Enhanced Oil Recovery Study of a New Mobility Control System on the

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An EOR study of a new mobility control system on the dynamic imbibition in a tight oil fracture network model Mingwei Zhao, Haonan He, Caili Dai, Yongpeng Sun, Yanchao Fang, Yifei Liu, Qing You, Guang Zhao, and Yining Wu Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.7b03283 • Publication Date (Web): 30 Jan 2018 Downloaded from http://pubs.acs.org on January 31, 2018

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Energy & Fuels

1

An EOR study of a new mobility control system on the

2

dynamic imbibition in a tight oil fracture network model

3

Mingwei Zhao1, Haonan He1, Caili Dai1∗, Yongpeng Sun1, Yanchao Fang1, Yifei Liu1,

4

Qing You2, Guang Zhao1, Yining Wu1

5

1

6

Shandong 266580, China.

7

2

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

School of Energy Resources, China University of Geosciences, Beijing 100083, China.

1

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

1

ABSTRACT

2

Aiming at increasing the recovery in tight oil reservoir with fractures, a new kind of

3

mobility control system with function of imbibition (MCSI) was prepared with

4

dispersed particle gel (DPG) and surfactant. The dynamic imbibition can effectively

5

control the mobility ratio in tight oil fracture network and increase oil recovery. Based

6

on the characteristics of tight oil reservoir fractures, the preparation method of

7

multiple fracture network model was established. The prepared fracture network

8

model has the characteristics of controllable fracture length, width, and height. The

9

MCSI system can reduce the oil-water interfacial tension to 10-2 mN/m. It features

10

low viscosity, strengthening water wet, thus promoting the imbibition effect. Dynamic

11

imbibition tests of multiple fracture network model show that the MCSI system has

12

higher oil recovery than each single component. At the same time, the subsequent

13

water flooding after soaking also has the function of enhancing oil recovery. The

14

effects of fluid type, flow rate, fracture width, and matrix fracture network model type

15

on oil recovery of MCSI are clarified.

16

Keywords: Tight oil reservoir; Mobility control system; Matrix fracture network

17

model; Dynamic imbibition

2


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Energy & Fuels

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1. INTRODUCTION

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Tight oil refers to the oil formed in tight reservoir1-2. In China, tight oil accounts for

3

2/5 of the recoverable oil resources, which has broad exploration prospects. In recent

4

years, the development of tight oil resources in China has made major breakthrough.

5

About 5 to 10 billion tons reserves were found in the Ordos basin, and it is

6

preliminary estimated that the amount of geological reserve is more than 20 billion

7

tons3. Compared with conventional reservoirs, tight oil reservoirs have the

8

characteristics of poor physical properties, such as low matrix permeability and low

9

porosity, where formation needs to be stimulated to generate fractures to obtain oil

10

and gas flow4-6. At present, segmented multi-fracture large scale volume fracturing

11

technology is mainly used, which makes the tight reservoir form complex fracture

12

networks intertwined by hydraulic fractures and natural fractures, thus provides the

13

channels for tight oil output7.

14

The matrix-fracture structure of tight oil reservoir is formed after fracturing, in

15

which the matrix is so tight that it is difficult to use conventional water flooding to

16

displace oil into fracture network8. On the one hand, the imbibition effect caused by

17

capillary force in the microscale pore throat is very important to the production of

18

crude oil. On the other hand, due to strong heterogeneity of reservoir between matrix

19

and fracture network, fractures are likely to become the flowing channels of water and

20

oil. The channels of water and gas in fractures lead to poor sweep efficiency in matrix,

21

so the control of the fluid mobility in fractures is also very important.

22

At present, with unique characteristics and advantages, chemical method has 3


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become one of the most important technologies to enhance oil recovery9-11, especially

2

ASP flooding which consists of polymer, surfactant and alkali, and SP flooding based

3

on polymer and surfactant. Polymer can increase the sweep efficiency by decreasing

4

mobility ratio. Surfactant can reduce the oil/water interfacial tension and improve the

5

effective use of crude oil. The interfacial tension between oil and water can be

6

reduced to 0.011~0.015 mN/m, and the recovery can reach 14%~24%13-17. In addition,

7

the wettability in matrix can be changed through imbibition, which is also regarded as

8

the mechanism of surfactant flooding process12. Alkali can enhance the mobility

9

control ability of polymer by emulsification. However, in the actual field test, polymer

10

is easily affected by the shearing within equipment and geological conditions, whose

11

viscosity decreases greatly. The presence of alkali may reduce the viscosity of

12

polymer, which leads to formation damage, wellbore scaling and emulsification of

13

crude oil. How to control the mobility of displacing fluid is still a great challenge. The

14

dispersed particle gel (DPG) with the functions of mobility ratio modification and

15

conformance control has received a large amount of attentions in the recent years.

16

DPG can adjust the flow profile effectively and make liquid flow to the low

17

permeable layers to recover crude oil18-20. The oil recovery increment can reach 46%

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and the subsequent water flooding recovery can be increased by 3.3%, which mean

19

the oil recovery of low permeability reservoir is greatly improved21-26. So if mobility

20

control system is combined with the imbibition function of surfactant, can larger oil

21

recovery be obtained? Based on this design, in this work, mobility control system is

22

formulated by DPG and surfactant. The mobility control system with function of 4


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imbibition (MCSI) can not only improve the sweep efficiency of the crude oil in

2

fractures, but also enhance effective use of crude oil in the core matrix through

3

imbibition effect. As reported before, the recovery in matrix-fracture network can be

4

increased27-29. However, it is not clear how does the dynamic imbibition of the system

5

impact on the oil recovery in the matrix fracture network.

6

In addition, how to make matrix fracture network model is a key work, so fracture

7

model needs to be designed at first30-33. Taking tight cores as the basic object, the

8

preparation methods in lab are mainly classified into four types: volume fracturing

9

method, artificial splitting method, vaporization method, and salt ion dissolving

10

method. Fracture network structures formed by volume fracturing method and

11

artificial splitting method are irregular and cannot be repeated. In the procession of

12

vaporization method, there are a lot of gases produced that cannot volatilize

13

thoroughly, which affect the flowing of fluids. Salt ion dissolution method is based on

14

the dissolution of salt ions and is only applied to high permeability cores. Therefore, it

15

is necessary to design and set up a new matrix fracture network model preparation

16

method for tight cores.

17

In this manuscript, a matrix fracture network model was designed and prepared

18

first. This method has advantages of controllable fracture width, good replicability

19

and high operability. MCSI was constructed by DPG and a kind of surfactant34-35.

20

Basic properties of the system were characterized. In addition, various factors which

21

impact on the oil recovery on MCSI in the matrix fracture model were evaluated

22

systemly, such as fluid type, fluid concentration, fluid flow rate, fracture width, and 5


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1

etc.

2

2. EXPERIMENTAL

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2.1 Materials. MCSI was composed of DPG, surfactant, and brine. Nonionic

4

polyacrylamide (PAM) was used to prepare DPG, with degree of hydrolysis 3.31%

5

and average molecular weight of 9,650,000 g/mol provided by Yuguang Co., Ltd.

6

Dongying, China. The cross-linker of phenolic resin was purchased from Fanghua Co.,

7

Ltd. Dongying, China. Tetradecyl hydroxypropyl sulfonyl betaine (THSB), as

8

surfactant was bought from Shanghai Connaught Industry Co., Ltd. China. The

9

inorganic salts, including NaCl, Na2SO4, NaHCO3, CaCl2, MgCl2·6H2O, and KCl,

10

were bought from Sinopharm Chemical Reagent Co., Ltd. The specific formula can

11

be seen in Table 1. The oil with viscosity of 55 mPa·s at 80 °C was composed of

12

dehydrated crude oil and kerosene with a volume ratio of 1:4. The artificial cores with

13

Klinkenberg gas permeability of 0.395 mD and porosity of 4.7% were bought from

14

Hai’an Petroleum Scientific Research Apparatus Co., Ltd. Hai’an, China.

15

Table 1

16

Composition of simulated formation water Ingredient

NaCl

Na2SO4

NaHCO3

CaCl2

MgCl2·6H2O

KCl

8800

400

19500

7.2

100

970

Mass concentration (mg/L) Total dissolved 29725.5 solids (mg/L) 6


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2.2 Methods and instruments. DPG was firstly prepared, and mixed with

2

surfactant and brine to form MCSI. The properties of MCSI, including viscosity,

3

interfacial tension, and the ability to improve the wetting performance were

4

characterized. After matrix fracture network models were developed in house, the

5

dynamic imbibition of MCSI system in the matrix fracture network model was studied.

6

2.2.1 Preparation of dispersed particle gel. The DPG was prepared by high speed

7

shearing method described as follows: firstly, 0.3 wt% PAM and 0.6 wt% phenolic

8

resin were put into an oven until a bulk gel was formed at 75 °C. Then, water (200 g)

9

and bulk gel (200 g) were added simultaneously to a colloid mill rotating at 3,000 rpm

10

and milled for 3 min at 30 °C. A light yellow solution obtained from the colloid mill

11

was considered as DPG solution. The average particle diameter of the DPG was 1.3

12

µm measured by Laser particle size distribution instrument (Bettersize2000, Baite

13

instrument Co., Ltd., China).

14

2.2.2 Viscosity measurement. Brookfield Viscometer (PVS Model, Brookfield,

15

America) was used to carry out the viscosity measurement of the MCSI at the

16

temperature of 80 °C, with viscometer 0 rotor (6 r/min). About 20 mL samples were

17

injected into the sleeve. After 15 min under constant temperature, the viscosity value

18

was measured and recorded by the viscometer. Then, the samples were put into the

19

oven at 80 °C for aging. The viscosities of 0.1 wt% MCSI (0.1 wt% DPG+0.1 wt%

20

THSB), 0.1 wt% DPG solution, and 0.1 wt% THSB surfactant solution were

21

measured with aging time, respectively.

7


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2.2.3 Interfacial tension measurement. 0.1 wt% MSCI, oil, and 0.1 wt% THSB

2

surfactant solutions were prepared. The interfacial tensions between oil and MCSI, oil

3

and 0.1 wt% THSB surfactant solution were observed at 80 °C by interfacial

4

tensiometer (TX500C, Kono Company, America), respectively. The rotational speed

5

was 6000 rpm and the interfacial tension was calculated from Vonnegut

6

approximation as reported36. The IFT values were recorded when it became stable for

7

30+ min. Fluids were put into the oven at 80 °C for aging. The interfacial tension

8

between oil and 0.1 wt% MCSI, oil and 0.1 wt% surfactant solution were measured

9

with aging time, respectively.

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2.2.4 Wettability alteration measurement. The ability of MCSI to change the rock

11

wettability was measured by the goniometer (JC2000D2, Zhongchen Co., Ltd., China).

12

Formation rock was imitated by water-wet quartz plates. Initial contact angles on

13

quartz plates were measured with oil drop first. Then, quartz plates were put into 0.1

14

wt% MCSI and 0.1 wt% THSB surfactant solution, respectively. Next, oil drop was

15

applied on the quartz plate and the contact angle was measured. After fluids were

16

aging in the oven at 80 °C for 5, 10, and 15 days, the wettability alteration degrees on

17

the quartz plates were measured, respectively37-39.

18

2.2.5 Manufacturing of matrix fracture network model. The preparation method for

19

the matrix fracture network model mainly includes the following steps. Firstly, a

20

cylindrical core was selected and cut vertically into several core sections with same

21

length by core cutting machine. Secondly, the core sections were cut horizontally in a

22

certain proportion and two small core blocks were obtained. Then, these small core 8


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Energy & Fuels

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blocks were stacked naturally according to their positions before cutting. Use the same

2

method to place other core sections and put them together horizontally, so that the

3

matrix fracture network model was formed. The diagrams of actual and physical model

4

can be seen in Fig. 1.

5 6

(a)

7 8 9

(b)

Fig. 1. Diagrams of (a) actual and (b) physical matrix fracture network model.

10

During dynamic imbibition experiment, the fracture width can be controlled by

11

applying appropriate confining pressure and axial pressure. The relationship between

12

confining pressure, axial pressure, and effective fracture width is built up below:

13

For a given fracture network model, the length of the total model, L and the end

14

face sectional area, A were measured. Confining pressure and axial pressure were

15

adjusted to a certain value. The coefficient, R was introduced to establish the 9


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1 2 3 4

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relationship between the flow rate, Q and the pressure drop, ∆P.

∆P = R× Q

(1)

The end face of fracture in model can be regarded as a rectangle, so the calculation formula which contains the fracture width, w was introduced as follows:

R=

12µd L wh3

(2)

6

Through the above two equations, the relationship between ∆P and w can be

7

established. Through adjusting the confining pressure, a range of ∆P could be

8

obtained indirectly, so different fracture width would be successfully established.

9

2.2.6 Dynamic imbibition experiment. Dynamic imbibition experiment was carried

10

out at 80 °C. The equipment used during dynamic imbibition included Isco pump

11

(Model 260D, Teledyne ISCO, America), confining pressure pump, pseudo tri-axial

12

core holder, piston pump, three accumulators, and etc. Actual experimental set

13

diagram is shown in Figure S1 in the Supporting Information and schematic

14

experimental set diagram is shown in Fig. 2.

15 10


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Energy & Fuels

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Fig. 2. Diagram of schematic dynamic imbibition setup.

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In this experiment, the oil recovery by dynamic imbibition was studied from five

3

aspects: fluid type, fluid concentration, flow rate, fracture width, and matrix fracture

4

network model type. The specific impact factors and parameters are shown in Table 2:

5

Table 2

6

The main parameters of dynamic imbibition experiment Group Impact factor

Parameter range

number Matrix fracture

4 cm × 2 section

2 cm × 4 section

1 network model

Fluid

0.06 wt% DPG+

0.10 wt% DPG+

0.12 wt% DPG+

concentration

0.1 wt% THSB

0.1 wt% THSB

0.1 wt% THSB

3

Flow rate

0.05 mL/min

0.10 mL/min

0.20 mL/min

4

Fracture width

7.7 µm

11.6 µm

15.4 µm

Treatment

MCSI

Surfactant

Brine

method

flooding

flooding

flooding

2

5

7 8 9 10 11

Taking the flow rate of 0.1 mL/min as an example, the main experimental procedure was as follows: (1) Artificial cylindrical cores were selected and cut into length of 2 cm, 4 cm of short sections by using core cutting machine; (2) After each section of core was marked, it was cut horizontally into small core 11


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1

blocks according to the ratio of 1:2 on the cross sectional direction. The length, height

2

and width of each core block were measured precisely. After dried over high

3

temperature, the dry mass of each piece was weighed;

4 5

(3) Each small core block was vacuumized and saturated with oil, and then wet mass was weighed. Then the oil content of each small piece was calculated;

6

(4) According to different fracture combination modes, small core blocks were

7

combined into network model. The oil content in each model was calculated,

8

respectively;

9

(5) Calculate the effective width of the model: After the model was placed in the

10

pseudo tri-axial core holder, displacement was conducted at the set flow rate of 1

11

mL/min using oil. According to the functional relation between confining pressure,

12

axial pressure and fracture width, the expected fracture width was obtained by

13

adjusting axial pressure and confining pressure;

14

(6) Brine flooding: Under the same axial pressure and confining pressure, brine

15

was injected into the model at the flow rate of 0.1 mL/min for 10 PV. The liquid

16

production and oil fraction were recorded at certain time intervals and the pressure

17

drop along the model was recorded at the same time;

18 19

(7) MCSI flooding: With MCSI solution, the procedure was the same as brine flooding;

20

(8) 2nd water flooding: After the MSCI flooding was finished, Isco pump was

21

paused all valves at both ends of the core holder were closed. The confining pressure

22

and axial pressure were still acting on the core holder. The entire experiment 12


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Energy & Fuels

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equipment was aging in the oven with 80 °C for 24 h. After aging for 24 hours, 2nd

2

water flooding was carried out and all steps were maintained the same. Then, the oil

3

recoveries at different stages were measured.

4

Three kinds of fracture widths of 7.7, 11.6 and 15.4 µm were set in the experiment.

5

The basic parameters in the experiments were as shown in Table 3:

6

Table 3

7

Basic parameters of dynamic imbibition

Experiment

Model type

Average

no.

Length section

porosity/%

oil

Total oil

Fracture

volume/cm3 volume/cm3 width/µm

1

4 cm

2

18.88

6.7204

8.0204

7.7

2

2 cm

4

4.98

1.8277

3.5082

7.7

3

2 cm

4

4.82

1.7644

3.4450

7.7

4

2 cm

4

4.73

1.7247

3.4052

11.6

5

2 cm

4

4.41

1.6227

3.3032

7.7

6

2 cm

4

4.58

1.6465

3.3270

7.7

7

2 cm

4

3.79

1.3875

3.0680

7.7

8

2 cm

4

4.46

1.5990

3.2795

15.4

9

2 cm

4

5.76

2.0388

3.7193

7.7

10

2 cm

4

6.70

2.3695

4.0500

7.7

11

2 cm

4

6.23

3.3695

5.0500

7.7

13


Energy & Fuels

1

3. RESULTS AND DISCUSSION

2

3.1 Fluid properties

3

3.1.1 Viscosity of mobility control system with function of imbibition. The viscosity

4

of 0.1 wt% THSB surfactant solution, 0.1 wt% DPG solution and 0.1 wt% MCSI were

5

measured with aging time, respectively. 8 0.1 wt% surfactant 0.1 wt% DPG 0.1 wt% MCSI

7 6 Viscosity(mPa·s)

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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5 4 3 2 1 0

0

2

4

6

8

10

12

14

16

Aging time(day)

6 7

Fig. 3. Viscosity of three types of fluid.

8 9

As shown in Fig. 3, the viscosities of DPG and MCSI are relative high. With the

10

increase of aging time, the viscosities decrease and tend to be stable. The viscosity

11

retention rate is still higher than 70% after 15 days’ aging. This indicates that both two

12

systems have good viscosity stability. From the formation mechanism of DPG, bulk

13

gel is a tight network structure formed by the dehydration synthesis between polymer

14

amide group and crosslinking agent methylol. This is mainly related to the formation

15

mechanism of phenolic resin DPG, which means that the bulk gel is compact network 14


Page 15 of 32

1

structure formed by dehydration condensation polymer methylol amide and

2

crosslinking agent. The structure can ensure that bulk gel has high viscosity40. Also,

3

during the preparing process of phenolic resin DPG, bulk gel with tight network

4

structure was only shredded by mechanical shearing, and its viscoelasticity was

5

retained. With time aging, DPG produced a certain degree of aggregation under salt

6

ions, which formed larger particle41. The nonuniform distribution of DPG reduced the

7

interaction forces between single particle and aggregated particles, thus resulted in the

8

reduction of viscosity.

9 10

3.1.2 Interfacial tension between oil and MCSI. The interfacial tension between oil

11

and 0.1 wt% MCSI, oil and 0.1 wt% surfactant solution were measured with aging

12

time, respectively, as shown in Fig. 4. 0.030 MCSI 0.1 wt% surfactant

0.025 0.020 IFT (mN/m)

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Energy & Fuels

0.015 0.010 0.005 0.000

0

2

4

6

8

10

12

Aging time (day)

13 14

Fig. 4. The interfacial tension of two types of fluid with aging time.

15 15


14

16

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1

From Fig. 4, the interfacial tension for both MCSI and surfactant solution is in the

2

growing trend. The ultra-low interface tension maintained by surfactant is longer,

3

comparing with MCSI solution. For the first 8 days, surfactant kept the interface

4

tension to ultra-low level. This is because the surfactant, THSB is a sulfonate betaine

5

surfactant, which has a chelating effect on the divalent salt ions in brine solution and

6

improves its characteristic of salt tolerance42. Under the brine condition, salt ions

7

could break the hydration shell and reduce the electrostatic repulsion of hydrophilic

8

head groups. More active molecules adsorbed on the oil-water interface and a close

9

interface layer arrangement could be formed. At the same time, due to the existence of

10

salt, some surfactants molecules lost their effectiveness and their adsorption capacity

11

on the oil-water interface were reduced, which made the molecular layer of interface

12

layer relatively sparse43. As a result, the ability of surfactant to reduce the interfacial

13

tension between oil and surfactant decreased with aging time.

14

However, MCSI solution maintained the interface tension to ultra-low level for 4

15

days only, then the interfacial tension increased to 10-2 mN/m level. Surfactant

16

components in MSCI adsorbed on the DPG particle surface by the hydrophobic effect,

17

so the amount of the surfactant molecules in MCSI were reduced44-45. Therefore, the

18

ability of MCSI to reduce the interfacial tension between oil and water has been

19

reduced.

20

16


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1

3.1.3 Wettability alteration by MCSI. To investigate the ability for fluid to change

2

rock wettability, the surfactant and MCSI solution were used to treat the quartz plates.

3

With the contact angle of oil/water/quartz plate system, water-wet quartz plates were

4

immersed in 0.1 wt% THSB surfactant and 0.1 wt% MCSI for different times. Then,

5

the contact angles of oil droplets were measured carefully, as shown in Fig. 5.

150 Surfactant MCSI

145 Contact angle (°)

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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140

135

130

0

5

10

15

20

Aging time (day) 6 7

Fig. 5. Contact angles of oil droplets in different types of fluid after aging.

8 9

From Fig. 5, both MCSI and surfactant solution could affect the wettability of the

10

quartz plate. The contact angles of oil droplets in both fluids increase with aging. The

11

surfactant components of two systems absorbed on the quartz plate by electrostatic

12

interaction and increased the hydrophilicity of the quartz plate.

13

With the same aging time, the contact angle on surfactant treated quartz plate was

14

higher. This was due to more surfactant molecules contained in the MCSI. With time 17


Energy & Fuels

1

aging, the amount of surfactant molecules and the adsorption on the quartz plate

2

surface were reduced. In addition, DPG components of MCSI also adsorbed on the

3

water wet quartz plate surface through hydrogen bonding interaction and reduced the

4

adsorption potential on the quartz plate surface. Thus, the adsorption of the surfactant

5

on the quartz plate was reduced. The ability to improve the wettability of quartz plate

6

of THSB surfactant was better than MCSI.

7 8

3.2 Oil recovery during MCSI dynamic imbibition

9

3.2.1 Effect of fluid type. With the matrix fracture network model of 2 cm × 4

10

section, at the flow rate of 0.1 mL/min and the fracture width of 7.7 µm, the oil

11

recovery by the dynamic imbibition of surfactant, DPG, MSCI solution, and water

12

were studied. The results are shown in Fig. 6. 4.0 Chemical flooding 2nd water flooding

3.5 3.0 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

Page 18 of 32

2.5 2.0 1.5 1.0 0.5 0.0

MCSI

surfactant dispersed particle gel Various fluids

13 14

Fig. 6. Oil recoveries by three types of fluid.

15 18


Page 19 of 32 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

1

From Fig. 6, the oil recovery by MCSI solution is the highest among the three

2

chemicals. As for surfactant flooding, on the one hand, surfactant solution first passed

3

through the fracture which was the dominant channel and displaced the oil in the

4

fracture. On the other hand, surfactant molecules absorbed on the matrix surface and

5

the oil in the matrix was stripped by dynamic imbibition. But the mobility control

6

ability of surfactant solution was weak, most of the surfactant molecules passed

7

through the fracture, so the number of surfactant molecules which entered the core

8

matrix to carry out dynamic imbibition was very small. As a result, the increased oil

9

recovery by surfactant flooding is mainly due to the displacement of oil in the fracture.

10

Due to the increased viscosity and larger particle size, the dispersed particle gel

11

mainly developed the ability to improve mobility as increased volumetric sweep

12

efficiency. However, MCSI consists of dispersed particle gel and surfactant, which

13

has the advantages of two fluids, thus features of dual function of mobility control and

14

oil discharging by imbibition. So the displacement effect of MCSI is better than each

15

single component, and the mechanisms of dynamic imbibition of various fluids are as

16

shown in Fig. 7.

17 18

Fig. 7. Mechanisms of dynamic imbibition of various fluids in tight oil fracture 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

1

model.

2 3

Moreover, after aging for 24 h, the oil recovery by 2nd water flooding after MCSI is

4

also higher than that with surfactant and DPG. For surfactant solution, the surfactant

5

molecules were mainly retained in the fractures, and the number of molecules which

6

entered the matrix for imbibition was very small. For DPG solution, DPG particles

7

mainly played a role in blocking the fracture and regulating the mobility, but the main

8

oil had already been discharged during the previous displacement process. For MSCI,

9

the DPG particles could block the fracture in the chemical displacement, which made

10

a large number of surfactant molecules enter into the matrix. After aging for 24 h, the

11

oil in the matrix was stripped to the fracture by imbibition, and the residual oil in

12

fracture and the oil in the matrix could be both displaced through 2nd water flooding.

13

So the oil recovery by 2nd water flooding after MCSI is also higher than that with

14

surfactant and DPG.

15

3.2.2 Effect of MCSI concentration. With the 2 cm × 4 section model, at the flow

16

rate of 0.1 mL/min and the fracture width of 7.7 µm, the effects of MCSI with

17

different concentrations (0.06 wt% DPG+0.1 wt% surfactant, 0.10 wt% DPG+0.1

18

wt% surfactant, 0.12 wt% DPG+0.1 wt% surfactant) on displacement effect were

19

studied. The relationship between the oil recovery and the MCSI concentration is

20

shown below:

20


Page 20 of 32

Page 21 of 32

5

4

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

Energy & Fuels

3

2

1

0

1 2

0.06%

0.1%

0.12%

MCSI concentration Fig. 8. Recoveries under different MCSI concentrations.

3 4

From Fig. 8, with the increase of MCSI concentration, the oil recovery improves.

5

On the one hand, the increased content of DPG in MCSI solution resulted in more

6

DPG particles, so more displacement fluid molecules were more beneficial to improve

7

the efficiency of the displacement for oil in the fracture. On the other hand, with the

8

increase of the MCSI concentration, more DPG particles blocked the fracture, which

9

made more surfactant molecules enter the core matrix. The oil in the matrix was

10

stripped into the fracture through imbibition and displaced outside. At the same time,

11

these particles played a key role in the mobility control in fractures. The viscosity of

12

the displacement fluid increased and more fracture space was blocked, the mobility

13

was improved and sweep efficiency was enhanced. Therefore, higher DPG content in

14

MCSI solution generates better oil recovery.

21


Energy & Fuels

1

3.2.3 Effect of fluid flow rate. With the 2 cm × 4 section model, at the fluid

2

concentration of 0.10 wt% DPG+0.1 wt% surfactant and the fracture width of 7.7 µm,

3

three different flow rates (0.05, 0.10, 0.20 mL/min) were carried out. The injection

4

pressures of MCSI flooding and 2nd water flooding at different flow rates were

5

observed, as shown in Fig. 9. 18 16

MSCI flooding 2nd water flooding

14 Injection pressure (kPa)

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 32

12 10 8 6 4 2 0

0.05 mL/min

0.1 mL/min

0.2 mL/min

Flow rate

6 7

Fig. 9. Pressure drop at three stages with different flow rate.

8 9

Fig. 9 shows that higher flow rate generates larger pressure drop along the model.

10

From Darcy’s law, the flow rate is proportional to the injection pressure. Besides, for

11

all the three different flow rates, the pressure drop of MCSI flooding is a little higher

12

than 2nd water flooding. This is mainly because that the viscosity of MCSI is much

13

higher than water. It can be known form Darcy’s law that the viscosity is proportional

14

to the injection pressure. After MCSI flooding, there would be some residual of

15

dispersed particle gel. After aging for 24 h, the DPG had possibility to aggregate as 22


Page 23 of 32

1

large particle groups. They would cause blocking in fracture, and result in higher

2

water flooding pressure46. So for all the three different flow rates, the pressure drop of

3

MCSI flooding is only a little higher than 2nd water flooding.

4 5

The experiment further studied the oil recovery of the MCSI flooding and 2nd water flooding at different flow rates. The results are shown in Fig. 10. 6 MCSI flooding 2nd water flooding

5 4 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

Energy & Fuels

3 2 1 0

0.05 mL/min

0.1 mL/min

0.2 mL/min

Flow rate

6 7

Fig. 10. Oil recoveries of different flooding agents at various flow rates.

8 9

It can be seen that, for the MCSI flooding and 2nd water flooding, the oil recoveries

10

of both two systems increase with the reducing of flow rate. When two systems

11

flowed through the model at higher flow rate, there was not enough time for them to

12

fully interact with the oil in the fracture. The range of action for the systems was

13

smaller so the displacement efficiency was reduced47. Besides, it is known that

14

imbibition is the main driving force of oil displacement48. Especially for MCSI, while

15

the flow rate was higher, the blocking space of DPG particles became smaller. Fewer 23


Energy & Fuels

1

surfactant molecules entered the matrix and the amount of stripped oil by imbibition

2

was smaller. The mobility control ability of DPG and the imbibition action of

3

surfactant became weaker at higher flow rate. As a result, the oil recoveries of both

4

two systems increase with the reducing of flow rate.

5

3.2.4 Effect of fracture width. While the 2 cm × 4 section model was used, at the

6

flow rate of 0.1 mL/min and the fluid concentration of 0.10 wt% DPG+0.1 wt%

7

surfactant, the dynamic imbibition experiment was carried out by adjusting the

8

confining pressure and axial pressure to three corresponding fracture widths: (7.7,

9

11.6, 15.4 µm). The recovery of MCSI flooding and 2nd water flooding at different

10

fracture widths is shown in Fig. 11. 7 6


5 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

Page 24 of 32

4 3 2 1 0

11 12

7.7 µm

11.6 µm

15.4 µm

Fracture width

Fig. 11. Recovery of different driving modes at different fracture widths.

13 14

Fig. 11 shows that when the fracture width is 11.6 µm, the recoveries of MCSI

15

flooding and 2nd water flooding are both higher than those of 7.7 µm and 15.4 µm. 24


Page 25 of 32

1

Therefore, for the dispersed particle gel with an average particle size of 1.3 µm, it

2

matches with the fracture width of the model. Dispersed particle gel has better

3

mobility control ability in the fracture width of 11.6 µm, so the recovery of the 2nd

4

water flooding is the highest in the core model at the fracture width of 11.6 µm.

5

3.2.5 Effect of matrix fracture network model type. Two types of matrix fracture

6

network models (4 cm × 2 section、2 cm × 4 section) were used to study the effect of

7

model types on oil recovery. The actual diagrams of two types of models are shown in

8

Fig. 1 (a).

9

Dynamic imbibition experiment was carried out at the flow rate of 0.05 mL/min

10

and the fracture width of 7.7 µm. The recoveries of two types of models with MCSI

11

flooding and 2nd water flooding are shown in Fig. 12. 4.5 4.0


3.5 3.0 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

Energy & Fuels

2.5 2.0 1.5 1.0 0.5 0.0

4 cm*2

2 cm*4

Fracture combination method

12 13

Fig. 12. Recoveries of two types of matrix fracture network models.

14 15

From Fig. 12, while the flow rate and fracture width are certain, the oil recoveries 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

1

in 2 cm × 4 section network model with MCSI flooding and 2nd water flooding are

2

higher than those with 4 cm × 2 section network model, respectively. When the

3

fracture network becomes more complex, the flowing resistance in fracture increases.

4

Thus the mobility is decreased, and the oil recovery is higher.

5 6

4. CONCLUSIONS

7

(1) With artificial cores, a method to prepare matrix fracture network model had been

8

developed. It has the characteristics of controllable fracture length, height and

9

width. It is also replicable and can be used for single factor study.

10

(2) MCSI system features low viscosity, ultra-low oil-water interfacial tension (10-2

11

mN/m), and strengthening hydrophilicity. These properties would promote the

12

imbibition effect.

13

(3) MCSI system has dual function of mobility control by DPG and oil discharging

14

through imbibition by surfactant, so the oil recovery during dynamic imbibition in

15

matrix fracture network model is better than that of single surfactant solution and

16

single DPG solution.

17

(4) Within a certain range, the recovery achieved by MCSI flooding and 2nd water

18

flooding is proportional to the MSCI concentration and the fracture network

19

complexity, and is inversely proportional to the displacement flow rate.

20

(5) MCSI system has better mobility control ability in fracture width of 11.6 µm than

21

that in other sizes, and the displacement effect of the 2nd water flooding is also the

22

highest in the matrix fracture network model with the fracture width of 11.6 µm. 26


Page 26 of 32

Page 27 of 32 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

1 2

Acknowledgements

3

The work was supported by the National Science Fund for Distinguished Young

4

Scholars (No. 51425406), the Chang Jiang Scholars Program (No. T2014152), the

5

National Key Basic Research Program (No. 2015CB250904), the Climb Taishan

6

Scholar Program in Shandong Province (No.tspd20161004), the Outstanding Young

7

Scientist Award of Shandong Natural Science Foundation (No. ZR2016EEB35), and

8

the Fundamental Research Funds for the Central Universities (14CX02184A,

9

16CX02056A).

10

11

AUTHOR INFORMATION

12

Corresponding Author

13

*Caili Dai, Phone: 86-532-86981183, Fax: 86-532-86981161, E-mail: [email protected].

14

Notes:

15

The authors declare no competing financial interest.

16

17

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Enhanced Oil Recovery Study of a New Mobility Control System on the

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