us to understand the fundamental mechanism and

105

engineering practice of oil-shale commercial development by MTI technology.

106

2. Material and experiment

107

2.1 Sample collection and preparation

108

Three large samples (Fig. 2) were collected from the Fushun oil-shale open-pit mine in 5

109

Liaoning Province, China. All the samples were sent to the laboratory as soon as possible and

110

were sealed with paraffin to avoid oxidation and breakage. The oil content of the oil-shale

111

samples was approximately 4.0% (Table 1). Sample #1

Sample #2

Sample #3

20 cm

20 cm

20 cm

112 113 114

Fig. 2. Photographs of three large oil-shale samples.

115

Table 1 Oil-shale samples and chambers used Size (length*width*high)

Size of rigid triaxial

Weight

Volume of oil shale /

Oil content

(mm)

pressure chamber (mm)

(Ton)

Volume of chamber (％)

(％)

#1

2200×1700×1100

φ2200*1270

8.230

85.20

4.12

#2

1700×1050×700

φ1700*910

3.213

60.49

3.89

#3

1150×800×650

φ1280*750

1.346

61.96

3.82

Sample no.

116

Based on the sample size, three different cylindrical chambers with rigid triaxial pressure

117

were built, welded with 8-mm-thick steel plate, and sealed at the base with 8-mm steel plate

118

(Table 1). The three large-scale irregular oil-shale samples were placed into the relevant

119

chamber and the remaining empty space was filled with concrete, and solidified for 3 weeks

120

to consolidate the samples. As shown in Fig. 3, the large-scale sample (Sample #2) was well

121

sealed. Injection and production boreholes were drilled in the top of the samples, and the

122

formation stress of the oil-shale deposits at different depths was mimicked by applying

123

different vertical stresses. We then started a pyrolysis pilot test on the samples.

6

300 mm

910 mm 400 mm

210 mm

124 125 126

Fig. 3. Sample #2 was sealed in a rigid triaxial pressure chamber.

127

2.2 Experimental systems

128

As displayed in Fig. 4, the apparatus for oil-shale in-situ pyrolysis and oil and gas extraction

129

consists of large rigid triaxial pressure chamber, 1000-t press machine and deformation

130

measurement system, boiler and water-treatment system, steam-injection pipe network and

131

input/output (I/O) control system, automatic monitoring system for temperature and pressure,

132

fluid cooling and separation system, pipe insulation and monitoring system, and sample

133

cracking-detection system. These subsystems are introduced briefly in the Appendix. Temperature and pressure detection system

Acoustic-emission system

Flowmeter

1000-t press machine

Pipe network

Seal Cooling and separation system Boiler Water pump AE sensor

Outlet

Oil shale

Wellbore

Gas Stove Chamber

134 135 136

Concrete

Fig. 4. Schematic and photograph of oil-shale in-situ pyrolysis and oil and gas extraction test system.

137

2.3 Experimental schemes and procedure

138

Samples #3, #2, and #1 were tested in sequence. Different burial depth models were designed

139

to investigate the effect of burial depth of the in-situ pyrolysis of oil shale. Some oil-shale

140

deposits are thick and need to be layered for mining. Single and layer-mining methods were 7

141

selected in this experiment, respectively. Specific test schemes for the different samples are

142

shown in Fig. 5 and Table 2.

143

Table 2 Experimental scheme Sample no.

Simulation

Vertical

overburden depth/m stress/MPa

Steps description of oil shale in-situ pyrolysis

Number of Distance between boreholes

boreholes/mm

20

300~500

2 layers pyrolysis, down seam 0.33m, #1

84

1.85

up seam 0.25m, space between up and down is 0.2m

#2

154

3.40

A single layer pyrolysis, 0.34m

20

200~300

#3

100

2.20

A single layer pyrolysis, 0.30m

13

200~400

Test time

17 Dec 2015 ~14 Jan 2016 11 Sept 2015 ~25 Sept 2015 2 June 2015 ~26 June 2015

144

Boreholes (32 mm in diameter) were drilled in the designated positions, and steel pipes

145

(25-mm outer diameter; 15-mm inner diameter) were placed in the boreholes. The upper part

146

of the pipes was sealed, whereas the lower part was a porous pipe to act as a steam-injection

147

inlet and oil and gas production outlet. The gap space between the steel pipe and the borehole

148

was sealed by using high-temperature graphite packing. The temperature transducers and the

149

pressure transducers were joined to the pipe inlet to monitor temperature and pressure,

150

respectively. Injection valves connected with the steam boiler outlet were installed on the top

151

of the pipes, which were resistant to the high temperature and pressure. The exhaust valves

152

were connected to the exhaust pipes. During the experiment, the synchronously adjusted

153

injection valves and the exhaust valves of each borehole, the flow rate, and the flow direction

154

of the steam can be controlled. Thus, the target area of oil-shale pyrolysis could be controlled

155

flexibly.

8

156 157

158 159

Fig. 5. Histogram of Sample #1, #2.

(a)

(b)

160

Fig. 6. Collection of shale oil and gas after condensation. (a) Shale oil, (b) gas burning.

161

First, superheated steam was injected into the oil-shale sample through the borehole selected

162

in the middle position to generate fractures and connectivity between the wells in the oil shale.

163

The connectivity was monitored by detecting changes of temperature and pressure values of

164

the wells. Furthermore, pyrolysis occurred as a result of steam thermal convection, while

165

steam flowed in the connected channel and gradually infiltrated the interior of the oil-shale

166

mass to pyrolyze organic matter, which led to the oil and gas extraction. When the production

167

well valve was opened, the oil, gas–fluid mixture and low-temperature steam entered into the

168

condenser for separation to obtain oil and gas products (Fig. 6). A total of 20 wells were

169

drilled in Sample #2, of which well 11 was located in the center (Fig. 7) and the horizontal

170

and vertical distances between wells were varied between 200 mm and 300 mm. Besides, the

171

well layout of Sample #1 and #3 are shown in Fig. 7.

9

Up seam

Down seam

172 173

Fig. 7. Well layout of Sample #1, #2 and #3.

174

Take Sample #2 as an example, the operating schedule of well valves was displayed. The

175

in-situ pyrolysis test of Sample #2 started on September 11, 2015. First, a fracturing

176

connection between wells was established, and then superheated steam was injected to extract

177

oil and gas. The test ran smoothly and was completed on September 25, 2015. Fig. 8 presents

178

the well valve operation schedule for steam injection and fluid discharge.

179 180 181 182 183

Fig. 8. Well valve operating schedule of Sample #2 for steam injection and fluid discharge. Note: The ordinate shows the well numbers (plus mean steam injection, minus mean fluid discharge). Abscissa for test time, unit: min.

184

3. Results and discussion

185 186

3.1 Variation of pressure fracturing-connection stage

after

superheated 10

steam

injection

during

187

Traditional hydraulic-fracturing technology has a large shortcoming in that a large amount of

188

water that enters oil-shale seams during fracturing (Sun et al., 2012), and subsequent heating

189

of this water will consume excessive energy.

190

Sample #2 was fractured to connect the wells with superheated steam (350°C) on 11

191

September 2015, and the pressure changes against time are presented in Fig. 9. The first

192

attempt was to inject superheated steam at 9:16 from well 10 at 2.5 MPa, which failed. The

193

second attempt was made at 10:30 simultaneously from wells 10 and 4 at 3.6 MPa (Fig. 9a).

194

The connection between wells 4, 7, and 10 initially failed but succeeded at 12:36, and the

195

steam pressure was reduced gradually to 1.85 MPa (Fig. 9b).

(c)

196 197 198

Fig. 9. Pressure contour (a, b) and curve (c) of fracturing-connection with superheated steam in Sample #2. (a) pressure contour after 22 minutes of the experiment, the time is shown as dotted green line in (c); (b) pressure contour after 148 minutes of the experiment, the time is shown as dotted green line in (c).

199

The entire fracturing connection process took approximately 2 h (from 10:30 to 12:36) and 11

200

the pressure–time curve was presented in Fig. 9c. Initially, the highest injection pressure of

201

well 4 occurred at 7.3 MPa. When well 4 was connected with well 7 instantaneously, the

202

pressure of well 7 increased rapidly from 0.1 MPa to 6.3 MPa, and the pressure of well 4

203

reduced to 6.3 MPa. The connection between well 4 and well 7 occurred after 80 minutes of

204

synchronized fluctuations, and the pressure stabilized at 1.0 MPa (Fig. 9c). The results

205

indicate that a fracturing pressure of 7.3 MPa, which is much higher than the strata stress of

206

3.40 MPa (according to overburden depth of 154 m), must overcome the high thermal stress

207

around the borehole, which lead to a demand for a higher fracturing pressure and a longer

208

time for the superheated steam-fracturing process. Similarly, Samples #1 and #3 showed the

209

same behavior during the fracturing stage (Fig. 10). The fracturing pressures of Samples #1

210

and #3 are 3.6 MPa and 4.2 MPa, respectively, which are higher than the respective strata

211

stresses of 1.85 MPa and 2.20 MPa. Thus, it is necessary to consider the overpressure

212

phenomenon in MTI industrial implementation by using steam to fracture and connect wells,

213

which threatens boiler safety. The final stabilization pressures of Samples #1 and #3 are 0.52

214

MPa and 0.45 MPa respectively, which are obviously lower than that of sample #2, indicating

215

that the lower strata stress has relatively lower stabilization pressure. Down seam

216 217

(a)

12

218 219

(b)

220

Fig. 10. Fracturing-connection with superheated steam. (a) Sample #1; (b) Sample #3.

221

3.2 Variation of temperature during in-situ pyrolysis

222

Fig. 11 shows the variation of temperature of Sample #2 during the pyrolysis process (please

223

refer to Fig. 7 for the well locations). The pyrolysis procedure was as follows. Superheated

224

steam was injected from wells on the right side and the steam seeped gradually to the left.

225

Steam flowed along the fracturing cracks to neighboring wells. As a result, the kerogen was

226

decomposed into oil and gas after heat convection. The specific procedures are described

227

below.

228

(1) On September 11, the oil-shale in-situ pyrolysis process was carried out by injecting

229

superheated steam. Wells 4 and 10 were selected for steam injection, and adjacent wells were

230

production wells (Fig. 11a). The temperature of the oil-shale bed near wells 4 and 10

231

increased rapidly after continuous injection. As shown in Fig. 11, the temperature increases

232

along the main flow direction between the two wells in the early stage, and heat was

233

transmitted gradually perpendicular to the main flow direction.

234

(2) The injection was implemented for well 3 on September 12 (Fig. 11b). The pressure

235

around this well increased significantly after injection. As shown in Fig. 11, wells 1, 2, 4, and

236

7 were selected as production wells and the main heating zone was located between these 13

237

wells. Oil and gas were carried by the steam and extracted from the production wells. When

238

the production wells were switched to wells 8, 11, and 14, the heat-transfer direction and

239

main heating zone changed to wells 8, 11 and 14 (Fig. 11c). By controlling the well valves,

240

the direction and rate of steam flow can be adjusted to optimize the steam injection as well as

241

flexibly control the heating area of the oil shale. On September 14, well 10 was opened as the

242

injection well while well 7 was closed (Fig. 11e). The temperature of oil-shale bed around

243

well 10 increased rapidly up to the temperature range of pyrolysis.

244

(3) Owing a power failure, the test was suspended from September 15 to 20, and restarted on

245

September 21. Between September 22 and 25, wells 8, 12, 17, and 18 were injected

246

successively with superheated steam and the surrounding wells were used as production wells

247

(Fig. 11f-i). The pyrolysis temperatures in the range of the injection and production wells

248

always exceeded 500°C, leading to the pyrolysis of oil-shale bed of sample 2# was completed.

249

As a result, the test was stopped.

14

250

Fig. 11. Temperature distribution of Sample 2# in-situ pyrolysis by superheated steam injection

251

According to the aforementioned analysis, the selection of opening or closing boreholes

252

according to the distribution of temperature can adjust the direction and rate of steam flow.

253

As a result, the flexibility of controlling the target heating area of oil shale can be achieved.

254

When the temperature of the production wells exceeded the critical pyrolysis temperature of

255

oil shale (~530°C) (Kok et al., 2001; Niu et al., 2013; Yang et al., 2016), the production yield

256

of oil and gas decreased obviously. In this case, the production wells should be closed to

257

prevent a large amount of superheated steam from discharging inefficiently and to drive heat

258

outward and expand the effective heating areas.

259

3.3 Variation of steam-pressure during in-situ pyrolysis

260

Fig. 12 shows the variation of steam pressure of Samples #2 and #3 in the in-situ pyrolysis

261

process,

262

fracturing-connection stage. As shown in Fig. 12, the steam pressure of Samples #2 and #3

respectively.

Superheated

steam

15

was

injected

into

oil

shale

after

263

shows similar variation during in-situ pyrolysis of oil shale. The steam pressure of each well

264

basically presents the decreasing trend step by step in different stages. The steam operating

265

pressures of Samples #2 and #3 were about 0.75 MPa and 0.40 MPa in the early period,

266

respectively, and both further decreased to around 0.1 MPa at the final stage.

267 268

(a)

269 270

(b)

271 272

Fig. 12. Variation of steam-pressure of in-situ pyrolysis by superheated steam injection. (a) Sample #2; (b) Sample #3.

273

The experimental process of Sample #2 indicates that the operating pressure of steam is low

274

during oil-shale in-situ pyrolysis by superheated steam injection of between 0.1 MPa and

275

0.75 MPa, which is far lower than the strata stress of 3.40 MPa. This pressure is less than 1/4 16

276

of the strata stress and is similar to the pyrolysis environment of the oil-shale ground retorting

277

furnace (Golubev, 2003; Han et al., 2009). Thus, during the in-situ pyrolysis of oil shale, the

278

porosity of the oil shale increased rapidly because of organic-matter pyrolysis and the

279

mechanical strength of the rock mass decreases synchronously (Kang et al., 2017; Saif et al.,

280

2017a). At the same time, thermal-induced fractures were generated, leading to a connected

281

pore-fracture network (Kang et al., 2011; Zhao et al., 2012). The pore-fracture network

282

significantly improved the permeability of the oil shale, and therefore the resistance of steam

283

flow significantly decreased.

284

3.4 Energy utilization for in-situ pyrolysis

285

This test collated energy-utilization data for Sample #1 over the following three time slots.

286

They are10:00 on 5 January to 22:00 on 7 January, 19:00 on 9 January to 17:00 on 10 January

287

and 18:30 on 10 January to 12:00 on 14 January, respectively.

288 289

Fig. 13. Period of 5–7 Jan., steam-injection volume (left) and discharge temperature of fluid (right) from production well

17

290 291

Fig. 14. Period of 8–10 Jan., steam-injection volume (left) and discharge temperature of fluid (right) from production well.

292 293

Fig. 15. Period of 10–14 Jan., steam-injection volume (left) and discharge temperature of fluid (right) from production well.

294

Figs. 13-15 show the volume of injected steam and the temperature of the extracted fluid

295

from production wells of Sample #1 for the three tested periods, respectively. The

296

temperature of the discharged fluid (a mixture of oil, gas, and low-temperature steam) was

297

affected by the temperature and pressure of the injected steam, the oil-shale retort process,

298

fracture characteristics, and mechanical properties of the oil-shale deposits (Wang et al.,

299

2018b; Wang et al., 2018c). Table 3 lists the average values of the measured data of the

300

injected steam and discharged fluid during the above three test periods. According to the data

301

in Table 3, the total energy of steam injection, pyrolysis energy consumption of the oil shale,

302

pipe energy loss, and the energy of fluid discharged from production wells and their ratios to

303

total energy were calculated (Table 4).

304 305

306 307

Table 3 Average value of measured data for injected steam and discharge fluid of Sample #1 in three test periods. Test sequence

Temperature of superheated steam (℃)

Temperature of discharged fluid (℃)

Boiler water consumption (L/h)

Discharge of condensed water (L/h)

Pressure of injection (MPa)

Time of injection (h)

1th

605.16

158.4

42.273

35.106

1.48

54.50

2nd

608.30

182.6

49.177

40.284

1.49

43.33

3rd

604.13

160.2

43.056

35.816

1.47

86.55

Table 4 Heat energy utilization of in-situ pyrolysis by injecting superheated steam of Sample #1 in three 18

308

test periods. Test sequence

Et (106 kJ

E1 (106 kJ)

E1/Et (%)

E2 (106 kJ)

E2/Et (%)

E3 (106 kJ)

E3/Et (%)

1th

8.92481

4.154

46.54

4.768

53.42

0.00281

0.0315

2nd

7.57524

3.181

41.99

4.392

57.98

0.00224

0.0296

3rd

13.88047

5.492

39.57

8.384

60.40

0.00447

0.0322

Avg

10.12684

4.276

42.70

5.848

57.27

0.00317

0.0311

309 310

Note: Et = E1 + E2 + E3. (Et: Total steam-injection energy; E1: Pyrolysis energy consumption of oil shale; E2: Energy of fluid

311

As demonstrated in Table 4, the total energy for in-situ pyrolysis accounted for 42.7% of the

312

injected thermal energy. The loss of energy in the pipes accounted for only 0.0311% of the

313

injected thermal energy. More than half of the heat (57.27% of the total injected thermal

314

energy) was released from the production wells. The temperature of the discharged fluid

315

varied between 130°C and 210°C. The average temperature was approximately 170°C (Figs.

316

13-15), which represents high-quality, low-temperature heat resources recycled for power

317

generation and industry.

318

Table 5 shows that the heat-utilization coefficient for low-temperature waste-heat

319

power-generation technology varies between 10.55% and 16.51% with the average value of

320

13.19%. Therefore, low-temperature waste-heat power generation should be considered as the

321

first choice for recovering waste heat from oil-shale in-situ pyrolysis projects by using

322

superheated steam injection.

323

324 325

discharged from production wells; E3: Pipe energy loss.)

Table 5 Heat-energy utilization of low-temperature waste-heat power-generation system. Item

E2 (106 kJ)

E4 (106 kJ)

E5 (106 kJ)

η (%)

1th

4.768

4.265

0.503

10.55

2nd

4.392

3.667

0.725

16.51

3rd

8.384

7.335

1.049

12.52

Avg

5.848

5.089

0.759

13.19

Note：E4: Energy discharged after power generation, E5: Power generation using energy, η: Power-generation efficiency.

19

326 327

3.5 Rock characteristics and production performance of oil shale during in-situ pyrolysis

328

After the in-situ pyrolysis test, oil-shale samples were broken to look at some boreholes (Fig.

329

16). Many different-sized cracks (visible cracks range in length from a few millimeters to

330

tens of centimeters) were distributed in the rock section between boreholes, which indicates

331

that many cracks were generated during fracturing and pyrolysis, which supports the previous

332

findings (Kang et al., 2011; Saif et al., 2017b; Saif et al., 2016; Zhao et al., 2012). The

333

pyrolysis areas between the boreholes were heated evenly by superheated steam and no

334

short-circuit accident was caused by the steam flow in a single crack. The oil shale in the

335

pyrolysis areas changed from brown to black; however, the oil shale below the borehole

336

bottom remained brown and few cracks appeared (Fig. 16), which indicates that the organic

337

matter was not pyrolyzed fully.

Pyrolysis crack zone 1 cm

Floor

338 339

Fig. 16. Borehole profile of oil-shale Sample #3 after in-situ pyrolysis test.

340

Steam flows and heats the oil-shale bed mainly in the direction parallel to the stratification in

341

the range of the steam-injection section of the boreholes, and it is difficult for steam to

342

penetrate into the floor of the oil-shale bed. The temperature increase of oil shale in the floor

343

was dependent mainly on heat conduction in the solid, which cannot easily reach the

344

pyrolysis critical temperature of oil shale (Wang et al., 2019b). Therefore, it can be foreseen 20

345

that the floor and roof of the oil-shale bed provide good thermal insulation and impervious

346

layers in the development of oil-shale in-situ pyrolysis projects in steam injection, which

347

effectively prevents steam leakage and heat loss.

348

The oil contents along the vertical position between the two boreholes were measured at

349

vertical intervals of 100 mm from the floor to the roof. Tests were undertaken at the Testing

350

Center of Coal Geology Research Institute, Shanxi, China. The measured oil contents are

351

shown in Fig. 17. The residual oil content of both samples along the borehole steam-injection

352

section, at 0–400 mm in the vertical direction was 0.1%–0.2%, which implies that the

353

oil-recovery rate of oil shale in this area exceeds 95%. Conversely, the oil-recovery rate of

354

oil-shale Sample #3 in the floor (–80 mm) was 52% and in the roof (500 mm), it was 57%.

355 356

Fig. 17. Oil-recovery rate of central position between injection well and production well.

357

In the oil-shale pyrolysis pilot test, we collected products from Samples #1, #2, and #3 from

358

the cooling and separation system, and the oil and gas production obtained are shown in

359

Table 6. The oil ratio of oil-shale Samples #1, #2, and #3 reached 3.08%, 2.74%, and 2.56 %,

360

respectively. By referring to the original oil content of oil-shale samples in Table 1, it was

361

found that the overall oil-recovery rate of oil-shale Samples #1, #2, and #3 reached 74.8%, 21

362

70.4%, and 67.0%, respectively, and their average was 70.7%. Therefore, the MTI technology

363

for in-situ oil-shale pyrolysis by superheated steam injection could achieve a promising oil

364

recovery.

365

Table 6 Statistical results of oil and gas production in pilot test Sample no.

Size（length*width*high）

Ore quality /kg

(mm)

Oil production /kg

Gas production /m3

Oil ratio/

#1

2200×1700×1100

8230

253.5

234.0

3.08

#2

1700×1050×700

3213

88.0

91.1

2.74

#3

1150×800×650

1346

34.5

43.6

2.56

366

Previous works have shown that superheated steam seeps through fissures and heats oil shale

367

by convection (Wang et al., 2018c; Wang et al., 2019b). Thermal stress occurs in oil shale

368

because of the uneven expansion of mineral particles. When the thermal stress exceeds the

369

mineral cementation strength, acoustic-emission phenomena of thermal cracking will occur in

370

rock. Superheated steam continues to infiltrate the interior of the oil-shale mass along the

371

newly generated thermal cracks to heat and pyrolyze organic matter. During the in-situ

372

pyrolysis of oil-shale samples, cracking elastic waves were monitored by acoustic-emission

373

probes that were installed at different locations around the chamber, and the

374

acoustic-emission events of thermal cracking were counted and located (Behnia et al., 2011;

375

Yong and Wang, 1980).

22

376 377

(a)

(b)

Floor

378 379

(c)

(d)

380 381

Fig. 18. Acoustic-emission positioning of thermal cracking of Sample #2 injected with superheated steam. (a) 17:40, 11 Sept; (b) 19:22, 11 Sept; (c) 04:48, 12 Sept; (d) 09:24, 14 Sept.

382

Fig. 18 shows the acoustic-emission positioning results of thermal cracking of Sample #2.

383

The superheated steam was injected at different times, which shows the number of

384

thermal-cracking events and their spatial locations. Fig. 18 shows that the thermal-cracking

385

events in the oil shale increase with time. During the initial stage of steam injection, steam

386

only flows along the main fracture channel, the number of thermal cracking events is limited

387

and the spatial distribution is scattered. With a continuous injection, steam is imported

388

continuously into the fracture network of oil shale, and the area that is covered by steam

389

seepage expands, which results in an increase in the number of thermal-cracking events and

390

provides a denser spatial distribution. A very significant phenomenon was found where few

23

391

acoustic-emission events were detected in the oil-shale floor of Sample #2 (Fig. 18d), which

392

indicates that there were relatively fewer thermal-cracking events in the oil-shale floor, which

393

was identical to the results in Fig. 16.

394

3.6 Relationship between effective energy rate of injected steam and gas production rate

395

Given that the main temperature range of organic-matter pyrolysis in oil shale was 400 -

396

550 °C, the thermal energy carried by steam below 400°C was invalid energy. The

397

relationship between effective thermal energy carried by steam at different pressures and the

398

pyrolysis energy consumption of oil shale above 400°C is presented in Fig. 19. The

399

experimental results from the oil shale in-situ pyrolysis were analyzed according to the

400

effective energy principle. The effective energy rate was calculated by multiplying the

401

injected steam volume above 400°C and time with the cumulative product of enthalpy during

402

the oil shale for the Sample #1 pilot test. The correlation curves between the effective energy

403

rate and gas production rate are plotted in Fig. 20 and Fig. 21, respectively.

404 405 406

Fig. 19. Relationship between steam carrying effective energy and oil-shale pyrolysis energy consumption for the critical temperature stage of organic-matter pyrolysis.

407

As presented in Fig. 20 and Fig. 21, a good correlation exists between the produced gas and

408

the effective energy rate of the injected steam. During the period of 930 min to 3750 min, the 24

409

effective energy rate was ~100 kJ/min and the gas yield varied between 4-5 L/min. During

410

3900-4100 min, the effective energy rate rapidly increased to 120-160 kJ/min, and the gas

411

yield rapidly increased to 11-14 L/min (Fig. 20). During the period of 5000 min to 5200 min,

412

the effective injected energy rate was greater than 120 kJ/min, and the gas yield was as high

413

as 24 L/min. During the period of 6100 min to 6700 min, the effective energy rate varied

414

between 100 kJ/min and 140 kJ/min, the gas yields ranged from 20 L/min to 28 L/min. In

415

9200-10800 min, the effective injected energy rate was less than 80 kJ/min; the lower gas

416

yield fluctuations were ~4 L/min (Fig. 21).

417 418 419

Fig. 20. Corresponding relationship between effective energy rate of injected steam and gas production rate of Sample #1 for 5–7 January.

420 421 422

Fig. 21. Corresponding relationship between effective energy rate of injected steam and gas production rate of Sample #1 for 7–14 January.

423

The production speed of boiler steam in this experiment was constant. Therefore, a high 25

424

effective energy rate corresponds to a high steam temperature, suggesting a considerable

425

quality of steam. The relationship between effective energy rate and gas production rate

426

follows an exponential function with a high correlation coefficient (Fig. 22). Fig.22 shows

427

that when the effective energy rate increases from 80 kJ/min to 120 kJ/min, the increasing

428

amplitude is 1.50 times and the corresponding gas production rate is increased from 5.0

429

L/min to 15 L/min (3.0 times). This aforementioned result suggests that the injection of

430

high-quality steam will help to achieve a higher energy utilization rate and oil and gas

431

production rate after MTI technology implementation.

432 433

Fig. 22. Relationship between effective energy rate and gas production rate.

434

4. Conclusions

435

The in-situ retorting technology of oil shale by MTI to extract oil and gas shows great

436

potential in industry. This paper mainly studied the in-situ pyrolysis pilot test of large

437

oil-shale samples by MTI in detail. Based on our experimental work, the conclusions of this

438

work can be summarized as follows: (1) Before in-situ pyrolysis, wells were connected by

439

high-temperature steam fracturing technology, which has the advantage of not bringing water

440

into oil-shale seams during fracturing and the disadvantage of a higher fracturing pressure

26

441

(about 2 times higher than the strata stress); (2) During the in-situ pyrolysis of oil-shale

442

samples, the operating pressure of steam in the reaction zone is lower than 1/4 of the strata

443

stress. The variations of temperature and pressure are controlled completely by steam seepage.

444

(3) The energy used for the pyrolysis reaction accounts for 42.7% of the total injected energy.

445

Moreover, 57.2% of the energy was discharged from the production wells to the ground and

446

the average temperature of the discharged fluid was ~170°C, which could be considered for

447

electricity generation in commercial operations, with an efficiency that reaches 13.19%; (4)

448

The oil-recovery rate in the pyrolysis area by MTI technology can exceed 95%, and the

449

overall oil-recovery rate reaches up to 70.7%; (5) The gas production rate and the effective

450

energy rate of the injected steam follow an exponential function.

451 452

Acknowledgments

453

This work was supported by the National Natural Science Foundation of China (11772213,

454

U1261102). And thanks for financial support from Datong Coal Mine Group for this

455

experiment.

456

Appendix A. Supplementary data

457 458

References

459 460 461 462 463 464 465 466 467 468

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Appendix

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30

600

The test system used for oil-shale in-situ pyrolysis and oil and gas extraction consists of eight

601

subsystems：

602

1) Rigid triaxial pressure chamber and wells

603

The large-scale sample was placed in the chamber, including the core of the test system, the

604

top of which was a 100-mm-thick steel plate. In the test process, the chamber was first loaded

605

into the XPS-1000 press machine, and then the applied vertical stress was transferred to the

606

steel plate from the XPS-1000 press machine through a spherical pedestal. The chamber

607

provided a vertical stress to the oil-shale sample that can simulate the real stress state at a

608

certain depth of oil-shale deposit.

609

A number of boreholes were drilled in the top of chamber, and we installed steel pipes in the

610

boreholes to form injection and production wells. Superheated steam was injected into the oil

611

shale sample through injection wells and the oil and gas products were discharged through

612

production wells. The oil-shale sample, triaxial pressure chamber and pipes formed a sealed

613

underground retorting system to avoid leakage in the system. Synchronous monitoring during

614

the test was used to obtain data for stratum deformation. Temperature, pressure, and

615

crack-detection sensors were installed on the chamber ( Fig. A1).

616

2) 1000-t servo control press machine and deformation monitoring system

617

The XPS-1000 press machine onsite was used to add loading to the chamber. This machine

618

has an excellent pressure servo control function, with a displacement monitoring accuracy of

619

up to 1/1000 mm and a displacement loading rate that can be set at 0.001–0.1 mm/s. The

620

servo system contained closed-cycle proportional control valves and variable frequency 31

621

control pumps, which ensures a long-term stable loading and an automatic recording of the

622

pressure and displacement data.

623

3) Boiler and water-treatment system

624

The boiler was composed mainly of a steam generator, superheating pipe, water pump, gas

625

stove, and safety valves, which can generate superheated steam with a maximum temperature

626

and pressure up to 600ºC and 15 MPa, and a water consumption of 65 L/h. The

627

water-treatment system consisted of multi-stage filtration and a reverse osmosis device,

628

which allowed the water purity to reach a pure water level that prevents boiler scale.

629

4) Steam-injection pipe network and I/O control system

630

Different well numbers were designed according to the different sizes of the three oil-shale

631

samples: 13 wells for Sample #3, 20 wells for Sample #2, and 20 wells for Sample #1. The

632

test success depends strongly on the I/O control of the well structure and the cementing

633

method, which are essential technologies for in-situ steam injection. In this test, the borehole

634

structures of all injection and production wells were identical. The injection and production

635

wells could be alternated timely according to the oil and gas output conditions to achieve an

636

efficient retorting of oil shale. The borehole structure consisted of four parts from bottom to

637

top, and included a porous segment, a sealed segment, a temperature-sensor-installation

638

segment, and a pressure-sensor-installation segment.

639

5) Automatic temperature and pressure detection system

640

The detection system contains sensors, transmission lines, a data-acquisition conversion box,

641

synchronous computer record storage software, and a hardware system. There were 26 sensor 32

642

lines in the test, which should remain stable and reliable during the test ( Fig. A1).

643 644

Fig. A1. Sensors of temperature and pressure layout.

645

6) Fluid cooling and separation system

646

The system consisted of a condenser, a cooling circulation pump, a liquid drain valve, a gas

647

discharge valve, a gas flow meter, a cooling tank, and temperature and pressure gauges.

648

7) Pipe insulation and monitoring system

649

Different insulation materials with varying structures and thicknesses were used for the

650

superheated steam-transmission pipes. Some thermocouples were installed at different

651

positions in the insulation to evaluate the thermal conditions and insulation efficiency. The

652

subsystem consisted of pipe-insulation layers, thermocouples, and a portable temperature

653

tester.

654

8) Rock-cracking-detection system by acoustic emission

655

This detection system is composed of low- and high-frequency acoustic-emission testing

656

instruments, which can locate the number and position of cracking events inside the rock

657

accurately. The PCI-2 acoustic-emission system is composed mainly of a signal amplifier, a

658

probe, a capture card, and analysis software. In the test, 8 high-frequency acoustic-emission 33

659

sensors and 12 low-frequency acoustic-emission sensors were installed around the chamber

660

to collect data synchronously.

661

34

Highlights: 1. A new oil shale in-situ retorting technology, MTI technology, is proposed. 2. This is the first pilot test on large-scale oil-shale sample pyrolysis by in-situ superheated steam injection throughout the world. 3. The operating pressure of steam during pyrolysis is lower than 1/4 of the strata stress, and the energy utilization of superheated steam for pyrolysis reaction accounts for 42.7%. 4. The oil-recovery rate in the pyrolysis area by MTI technology can exceed 95%, and the overall oil-recovery rate reaches up to 70.7%.