Enhanced Shale Gas Recovery by the Injections of CO2, N2 and CO2

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Enhanced Shale Gas Recovery by the Injections of CO2, N2 and CO2/N2 Mixture Gases Xidong Du, Min Gu, Zhenjian Liu, Yuan Zhao, Fulong Sun, and Tengfei Wu Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.9b00822 • Publication Date (Web): 08 May 2019 Downloaded from http://pubs.acs.org on May 9, 2019

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Energy & Fuels

1

Enhanced Shale Gas Recovery by the Injections of CO2, N2 and

2

CO2/N2 Mixture Gases

3 4

Xidong Du a,b,c, Min Gu a,b,, Zhenjian Liu a,b, Yuan Zhao d, Fulong Sun e,f,

5

Tengfei Wu e,f

6

a

7

Chongqing, 400044, China

8

b

9

China

State Key Laboratory of Coal Mine Disaster Dynamics and Control, Chongqing University,

College of Resources and Environmental Science, Chongqing University, Chongqing 400044,

10

c

11

China

12

d

Sinohydro Bureau 8 Co. LTD., POWERCHINA, Changsha 410004, China

13

e

China Coal Technology and Engineering Group Shenyang Research Institute, Fushun 113122,

14

China

15

f

School of Earth Sciences, East China University of Technology, Nanchang, Jiangxi 330013,

State Key Laboratory of Coal Mine Safety Technology, Fushun 113122, China

16 17

ABSTRACT: In this paper, the experiments of enhanced shale gas recovery by the

18

injections of CO2, N2 and CO2/N2 mixture gases were carried out in a fixed bed setup

19

to investigate the influence of the types of displacing fluid on CH4 recovery and gas

20

flow dynamics. Investigation results show that when taking CO2 or N2 as

21

displacement agent, Coats-Smith dispersion-capacitance model can give an excellent Corresponding

author. Tel.:+86 15922640072; fax:+86 23 65105719 E-mail address: [email protected] (Gu Min) 1

ACS Paragon Plus Environment

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simulated result to the breakthrough curves of CO2 and N2. The injection of N2 leads

23

to the shortest breakthrough time (tb) of injected gas and the lowest recovery of CH4

24

product (RCH4-product), while injecting CO2 into shale formations results in the longest tb

25

of injected gas and the highest RCH4-product with a relatively sharp displacement front.

26

The differences of dispersion coefficient (KD) and the flowing fraction of pore space

27

(Fv) in Coats-Smith dispersion-capacitance model are the underlying reasons for the

28

distinct behaviors of CO2 injection and N2 injection. With increasing CO2 mole

29

fraction in CO2/N2 mixture gases, RCH4-product rises. The injection of 50:50/N2:CO2

30

mixture gases exhibits a biggest enhancement degree of N2 concentration during

31

displacement process. The injection of N2-rich mixture can significantly prolong tb of

32

CO2 and help to sequestrate injected CO2 over a long term. For the transport of CO2 in

33

reservoir, Fv increases, KD and the mass transfer coefficient between mobile and

34

immobile regions (Km) decreases with increasing N2 concentration in binary gas

35

mixture, revealing that N2 can hinder the diffusion of CO2 into micropore system to

36

displace CH4. The fluctuation range of flow rate of injected gas (Finjected-gas) and the

37

CO2 storage amount (Vstorage-CO2) enhance as CO2 mole fraction in mixture raises. In

38

order to optimize RCH4-product, Vstorage-CO2 and CO2 sequestration time, the selection of

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displacing fluid and the ratio of CO2/N2 mixture gases should be taken into

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consideration.

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KEYWORDS: Displacing fluid; Enhanced shale gas recovery; Gas flow dynamics;

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CO2 geological sequestration; Competitive adsorption

43 2


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1. INTRODUCTION

45 46

The successful extraction of shale gas resource from shale formation with

47

ultralow permeability and porosity needs to create abundant artificial fracture

48

networks before gas exploration.1-9 Recently, in the reservoir treatment, using CO2 to

49

fracture the reservoirs of the unconventional oil and gas has obtained lots of

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attention.10,11 Based on the higher affinity of CO2 over CH4 on shale surface, injected

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CO2 can effectively displace the pre-adsorbed CH4 and subsequently stay in shale

52

sediments, which is a promising technology to reduce anthropogenic CO2 emission

53

into atmosphere and mitigate the greenhouse effect.12-17 The valuable by-product CH4

54

can partly offset the cost of the capture, transport and sequestration of CO2, promoting

55

the development of enhanced gas recovery by CO2 injection.18,19 In addition, injecting

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N2 into gas-bearing formation can cause large number of CH4 desorption from

57

reservoir matrix by lowering the partial pressure of CH4. The employ of N2 as injected

58

agent is also available for increasing CH4 recovery.20 Therefore, CO2 and N2 are

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considered as the nonaqueous displacing fluids to enhance shale gas recovery in this

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research.

61

Some scholars have compared the displacement process and replacement effect

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of CH4 through laboratory experiment and numerical simulation analysis when CO2

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and N2 are injected into coal seams or sandstone sediments.20-23 Their findings

64

indicate that the main function of N2 is to facilitate the desorption of pre-adsorbed

65

CH4 by reducing CH4 partial pressure and drive CH4 toward the production well, 3


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while injected CO2 mainly works as the displacing fluid to directly replace the

67

adsorbed CH4 out of material surface.20 Meanwhile, N2 breaks through rapidly from

68

gas-bearing reservoir with a more dispersed displacement front. Contrarily, the

69

displacement of CH4 by CO2 is nearly piston-like and the breakthrough time of CO2 is

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longer.21 Moreover, the injection of N2 is conductive to obtaining a fast initial

71

recovery of the original gas, and the injection of CO2 helps to acquire a higher total

72

recovery of in-place CH4.22 Despite these differences between the displacement

73

processes of N2 injection and CO2 injection are obvious, researchers simply attribute

74

them to the ascending order in the adsorption capacities of N2, CH4 and CO2 on coal

75

and sandstone surface. The underlying mechanisms of enhanced CH4 recovery by the

76

injections of N2 and CO2 are still not well-understood. What’s more, there have been

77

very few relevant studies addressing the shale gas formations. Therefore, it is

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meaningful to perform the experimental investigation to compare the behaviors and

79

mechanisms of enhanced shale gas recovery by N2 injection and CO2 injection.

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When collected CO2 is injected into coal seam, the adsorption amount of CO2 is

81

larger than the desorption amount of CH4, which will result in the obvious

82

adsorption-induced swelling of coal matrix.24 The swelling of coal particle tends to

83

close fracture and pore systems and reduce coal permeability, making it unfavorable

84

for the production of coalbed methane and the injection of CO2. However, the

85

injection of N2 in coalbed often leads to the shrinkage of coal matrix and the increase

86

in permeability.25 Thus, the injection of CO2/N2 mixture gases into coal seam, which

87

has the advantage of keeping the coal permeability without considerable change 4


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during displacement process, is emerged.26,27 Furthermore, some investigations reveal

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that injecting the mixture of CO2-N2 into coalbed even could be more effective to

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maximize CO2 sequestration capacity.22 Flue gas, the main components of which are

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N2 and CO2, refers to the combustion exhaust gas produced at power plants. The

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direct injection of flue gas into coalbed has also been implemented.28 The physical

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properties of shale and coal display the similar characteristics (naturally occurring

94

carbonaceous organic-rich porous materials), and the shale reservoir is akin to coal

95

bed with a distinct gas trapping mechanism of physical adsorption.29,30 Shale gas

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reservoir treatment by a CO2-based approach can also bring about the swelling of

97

organic matter and clay minerals within shale.31 Therefore, it is also meaningful to

98

discuss the behavior of the displacement of CH4 by injecting CO2/N2 mixture gases in

99

shale reservoir.

100

In this paper, the experiments of enhanced shale gas recovery by the injections of

101

CO2, N2 and various CO2/N2 mixture gases were conducted on a fixed bed setup. The

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experimental results were collected and analyzed by dynamic Coats-Smith

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dispersion-capacitance model. The recovery of CH4 and the gas flow dynamics

104

behavior for different injection schemes were investigated. The research results will

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lay the foundation for the better understanding of the gas displacement process and

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provide guide for optimizing the designs of gas injection composition and injection

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strategy in field applications.

108 109

2. EXPERIMENTAL SECTION 5


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2.1. Material Preparation and Characterization

112 113

The Cn marine shale sample used in this study was collected from the

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Changning, southern district of Sichuan Basin of China where it is being explored as a

115

pilot field. The obtained Cn shale sample belongs to Lower Silurian Longmaxi

116

formation.

117

The total organic carbon (TOC) content of Cn shale is 2.81 wt%, meeting the

118

TOC value of exploration target of gas-bearing shale reservoir. The composition and

119

pore parameters of Cn shale are summarized in our previous paper.32

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Prior to conducting the displacement experiments, Cn shale sample was crushed

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and sieved into 0.0075-0.085 cm. The sample was placed in a drying oven at 383 K

122

for 24 h to remove the moisture and impurities. CO2, CH4 and N2 gases with a purity

123

of 99.99% were provided by Chongqing Tianke Gas Company, Ltd., Chongqing,

124

China.

125 126

2.2. Experimental Setup and Method

127 128

2.2.1. Experimental Setup

129 130 131

The schematic diagram of the experiment apparatus for the displacement experiments is shown in Figure 1. 6


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Energy & Fuels

132 pressure

pressure regulator

data collector

P transducer gas-mass flow controller

thermostatic water bath syringe pump

CH4

N2

CO2

reference column

gas-mass flow controller gas chromatography

adsorption column

vacuum pump

133 134

Figure 1. Schematic diagram of the experiment apparatus.

135 136 137

This setup consists of three parts, namely, gas supply unit, adsorption bed unit and gas analysis unit.

138

The gas supply unit includes gas cylinders, gas-mass flow controller and syringe

139

pump. An ISCO 260D syringe pump (Teledyne ISCO, USA) was used to maintain the

140

injection of high pressure CO2, N2 and various CO2/N2 mixture gases.

141

The adsorption bed unit includes adsorption column, reference column, pressure

142

transducer, thermostatic water bath and vacuum pump. The adsorption column is a

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stainless steel column of 1.8 cm inner diameter and 50 cm length. The water bath with

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temperature fluctuation range of less than ±0.1℃ and the pressure transducer with a

145

precision of 0.05% of the full-scale value 30MPa (Keller, Druckmesstechnik,

146

Switzerland) were applied.

147

In gas analysis unit, the composition of effluent gas was analyzed by gas

148

chromatograph (Shimadzu 2010Plus, Japan) and the flow rate of effluent gas was

149

controlled and recorded by gas-mass flow controller. 7


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2.2.2. Experimental Method

152 153

For this experiment study, the main procedures include:

154

(1) Leak test. After loading about 200 g of dry Cn shale sample into adsorption

155

column, the whole system was vacuumed at 318 K for 5 h. Subsequently, helium (He)

156

gas was injected into both adsorption column and reference column until the pressure

157

reached to 10 MPa for a leak test;

158

(2) Void volume measurement. The void volume of adsorption column packed

159

with shale sample was measured by helium expansion at 318 K at the pressures of

160

1.00 MPa, 3.00 MPa, 5.00 MPa and 7.00 MPa individually. The final result was the

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average value of tests under four different pressures. This approach can correct the

162

systematic error in void volume measurement induced by altering the reservoir

163

condition.33,34 After determining the void volume, the voidage of adsorption column

164

of 35.01% was obtained;

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(3) CH4 pre-adsorption. The adsorption column was filled with CH4 up to 5.10

166

MPa at 318 K. Ten hours later, the adsorption equilibrium of CH4 was reached, and

167

the pressure of adsorption column decreased to about 5.03 MPa;

168

(4) Displacement of CH4 by different gases. When the displacing fluid was

169

pressurized to 8.00 MPa by syringe pump, the fluid was injected into adsorption

170

column, and the outlet valve was opened simultaneously. During the displacement

171

process, the pressure of adsorption column was maintained at 8.00 MPa ， and the 8


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flow rate of outlet was kept at 10 ml/min. The volume and composition of produced

173

gas were obtained by mass flow controller and gas chromatograph, respectively. The

174

flow rate of injected gas was recorded by syringe pump. The experiments were

175

terminated when mole percentage of CH4 in effluent reduced to 2.0%.

176 177

2.2.3. Reproducibility of the Displacement Experiments

178 179

The result of repeated experiment of the displacement of CH4 by injecting CO2 is

180

given in Figure 2. It can be found that the breakthrough curves of CO2 and CH4 have

181

good repeatability, revealing that the experimental data in this study are reliable.

182 100

Mole fraction of CH4 and CO2 in effluent (%)

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Energy & Fuels

90 80

Exp. 1 (CH4)

70

Exp. 1 (CO2) Exp. 2 (CH4)

60

Exp. 2 (CO2)

50 40 30 20 10 0 0

50

100

150

200

250

183 184

300

350

400

450

500

550

t/min

Figure 2. Reproducibility of CO2-CH4 displacement experiment.

185 186

3. RESULTS AND DISCUSSION

187 188

3.1. Performances of Enhanced Shale Gas Recovery by Injecting CO2 and N2

189 9


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190

3.1.1. Breakthrough Curves of CO2 and N2 during Displacement Process

191 192

The composition variations of the produced gas in the outlet during displacement

193

process for CO2 injection and N2 injection are displayed in Figure 3. It can be seen

194

that there are some differences between the breakthrough curves of CO2 and N2. The

195

platform of N2 breakthrough curve is shorter and the slope of N2 breakthrough curve

196

is smaller. Unlike N2, injected CO2 transports slowly through the reservoir, and CO2

197

concentration in effluent increases sharply. These results are in excellent agreement

198

with the findings on coalbeds and sandstones.20-23,25,35 However, the differences

199

between the performances of N2 injection and CO2 injection on coalbeds are more

200

obvious than those on shale reservoirs. One reason is that the swelling/shrinkage of

201

coal matrix induced by gas adsorption/desorption on coalbeds, which can influence

202

reservoir permeability, gas flow and displacement process, is more remarkable than

203

that of shale sediments under same conditions. The buried depth of most mining coal

204

seams is less than 1000 m, and the buried depth of shale reservoir is always more than

205

1000 m with a bigger constraint from surrounding rocks. The TOC content of shale

206

sample is usually less than 10%, whereas coal TOC content is often higher than

207

75%.30 The bigger constraint and the smaller TOC content of shale decrease the

208

impact of the swelling/shrinkage of matrix in in-situ reservoir condition. Another

209

reason is that the porosity of column packed with particles in this study is much

210

bigger than coal core, weakening the effect of gas seepage and diffusion on

211

displacement behavior. 10


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212 100

Mole fraction of CH4, CO2 and N2 in effluent (%)

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Energy & Fuels

90 80 70

CH4 (N2 injection)

60

N2 (N2 injection)

50

CH4 (CO2 injection)

40

CO2 (CO2 injection)

30 20 10 0 0

50

100

150

250

300

350

400

450

500

t/min

213 214

200

Figure 3. Composition variations of produced gas for CO2 injection and N2 injection.

215 216

The time when the mole fraction of CO2 or N2 in effluent increases to 3.0% is

217

defined as breakthrough time (tb). The results of tb are listed in Table 1. Apparently, tb

218

of CO2 is much longer than that of N2, which reveals that injecting CO2 into shale

219

reservoir is favorable for the extraction of CH4 product (CH4 mole fraction in effluent

220

larger than 97%). The recovery of CH4 (R) during displacement process is obtained by

221

Eq. (1): t

R 

222

Foutlet  ct,CH4 dt 0

VoriginalCH4

%

(1)

223

where Voriginal-CH4 is the volume of injected original CH4 recorded by gas-mass flow

224

controller; t is time; Foutlet is the flow rate of outlet and ct,CH4 is mole percentage of

225

CH4 in effluent.

226

Table 1 presents the results of CH4 recovery at time tb (RCH4-product) and at the end

227

of experiment (Rultimate-CH4). RCH4-product is 52.90% for CO2 injection and 41.60% for N2

228

injection. The longer tb can bring about larger RCH4-product. This confirms that one 11


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229

major drawback associated with N2 injection is the early breakthrough of injected N2

230

at producing well, which can rapidly deteriorate the quality of produced gas.

231

Meanwhile, Rultimate-CH4 is 96.91% for CO2 injection and 95.81% for N2 injection. The

232

influence of the species of injection gas on ultimate CH4 recovery is weak. Compared

233

with N2 injection, more adsorbed CH4 is driven into the non-adsorbed/free-gas phase

234

when taking CO2 as displacing fluid. More than 96% recovery of the original gas

235

verifies the feasibility of enhanced CH4 recovery by the injection of CO2 or N2 into

236

gas-bearing shale formations.

237 238

Table 1. Calculated and Simulated Results for N2 Injection and CO2 Injection Injected

tb

RCH4-product

Rultimate-CH4

fluid

(min)

(%)

(%)

N2

120

41.60

95.81

CO2

150

52.90

96.91

KD

Km

Ltransition

(10-7m2/s)

(10-5s-1)

(cm)

0.96

9.29

4.79

51.28

0.80

1.75

4.74

22.26

Fv

239 240

3.1.2. Comparison of Gas Flow Dynamics of CO2 Injection and N2 Injection

241 242

3.1.2.1. Flow and Transport Model for Injected Gas in Gas Shale Reservoir

243 244

Under higher pressure condition, the adsorption amount of injected gas on

245

porous material increases and the effluent composition curve is always asymmetrical

246

with a long tail.36 Regarding to this phenomenon, Coats and Smith have proposed a

247

dispersion-capacitance model based on the assumption that the pore spaces are

248

divided into flowing and stagnant regions to describe the skewed concentration 12


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distribution curve.37 The mass transfer between flowing and stagnant region is mainly

250

dependent on gas diffusion process within pore structure. Many studies have shown

251

the effectiveness of dispersion-capacitance model to explain the tailing feature and

252

have confirmed that the stagnant region is the main reason for the appearance of the

253

longer tail of breakthrough curves.38-40 Meanwhile, stagnant region is the place where

254

competitive adsorption of in-place gas and injected gas takes place.10

255 256

The flowing fraction of the pore spaces (Fv) within shale particle can be described by Eq. (2):40 Fv 

257

Vv Vv  Vs

(2)

258

where Vv is the volume of pore space for the flowing region and Vs is the volume of

259

pore space for the stagnant region.

260 261

The governing transport equations for Coats-Smith dispersion-capacitance model are:38 Fv

262

Cv Cv C  2C v   (1  Fv ) s  K D t x t x 2

(1  Fv )

263

Cs  K m (Cv  Cs ) t

(3)

(4)

264

where Cv is the gas concentration in flowing region; Cs is the gas concentration in

265

stagnant region; x is the distance from inlet; KD is the longitudinal dispersion

266

coefficient and Km is the mass transfer coefficient between mobile and immobile

267

regions.

268

Equations (3) and (4) can be numerically solved by software Matlab 2014a based

269

on experimental data, initial conditions and boundary conditions. The boundary 13


Energy & Fuels

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conditions are as follows.

271

Cv(0,tD)=1, tD≧0

(5a)

272

Cv(∞,tD)=0, tD≧0

(5b)

274

Cv(xD,0)=0, 0≦xD≦1

(6a)

275

Cs(xD,0)=0, 0≦xD≦1

(6b)

273

The initial conditions are:

276

where tD=t/L, dimensionless time; L is the length of adsorption column;  is the

277

mean interstitial velocity; xD=x/L, dimensionless distance.

278 100

Mole percentage of N2 and CO2 in effluent (%)

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90 80 70 60 50 40 30 20

N2 (N2 injection)

10

CO2 (CO2 injection) Coats-Smith dispersion-capacitance fitting

0 0

279 280

50

100

150

200

250

300

350

400

450

500

550

t/min

Figure 4. Simulated and experimental results for CO2 injection and N2 injection.

281 282

The simulated results obtained by Coats-Smith dispersion-capacitance model for

283

CO2 injection and N2 injection are presented in Figure 4. The simulated results match

284

well with the experiment data, which manifests that adopted Coats-Smith

285

dispersion-capacitance model is able to describe the transport and migration of

286

injected CO2 and N2 in shale reservoir. In addition, shale reservoir is a porous media

287

that has wide pore size distribution ranging from 5 nm to 800 nm relating to the shale 14


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formation.10 During the displacement process, a part of injected fluid flows through

289

the connected macropores and fractures where preferential flow paths are formed. In

290

these preferential flow paths, the flowing velocity of injected fluid is high.

291

Meanwhile, another part of injected fluid diffuses into the disconnected micropores

292

where the competitive adsorption takes place. In these disconnected micropores, the

293

flowing velocity of injected fluid is extremely small when compared with the flowing

294

velocity of injected fluid in preferential flow paths. There are two distinct regions in

295

the pore structure of shale based on the flowing velocity of injected fluid during

296

displacement process. This characterization of pore structure is conformed to the

297

assumption of Coats-Smith dispersion-capacitance model, which represents the pore

298

space as flowing and stagnant regions. Therefore, Coats-Smith dispersion-capacitance

299

model is suitable for shale.

300 301

3.1.2.2. Differences of Gas Flow Dynamic between Injected CO2 and Injected N2

302 303

Table 1 lists the results of the parameters of Fv, KD, Km in Coats-Smith

304

dispersion-capacitance model. It is interesting to find that the significant differences

305

between CO2 and N2 are the flowing fraction of the pore spaces Fv and the

306

longitudinal dispersion coefficient KD.

307

The value of Fv for N2 is up to 0.96, whereas Fv for CO2 is only 0.80 under same

308

experiment conditions. Because the competitive adsorption takes place in stagnant

309

region, this result reveals that majority of injected N2 is in the free state in the flowing 15


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310

region to act as a displacing agent to sweep CH4 from mesopores and macropores to

311

micro-fracture network rather than in the adsorbed state in stagnant region to compete

312

with in-place CH4 for adsorption sites, agreeing well with the findings of Wu et al.12

313

Given the fact that CH4 is preferentially adsorbed over N2 with a ratio of up to 3.2:1

314

by molecule on shale,41 the desorption of pre-adsorbed CH4 is mainly dependent on

315

the decrease of CH4 partial pressure due to the continuous N2 injection. Unlike

316

injected N2, more incoming CO2 molecules are in the stagnant region in the

317

micropores within the organics and clay minerals. On the one hand, the ratios of CO2

318

adsorption amount relative to CH4 are on the factor of 5 to 1 on shale.42 On the other

319

hand, unlike the tetrahedron shape of CH4 molecule, CO2 molecule is linear shape and

320

has a smaller kinetic diameter, allowing CO2 molecule to enter into more restricted

321

micropores where the entry of CH4 molecule is not permitted. Previous investigation

322

has found that CO2 molecules can access an additional 40% of the organic pore space

323

compared with CH4 molecules in shale reservoir.43 As a result, more CO2 molecules

324

are retained in the stagnant region to enhance CH4 desorption, resulting in the

325

decrease of Fv and the increase of Rultimate-CH4. Meanwhile, the competitive adsorption

326

reduces the transport rate of injected CO2 and prolongs the timing of CO2

327

breakthrough.

328

It should be noted that the dispersion coefficient KD of N2 is more than 5 times

329

higher than that of CO2. The higher KD leads to the potential excessive mixing of

330

native and injected gas and has substantially negative effect on the recovery of CH4

331

product. Several researches have indicated that the larger dispersion coefficient 16


Page 16 of 44

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

Energy & Fuels

332

accelerates the mixing of injected gas and original gas, shortens the breakthrough time

333

of injected gas and obviously reduces RCH4-product.5,10,18,19,44 Owing to the lower

334

adsorption affinity of N2 on shale, the interaction of N2-shale surface is weaker and

335

the transport rate of N2 is faster. Injected N2 quickly mixes with the free CH4 in the

336

macropores and fractures, resulting in the larger KD. Contrarily, the stronger

337

interaction of CO2-shale surface inhibits CO2 migration in reservoir, leading to the

338

slow mixing of CO2 and CH4, the smaller KD and the longer tb. Meanwhile, the

339

viscosity and density of fluid can also influence the dispersion coefficient.45-47 More

340

time for CO2 retained in reservoir is beneficial to replace the pre-adsorbed CH4 and

341

improve Rultimate-CH4. Taking RCH4-product into consideration, the injection of CO2 into

342

shale formations is more attractive.

343

The mass transfer coefficient Km between flowing and stagnant regions of N2 is a

344

little bigger than that of CO2. The lower affinity of N2 to shale surface facilitates the

345

flow of injected N2, which reduces the thickness of mass transfer boundary layer and

346

increases Km. However, CO2 molecule with smaller kinetic diameter is preferentially

347

access to smaller pores in stagnant region, although the mass transfer boundary layer

348

is thicker. Therefore, the difference of Km between CO2 and N2 is not obvious.

349 350

3.1.3. Concentration Distributions of CO2 and N2 along the Reservoir

351 352

The concentration distributions of CO2 and N2 from the injection well towards

353

producing well at different times in flowing region and stagnant region are shown in 17


Energy & Fuels

354

Figure 5(a) and 5(b), respectively. It is evident that the migrations of injected CO2 and

355

N2 along the adsorption column are different. Especially, in the stagnant region, the

356

difference is more remarkable.

357

As displayed in Figure 5(a) that the concentration distribution of injected CO2

358

along the column is steeper than that of injected N2 in the flowing region, suggesting

359

that the transition zone length of N2 is wider. As injection proceeds, the transition

360

zone length increases. The calculation of average transition zone length (Ltransition) is

361

by Eq. (7).10

362

Ltransition  3.62 K D  tf  tb 

363

where tf is the displacement finish time when mole fraction of CO2 or N2 in effluent

364

reaches to 98%.

(7)

365 0.9 0.8

t=30min (N2)

0.7

t=30min (CO2)

0.6

t=90min (N2)

0.5

t=90min (CO2) t=150min (N2)

0.4

t=150min (CO2)

0.3

t=200min (N2)

0.2

t=200min (CO2)

0.1

t=400min (N2) t=400min (CO2)

0.0 -15

366

1.0

(a)

Mole percentage of N2 and CO2 in stagnant region

1.0

Mole percentage of N2 and CO2 in flowing region

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

Page 18 of 44

-10

-5

0

5

10

15

20

25

30

35

40

45

50

(b)

0.9 0.8 0.7

t=30min (N2)

0.6


0.5

t=90min (CO2)

0.4

t=150min (N2)

0.3

t=150min (CO2) t=200min (N2)

0.2

t=200min (CO2) t=400min (N2)

0.1

t=400min (CO2)

0.0 -20

-15

-10

-5

0

L/cm

5

10

15

20

25

30

35

40

45

50

L/cm

367

Figure 5. Comparison the concentration distributions of CO2 and N2 at different times in flowing

368

region (a) and stagnant region (b).

369 370

The result of Ltransition is listed in Table 1. Ltransition of N2 is 51.28 cm, and Ltransition

371

of CO2 is only 22.26 cm. Ltransition of N2 is two times bigger than that of CO2. The

372

greater KD of injected N2 disturbs the N2 velocity distribution on the displacement 18


Page 19 of 44

373

front and brings about the longer Ltransition.

374

In stagnant region, the migration of injected N2 is faster than injected CO2. The

375

slower transport rate of injected CO2 gives more time for CO2 to replace adsorbed

376

CH4 and thus the CH4 desorption induced by CO2 adsorption is more complete.

377

Meanwhile, the competitive adsorption certainly slows down the increase rate of CO2

378

concentration. Unlike the much steeper concentration curves of CO2 in flowing region

379

than N2 concentration curves, the concentration distributions curves of CO2 are as

380

steep as those of N2 in stagnant region.

381 1.0

(a)



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

Energy & Fuels

0.9 0.8 0.7

x=5cm (N2)

0.6

x=5cm (CO2)

0.5

x=20cm (N2) x=20cm (CO2)

0.4

x=35cm (N2)

0.3

x=35cm (CO2)

0.2

x=50cm (N2)

0.1

x=50cm (CO2)

0.0 0

50

100

150

200

250

300

350

400

450

500

550

(b)

1.0 0.9 0.8 0.7

x=5cm (N2)

0.6

x=5cm (CO2)

0.5

x=20cm (N2)

0.4

x=20cm (CO2)

0.3

x=35cm (N2)

0.2

x=35cm (CO2)

0.1

x=50cm (N2) x=50cm (CO2)

0.0 0

50

100

150

200

250

300

350

400

450

500

382 383

Figure 6. Comparison the concentration distributions of CO2 and N2 at different locations in

384

flowing region (a) and stagnant region (b).

t/min

550

t/min

385 386

The concentration distributions of injected CO2 and N2 at different locations with

387

time in flowing region and stagnant region are shown in Figure 6(a) and 6(b),

388

respectively. The concentrations of CO2 at different locations in flowing region

389

increase quickly than those of N2. This is because the larger KD can make the tailing

390

phenomenon of N2 concentration curve more obvious. In stagnant region, when x is

391

smaller than 20 cm, N2 concentration curves are steeper; when x is larger than 20 cm,

392

the steep degrees of the curves of two gases are similar. The stronger competitive 19


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

393

adsorption between original CH4 and injected CO2 within stagnant region declines the

394

change in CO2 concentration. In addition, it can be seen that at the end of experiment

395

(t=500min), CO2 concentration decreases obviously with the increase in distance x,

396

while the variation of N2 concentration with distance x is not apparent. This

397

phenomenon manifests that the displacement effect near the injection well is the best

398

for CO2 injection, whereas the displacement effect for N2 injection is about the same

399

over the whole reservoir. Meanwhile, the concentration curves of CO2 and N2 in

400

mobile region is steeper than those in immobile region at same locations.

401 402

3.2. Performances of Enhanced Shale Gas Recovery by Injecting CO2/N2 Mixture

403

Gases

404 405

3.2.1. Breakthrough Curves for CO2/N2 Mixture Gases Injection

406 407

Figure 7 shows the composition profiles of the produced gas for three mixture

408

gases injection scenarios. In order to investigate the effect of the proportion of CO2/N2

409

mixture gases on the displacement process, the mixture gases of 80:20/N2:CO2,

410

50:50/N2:CO2 and 20:80/N2:CO2 are selected. Notably, the breakthrough behaviors of

411

N2 and CO2 for mixture gases injection are distinct from those of N2 and CO2 for

412

single component gas injection. The breakthrough curves of produced N2 all exhibit

413

the phenomenon of elevated N2 concentration, i.e., after N2 breakthrough, N2

414

concentration quickly increases to the maximum and then slowly decreases to the feed 20


Page 20 of 44

Page 21 of 44

415

concentration. The occurrence of elevated N2 concentration is also found in the

416

processes of enhanced gas recovery on coalbeds and sandstones by the injection of the

417

mixture of CO2-N2.20-22 Due to the higher affinity of CO2, injected CO2 diffuses

418

preferentially into micropores to displace original CH4, while injected N2 is still in

419

free state in the macropores and fractures. The amount of displaced CH4 is less than

420

that of adsorbed CO2, resulting in the enhancement of N2 concentration in the gas

421

phase.20

(a) 80%N2+20%CO2

90 80 70 60

CH4

50

N2

40

CO2

30 20 10 0 0

50

100

150

200

250

300

424

350

400

450

500

550

600

100

(b) 50%N2+50%CO2

90

CH4

80

N2

70

CO2

60 50 40 30 20 10 0 0

50

100

150

200

250

300

350

400

450

500

550

600

650

t/min

t/min

Mole fraction of CH4, N2 and CO2 in effluent (%)

423

100


422 Mole fraction of CH4, N2 and CO2 in effluent (%)

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

Energy & Fuels

100

(c) 20%N2+80%CO2

90 80 70 60

CH4

50

N2

40

CO2

30 20 10 0 0

50

100

150

200

250

300

350

400

450

500

550

600

t/min

425

Figure 7. Composition variations of produced gas for three different injection scenarios: (a)

426

80:20/N2:CO2, (b) 50:50/N2:CO2 and (c) 20:80/N2:CO2.

427 428

Figure 8 compares the increase degree of N2 concentration for three mixture

429

gases injection cases. The ratio of maximum concentration (Cmax-N2) to the initial 21


Energy & Fuels

430

concentration (Cini-N2) of N2 is defined as the increase degree of N2 concentration. For

431

the injection of 80:20/N2:CO2, the increase degree is lowest. This is because the initial

432

N2 proportion is highest. The difference between CO2 adsorption amount and CH4

433

desorption amount is smallest, causing the slight change of N2 concentration.

434 100

N2 (80 % N2 + 20 % CO2)

90

Mole percentage of N2 in effluent (%)

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

Page 22 of 44

Cmax-N2/Cini-N2=1.07

N2 (50 % N2 + 50 % CO2)

80

N2 (20 % N2 + 80 % CO2)

70


60 50 40


30 20 10 0 0

435 436

50

100

150

200

250

300

350

400

450

500

550

600

650

t/min

Figure 8. Enhancement degree of N2 concentration for mixture gases cases.

437 438

Although for the injection of 50:50/N2:CO2 the difference between CO2

439

adsorption amount and CH4 desorption amount is not largest, the enhancement degree

440

of N2 concentration is highest. On the one hand, when injected N2 and CO2 migrate

441

along the shale reservoir together, injected CO2 quickly adsorbs on shale surface, and

442

non-adsorbed N2 continuously moves to the output well. The larger adsorption

443

amount of CO2 than CH4 desorption amount induces the enhancement of subsequent

444

injected N2 concentration. On the other hand, previous non-adsorbed N2 causes CH4

445

desorption by lowering CH4 partial pressure and also adsorbs on shale surface near

446

the output well. Then injected CO2 will competitively displace adsorbed N2 out of

447

micropores near production well, which also increases the concentration of 22


Page 23 of 44

448

subsequent N2. Thus, combining the factors of the difference in CO2 adsorption

449

amount and CH4 desorption amount at first stage and the subsequent displacement of

450

N2 by CO2, the largest increase of N2 concentration is obtained for the injection of

451

50:50/N2:CO2.

452

For the injection of 20:80/N2:CO2, though CO2 proportion in the mixture is

453

highest, the displaced amount of N2 near the output well is lower, which leads to the

454

moderate enhancement of N2 concentration.

455

breakthrough time (min)

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

Energy & Fuels

456

360 340 320 300 280 260 240 220 200 180 160 140 120 100 80 60 40 20 0

345min

N2 CO2 270min

185min 145min 120min

N2

125min

150min

129min

80:20/N2:CO2 50:50/N2:CO2 20:80/N2:CO2

CO2

457

Figure 9. Breakthrough times of N2 and CO2 for N2 case, CO2 case and CO2/N2 mixture gases

458

cases.

459 460

The breakthrough times of N2 and CO2 for the injections of CO2, N2 and CO2/N2

461

mixture gases are plotted in Figure 9. As shown in Figure 9, tb of N2 for N2 injection

462

is shortest. Accordingly, RCH4-product for N2 injection is lowest. With increasing CO2

463

proportion, tb of N2 in mixture gases case increases, and thereby RCH4-product improves.

464

Compared with tb of N2 for N2 case and mixture gases cases, tb of CO2 for CO2 case is

465

longest, bringing about the biggest RCH4-product for CO2 injection. Injection of CO2-rich 23


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

466

mixtures into shale reservoir helps to gain higher RCH4-product. The main shortcomings

467

of N2 injection are N2 premature breakthrough to the outlet and the decline in

468

RCH4-product.

469

It should also be noted that injecting the mixture of CO2-N2 can considerably

470

prolong tb of CO2. With increasing N2 concentration, tb of CO2 for mixture gases case

471

significantly enhances. For example, tb of CO2 for the injection of 80:20/N2:CO2 is

472

345 min, while tb of CO2 for CO2 injection is only 150 min. This reveals that injection

473

of N2-rich mixtures contributes to prevent the rapid breakthrough of injected CO2 and

474

safely store CO2 into shale sediment over a long term, although the injection of

475

mixture gases reduces the geological sequestration amount of anthropogenic CO2.

476 477

3.2.2. Simulated Results of the Migration of Injected CO2 for Mixture Gases Injection

478 479

The experimental and simulated results of the migration of injected CO2 during

480

mixture gases displacement process are described in Figure 10. It is obvious that the

481

simulated results are in good agreement with the experimental data, suggesting that

482

Coats-Smith dispersion-capacitance model can also describe CO2 migration during

483

mixture gases displacement process. However, the simulated results for mixture gases

484

cases especially for the injection of 50:50/N2:CO2 are worse than those for N2

485

injection and CO2 injection as shown in Figure 4. This may be due to the fact that

486

multicomponent sorption behavior is more complicated. Previous studies also

487

reported that, although excellent matches were obtained for CO2 injection and N2 24


Page 24 of 44

Page 25 of 44

488

injection, the transports of ternary systems were predicted with less accuracy.20,48

489 100

CO2 (80% N2 + 20% CO2)

90

Mole percentage of CO2 in effluent (%)

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

Energy & Fuels

CO2 (50% N2 + 50% CO2)

80

CO2 (20% N2 + 80% CO2)

70

Coats-Smith dispersion-capacitance fitting

60 50 40 30 20 10 0 0

50

100

150

200

250

490 491

300

350

400

450

500

550

600

t/min

Figure 10. Experimental and simulated results of CO2 migration for mixture gases displacement.

492 493

Table 2. RCH4-product and the Fitting Parameters of Fv, KD and Km for CO2 Case, N2 Case and

494

Mixture Gases Cases

Injected fluids

RCH4-product

Fv

(%)

KD

Km

(10-7m2/s)

(10-5s-1)

N2

41.60

0.96

9.29

4.79

80%N2+20%CO2

44.21

0.93

0.17

1.01

50%N2+50%CO2

45.98

0.87

0.19

2.74

20%N2+80%CO2

51.01

0.85

1.35

4.40

CO2

52.90

0.80

1.75

4.74

495 496

The parameters of Fv, KD and Km of CO2 for mixture gases cases are summarized

497

in Table 2. Fv decreases with the increase of CO2 proportion in mixture gases, which

498

manifests that overmuch N2 in mixture gases can hinder CO2 to diffuse into

499

micropores to displace pre-adsorbed CH4. Because the main function of injected N2 is 25


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

500

to reduce CH4 partial pressure and sweep gaseous CH4 out of reservoir, excessive N2

501

gas is unfavorable for the direct displacement of adsorbed CH4. Meanwhile, with

502

increasing CO2 concentration, more CO2 diffuses into stagnant region to enhance

503

competition of CO2-CH4, which can indirectly reduce the migration rate of N2,

504

prolong tb of N2 and obtain larger RCH4-product. When adopting CO2/N2 mixture gases as

505

displacing fluid, the relative ratio of two gases should be considered for different

506

goals such as RCH4-product, CO2 sequestration amount and CO2 sequestration time.

507

KD of CO2 increases obviously as CO2 mole fraction increases. Dispersion

508

coefficient is a key parameter for the economy of enhanced CH4 recovery project.10

509

Lower KD weakens the mixing of CO2 and CH4 and inhibits the rapid breakthrough of

510

injected CO2. Therefore, the injection of N2-rich mixture can effectively prolong tb of

511

CO2 and sequestrate injected CO2 over the long term.

512

Km of CO2 also increases with increasing CO2 concentration. The bigger flow

513

velocity helps to diminish the thickness of mass transfer boundary layer.49 Injected

514

more CO2 into shale reservoir can accelerate the interstitial velocity of CO2 and thus

515

increase Km. The bigger Km promotes the diffusion of CO2 into stagnant, which is

516

good for the recovery of adsorbed CH4 in the micropores.

517 518

3.3. Fluctuation of Flow Rate of Injected Gas for Different Injection Scenarios

519 520

Figure 11 presents the fluctuations of flow rate of injected gas (Finjected-gas) for all

521

displacement experiments. It is obvious that Finjected-gas fluctuates continuously, which 26


Page 26 of 44

Page 27 of 44

522

can serve as an index to evaluate the intensity of the competition adsorption during

523

whole displacement test.

524 200

(a)

200

100% N2

180

140

Finjected-gas (ml/min)

140


160

120

80% N2 + 20% CO2

120

100

100

80

9 ml/min

60

80

11 ml/min

60

40

40

20

20

0

0 0

50

100

150

200

525

250

300

350

400

450

500

0

50

100

150

200

250

300

t/min

200

(c)

350

400

450

500

550

600

t/min

200

50% N2 + 50% CO2

180

20 % N2+ 80% CO2

(d)

180 160

140

140


160

120

120

100

100

13 ml/min

80 60

80

15 ml/min

60

40

40

20

20

0

0 0

526

(b)

180

160


50

100

150

200

250

300

350

400

450

500

550

600

650

0

50

100

150

200

t/min

250

300

350

400

450

500

550

600

t/min

200

100% CO2

(e)

180 160

18 ml/min

140


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

Energy & Fuels

120 100 80 60 40 20 0 0

527

50

100

150

200

250

300

350

400

450

500

550

t/min

528

Figure 11. Fluctuations of the flow rate of injected gas for different injection scenarios: (a) N2, (b)

529

80:20/N2:CO2, (c) 50:50/ N2:CO2, (d) 20:80/ N2:CO2 and (e) CO2.

530 531

The fluctuation range of Finjected-gas is the smallest when taking N2 as injectant. 27


Energy & Fuels

532

According, the intensity of the competition process for CH4-N2 is the weakest. With

533

increasing CO2 concentration, the fluctuation range of Finjected-gas gradually enlarges.

534

When injecting CO2 into shale reservoir, the fluctuation range of Finjected-gas is the

535

largest. The intensity of the competition process is enhanced with the injection of

536

large amounts of CO2. Thus, the fluctuation range of Finjected-gas rises and Rultimate-CH4

537

improves. In addition, it can find that the average value of Finjected-gas also ascends as

538

CO2 concentration increases as described in Figure 11.

539 120

T = 318 K

110 100 90 80 3

Density (kg/m )

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

Page 28 of 44

70 60 50 40 30

50% CO2+50% CH4

20

25% CO2+25% N2+50% CH4

10

50% N2+50% CH4

0 0

540

1

2

3

4

5

6

7

8

P (MPa)

541

Figure 12. Densities of the mixture gases as a function of pressure at 318 K (as obtained from the

542

NIST REFPROP database, version 8.0).

543 544

The differences between Finjected-gas for N2 case, CO2 case and mixture gases

545

cases can be ascribed to two reasons. One reason is that the adsorption capacity of N2

546

on shale is lower than that of CO2. With increasing CO2 proportion, more gas adsorbs

547

in pore system and is needed to inject into reservoir to maintain reservoir pressure.

548

Another reason is that the changes of the density of mixture gases are different.

549

During the displacement process, there are the mixture gases in adsorption column. In 28


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

Energy & Fuels

550

order to illustrate the effect of the density change of mixture gases on Finjected-gas, we

551

take the mixture gases of 50:50/CO2:CH4, 25:25:50/CO2:N2:CH4 and 50:50/N2:CH4 as

552

example. The density changes of three mixture gases with pressure at 318 K are

553

shown in Figure 12. As can be seen from Figure 12 that the density change of

554

50:50/CO2:CH4 is the largest, and the density change of 50:50/N2:CH4 is the smallest.

555

Increasing CO2 mole fraction can enlarge the density change of mixture gases.

556

Therefore, injecting CO2 will result in the largest fluctuation range of Finjected-gas.

557

Accordingly, with the decrease in the CO2 feed concentration, the fluctuation range of

558

Finjected-gas becomes smaller. In addition, the advantage of using N2 as injectant is that

559

injecting less N2 can maintain reservoir pressure at a higher value.

560 561

3.4. Storage Capacity of Injected CO2 for CO2 Case and Mixture Gases Cases

562 563

The sequestration capacity of CO2 is also needed to take into consideration for

564

the goal of mitigating the effect of global warming. In this study, the amount of stored

565

CO2 in shale reservoir (Vstorage-CO2) during the displacement process was decided by

566

Eq. (8).

567

t

VstorageCO2  Vt,injectedCO2  Foutlet  ct,CO2 dt 0

(8)

568

where Vt,injected-CO2 is the volume of injected CO2 recorded by syringe pump at time t

569

and ct,CO2 is CO2 mole percentage in effluent at time t.

570

29


Energy & Fuels

12

100% CO2

10

80% CO2+20% N2 50% CO2+50% N2

8

Vstorage-CO2 (L)

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

Page 30 of 44

20% CO2+80% N2 6 4 2 breakthrough time

0 0

571

50

100

150

200

250

300

350

400

450

500

550

t/min

572

Figure 13. Amounts of CO2 stored in reservoir as a function of time for CO2 case and mixture

573

gases cases.

574 575

As shown in Figure 13, at the initial stage of the injection, Vstorage-CO2 increases

576

sharply. To enhance reservoir pressure from 5.03 MPa to 8.00 MPa, lots of gas is

577

needed to inject into adsorption column in the first few minutes. Liu et al. also found

578

that the displacement of pre-adsorbed CH4 by injected CO2 on shale was faster in the

579

previous 1.5 h.50 As the injection proceeds, the adsorption rate of CO2 gradually

580

decreases,51 and thus the increase rate of Vstorage-CO2 begins to slow down. Finally,

581

Vstorage-CO2 reaches to a maximum value. Moreover, Vstorage-CO2 and the increase rate of

582

Vstorage-CO2 all improve when the injectant is increasingly enriched with CO2 gas.

583

Injecting CO2 into shale reservoir results in the highest Vstorage-CO2 and the biggest

584

increase rate of Vstorage-CO2, which suggests that injecting CO2 has the advantage to

585

accelerate and maximize the storage of anthropogenic CO2. Previous research has

586

indicated that the difference between the sequestration capacities of CO2 on coal by

587

the injections of CO2 and mixture of CO2-N2 is not very large when the permeability 30


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

Energy & Fuels

588

of coal decreases obviously during CO2 injection.22 However, in this investigation, the

589

increase of Vstorage-CO2 is extremely obvious when taking CO2 as displacing fluid. This

590

reveals that the swelling of shale matrix during displacement process is much smaller,

591

and the swelling effect of matrix has little influence on shale permeability and

592

Vstorage-CO2.

593 594

4. CONCLUSIONS

595 596

The performances of enhanced shale gas recovery by the injections of CO2, N2

597

and CO2/N2 mixture gases were investigated on a fixed bed experiment setup. The

598

influence of the types of displacing gas on CH4 recovery and gas flow dynamics was

599

discussed. The main conclusions are as follows:

600

(1) The injection of N2 leads to the shortest tb of injected gas and lowest

601

RCH4-product of 41.60%, while injecting CO2 results in the longest tb of injected gas and

602

highest RCH4-product of 52.90% with a sharp displacement front. Coats-Smith

603

dispersion-capacitance model can fit the breakthrough curves of N2 and CO2 well for

604

N2 injection and CO2 injection. The differences in Fv and KD in Coats-Smith

605

dispersion-capacitance model are the underlying reasons for the distinct behaviors of

606

CO2 injection and N2 injection.

607

(2) RCH4-product increases with increasing CO2 proportion in the mixture of

608

CO2-N2. The phenomena of elevated N2 concentration in gas phase are found for all

609

mixture gases injection schemes, which can be attributed to the competitive 31


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

610

adsorption of CH4, CO2 and N2. Injecting 50:50/N2:CO2 mixture gases shows the

611

highest enhancement of N2 concentration. Taking N2-rich gases as injectant can

612

obviously prevent CO2 premature breakthrough. tb of CO2 for the injection of

613

80:20/N2:CO2 is 345 min, while tb of CO2 for CO2 injection is only 150 min. Fv of

614

CO2 decreases, and KD and Km of CO2 increase with the increase of CO2 feed

615

concentration.

616

(3) Finjected-gas can serve as an index to evaluate the intensity of competition

617

process. With the increase of CO2 proportion in mixture, Finjected-gas increases.

618

Finjected-gas for N2 injection is the smallest and Finjected-gas for CO2 injection is the

619

biggest. Vstorage-CO2 and the increase rate of Vstorage-CO2 also enhance with increasing

620

CO2 concentration. Vstorage-CO2 for CO2 injection is 11.82 L, while Vstorage-CO2 for the

621

injection of 80:20/N2:CO2 is only 1.57 L. Injecting CO2-rich gases into shale reservoir

622

is favorable for the storage of a large amount of CO2.

623

According to the discussion above, we can find that the injection of CO2 can

624

maximize the recovery of CH4 product and the sequestration amount of injected CO2,

625

while the injection of CO2/N2 mixture gases helps to prolong the breakthrough time of

626

CO2 and sequestrate injected CO2 over a long term. For the future application of the

627

technology of enhanced shale gas recovery by gas injection, the selection of

628

displacing fluid and the ratio of CO2/N2 mixture gases should be taken into

629

consideration for the different goals such as RCH4-product, Vstorage-CO2 and CO2

630

sequestration time.

631 32


Page 32 of 44

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632

Energy & Fuels

ACKNOWLEDGMENTS

633 634

This work was supported by the Major State Basic Research Development Program of

635

China (973 Program, grant no. 2014CB239204), Chongqing Science and Technology

636

Commission Projects (grant no. cstc2017jcyj-yszx0012 and cstc2018jcyj-yszx0016)

637

and Special Youth Project of Science and Technology Innovation Enterprise Capital

638

of China Coal Technology Engineering Group Co., Ltd. (grant no. 2018-2-QN016).

639 640

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641

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(2) Pan, Y.; Hui, D.; Luo, P. Y.; Zhang, Y.; Sun, L.; Wang, K. Energy Fuels 2018, 32, 1963-1978.

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(4) Pei, P.; Ling, K. G.; He, J.; Liu, Z. Z. J. Nat. Gas Sci. Eng. 2015, 26, 1595-1606.

645

(5) Du, X. D.; Gu, M.; Duan, S.; Xian, X. F. ASME J. Energy Res. Technol. 2017, 140(1),

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(13) Duan, S.; Gu, M.; Du, X. D.; Xian, X. F. Energy Fuels 2016, 30, 2248-2256.

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(14) Yin, H.; Zhou, J. P.; Jiang, Y. D.; Xian, X. F.; Liu, Q. L. Fuel 2016, 184, 289-303.

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(20) Jessen, K.; Tang, G. Q.; Kovscek, A. R. Transp. Porous Med. 2008, 73, 141-159.

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(21) Sim, S. S. K.; Turta, A. T.; Singhal, A. K.; Hawkins, B. F. J. Can. Petrol. Technol. 2009,

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(22) Pini, R.; Storti, G.; Mazzotti, M. Adsorption 2011, 17, 889-900.

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(23) Zhou, F. D.; Hussain, F.; Cinar, Y. Int. J. Coal Geol. 2013, 116-117, 53-62.

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(24) Ranathunga, A. S.; Perera, M. S. A.; Ranjith, P. G.; Wei, C. H. Fuel 2017, 189, 391-399.

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(27) Shi, J. Q.; Durucan, S. SPE Reservoir Evaluation & Engineering, 2005, 291-299.

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(28) Bustin, R. M.; Cui, X. J.; Chikatamarla, L. Am. Assoc. Pet. Geol. Bull. 2008, 92, 15-29.

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(29) Tang, X.; Ripepi, N.; Valentine, K. A.; Keles, C.; Long, T.; Gonciaruk, A. Fuel 2017, 209,

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606-614. (30) Edwards, R. W. J.; Celia, M. A.; Bandilla, K. W.; Doster, F.; Kanno, C. M. Environ. Sci. Technol. 2015, 49, 9222-9229.

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(31) Heller, R.; Zoback, M. Journal of Unconventional Oil and Gas Resources 2014, 8, 14-24.

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(32) Gu, M.; Xian, X. F.; Duan, S.; Du, X. D. J. Nat. Gas Sci. Eng. 2017, 46, 296-306.

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(33) Tian, H.; Li, T. F.; Zhang, T. W.; Xiao, X. M. Int. J. Coal Geol. 2016, 156, 36-49.

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(34) Hu, H.; Zhang, T.; Wiggins-Camacho, J. D.; Ellis, G. S.; Lewan, M. D.; Zhang, X. Mar. Pet.

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(36) Van Genuchten, M. T. Non-equilibrium transport parameters from miscible displacement

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(37) Coats, K. H.; Smith, B. D. Society of petroleum engineers journal 1964, 4(1), 73-84.

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(38) Batycky, J. P.; Maini, B. B.; Fisher, D. B. Society of Petroleum Engineers Journal 1982,

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(42) Godec, M.; Koperna, G.; Petrusak, R.; Oudinot, A. Int. J. Coal Geol. 2013, 118, 95-104.

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(43) Liu, F. Y.; Ellett, K.; Xiao, Y. T.; Rupp, J. A. Int. J. Greenh. Gas Con. 2013, 17, 111-126.

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(44) Honari, A.; Bijeljic, B.; Johns, M. L.; May, E. F. Int. J. Greenh. Gas Con. 2015, 39, 39-50.

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(45) Nunge, R. J.; Gill, W. N. Industrial and Engineering Chemistry, 1969, 61(9), 33-49.

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(46) Greenkorn, R. A.; Kessler, D. P. Industrial and Engineering Chemistry, 1969, 61(9), 14-32.

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(47) Perkins, T. K.; Johnston, O. C. Society of Petroleum Engineers Journal, 1963, 3(1), 70-84

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(48) Connell, L. D.; Sander, R.; Pan, Z.; Camilleri, M.; Heryanto, D. Int. J. Coal Geol. 2011, 87,

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(50) Liu, J.; Yao, Y. B.; Liu, D. M.; Elsworth, D. Int. J. Coal Geol. 2017, 179, 211-218.

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(51) Luo, X. R.; Wang, S. Z.; Wang, Z. G.; Jing, Z. F.; Lv, M. M.; Zhai, Z. D.; Han, T. Int. J. Coal

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Geol. 2015, 150-151, 210-223.

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

Energy & Fuels

Enhanced Shale Gas Recovery by the Injections of CO2, N2 and CO2/N2 Mixture Gases

Xidong Du a,b,c, Min Gu a,b,, Zhenjian Liu a,b, Yuan Zhao d, Fulong Sun e,f, Tengfei Wu e,f a

State Key Laboratory of Coal Mine Disaster Dynamics and Control, Chongqing University,

Chongqing, 400044, China b

College of Resources and Environmental Science, Chongqing University, Chongqing 400044,

China c

School of Earth Sciences, East China University of Technology, Nanchang, Jiangxi 330013,

China d

Sinohydro Bureau 8 Co. LTD., POWERCHINA, Changsha 410004, China

e

China Coal Technology and Engineering Group Shenyang Research Institute, Fushun 113122,

China f

State Key Laboratory of Coal Mine Safety Technology, Fushun 113122, China



Corresponding author. Tel.:+86 15922640072; fax:+86 23 65105719 E-mail address: [email protected] (Gu Min) 1


Energy & Fuels

pressure

pressure regulator

data collector

P transducer gas-mass flow controller

thermostatic water bath syringe pump reference column

CH4

N2

CO2

gas-mass flow controller gas chromatography

adsorption column

vacuum pump

Figure 1. Schematic diagram of the experiment apparatus.

100

Mole fraction of CH4 and CO2 in effluent (%)

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

Page 38 of 44

90 80

Exp. 1 (CH4)

70

Exp. 1 (CO2) Exp. 2 (CH4)

60

Exp. 2 (CO2)

50 40 30 20 10 0 0

50

100

150

200

250

300

350

400

450

500

550

t/min

Figure 2. Reproducibility of CO2-CH4 displacement experiment.

2


Page 39 of 44

Mole fraction of CH4, CO2 and N2 in effluent (%)

100 90 80 70

CH4 (N2 injection)

60

N2 (N2 injection)

50

CH4 (CO2 injection)

40

CO2 (CO2 injection)

30 20 10 0 0

50

100

150

200

250

300

350

400

450

500

t/min

Figure 3. Composition variations of produced gas for CO2 injection and N2 injection.

100

Mole percentage of N2 and CO2 in effluent (%)

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

Energy & Fuels

90 80 70 60 50 40 30 20

N2 (N2 injection)

10

CO2 (CO2 injection) Coats-Smith dispersion-capacitance fitting

0 0

50

100

150

200

250

300

350

400

450

500

550

t/min

Figure 4. Simulated and experimental results for CO2 injection and N2 injection.

3


Energy & Fuels

1.0

(a)



1.0 0.9 0.8

t=30min (N2)

0.7

t=30min (CO2)

0.6

t=90min (N2)

0.5


0.4

t=150min (CO2) 0.3

t=200min (N2)

0.2

t=200min (CO2)

0.1

t=400min (N2) t=400min (CO2)

0.0 -15

-10

-5

0

5

10

15

20

25

30

35

40

45

(b)

0.9 0.8 0.7

t=30min (N2)

0.6


0.5

t=90min (CO2)

0.4

t=150min (N2)

0.3

t=150min (CO2) t=200min (N2)

0.2

t=200min (CO2)

0.1

t=400min (N2) t=400min (CO2)

0.0 -20

50

-15

-10

-5

0

5

L/cm

10

15

20

25

30

35

40

45

50

L/cm

Figure 5. Comparison the concentration distributions of CO2 and N2 at different times in flowing region (a) and stagnant region (b).

1.0

(a)



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

Page 40 of 44

0.9 0.8 0.7

x=5cm (N2)

0.6

x=5cm (CO2)

0.5

x=20cm (N2) x=20cm (CO2)

0.4

x=35cm (N2)

0.3

x=35cm (CO2)

0.2

x=50cm (N2)

0.1

x=50cm (CO2)

0.0 0

50

100

150

200

250

300

350

400

450

500

550

(b)

1.0 0.9 0.8 0.7

x=5cm (N2)

0.6

x=5cm (CO2)

0.5

x=20cm (N2)

0.4

x=20cm (CO2)

0.3

x=35cm (N2)

0.2

x=35cm (CO2)

0.1

x=50cm (N2) x=50cm (CO2)

0.0 0

50

100

150

200

t/min

250

300

350

400

450

500

t/min

Figure 6. Comparison the concentration distributions of CO2 and N2 at different locations in flowing region (a) and stagnant region (b).

4


550


100

(a) 80%N2+20%CO2

90 80 70 60

CH4

50

N2

40

CO2

30 20 10 0 0

50

100

150

200

250

300

350

400

450

500

550

600

100

(b) 50%N2+50%CO2

90 80

CH4

70

N2

60

CO2

50 40 30 20 10 0 0

50

100

150

200

250


300

350

400

450

500

550

600

650

t/min

t/min 100

(c) 20%N2+80%CO2

90 80 70 60

CH4

50

N2

40

CO2

30 20 10 0 0

50

100

150

200

250

300

350

400

450

500

550

600

t/min

Figure 7. Composition variations of produced gas for three different injection scenarios: (a) 80:20/N2:CO2, (b) 50:50/N2:CO2 and (c) 20:80/N2:CO2.

100

N2 (80 % N2 + 20 % CO2)

90

Mole percentage of N2 in effluent (%)

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

Energy & Fuels


Page 41 of 44


N2 (50 % N2 + 50 % CO2)

80

N2 (20 % N2 + 80 % CO2)

70


60 50 40


30 20 10 0 0

50

100

150

200

250

300

350

400

450

500

550

600

650

t/min

Figure 8. The enhancement degree of N2 concentration for mixture gases cases. 5


360 340 320 300 280 260 240 220 200 180 160 140 120 100 80 60 40 20 0

Page 42 of 44

345min

N2 CO2 270min

185min 150min

145min 120min

N2

125min

129min

80:20/N2:CO2 50:50/N2:CO2 20:80/N :CO 2 2

CO2

Figure 9. Breakthrough times of N2 and CO2 for N2 case, CO2 case and CO2/N2 mixture gases cases.

100

CO2 (80% N2 + 20% CO2)

90

Mole percentage of CO2 in effluent (%)

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

breakthrough time (min)

Energy & Fuels

CO2 (50% N2 + 50% CO2)

80

CO2 (20% N2 + 80% CO2)

70

Coats-Smith dispersion-capacitance fitting

60 50 40 30 20 10 0 0

50

100

150

200

250

300

350

400

450

500

550

600

t/min

Figure 10. Experimental and simulated results of CO2 migration for mixture gas displacement.

6


Page 43 of 44

200

(a)

200

100% N2

160

160

140

140


180


180

120

(b)

80% N2 + 20% CO2

120

100

100

80

9 ml/min 60

80

11 ml/min 60

40

40

20

20

0

0 0

50

100

150

200

250

300

350

400

450

500

0

50

100

150

200

250

300

t/min

200

(c)

350

400

450

500

550

600

t/min

200

50% N2 + 50% CO2

180

160

160

140

140


180


120

20 % N2+ 80% CO2

(d)

120

100

100

13 ml/min

80 60

80

15 ml/min 60

40

40

20

20

0

0 0

50

100

150

200

250

300

350

400

450

500

550

600

650

0

50

100

150

200

t/min

250

300

350

400

450

500

550

600

t/min

200

100% CO2

(e)

180 160

18 ml/min

140


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

Energy & Fuels

120 100 80 60 40 20 0 0

50

100

150

200

250

300

350

400

450

500

550

t/min

Figure 11. Fluctuations of the flow rate of injected gas for different injection scenarios: (a) N2, (b) 80:20/N2:CO2, (c) 50:50/ N2:CO2, (d) 20:80/ N2:CO2 and (e) CO2.

7


Energy & Fuels

120

T = 318 K

110 100 90

3

Density (kg/m )

80 70 60 50 40 30

50% CO2+50% CH4

20

25% CO2+25% N2+50% CH4

10

50% N2+50% CH4

0 0

1

2

3

4

5

6

7

8

P (MPa)

Figure 12. Densities of the mixture gases as a function of pressure at 318 K (as obtained from the NIST REFPROP database, version 8.0).

12

100% CO2

10

80% CO2+20% N2 50% CO2+50% N2

8

Vstorage-CO2 (L)

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

Page 44 of 44

20% CO2+80% N2 6

4

2 breakthrough time

0 0

50

100

150

200

250

300

350

400

450

500

550

t/min

Figure 13. Amounts of CO2 stored in reservoir as a function of time for CO2 case and mixture gases cases.

8


Enhanced Shale Gas Recovery by the Injections of CO2, N2 and CO2

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