Experimental and Numerical Study on CO2 Sweep Volume during

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Experimental and Numerical Study on CO2 Sweep Volume during CO2 Huff-n-Puff EOR Process in Shale Oil Reservoirs Lei Li, Yuliang Su, James J. Sheng, Yongmao Hao, Wendong Wang, Yuting Lv, Qingmin Zhao, and Haitao Wang Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.9b00164 • Publication Date (Web): 16 Apr 2019 Downloaded from http://pubs.acs.org on April 17, 2019

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Energy & Fuels

1

Experimental and Numerical Study on CO2 Sweep Volume during CO2 Huff-

2

n-Puff EOR Process in Shale Oil Reservoirs

3

Lei Li a,b, Yuliang Su a,b, James J. Sheng c, Yongmao Hao a, Wendong Wang a, Yuting Lv d,Qingmin Zhao e, Haitao Wang e

4 5 6 7 8 9 10 11 12

Ministry of Education, Qingdao China, 266580

13

ABSTRACT

14

CO2 huff-n-puff has been proved to be the most effective enhanced oil recovery (EOR) method in shale

15

oil reservoirs. The injected CO2 will replenish reservoir energy and penetrate the reservoir matrix to

16

extract oil. However, the CO2 sweep volume during the huff-n-puff process hasn’t been accurately

17

evaluated by existing studies. In this paper, the CO2 sweep volume was investigated through

18

experimental and numerical simulation methods. In the experimental study, the CO2 sweep areas were

19

depicted by X-ray computed tomography (CT) scan technology. The results indicated that the ratio of

20

CO2 sweep area was 78.63% in the seventh huff-n-puff cycle, leading to a total oil recovery of 56.80%.

21

The numerical simulation considered the mechanisms of molecular diffusion and nanopore confinement.

22

The results showed that in the first huff-n-puff cycle, the gas sweep volume percentage was 9.47% after

23

100 days’ huff period. In the gas swept volume, oil viscosity was reduced by 25.9% to 68.2%. After

24

three cycles of CO2 injection, the oil recovery manifested a 1.5% increase to the case without huff-n-

25

puff. The contributions of different parameters on gas sweep volume and cumulative oil recovery were

26

investigated. The results illustrated that the nanopore confinement effect and molecular diffusion had

27

significant impacts on the gas sweep volume and cumulative oil recovery. Higher injection pressure,

28

longer huff time, and more huff-n-puff cycles lead to larger gas sweep volume, as well as cumulative

29

oil recovery. A suitable primary depletion period and a huff-n-puff schedule should be determined based

30

on the requirements of field production. The investigations in this study provide insights to better

31

understand the EOR mechanisms and optimize the design of CO2 huff-n-puff operations in shale oil

32

reservoirs.

33

1. INTRODUCTION

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In the past decade, the development of hydraulic fracturing technology and the reduced cost of the

35

horizontal well made it possible to produce shale oil economically.1-3 According to Annual Energy

36

Outlook 2017, tight oil production has increased significantly since 2010, comprising more than a third

a

School of Petroleum Engineering, China University of Petroleum (East China), Qingdao, Shandong, China,

266580 b

Key Laboratory of Unconventional Oil & Gas Development (China University of Petroleum (East China)),

c

Department of Petroleum Engineering, Texas Tech University, Lubbock, TX, USA, 79401 College of mechanical and electronic engineering, Shandong University of Science and Technology, Qingdao, 266590 d

e

Sinopec Exploration and Production Research Institute, Beijing, China, 100083

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of the onshore production of crude oil in the lower 48 states.4,5 Earlier in December 2018, the EIA

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released that the shale oil production for this month raised to 8.032 million barrels per day in United

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States.6,7 However, there are still major issues to be addressed: high initial rates drop off very quickly,8

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and oil recovery factors normally are less than 10% in shale plays. Therefore, it is imperative to enhance

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oil recovery in the hydraulic fractured shale oil reservoir. To replenish reservoir pressure, engineers

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inject some fluids into the reservoir, such as water, gas and polymer fluid. Generally, the secondary oil

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recovery is low because the displacing fluids hardly sweep into the reservoir pores.9 Waterflooding has

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a poor sweep efficiency in shale reservoirs due to the ultra-low reservoir permeability.10,11 Gas will

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break through the hydraulic fractures, leading to a low sweep efficiency. Thus, the method CO2 huff-n-

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puff injection, using the same well as both the production and the injection well, was applied to enhance

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oil recovery.12-19 The method has been proved effective both in conventional oil reservoir20-22 and in lab

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experimental tests of shale core samples.23-36 Using this method, the injected CO2 penetrates the

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reservoir matrix and diffuses into the shale oil. Meanwhile, shale reservoir rock will adsorb and trap the

50

CO2 during this process. Therefore, CO2 huff-n-puff is also a feasible way to utilize and sequestrate the

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released CO2 caused by the consumption of fuels.37-39

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The purpose of CO2 huff-n-puff injection is to enlarge the gas-oil contact area to enhance gas sweep

53

efficiency. In the gas penetrated region, the reservoir pressure increases, oil-gas interfacial tension

54

decreases, and oil viscosity declines. All these lead to high displacement efficiency. However, the above

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mechanisms only work well in the gas swept volume. Thus, it is essential to investigate the gas sweep

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volume or gas penetration area in shale reservoirs during the huff-n-puff process. The tests in the

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previous literature discussed the effects of operating parameters such as injection cycles, injection

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pressure, injection gases, depletion rate, soaking time and other variables on gas huff-n-puff.10,12,14,35,40-45

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However, few articles investigate the gas sweep volume, which is the key parameter to enhance oil

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recovery in shale reservoir during gas injection. Tracking the gas swept volume in experiments is tough.

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Nowadays, some scientists apply CT scanning image technology on the process of gas penetration to

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check the CT number changes, which reflect the density of the core plug.27,46-48 As the CT number has

63

a linear relationship with density, and the oil density is higher than gas density, CT scan technology can

64

be utilized to describe the fluid variation in core plugs. Kovscek et al.46 applied the CT scan to help

65

visualize two-phase flow and fluid distribution during CO2 flowing through the siliceous shale core

66

plug. The core plug permeability is 0.02-1.3mD, and porosity is 30-40%. Adel et al. conducted and

67

recorded the core saturation process using the ultra-low permeability shale core.47 During the oil

68

saturation, the CT number increased as the oil penetrated the core. Tovar et al. presented the CT scan

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images which show the changes in the CT number during crude oil saturation process as a function of

70

time for core plugs from the Barnett Shale.48 Within hours of CO2 injection, the CT number changes as

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CO2 begins penetrating the organic-rich shale core plug. Li and Sheng proposed the CT number method

72

to calculate the oil recovery in each huff-n-puff cycle.27 However, the gas sweep area was not discussed

73

quantitatively in previous articles. In this study, we conducted CO2 huff-n-puff experiment on the ultra2 ACS Paragon Plus Environment

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low permeability Eagle Ford core plug, and applied the CT scan to describe the gas swept region

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quantitatively.

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However, the gas sweep region in core plugs in the lab experiment cannot represent the situation in

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field production due to the immense size difference. In our previous work, we conducted a series of

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huff-n-puff experiments with different core sizes and found that the core with a larger diameter yielded

79

a lower oil recovery.27 The oil recovery in lab experiments could reach 50% to 60%,24,31,40,47,48 whereas

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the oil recovery is still less than 20% in field scale production.12,14,16,42,49 Thus, numerical simulation is

81

needed to investigate the gas penetration in the field size. Field scale simulation has been discussed by

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many researchers, who have explored the effect of operating parameters on oil recovery including

83

soaking time, injection rate, miscible condition, CO2 diffusivity and number of huff-n-puff

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cycles.16,25,31,41-45,50,51 But few articles discussed the CO2 sweep volume in the reservoir and the

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mechanisms of CO2-shale oil action in the gas penetrated region. In this work, a dual permeability model

86

was applied to evaluate the gas sweep volume in the field case. We considered the mechanisms of

87

molecular diffusion and nanopore confinement on phase behavior in shale oil reservoirs in the

88

simulation model. The effects of different parameters on gas sweep volume and CO2 huff-n-puff

89

performance were investigated.

90

2. EXPERIMENTAL SECTION

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2.1. Experimental Materials. The core plug used in this study is obtained from Eagle Ford

92

formation with dimensions of 1.5 inches in diameter and 2 inches in length. The crude oil is from

93

Wolfcamp formation with a viscosity of 2.35 cp at room temperature (72°F) and atmosphere pressure

94

(14.7 psi). The oil composition is presented in Table 1. The permeability and porosity of the core plug

95

are measured to be 240 nD and 7.28% by pulse method with helium. The initial pressure of the CO2 gas

96

(purity of > 99%) is 850 psi.

97

Table 1. Components of Wolfcamp Dead Crude Oil Components

C3-4

C5-6

C7-8

C9-14

C15-21

C22-40

C41+

Mol. Fraction

0.02%

7.29%

23.50%

37.87%

16.50%

6.61%

8.21%

98

2.2. CO2 Huff-n-Puff Experiment. The experimental setup used in this work is designed and

99

modified based on our previous studies.48,51,52 The schematic of CO2 huff-n-puff experiment is shown

100

in Figure 1. The experimental scheme comprises of a pumping system, an accumulator, a CO2 tank, a

101

huff-n-puff vessel equipped with CT scan, and an oil-gas separator. The huff-n-puff container is the

102

heart of the setup. The shale core sample is put horizontally in the huff-n-puff vessel. A high

103

permeability media created by glass beads of 2 mm of diameter is placed into the vessel around the core

104

sample to imitate shale reservoir matrix surrounding by fractures. Then the huff-n-puff vessel is

105

positioned inside the CereTom (CT) scanner to monitor the density changes in the core sample during

106

the test. The pumping system works with the accumulator and the CO2 tank to increase CO2 pressure.

107

The oil-gas separator consists of a container of 10 ml filled with absorbent cotton to record the oil 3 ACS Paragon Plus Environment

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2.3. Experimental results and calculation of gas swept area. The weights of dry core plug and

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oil saturated core plug are 123.2952g and 126.5509g, respectively. The saturated oil is calculated to be

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3.2557g. The calculated porosity by the weight of saturated oil is 7.10%, which is similar to the helium

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porosity of 7.28%. It illustrates that the core plug is fully saturated with crude oil. The produced oil,

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enhanced oil recovery, and gas swept area ratio results are shown in Table 2. After seven huff-n-puff

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cycles, the cumulative oil recovery is 56.8%, and the swept area ratio is 78.63%. The oil recovery in

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the first cycle is the highest which is 13.18%, and then decreases as the injection cycle increases. In this

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study, CT scan recorded the density changes inside the core to reflect the gas swept area. Figure 3

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presents the changes in CT images and the depicted CO2 swept area (in black) during the huff time of

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cycle 3. The scale in Figure 3 is in terms of Hounsfield units (HU), commonly referred to as the CT

134

number. CT number is in a linear relationship with density. The density is different if the pore is

135

saturated with different proportional oil or gas, and therefore the CT number changes. As measured, the

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CT number for the crude oil is -184 HU, for water is 0 HU, and for air is -1000 HU.27 The red areas in

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Figure 3 a-c are the selected areas with a threshold of the gas swept region in core center. Figure 3 d-

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f draws the gas swept region and labeled with the calculated ratio of swept area to the core transection

139

area. It illustrates that at the beginning of the huff period of cycle 3, 51.98% of the transection area is

140

invaded by CO2 gas. After 1 hour’s CO2 injection, the swept area ratio reaches 62.10%, and the swept

141

area ratio is 64.01% at the end of huff time. It illustrates that injected gas penetrates fast in the first

142

hour’s huff period and then sweeps slowly. To check the gas swept area in different cycles, Figure 4

143

presents the CT images and the depicted CO2 swept area for cycle 1, cycle 5, and cycle 7 at the end of

144

huff time. The results show that more huff-n-puff cycles lead to a larger sweep area. The sweep area

145

ratio increases faster in the first three cycles.

146

Table 2. The Produced Oil and Enhanced Oil Recovery Results Injected cycle

Cycle 1

Cycle 2

Cycle 3

Cycle 4

Cycle 5

Cycle 6

Cycle 7

Oil produced in each cycle, g

0.4290

0.3140

0.2945

0.2615

0.2635

0.1612

0.1254

Cumulative produced oil, g

0.4290

0.7430

1.0375

1.2990

1.5625

1.7237

1.8491

Oil recovery in each cycle, %

13.18

9.64

9.05

8.03

8.09

4.95

3.85

Cumulative oil recovery, %

13.18

22.82

31.87

39.90

47.99

52.94

56.80

Swept ratio, %

40.13

55.14

64.01

70.25

74.81

76.88

78.63

147

One thing that should be noted is the injected CO2 distributes heterogeneously in the core as shown

148

in Figure 3 and Figure 4. The core plug is drilled in a horizontal direction. There’re some relatively

149

high permeability zones or microfractures in the bedding during the reservoiring process. The injected

150

gas will first penetrate the microfractures and then infiltrate into the low permeability core matrix under

151

concentration and pressure gradient. In some regions, the microfractures are not developed, the

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permeability is extremely low, and some pores are barely connected. Thus the injected CO2 is difficult

153

to penetrate these areas. The results indicate the microfractures have a positive effect on gas penetration.

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The microfractures provide more contact areas between the injected gas and crude oil, and help the

155

injected CO2 flow inside the matrix. In the penetrated region, CO2 has a series of reactions with the 5 ACS Paragon Plus Environment

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192

where Dij is the binary diffusion coefficient between component i and j in the mixture, ) is the molar

193

density of the diffusing mixture, and )0 is the reduced density, )0

194

density-diffusivity product.

0 '(

is the zero-pressure limit of the

195

3.1.2. Nanopore Confinement Effect. For shale oil reservoirs, one big difference from

196

conventional oil reservoirs is that the pore sizes in shale are on the order of tens of nanometers.58,59

197

According to the previous study, the interaction between molecular and pore walls is significant in

198

nanopores especially when the pore diameter is less than 10 nm.60-64 The relative critical-pressure or

199

critical-temperature of the molecular in nanopores are shifted from bulk properties, which can be

200

calculated using the following equations developed by Ma et al.63 and Jin et al.65: 6 56 =

6

6 56 =

5

6

7

6

8

= 0.6

8

for

7

9eff

9eff

> 1.5

(3)

< 1.5

(4)

0.783

(5)

9eff

201

where r is the pore radius, nm, 6

202

the pore, °K,

203

effective molecular diameter, nm.

7

( )

( )

= 1.5686

( )

for

9eff

7

7

=

1.338

( )

= 1.1775

7

7

6

8

7

is bulk critical temperature, °K, 6

is bulk critical pressure, atm,

8

8

is the critical temperature in

is the critical pressure in the pore, atm, 9eff is the

204

In this study, the phase behavior considering nanopore confinement is calculated through the phase

205

equilibrium model and implemented in the numerical simulation as shown in Figure 5. The phase

206

equilibrium model is modified based on cubic Peng-Robinson equation of state (PR-EOS) by coupling

207

with the Young-Laplace capillary pressure equation, and shifted critical properties.66-70

208

Including the confinement effect, the criterion of phase equilibrium is: @'A(6

A

) = @'B(6

@'A(6

A

)=

'A ' A

(7)

@'B(6

B

)=

'B ' B

(8)

B

=

E8

+

B

), ' = 1, C D

(6)

(9)

A

209

where @'A, @'B are the fugacity of component i in the liquid and vapor, respectively.

210

pressures in the liquid phase and vapor phase, respectively.

'

and


'

A

and

B

are the

are mole fraction of component

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Energy & Fuels

211

i in the liquid phase and vapor phase exits at equilibrium at a given pressure and temperature,

212

respectively,

213

respectively.

214 215

'A

and

'B

are the fugacity coefficients of component i in the liquid and vapor phases,

The capillary can be calculated by the Young-Laplace capillary pressure equation. The IFT between the liquid and vapor phases can be estimated by the Macleod and Sugden correlation.71 D

9=

[F '

()A[

]'

'

)B

]

4

)

' '

(10)

216

where 9 is the IFT between the liquid and vapor phases, )A and )B are the average density of bulk

217

liquid and vapor phases, respectively.

'

is the parachor of the i-component.

218

The PR-EOS equation is solved separately for liquid and vapor phase after including confinement

219

effect and meet the requirement of minimized Gibbs molar free energy rule. After that, the calculated

220

properties are implemented into reservoir simulation software CMG-GEM to analyze the field CO2

221

huff-n-puff performance and gas sweep volume.


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Input zi, Tci, Pci, wi, G , r, [P]i, T, P Generate modified Tci, Pci Initial K-value with Wilson’s equation PR EOS and Flash calculation

Calculate the parameters in different pore sizes

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Obtain xi , yi , IFT, Pcap, PL and PV Using PL and PV to calculate fiL , fiV , ,

Update K-values

No

fL = f V

Solve Laplace equation for Pcap

Yes No

PL K PV Yes Output xi , yi , IFT, Pcapi ri+1 K ri Molecular diffusion calculation Fluid properties in confined pores Implement into CMG-GEM simulator

222 223

Figure 5. The workflow of CO2 huff-n-puff simulation study considering nanopore confinement and molecular

224

diffusion

225

3.2. Build Up of Lab Scale Model. A compositional model with radial coordinate was built to

226

simulate the CO2 huff-n-puff process using Computer Modelling Group’s GEM reservoir simulator on

227

the basis of our previous work28. As shown in Figure 6, the shale core is centralized inside the huff-n-

228

puff vessel, which is surrounded by a high permeability media to mimic the space created by glass beads.

229

The dimensions of the core container used to store the core are 2.5 inches in diameter and 4 inches in

230

length. The diameter of the core plug used in the test is 1.5 inches, and the length is 2 inches. The radial

231

model has 26 layers in R direction and 24 layers in Z direction. The shale matrix is set as sector 1

232

covering grid blocks from 1 to 20 in R direction and grid blocks from 7 to 18 in Z direction as shown

233

in Figure 6b. The distribution of porosity, absolute permeability, and oil saturation are assumed to be

234

homogeneous in the core plug. The validation of the model is established by accurately reproducing the

235

results performed in the laboratory as presented in Figure 7. Then the simulation is enlarged to field

236

scale. 10 ACS Paragon Plus Environment

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4 inches 24 layers R Core

Z Mimic the annulus filled with glass beads

4 inches

237 238 239

2 inches

26 layers

2.5 inches

a. The radial model

b. The dimensions of each part

Figure 6. Radial grid system used in CO2 huff-n-puff EOR modeling. 70 60

Cumulative oil recovery (%)

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

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Cumulative oil recovery-Simulation result Cumulative oil recovery-Experiment data

50 40 30 20 10 0 0.0

240 241

1.0

2.0 Time (day)

3.0

4.0

Figure 7. Reproduction of the CO2 huff-n-puff in core sample using a lab-scale simulation model.

242

3.3. Build Up of Field Model. As described in Figure 8, a dual permeability compositional model

243

is established to simulate the CO2 huff-n-puff process in a horizontal well with hydraulic fractures and

244

natural fractures. The domain of the model is 4147.5ft in I direction, 2724 ft in J direction, and 50 ft in

245

K direction. The fracture spacing is 592.5ft, and the fracture length is 724ft as presented in Figure 8b.

246

The simulation model includes two parts: the stimulated reservoir volume (SRV) and un-stimulated

247

reservoir volume (USRV). As the changes of pressure, saturation and fluid properties are more sensitive

248

in the region near hydraulic fractures, the fracture region is amplified as presented in Figure 8c. The

249

model input parameters including the matrix, hydraulic fracture, and natural properties are shown in

250

Table 3.36 The composition of the crude oil sample used in this study is based on the data of Bakken

251

oil as presented in Table 4.

252

We run the field model using the control of field oil rate data in the first 450 days as shown in Figure

253

9a. The bottom-hole pressure (BHP) is predicted as a solid curve as shown in Figure 9b. The simulation

254

production BHP result shows a good match with the field BHP data. 11 ACS Paragon Plus Environment

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592.5 ft

I

J

SRV

2724 ft

USRV

K

a. Horizontal well with hydraulic and natural fractures

255

Hydraulic Fracture Fracture 724 ft

USRV

Reservoir

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b. Unit fracture model

256

Figure 8. Field model of CO2 huff-n-puff in hydraulic fractured reservoir.

257

Table 3. Field Model Input Parameters36 Parameters

Value

nx, ny, nz

40×61×2

depth (ft)

8943

matrix perm (both SRV and USRV) (md)

0.0003

fracture perm (SRV) (md)

0.0313

fracture perm (USRV) (md)

0.00216

matrix poro (both SRV and USRV) (%)

5.6

fracture poro (SRV) (%)

0.56

fracture poro (USRV) (%)

0.22

natural fracture space (SRV) (ft)

0.77

natural fracture space (USRV) (ft)

2.27

water saturation

40 %

initial reservoir pressure (psi)

7600

CO2 diffusion coefficient in oil phase

2.12 E-06

reservoir temperature (°F)

255

c. Enlarged view of hydraulic fracture

258 259

Table 4. Components of Bakken Oil Components

C1

C2

C3

C4

C5-6

C7-12

C13-21

C22-80

Mol. Fraction

33.80%

8.80%

9.69%

6.01%

8.82%

18.93%

7.69%

6.22%

260


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40

Oil result OilRate Rate Simulation SC Oil Rate SC field data, used as constraints

Oil Rate SC (bbl/day)

30

20

10

0 0

50

100

150

261 262

200 250 Time (day)

300

350

400

450

500

a. History matching process with oil rate control 8,000

50 bottom-hole Pressure pressure, Well WellBottom-hole Bottom-hole Pressure Simulated Oil Oil Rate Rate SC SC field data, used as constraints Well bottom-hole pressure, field data Oil rate historical data

40 6,000

30 4,000 20

Oil Rate SC (bbl/day)

Well Bottom-hole Pressure (psi)

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

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2,000 10

0

0 0

263

200 250 Time (day)

264

b. Well bottom hole pressure in simulation field model vs. well bottom hole pressure of field data

265

50

100

150

300

350

400

450

Figure 9. History matching of the bottom-hole pressure from Middle Bakken shale reservoir.

266

3.4. CO2 Huff-n-Puff EOR Performance in Field Study. The operation schedules of the field

267

cases used in this study are shown in Table 5. CO2 Huff-n-Puff injection is conducted in Case 1. For

268

these two cases, firstly, the reservoir produced in the primary depleted model with Bakken historical oil

269

rate data for 450 days as shown in Figure 10 and then produced at a specific rate of 6.84 bbl/day for

270

another 550 days. After that, Case 2 continued to produce oil at a constant BHP of 1000 psi for 1600

271

days. For Case 1, CO2 huff-n-puff was conducted with a huff period of 100 days and a puff period of

272

100 days. Totally three injection cycles (600days) were conducted. The injection well was constrained

273

to the maximum injection pressure of 7000 psi and the maximum surface gas rate of 1000 MSCF/day. 13 ACS Paragon Plus Environment

Energy & Fuels

274

The production well was restrained to the minimum BHP of 1000 psi. Then the oil produced at the

275

constant BHP of 1000psi for another 1000 days. The well BHP and oil rate pattern are described in

276

Figure 10. The highest oil production rate during the first 450 days’ primary depletion time is 26.66

277

bbl/day when the reservoir pressure is the initial reservoir pressure. When the oil rate decreases from

278

26.66 bbl/day to 6.84 bbl/day, the reservoir pressure declines from 7600 to 2545 psi. Then the well is

279

produced at a constant rate of 6.84 bbl/day for another 550 days. During this period, the reservoir

280

pressure decreases from 2545 psi to 1060 psi. Then, the huff-n-puff process starts. During the puff

281

period, the highest oil production rate is 41.42 bbl/day, and the lowest oil production rate is 12.28

282

bbl/day. The oil rate is raised by 79.5% to 505% compared to the oil production rate during the primary

283

depletion process.

284

Table 5. Operation Schedule of Two Field Cases Case

Depletion at historical oil

Constant oil rate

No.

rate

production

Case 1

450 days

550 days

600 days

1000 days

Case 2

450 days

550 days

0 days

1600 days

Constant BHP

Huff-n-puff

Production

Cycle 1 Cycle 2 Cycle 3

8,000

50 puff puff Well Bottom-hole Pressure puff Oil Rate SC huff huff huff 450 days’ Depletion at constant rate

6,000

550 days’ Depletion at constant rate

30 4,000 20

2,000 10

0 0

285 286

40 Oil Rate SC (bbl/day)

Well Bottom-hole Pressure (psi)

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 14 of 30

200

400

600

0 800 1,000 1,200 1,400 1,600 1,800 Time (day)

Figure 10. The well bottom-hole pressure and oil rate pattern during the reservoir development.

287

The oil recovery factor results of these two cases with/without huff-n-puff are compared and

288

presented in Figure 11. After 1000 days’ primary depletion, the oil recovery is 3.55%. In the continued

289

three huff-n-puff injection cycles, the oil recovery differences between these two cases are 0.42%,

290

0.97%, and 1.5%, respectively. At the end of 2600 days of production, the oil recovery of Case 1 is 1.62%

291

higher than Case 2.


Page 15 of 30

10.0 Three huff-n-puff cycles Primary depletion

8.0 Oil recovery factor (%)

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

6.0

1.62 1.89 1.5 4.0

0.97 0.42

2.0

0.0 0

292 293

500

1,000 1,500 Time (day)

2,000

2,500

3,000

Figure 11. The oil recovery factor results of cases with/without huff-n-puff comparison.

294

3.5. CO2 Sweep Volume Calculation and Analysis. Figure 12 presents the distribution of mole

295

fraction of CO2 in the oil phase (CO2oil) in X-Z cross section at the end of the huff time (100 days) of

296

the first huff-n-puff cycle. It illustrates that during the huff period, the injected CO2 gas sweep volume

297

is confined to the region near the fracture and the injected gas mainly penetrates the areas in the SRV

298

region. The average CO2 mole fraction in the oil phase and average oil saturation in the gas swept

299

volume can be calculated in equations (11) and (12).

=

F B'

=

'

(11)

F B' F B'

'

(12)

F B'

300

where

301

fraction in oil phase in the block i.

is the porosity, B' is the block i volume,

'

is the oil saturation in block i,

Block 3 (39, 12, 1) 200 ft to fracture Block 2 (37, 14, 1) 100 ft to fracture Block 1 (31, 20, 1) 10 ft to fracture

302 303

Figure 12. The distribution of CO2oil in field model at the end of huff period.


'

is the CO2 mole

Energy & Fuels

304

Using the data in the field model, at the end of huff time (100days), the average CO2oil is 39.7%.

305

Figure 13 presents the sweep volume percentage in the SRV/reservoir region at different huff time

306

during the huff period. At the end of 100 days’ huff period, the sweep volume percentage in the SRV

307

region and the reservoir region are 35.65% and 9.47%, respectively. CO2 penetrates fast at the beginning

308

of the soaking period due to the high pressure gradient and saturation difference, and then becomes

309

stable. During the soaking period, the injected CO2 continues to penetrate the reservoir matrix, causing

310

further reservoir pressure increase, as well as oil viscosity decline. A detailed investigation in pressure,

311

oil viscosity, gas saturation, and CO2oil in blocks (31, 20, 1), (37, 14, 1) and (39, 12, 1) during the huff

312

period are shown in Figures 14-17, respectively. The positions of the three investigated blocks are

313

shown in Figure 12. Block 1 (31, 20, 1), block 2 (37, 14, 1) and block 3 (39, 12, 1) are at 10 ft, 100ft,

314

and 200 ft distance from the fracture, respectively. 50

Sweep volume percentage in SRV region (%) Sweep voulme percentage of the reservoir (%)

Sweep volume percentage (%)

45 40 35 30 25 20 15 10 5 0 0

20

315 316 317

40

60

80

100

120

Huff time (days)

Figure 13. CO2 sweep volume percentage in SRV region and in the reservoir at different huff time in the first huff-n-puff cycle. Cycle 1 Cycle 2 Cycle 3 10,000

puff puff Block (11,20,1), distance to fracture: 10 ft puff Block (17,14,1), distance to fracture: 100 ft Block (19,12,1), distance to fracture: 200 ft huff huff huff

8,000

Pressure (psi)

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 16 of 30

6,000

4,000

2,000

0 0

318 319

200

400

600 800 Time (day)

1,000

1,200

1,400

1,600

Figure 14. Changes of pressure in blocks (31, 20, 1), (37, 14, 1) and (39, 12, 1) during the huff-n-puff process.


Page 17 of 30

320

Figure 14 shows the changes of reservoir pressure in block 1 (31, 20, 1), block 2 (37, 14, 1) and

321

block 3 (39, 12, 1) during the huff-n-puff process. The pressure in block 1, which located at 10ft to the

322

fracture, can reach the designed pressures (huff pressure of 7000 psi and puff pressure of 1000 psi). For

323

block 2 (37, 14, 1) at a distance of 100ft to the fracture, the maximum reservoir pressure is 6800 psi

324

during the huff period, and the minimum pressure is 1800 psi during puff period. Thus the pressure

325

gradient for the oil production is 5000 psi, which is 83.3% of that in block 1 (31, 20, 1). For block 3

326

(39, 12, 1), which located at a distance of 200ft to the fracture, the maximum and minimum pressure

327

are 6400 psi during the huff period and 2200 psi during the puff period. The pressure gradient is 4200

328

psi, which is 70% of that in block 1 (31, 20, 1). When compared to the reservoir pressure of 1400 psi

329

before the huff-n-puff process, the reservoir pressure increases not only in the area near the well-bottom,

330

but also the areas more than a distance of 200ft to the fracture. The further the distance to the fracture,

331

the lower the pressure gradient for oil production. Cycle 1 Cycle 2 Cycle 3

1.00 Block (11,20,1), distance to fracture: 10 ft Block (17,14,1), distance to fracture: 100 ft Block (19,12,1), distance to fracture: 200 ft

Mole Fraction of CO2 in Oil

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

0.80

puff

puff huff

huff

puff huff

0.60

0.40

0.20

0.00 0

332

200

400

600

800 Time (day)

1,000

1,200

1,400

1,600

333 334

Figure 15. Changes of CO2 mole fraction in oil phase in blocks (31, 20, 1), (37, 14, 1) and (39, 12, 1) during the

335

Figure 15 describes the changes of mole fraction of CO2 in the oil phase in blocks (31, 20, 1), (37,

336

14, 1) and (39, 12, 1) during the huff-n-puff process. For the huff period in the first huff-n-puff cycle,

337

the mole fraction of CO2 in oil phase for blocks (31, 20, 1), (37, 14, 1) and (39, 12, 1) are 0.25, 0.25

338

and 0. It illustrates that CO2 penetrates to the area of 100ft to the fracture during the huff period. While,

339

block 3 (39, 12, 1) is located at a deeper area inside the reservoir matrix. CO2 does not penetrate to this

340

block as CO2oil is equal to zero. To analyze the properties changes in these picked blocks, we need to

341

take the gas saturation and oil viscosity variation into consideration as shown in Figures 16-17. During

342

the second and third huff periods, the CO2oil in block 1 (31, 20, 1) is zero. All the oil in this area has

343

been produced. The gas saturation reaches 65% according to Figure 16, and the oil viscosity is zero as

344

no more oil left in this block as shown in Figure 17. However, for the puff period in the second cycle,

345

oil is produced from deeper reservoir blocks to block 1 (31, 20, 1). Thus the gas saturation decreases

huff-n-puff process.


Energy & Fuels

346

from 64% to 56.5%. As the pressure declines during the puff period, the solution gas is released from

347

the oil. Thus, the CO2oil is around 42.5% at the beginning of the puff period and decreases to 28.5% at

348

the end of the puff period as shown in Figure 15. Meanwhile, the oil viscosity declines by 25.9%, from

349

0.54 to 0.4 cp. It shows the same trend for block 1 (31, 20, 1) in the puff period of the third cycle. Cycle 1 Cycle 2 Cycle 3 puff

0.70

puff

puff huff

huff

huff

Block (11,20,1), distance to fracture: 10 ft Block (17,14,1), distance to fracture: 100 ft Block (19,12,1), distance to fracture: 200 ft

0.60

Gas Saturation

0.50 0.40 0.30 0.20 0.10 0.00 0

200

400

600

350 351 352

800 Time (day)

1,000

1,200

1,400

1,600

Figure 16. Changes of gas saturation in blocks (31, 20, 1), (37, 14, 1) and (39, 12, 1) during the huff-n-puff process. Cycle 1 Cycle 2 Cycle 3

1.00 Block (11,20,1), distance to fracture: 10 ft Block (17,14,1), distance to fracture: 100 ft Block (19,12,1), distance to fracture: 200 ft

0.80 Oil Viscosity (cp)

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 30

puff huff

huff

puff

puff huff

0.60

0.40

0.20

0.00 0

353

200

400

600

800 Time (day)

1,000

1,200

1,400

1,600

354

Figure 17. Changes of oil viscosity in blocks (31, 20, 1), (37, 14, 1) and (39, 12, 1) during the huff-n-puff process.

355

The properties of these parameters in block 2 (37, 14, 1) are different from that in block 1 (31, 20,

356

1). During the huff periods of these three cycles, the CO2oil in block 2 increases from 0 to 25%, from

357

20% to 56%, and from 32% to 66% as more CO2 penetrates this block. The gas saturation remains zero

358

because all the penetrated CO2 dissolves into the crude oil. The oil viscosity decreases by 68.2%, from

359

0.44 cp to 0.14 cp at the end of the huff period. During the puff period, the CO2oil in block 2 decreases 18 ACS Paragon Plus Environment

Page 19 of 30 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

360

due to the reduction of solution gas. The gas saturation increases to 10%, 26.1%, and 29.2% at the end

361

of these three puff periods, which means that the corresponding amounts of oil in block 2 has been

362

produced. The oil viscosity in block 2 increases during the puff period because the resolved CO2 gas

363

dissolves out from the crude oil as the pressure decreases. In this case, the oil viscosity is dependent

364

more on the gas dissolve phenomena than the pressure decline.

365

While for block 3 (39, 12, 1), which located at the distance of 200ft to the fracture, CO2oil and gas

366

saturation during the three huff-n-puff cycles are both zero. It indicates that CO2 has not swept this

367

block and the oil in block 3 has not been produced. One thing should be noted is that the change trend

368

of oil viscosity in block 3 during the puff period in these three cycles is different from that in block 2.

369

The reason is that there’s no solution CO2 gas in the crude oil. Thus, the oil viscosity is only influenced

370

by the change of reservoir pressure.

371

4. FIELD CASE SENSITIVITY ANALYSIS

372

The objective of the sensitivity study is to investigate the effects of different parameters on gas sweep

373

volume. These parameters include nanopore confinement, CO2 diffusion coefficient, primary depletion

374

time, number of CO2 huff-n-puff cycle, injection pressure, and huff and puff time. Fourteen more cases

375

were investigated in this study, and the operation parameters of the cases are shown in Table 6.

376

Table 6. Operation Parameters of Investigated Cases Total primary Case No.

depletion time, days

Case 1

CO2 diffusion Huff time,

Injection

Huff-n-Puff

Pore

days

pressure, psi

cycles

diameter, nm

coefficient cm2/s

1000

100

7000

3

10

2.12×10-6

Case 3

1000

100

7000

3

5

2.12×10-6

Case 4

1000

100

7000

3

1000

2.12×10-6

Case 5

1000

100

7000

3

10

2.12×10-5

Case 6

1000

100

7000

3

10

2.12×10-7

Case 7

1000

100

7000

3

10

0

Case 8

500

100

7000

1

10

2.12×10-6

Case 9

1500

100

7000

1

10

2.12×10-6

Case 10

1000

50

7000

1

10

2.12×10-6

Case 11

1000

200

7000

1

10

2.12×10-6

Case 12

1000

300

7000

1

10

2.12×10-6

Case 13

1000

100

3000

1

10

2.12×10-6

Case 14

1000

100

5000

1

10

2.12×10-6

Case 15

1000

100

9000

1

10

2.12×10-6

Case 16

1000

100

7000

20

10

2.12×10-6

(base case)

377

4.1. Effect of Nanopore Confinement. Figure 18 shows the nanopore confinement effect on gas

378

sweep volume and cumulative oil recovery during the CO2 huff-n-puff process. It can be observed that 19 ACS Paragon Plus Environment

Energy & Fuels

379

the gas sweep volume percentage for pore sizes of 5, 10, 1000nm are 10.18%, 9.47%, and 7.45%,

380

respectively. The corresponding cumulative oil recovery is 7.16%, 6.47%, and 5.31% as shown in

381

Figure 18b. The results indicate that the nanopore confinement has a positive effect on CO2 huff-n-

382

puff EOR performance. In the confinement pore space, the minimum miscible pressure of CO2-oil

383

system decreases, leading to an easier gas penetration process. Additionally, the bubble point pressure

384

of the crude oil system reduces in the confined pores than that in the bulk phase, implicating that the

385

single-phase production period will last longer and leading to higher oil recovery. 10.0

8.0

12

9

6

3

6.0

4.0

2.0

0 1

10

386

387

pore diameter = 5 nm pore diameter = 10 nm No nanopore confinement effect

Sweep volume percentage (%) Cumulative oil recovery (%)


15

100

1000

10000

0.0 0

200

400

600

Pore diameter (nm)

800 1,000 Time (day)

1,200

1,400

1,600

1,800

a. Effect of nanopore confinement on gas sweep b. Effect of nanopore confinement on cumulative oil volume. recovery. Figure 18. Effect of nanopore confinement on gas sweep volume and cumulative oil recovery.

388

4.2. Effect of CO2 Diffusion Coefficient. The CO2 diffusion coefficient of 0, 2.12×10-7, 2.12×10-6,

389

and 2.12×10-5 were studied, while the other parameters were kept the same as the base case. As shown

390

in Figure19a, the CO2 sweep volume increases from 4.93%, 8.13%, 9.47%, to 10.12%, respectively in

391

these cases. The cumulative oil recovery was also investigated for each case. Figure 19b shows that

392

with higher diffusion coefficient, more injected CO2 diffuses into the matrix instead of concentrating

393

around the fractures, and more oil recovery will be produced. 10.0 2.12×10-5 cm^2/s 2.12×10-6 cm^2/s 2.12×10-7 cm^2/s No diffustion

15 Sweep volume percentage (%) 8.0

12



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

Page 20 of 30

9

6

3

0

395

4.0

2.0

0

394

6.0

2.12*10-7 2.12*10-6 2.12*10-5

0.0 0

500

CO2 diffusion coefficient (cm2/s)

1,000

1,500

Time (day)

a. Effect of CO2 diffusion coefficient on gas sweep b. Effect of CO2 diffusion coefficient on cumulative volume. oil recovery. Figure 19. Effect of CO2 diffusion coefficient on gas sweep volume and cumulative oil recovery.


Page 21 of 30

396

4.3. Effect of Primary Depletion Time. Figure 20 compares the gas sweep volume and cumulative

397

oil recovery at different depletion time, which are 500, 1000, and 1500 days, respectively. The sweep

398

volumes for these three cases are 4.32%, 9.54%, and 14.06%. The later the CO2 huff-n-puff is conducted,

399

the larger the gas sweep volume will be. The longer time primary depletion leads to lower reservoir

400

pressure. Thus, the pressure gradient at the initial reservoir system is higher, resulting in CO2 convection

401

flow into a more extensive portion of the reservoir. As shown in Figure 20b, although the cumulative

402

oil recovery in the early stage (before 1600 days) is lower if the huff-n-puff process starts late, after the

403

three CO2 huff-n-puff cycles, the case with longer primary depletion time has the highest oil recovery.

404

Thus, it’s important to decide when to start the CO2 huff-n-puff process. 10.0

25

8.0

20

15

10

5

6.0

4.0

2.0

0

0.0

0

405

primary depletion time = 500 days primary depletion time = 1000 days primary depletion time = 1500 days



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

500 1000 1500 Primary depeltion time (days)

2000

0

500

1,000 1,500 Time (day)

2,000

2,500

3,000

a. Effect of primary depletion time on gas sweep volume.

406

b. Effect of primary depletion time on cumulative oil recovery. Figure 20. Effect of primary depletion time on gas sweep volume and cumulative oil recovery.

407

4.4. Effect of CO2 Huff and Puff Time. In this section, four different huff time and puff time 50

408

days, 100 days, 200 days, and 300 days were chosen to investigate the CO2 huff-n-puff performance.

409

As shown in Figure21a, the swept volume at the end of the first huff period for the above cases are

410

7.63%, 9.47%, 10.51%, and 10.88%, respectively. As huff time increases, the injected CO2 will have

411

more time to mix with the oil in the matrix and sweep more areas before it being produced back. At the

412

early stage of the huff period, the gas sweep volume increases rapidly due to the high pressure gradient.

413

When huff time is more than 200 days, CO2 penetrates slowly. Figure 21b indicates that larger huff

414

and puff time leads to a higher oil production with the same operation time of 3500days.


Energy & Fuels

10.0


huff 50 puff 50 huff 100 puff 100 huff 200 puff 200 huff 300 puff 300

8.0 Cumulative oil recovry (%)


12

10

8

6.0

4.0

2.0

6 50

100

150

200

250

0.0

300

0

500

1,000

Huff time (days)

415

1,500 2,000 Time (day)

2,500

3,000

3,500

4,000

416

a. Effect of huff and puff time on gas sweep volume. b. Effect of huff and puff time on cumulative oil recovery. Figure 21. Effect of huff and puff time on gas sweep volume and cumulative oil recovery.

417

4.5. Effect of CO2 Injection Pressure. The injection pressure also impacts CO2 huff-n-puff

418

performance. Figure 22 presents the gas sweep volume and cumulative oil recovery results when using

419

different gas injection pressures. The gas sweep volume ratios are 3.25%, 6.47%, 9.47%, and 12.28%

420

when using injection pressures of 3000, 5000, 7000, and 9000 psi, respectively. A higher injection

421

pressure results in a larger sweep volume and the two parameters are in a linear relationship. As the

422

pressure gradient increases, more gas can be injected to the reservoir, resulting in higher cumulative oil

423

recovery. 10.0

20

Injection pressure = Injection pressure = Injection pressure = Injection pressure =

Sweep volume percentage (%) 8.0

15



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 30

10

5

9000 psi 7000 psi 5000 psi 3000 psi

6.0

4.0

2.0

0 3000

424 425

4000

5000

6000

7000

8000

9000

0.0 0

200

400

600

Injection Pressure (psi)

800 1,000 Time (day)

1,200

1,400

1,600

1,800

a. Effect of injection pressure on gas sweep volume. b. Effect of injection pressure on cumulative oil recovery. Figure 22. Effect of injection pressure on gas sweep volume and cumulative oil recovery.

426

4.6. Effect of Number of CO2 Huff-n-Puff Cycles. More CO2 huff-n-puff cycles were conducted

427

to check the penetration depth at different cycles, as presented in Figure 23. As expected, more cycles

428

lead to deeper penetration depth and a larger sweep volume percentage. The injected CO2 swept 9.47%,

429

15.92%, and 21.65% of the reservoir volume when 1, 3, and 10 huff-n-puff cycles were conducted. At

430

the end of the 20th cycle, gas penetrated the whole SRV region between the hydraulic fractures. The

431

sweep volume percentage of the reservoir is 26.58%, and the cumulative oil recovery reaches 15.39%. 22 ACS Paragon Plus Environment

Page 23 of 30

20.0

40

Cumulative oil recovery, %



30

20

10

0 0

432

5

10

15

20

15.0

10.0

5.0

0.0 0

1,000

2,000 Time (day)

Injection cycles

3,000

4,000

5,000

433

a. Effect of number of huff and puff injection b. Effect of number of huff and puff injection cycles on cycles on gas sweep volume. cumulative oil recovery. Figure 23. Effect of number of huff and puff injection cycles on gas sweep volume and cumulative oil recovery.

434

The relationship of cumulative oil recovery and gas sweep volume after summarizing the above

435

cases is presented in Figure 24. The cumulative oil recovery is in a positive relationship with the gas

436

sweep volume. Supposing the CO2 displacement efficiency is constant, the cumulative oil recovery

437

should be in a linear relationship with the gas sweep volume. The gas sweep volume plays a significant

438

role in enhancing oil recovery. We summarize the sensitivity parameters and represent by tornado plot

439

shown in Figure 25. The most sensitive parameter for increasing gas sweep area is the primary depletion

440

time, followed by injection cycles, injection pressure, huff time, and CO2 diffusion coefficient. 18 16


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

14 12 10 8 6 4 2 0 0

441 442

5

10

15

20

CO2 sweep volume (%)

Figure 24. Relationship of cumulative oil recovery vs. gas sweep volume.


25

30

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

443 444

Figure 25. Tornado plot for the sensitivity analysis on gas sweep volume.

445

5. CONCLUDING REMARKS

446

In this study, the gas sweep volume was investigated in both experimental and numerical study. The

447

CT scan method depicted the gas swept area in the shale core plug during the huff-n-puff process. The

448

results showed that the gas swept ratios in seven CO2 huff-n-puff cycles were 40.13%, 55.14%, 64.01%,

449

70.25%, 74.81%, 76.88%, and 78.63%, respectively. During the huff period in one specific cycle, the

450

injected gas penetrated the microfractures first and then diffused into the low permeability core matrix

451

under concentration difference and pressure gradient.

452

The numerical simulation results illustrated that nanopore confinement and molecular diffusion had

453

positive effects on the gas sweep volume and cumulative oil recovery. Most of the injected CO2

454

concentrated in the SRV region. For a 600 ft hydraulic spacing reservoir, the CO2 penetrated 9.47% of

455

the reservoir volume after 100 days’ huff period, reducing the oil viscosity by about 25.9% to 68.2%.

456

A series of simulations were performed to evaluate the impacts of key parameters on the gas sweep

457

volume during the huff-n-puff process, concluding that primary depletion time is the most sensitive

458

parameter, followed by injection cycles, injection pressure, huff time, and CO2 diffusion coefficient.

459

The cumulative oil recovery has a positive relationship with the gas sweep volume. This study provides

460

a better understanding of gas sweep volume and factors affecting gas penetration during the huff-n-puff

461

process, which can provide guidance on the optimization of CO2 huff-n-puff EOR in shale oil

462

production.

463

NOMENCLATURE CO2oil H %

= = = =

CO2 mole fraction in oil phase penetration reservoir height permeability tensor phase pressure, % represents o, g, w (oil, gas and water) 24 ACS Paragon Plus Environment

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Page 25 of 30 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

% % ' %

B'

'

'

'

$ %

&% %

'A 'B '(

) )0 )0 H' R T 9'( I'(

0 '(

'

9 J 0 )A )B ' E8

A B ' @A @'B

6 6

7 8 7

= = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = = =

phase flowrate per unit rock volume, % represents o, g, w (oil, gas and water) phase pressure gradient, % represents o, g, w (oil, gas and water) oil saturation in block i phase saturation, % represents o, g, w (oil, gas and water) block i volume in field simulation model component mole fraction in liquid phase penetration depth CO2 mole fraction in oil phase in the block i average CO2 mole fraction in oil phase in penetrated area component mole fraction in liquid phase mole fraction of component i in liquid phase component mole fraction in vapor phase mole fraction of component i in vapor phase overall component mole fraction molar density phase mobility component diffusion flux, % represents o, g, w (oil, gas and water) tortuosity porosity fugacity coefficient of component i in the liquid phase fugacity coefficient of component i in the vapor phase binary diffusion coefficient between component i and j in the mixture molar density of the diffusing mixture reduced density zero-pressure limit of the density-diffusivity product molecular weight of component i universal gas constant absolute temperature collision diameter collision integral of the Lennard-Jones potential diffusion coefficient of component i in the mixture interfacial tension oil-gas contact angle pore radius average density of bulk liquid phase average density of bulk vapor phase parachor of the i-component capillary pressure pressure pressure in the liquid phase pressure in vapor phase fugacity of component i in the liquid phase fugacity of component i in the vapor phase bulk critical temperature critical temperature in the pore bulk critical pressure 25 ACS Paragon Plus Environment

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

8

9eff SRV USRV 464

= = = =

critical pressure in the pore Effective molecular diameter stimulated reservoir volume un-stimulated reservoir volume

ACKNOWLEGEMENTS

465

The work presented in this paper is supported by the China National Science Foundation (51674279,

466

51804328), the China Major National Science and Technology Project (2017ZX05049003-001,

467

2017ZX05072), the China Postdoctoral Science Foundation (2018M630813), the Shandong province

468

Natural Science Foundation (ZR2018BEE018), the Fundamental Research Funds for the Central

469

Universities (18CX02170A), the Postdoctoral Applied Research Project Foundation of Qingdao city

470

(BY201802003), and the Funding for Scientific Research of China University of Petroleum East China

471

(YJ20170013).

472

REFERENCES

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(1) Montgomery J, O’Sullivan F. Spatial variability of tight oil well productivity and the impact of technology. Appl Energy 2017;195:344-355. (2)

Experimental and Numerical Study on CO2 Sweep Volume during

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