Inhibition of the Hydration Expansion of Sichuan Gas Shale by

Subscriber access provided by UNIV OF SOUTHERN INDIANA

Fossil Fuels

Inhibition of the Hydration Expansion of Sichuan Gas Shale by Adsorption of Compounded Surfactants Jingping Liu, Zhiwen Dai, Congjun Li, Kaihe Lv, Xianbin Huang, Jinsheng Sun, and Bing Wei Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.9b00637 • Publication Date (Web): 09 Jun 2019 Downloaded from http://pubs.acs.org on June 10, 2019

Just Accepted “Just Accepted” manuscripts have been peer-reviewed and accepted for publication. They are posted online prior to technical editing, formatting for publication and author proofing. The American Chemical Society provides “Just Accepted” as a service to the research community to expedite the dissemination of scientific material as soon as possible after acceptance. “Just Accepted” manuscripts appear in full in PDF format accompanied by an HTML abstract. “Just Accepted” manuscripts have been fully peer reviewed, but should not be considered the official version of record. They are citable by the Digital Object Identifier (DOI®). “Just Accepted” is an optional service offered to authors. Therefore, the “Just Accepted” Web site may not include all articles that will be published in the journal. After a manuscript is technically edited and formatted, it will be removed from the “Just Accepted” Web site and published as an ASAP article. Note that technical editing may introduce minor changes to the manuscript text and/or graphics which could affect content, and all legal disclaimers and ethical guidelines that apply to the journal pertain. ACS cannot be held responsible for errors or consequences arising from the use of information contained in these “Just Accepted” manuscripts.

is published by the American Chemical Society. 1155 Sixteenth Street N.W., Washington, DC 20036 Published by American Chemical Society. Copyright © American Chemical Society. However, no copyright claim is made to original U.S. Government works, or works produced by employees of any Commonwealth realm Crown government in the course of their duties.

Page 1 of 20 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

Inhibition of the Hydration Expansion of Sichuan Gas

2

Shale by Adsorption of Compounded Surfactants

3

Jingping Liu1,* Zhiwen Dai1, Congjun Li2, Kaihe Lv1, Xianbin Huang1, Jinsheng Sun1,2, Bing,

4

Wei3,*

5

1College

6

People’s Republic of China.

7

2CNPC

Engineering Technology R&D Company Limited, Beijing 102206, People’s Republic of China

8

3State

Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum

9

University, Chengdu, Sichuan 610500, China

of Petroleum Engineering, China University of Petroleum (East China), Qingdao 266580,

10

ABSTRACT

11

Water-based drilling fluids are characterized by cost-effective, wide sources of raw

12

materials and environment-friendly. However, it is prone to cause various accidents

13

that affect the drilling efficiency. One of the main problems is that conventional

14

inhibitors cannot effectively suppress the hydration expansion of shale in Sichuan. In

15

this study, we found that a mixture of Span 20 and Tween 60 can enhance the

16

hydrophobicity of shale by forming a hydrophobic membrane on shale surface,

17

which reduces the number and weakens the hydrogen bond between water and

18

shale, thereby greatly reducing the amount of water entering into the shale.

19

Consequently, hydration expansion rate of shale, dissolution of salts in the shale and

20

the decrease of compressive strength are suppressed by adding the mixture of

21

surfactants. Thereby wellbore stability is maintained during drilling. The expansion

22

rate of average hole-diameter is only 7.47%, and drilling rate was 1.71 times as fast

23

as using oil-based mud in a nearby well in the field tests in Sichuan, China.

24

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

1. INTRODUCTION

2

The development of unconventional energy has changed the global supply of oil and

3

gas, the shale gas in especial now is sweeping the world.1-3 Shale gas has many

4

advantages, ranging from a large resource potential and a wide distribution range to

5

a high efficiency and cleanliness. Its large-scale development will change the world

6

landscape of energy use and have a profound impact on the global economy.4,5

7

Drilling fluid plays a very important role in the development of oil and gas field.6

8

Drilling fluids usually consist of water or oil, clay particles, treatment agents,

9

weighting materials, and other components7. Its main function is to stabilize the

10

borehole wall, transport drill cuttings, clean the wellbore, control the pressure, cool

11

and lubricate the drill bit, and form a thin and impervious filter cake.8-10

12

Oil-based drilling fluids have played an important role in early shale gas drilling due

13

to good lubricity and strong stability, but they are costly and detrimental to the

14

environment.11 Water-based drilling fluids are widely considered to be cost-effective,

15

wide sources of raw materials and environment-friendly.12-14 However, various

16

accidents, such as borehole collapse and sticking, can occur due to the hydration

17

expansion of the clay minerals in shale during the drilling of shale gas wells with

18

water-based drilling fluids.15 Therefore, water-based drilling fluids cannot be used in

19

large-scale applications in drilling for shale gas in Sichuan.

20

One of the most effective approaches for managing the hydration expansion of clay

21

minerals is by adding inhibitors. For example, the addition of quicklime can reduce

22

the swelling potential of pulverized expansive shale.16 Organic cations can narrow

23

the diffusion pathway and decrease the diffusive transport of water by adsorbing

24

onto the external surfaces of clay minerals.17 Silicates, which were first introduced in

25

the 1930s to solve the shale instability issues, have also been shown to enhance the

26

stability of shale.18,19 Potassium chloride20 and sodium chloride21 are commonly

27

added to water-based drilling fluids to minimize clay hydration. In addition,

28

polymers22 and polyamines23 are widely used to control clay swelling. Finally,

29

nano-materials own the capability to adsorb at interface forming a tight film and to

30

inhibit shale hydration.24-28 Various nanoparticles can control water invasion into the


Page 2 of 20

Page 3 of 20 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

wellbore and reduce clay swelling in shale; examples include nanographite29,

2

nanosilica30, carbon nano tubes31, graphene oxide32, copper oxide, and zinc oxide33.

3

However, wellbore instability caused by shale swelling during the drilling of gas shale

4

formations in Sichuan, China is still a major issue. Therefore, the introduction of a

5

high-efficiency hydration inhibitor for Sichuan shale formations is one of the key

6

approaches to facilitating efficient shale gas development in China.

7

Span 20 (sorbitol sorbate) is mainly used in medicine, cosmetics, and textiles as a

8

water/oil emulsifier, wetting agent, and mechanical lubricant. Tween 60

9

(polyoxyethylene sorbitan monostearate) is mainly used as an emulsifier, stabilizer

10

(especially in frozen confections to prohibit the separation of oil and water), and a

11

dispersing agent (such as in the dispersion of non-dairy Coffeemate). However, the

12

ability of a mixture of Span 20 and Tween 60 to behave as an inhibitor during shale

13

drilling has never been explored.

14

In this study, we evaluated the ability of a mixture of Span 20 and Tween 60 to

15

inhibit shale expansion and studied the inhibitory mechanism. Interestingly, we

16

found that this mixture functioned as an excellent inhibitor of Sichuan shale

17

expansion, whereas commonly used inhibitors were ineffective. This study provides

18

a novel method to inhibit Sichuan shale hydration in China.

19

2. Shale sample

20

The contents and types of clay minerals in shale are the key factors determining the

21

hydration expansion properties of shale. At present, the main producing area of

22

shale gas in China is in Sichuan, and the Longmaxi Formation is the main production

23

layer of shale gas development in Sichuan, so we choose shale from the Longmaxi

24

formation as our research subject. The shale composition was analyzed by INCA

25

X-ray spectrometry (SY/T 5163-2010).


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 2

Figure 1. (a) Mineralogical composition analysis of shale. (b) Ultrastructural features

3

of illite in gas shale by scanning electron microscopy.

4

As shown in Figure 1(a), the composition of the shale was high in clay minerals (illite,

5

smectite, kaolinite, chlorite), quartz, and calcite, with proportions of 24%, 30.3%,

6

and 27.4%, respectively. Clay minerals were mainly composed of illite, which had an

7

incomplete slat-like morphology when viewed under a scanning electron microscope

8

(Figure 1(b)). Clay minerals did not contain smectite, indicating that the hydration

9

expansion of the gas shale from the Longmaxi Formation in Sichuan was mainly

10

caused by the hydration expansion of illite. Therefore, inhibitors that can effectively

11

inhibit the hydration of gas shale are likely to inhibit the hydration of illite.

12

3. Surface tension and contact angle measurement

13

The contact angle of water droplets on shale after interacting with an inhibitor can

14

indicate the effect of the inhibitor on the hydrophobicity of the shale surface. In

15

general, the stronger the shale hydrophobicity, the weaker the hydration expansion.

16

It reveals that the inhibitor is effective in mitigating shale hydration. In this

17

experiment, the contact angle of water droplets at different temperatures was

18

measured with a DCAT21 surface tension meter using the Washburn method

19

(Germany Data Physics Instrument Co., Ltd.).34 The inhibitor (SP) was a mixture of

20

Span 20 and Tween 60 at a ratio of 1:1.


Page 4 of 20

Page 5 of 20 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

Figure 2. Surface tension of the inhibitor at different concentrations and

3

temperatures

4

Figure 2 shows the results of the surface tension test of SP. As the SP concentration

5

increased from 0.5% to 5%, the surface tension of the solution increased moderately.

6

As the temperature increased from 25 °C to 80 °C, the surface tension of the solution

7

decreased moderately. The effect was more pronounced from 60 °C to 80 °C. SP can

8

effectively reduce the surface tension of water in a wide range of temperature and

9

concentrations, consequently, reduce the capillary force of shale and the water

10

absorption due to capillary force. Therefore, it has the capability to inhibit hydration

11

expansion of shale.


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 2

Figure 3. Contact angle of shale at different temperatures after immersion in water

3

solutions of different inhibitor concentrations

4

As the SP concentration increased from 0.5% to 5%, the contact angle of water

5

droplets on shale increased shown in Figure 3. As the temperature increased from

6

25 °C to 60 °C, the contact angle decreased moderately. However, after the

7

temperature reached 80 °C, the contact angle was reduced greatly. These results

8

show that increasing the concentration of SP and decreasing the temperature can

9

increase the contact angle of shale with water, thereby increasing the

10

hydrophobicity of shale.

11

4. Expansion test of shale

12

Shale expansion is a key feature reflecting the interaction between shale and water,

13

and it affects the stability of the shale wall during drilling. Because the main

14

component of clay minerals in shale is illite, it is also necessary to study the

15

hydration expansion properties of illite. A series of expansion tests for illite and shale

16

in an inhibitor solution at different concentrations and temperatures were carried

17

out. The illite mineral, with an effective content of 60 w/w%, was purchased from

18

Chengdu Chunfeng Petroleum Technology Co., Ltd.


Page 6 of 20

Page 7 of 20 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

Figure 4. (a) Expansion rate of illite in an inhibitor solution of different concentrations at

3

25 °C. (b) Expansion rate of shale in an inhibitor solution of different concentrations. (c)

4

Expansion rate of shale in water at different temperatures without SP. (d) Expansion rate of shale

5

in an SP solution at different concentrations at 25 °C. (e) Expansion rate of shale in 3% SP

6

solution at different temperatures.

7

As shown in Figure 4(a), the final expansion rates of illite in water, 5% potassium

8

chloride, 5% sodium chloride, 5% potassium silicate, and 5% sodium silicate were

9

33.07%, 28.3%, 29.21%, 26.95%, and 27.5%, respectively, indicating that these

10

inhibitors have moderate inhibitory effects on illite. However, the decrease in


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

swelling was not significant, revealing the relatively weak performance of these

2

inhibitors. In a 3% SP solution, the final expansion rate of illite was only 5.19%, which

3

is 27.88% lower than its expansion in water, indicating that SP can significantly

4

inhibit the hydration expansion of illite. Because of the high content of illite in the

5

shale composition, the expansion rate of shale in inhibitor solutions of different

6

concentrations showed a phenomenon similar to that of Figure 4(a). As shown in

7

Figure 4(b), the final swelling rates of shale in water, 5% potassium chloride, 5%

8

sodium chloride, 5% potassium silicate, and 5% sodium silicate solution were 15.42%,

9

13.25%, 13.64%, 12.62%, and 12.85%, respectively, indicating that the inhibition of

10

these commonly used inhibitors on shale was not significant. The expansion rate of

11

shale in a 3% SP solution was only 2.46%, which was 12.96% lower than that in water,

12

indicating that SP is an excellent choice in controlling shale expansion.

13

The expansion of shale in SP solutions of different concentrations is presented in

14

Figure 4(c). When the SP concentration ranged from 0.5 to 4%, the final expansion

15

rate of shale decreased from 10.34% to 1.24%, indicating that the degree of the

16

inhibitory expansion increased with the SP concentration. When the SP

17

concentration was higher than 3%, the expansion of shale was less dependent on the

18

SP concentration, with a relatively steady performance. Taking cost-effectiveness

19

and practical use into account, an optimized concentration of 3% was used for the

20

following characterizations.

21

As shown in Figure 4(d), the expansion of shale increased with increasing

22

temperature. As the temperature increased from 40 °C to 100 °C, the final expansion

23

rate of shale increased from 15.89% to 17.95%, indicating that high temperatures

24

promoted shale hydration. SP showed good performance in controlling shale

25

swelling under different temperatures as presented in Figure 4(e). As the

26

temperature increased from 40 °C to 100 °C, the final expansion rate increased from

27

1.27% to 4.12%, indicating that SP effectively controlled shale expansion at high

28

temperatures. All samples showed a similar trend of expansion and stabilized quickly

29

at approximately the same time point, which may have been related to the rapid

30

water absorption of shale and the rapid achievement of water saturation.


Page 8 of 20

Page 9 of 20 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

5. SEM analysis

2

To understand interactions between shale and SP better, ultrastructural

3

observations were made using a JEOL JSM-6510 scanning electron microscope with

4

an accelerating voltage of 3.0 kV.

5 6

Figure 5. SEM of gas shale (a) original shale. (b) shale after exposure to a 3% SP

7

solution for 24 hours.

8

As shown in Figure 5, after the shale was immersed in a 3% SP solution for 24 hours,

9

SP was strongly adsorbed onto the surface of the shale, which altered the wettability

10

of the shale and the surface of the shale to hydrophobic (Figure 3), thereby

11

effectively inhibiting shale hydration (Figure 4).

12

6. Infrared analysis

13 14

Figure 6. IR of shale before and after immersion in a 3% SP solution for 24 hours.

15

As shown in Figure 6, the hydrogen bonds formed by the free hydroxyl groups in


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

shale and SP-inhibited shale were at positions 3618.459 cm-1 and 3628.103 cm-1,

2

respectively, indicating that the addition of SP weakened the strength of the

3

hydrogen bonds formed by the free hydroxyl groups in the shale. At the same time,

4

the peak areas of the hydrogen bonds formed by the free hydroxyl groups in clean

5

shale and SP-inhibited shale were 2.332 and 0.256 %*cm-1, respectively, indicating

6

that SP greatly reduced the number of hydrogen bonds.

7

The hydrogen bonds formed by self-associated hydroxyls in shale and SP-suppressed

8

shale were represented by 3398.574 and 3408.218 cm-1, respectively. The smaller

9

the wavenumber, the larger the wavelength, the smaller the frequency, and the

10

higher the energy. The wavenumber of the hydrogen bond absorption peak formed

11

by the self-associated hydroxyl groups in SP-suppressed shale was larger than that in

12

shale, indicating that the addition of SP weakened the strength of the hydrogen

13

bonds. At the same time, the peak areas of the hydrogen bonds formed by

14

self-associated hydroxyl groups were 1.451 and 0.053 %*cm-1, respectively,

15

indicating that SP greatly reduced the number of hydrogen bonds in shale. In the

16

infrared spectrum of the Longmaxi Formation shale in 3% SP solution, there is a

17

double peak at 2924.35 cm-1, which is the bond of C-H stretching vibration, which

18

confirms that the SP occurs a lot of adsorption on the surface of the shale.

19

In summary, the addition of SP weakened the strength of the hydrogen bonds

20

formed by the free hydroxyl groups and the self-associated hydroxyl groups. At the

21

same time, SP significantly reduced the number of the two types of hydrogen bonds,

22

which explains why SP can inhibit the expansion of shale.

23

7. Shale compressive strength test

24

Shale strength can affect the stability of the borehole during the drilling process. The

25

lower the strength, the more likely accidents are to occur during drilling. Conversely,

26

the higher the strength, the more stable the borehole wall. Shale cores, with a

27

diameter of 25 mm and a length of 30 mm, were first dried in an electrothermal

28

constant temperature oven (202-OA type) at 100 °C for 6 hours, and then cooled in a

29

desiccator for 4 hours. Finally, the cores were immersed in different inhibitor

30

solutions for 24 hours, before uniaxial compression tests of the shale samples were


Page 10 of 20

Page 11 of 20 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

conducted using a TAW-2000 rock triaxial tester with an axial deformation rate of

2

0.00125 mm/s. The water used in this experiment is deionized water.

3 4

Figure 7. (a) Shale strength after immersion in an SP inhibitor solution of different

5

concentrations. (b) Shale strength after immersion in commonly used inhibitor solutions. (c)

6

Shale strength after immersion in water at different temperatures. (d) Shale strength after

7

immersion in a 3% SP solution at different temperatures.

8

As shown in Figure 7(a), SP effectively mitigated the degradation of the shale

9

compressive strength after immersion in water. After the shale was soaked in water,

10

the compressive strength was 31.39 MPa. When 0.5% SP was added to the soaking

11

water, the shale compressive strength increased to 46.37 MPa, and as the SP

12

concentration in water increased, the shale compressive strength continued to

13

increase. When the concentration reached 4%, the shale compressive strength was

14

65.28 MPa, which was similar to the original shale compressive strength of 77.46

15

MPa. The shale cores were dried at 100 °C for 6 h, and then cooled in a desiccator for

16

4 h. Compared with conventional inhibitors, such as sodium chloride, potassium

17

chloride, and silicate (Figure 7(b)), SP was much more effective in mitigating the


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

degradation of the shale compressive strength. When the SP concentration was

2

higher than 3%, the compressive strength was less dependent on the concentration,

3

with a relatively steady performance.

4

As shown in Figure 7(c), with increasing temperature, the compressive strength of

5

shale after soaking in water decreased moderately from 30.74 MPa at 40 °C to 27.42

6

MPa at 100 °C, which may have been related to the elevated temperature that

7

promoted shale expansion. After adding 3% SP, the compressive strength of shale

8

was greatly improved and varied from 61.43 MPa at 40 °C to 57.45 MPa at 100 °C,

9

indicating that SP was conducive to maintaining the strength of shale after soaking in

10

water at different temperatures.

11

8. Ion detection experiment

12

To study the composition and content of soluble salts in gas shale, the water before

13

and after soaking shale was quantitatively analyzed. The gas shale was crushed with

14

a pulverizer. Ten grams of shale powder was then immersed in 500 ml of water for

15

72 hours, and the water-soaked shale was removed by filtering with a qualitative

16

filter paper. Finally, anions, such as F-, Cl-, and SO42-, and cations, such as K+, Na+,

17

Mg2+, and Ca2+, in the filtered water were quantitatively analyzed by ICS-5000

18

multi-function ion chromatography. The water used in this experiment is deionized

19

water.

20

The concentrations of SO42-, Cl-, F-, K+, Na+, and Mg2+ in water increased from 1.0,

21

0.46, 0, 0, 0.3, and 0 mg/L to 16.5, 3.3, 0.2, 7.2, 14.2, and 0.1 mg/L, respectively,

22

after soaking the shale, indicating that the shale contained large quantities of soluble

23

salts, including sulfate, chloride, potassium, and sodium. When shale was exposed to

24

water, these salts dissolved, which may have caused shale collapse. As shown in

25

Figure 8(b), the concentrations of SO42-, Cl-, K+, and Na+ in the SP solution decreased

26

greatly after soaking the shale, indicating that SP can effectively inhibit the

27

dissolution of salts in shale into water, which is good for stabilizing the shale wall. As

28

shown in Figure 8(c), the concentrations of SO42-, Cl-, F-, K+, Na+, and Mg2+ in water

29

increased to 17.1, 3.8, 0.2, 7.8, 15.3, and 0.4 mg/L after soaking the shale at 100 °C,

30

generally higher than the ion concentration in water after shale immersion at 25 °C,


Page 12 of 20

Page 13 of 20 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

indicating that high temperatures promote the dissolution of salts in shale. The

2

concentrations of SO42-, Cl-, K+, and Na+ in the SP solution decreased to 8.5, 1.3, 3.0,

3

and 6.1 mg/L after soaking shale at 100 °C, indicating that SP can effectively inhibit

4

the dissolution of salts in shale at high temperatures.

5 6

Figure 8. (a) Ion concentration in water for shale immersed at 25 °C. (b) Ion

7

concentration in water for shale immersed at 25°C. (c). Ion concentration in water

8

for shale immersed at 100°C.

9 10

Figure 9. (a) Mechanism of SP inhibition of shale hydration. (b) Mechanism of SP

11

inhibitor stabilizing shale wall.


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

Page 14 of 20

1

The mixture of Span 20 and Tween 60 formed a hydrophobic membrane on the

2

surface of the shale by adsorption, greatly reducing the amount of water entering

3

into the shale (Figure 9(a)), which effectively inhibited the hydration expansion of

4

the gas shale in Sichuan, maintained the compressive strength of the shale, and

5

reduced the dissolution of salts in the shale, thereby effectively maintaining wellbore

6

stability during drilling (Figure 9(b)).

7

9. Shale gas field tests

8

SP was successfully applied in a gas shale field. A gas shale well in Sichuan, China was

9

chosen for the field trial. The well was 4718 m deep, and the bottom-hole

10

temperature was 100 °C. The well was drilled with drilling fluid containing 3% SP. Table 1 Drilling fluid formula and stratigraphic lithology

11 Bottom hole temperature (°C)

100

Well depth (m)

2570-4 178

Drilling fluid formula

Stratigraphic lithology

2% Bentonite + 0.1% NaOH + 0.1% Na2CO3 + 3% SP + 5 - 7% Resin fluid loss additive + 3-5% Plugging agent + 3-4% Lubricant + Barite

black mudstone, shale, siliceous shale, carbonaceous shale, with several to several tens of centimeters thick of rich bioclastic argillaceous limestone at the top, partially deep grayish gray mudstone, brownish gray argillaceous siltstone strip or thin layer

12

The drilling fluid formulation and formation lithology are shown in Table 1, and the

13

well containing mainly shale was more likely to cause down-hole accidents. The

14

performance of the drilling fluid is shown in Table 2, and the yield point, plastic

15

viscosity, and gel strength met design requirements. In particular, the 4.8 mL of

16

FLHTHP was very low, which was conducive to the stability of the well wall. Table 2 Performance of drilling fluids used in field

17 Well

Density (g/cm3)

PV (mPa·s)

YP (Pa)

Gel (G’/G’’) (Pa/Pa)

FLAPI (mL)

Before hot rolling

1.79–1.80

55

21.5

3.5/6.5

0.2

After hot rolling

1.79–1.80

63

24

3 /7.5

0.4

FLHTHP (mL)

4.8

18

The wellbore diameter was measured during drilling, which is an important

19

parameter for evaluating drilling fluid performance in the field. The closer the actual


Page 15 of 20 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

wellbore diameter was to the design value, the better the performance of the drilling

2

fluid. As shown in Figure 10, the actual wellbore diameter was similar to the design

3

value with an average expansion rate of 7.47%, indicating a good drilling fluid

4

performance.

5

Water-based drilling fluid was used to drill 1608 m in the horizontal section. The

6

drilling rate was 14 m/h, which was 1.71 times as fast as using oil-based mud (6.94

7

m/h) in a nearby well. The horizontal section construction time was 6.83 days.

8

During drilling, the wellbore was stable, the amount of drill cuttings on the vibrating

9

screen was normal, and the particles were clear (Figure 11). The operation of lifting

10

and lowering the casing were smooth, indicating that the water-based drilling fluid

11

had strong shale-inhibition and anti-collapse performance and was able to meet the

12

normal needs of drilling horizontal wells in gas shale.

13 14

Figure 10. Curve of the diameter of the drilled well in Sichuan, China.


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

Figure 11. Drill cuttings on the vibrating screen during drilling.

2 3

10. CONCLUSION

4

In this study, the results demonstrate that Span 20 and Tween 60 could

5

self-assemble at shale surface and form a hydrophobic membrane, which weakens

6

the hydrogen bond strength and reduces the amount of hydrogen bonds formed by

7

the free hydroxyl groups and self-associated hydroxyls of the adsorbed water in the

8

shale. These effects were also confirmed by the wavenumber and area of the peak

9

formed by hydrogen bond in the infrared spectrum. That is the main reason why the

10

mixture could greatly reduce the amount of water entering into the shale. Through

11

shale compressive strength test, ion detection experiment and expansion test, it is

12

confirmed that the mixture can inhibit the hydration swelling of the gas shale in

13

Sichuan. This will provide technical support for the large-scale application of

14

water-based drilling fluids in Sichuan shale gas drilling and promote the low-cost

15

development of shale gas in China.

16

 AUTHOR INFORMATION

17

Corresponding Authors

18

Email: [email protected] (J. Liu) and [email protected] (B. Wei)

19

Notes

20

The authors declare no competing financial interests.

21

 ACKNOWLEDGMENTS

22

This research was financially supported by Petro China Innovation Foundation

23

(Grants 2018D-5007-0306), Shandong Natural Science Foundation (Grants


Page 16 of 20

Page 17 of 20 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

ZR2018BEE010) and the Fundamental Research Funds for the Central Universities

2

(Grants 18CX02033A).

3

REFERENCES

4

(1) Yaser, K. S.; Thomas, A. A novel polygeneration process to co-produce ethylene and

5

electricity from shale gas with zero CO2 emissions via methane oxidative coupling. Energy

6

Convers. Manage. 2015, 92, 406-420.

7

(2) Harkness, J. S.; Darrah, T. H.; Warner, N. R.; Whyte, C. J.; Moore, M. T.; Millot, R.;

8

Kloppmann, W.; Jackson, R. B.; Vengosh, A. The geochemistry of naturally occurring

9

methane and saline groundwater in an area of unconventional shale gas development.

10

GEOCHIM COSMOCHIM AC. 2017, 208, 302-334.

11

(3) Zhang, Y.; Gao, M. W.; You, Q.; Fan, H. F.; Li, W. H.; Liu, Y. F.; Fang, J. C.; Zhao, G.; Jin, Z. H.;

12

Dai, C. L. Smart mobility control agent for enhanced oil recovery during CO2 flooding in

13

ultra-low permeability reservoirs. Fuel. 2019, 241, 442-450.

14

(4) Estrada, J. M.; Bhamidimarri, R. A review of the issues and treatment options for

15

wastewater from shale gas extraction by hydraulic fracturing. Fuel. 2016, 182, 292-303.

16

(5) Zhang, X.; Wei, B.; Shang, J.; Gao, K., Pu, W., Xu, X., Wood, C.; Sun, L. Alterations of

17

geochemical properties of a tight sandstone reservoir caused by supercritical CO2-brine-rock

18

interactions in CO2-EOR and geosequestration. J. CO2 Util. 2018, 28, 408-18.

19

(6) Aftab, A.; Ismail, A. R.; Ibupoto, Z. H.; Akeiber, H.; Malghani, M. G. K. Nanoparticles based

20

drilling muds a solution to drill elevated temperature wells: A review. RENEW SUST ENERG

21

REV. 2017, 76, 1301-1313.

22

(7) You, L. J.; Kang, Y. L.; Chen, Z. X.; Chen, Q; Yang, B.; Wellbore instability in shale gas wells

23

drilled by oil-based fluids. Int. J. Rock Mech. Min. Sci. 2014, 72(2), 294-299.

24

(8) Sehly, K.; Chiew, H. L.; Li, H.; Song, A.; Leong, Y. K.; Huang, W. Stability and Ageing

25

Behaviour and the Formulation of Potassium-Based Drilling Muds. Appl. Clay Sci. 2015, 104,

26

309–317.

27

(9) Dolz, M.; Jiménez, J.; Hernández, M. J.; Delegido, J.; Casanovas, A. Flow and thixotropy of

28

non-contaminating oil drilling fluids formulated with bentonite and sodium carboxymethyl

29

cellulose. J. Pet. Sci. Eng. 2007, 57, 294–302.

30

(10) Norman, R.; Morrow; Jill, S.; Buckley. Effect of synthetic drilling fluid base oils on


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

asphaltene stability and wetting in sandstone cores. ENERG FUEL 2005, 19(4), 1412–1416.

2

(11) Wei, B.; Li, Q.; Jin, F.; Li, H.; Wang, C. The potential of a novel nano-fluid in enhancing oil

3

recovery. Energy Fuels 2016, 30(4), 2882-2891.

4

(12) Sadeghalvaad, M.; Sabbaghi, S. The effect of the TiO2/polyacrylamide nanocomposite on

5

water-based drilling fluid properties. Powder Technol. 2015, 272, 113-119.

6

(13) Wei, B.; Zhang, X.; Wu, R.; Zou, P.; Gao, K.; Xu, X.; Pu, W.; Wood, C. Pore-scale

7

monitoring of CO2 and N2 flooding processes in a tight formation under reservoir conditions

8

using nuclear magnetic resonance (NMR): A case study. Fuel 2019, 246, 34-41.

9

(14) Kelland, M. A.; Iversen, J. E. Kinetic hydrate inhibition at pressures up to 760 bar in deep

10

water drilling fluids. Energy Fuels 2010, 24(5), 3003-3013.

11

(15) Aftab, A.; Ismail, A. R.; Ibupoto, Z. H.; Akeiber, H.; Malghani, M.G.K. Nanoparticles based

12

drilling muds a solution to drill elevated temperature wells: A Review. Renewable

13

Sustainable Energy Rev. 2017, 76, 1301-1313.

14

(16) Haddadin; Malik, S. Y.; Abou, A.; Ansam, A.; Abu, R. I.; Haddadin, J. Kinetics of

15

hydrocarbon extraction from oil shale using biosurfactant producing bacteria. Energ. Convers.

16

Manage. 2009, 50, 983-990.

17

(17) Birgit, S.; Stefan, D. The effect of surface charge and wettability on H2O self diffusion in

18

compacted clays. Clay. Clay. Miner. 2011, 1, 42–57.

19

(18) Van, O. E.; Ripley, D.; Ward, I.; Chapman, J. W.; Williamson, R.; Aston, M. Silicate-based

20

drilling fluids: competent, cost-effective and benign solution to wellbore stability problems.

21

IADC/SPE-35059, 1996.

22

(19) Stewart, M. R.; Kosich, B.; Warren, B. K.; Urquhart, J. C.; McDonald, M. J. Use of silicate

23

mud to control borehole stability and overpressured gas formations in northeastern British

24

Columbia. SPE-59751, 2000.

25

(20) Boek, E. S.; Coveney, P. V.; Skipper, N. T. Monte carlo molecular modeling studies of

26

hydrated Li-, Na-, and K-Smectites: understanding the role of potassium as a clay swelling

27

inhibitor. J. Am. Chem. Soc. 1995, 117 (50), 12608-12617.

28

(21) O’Brien, D. E.; Chenevert, M. E. Stabilizing sensitive shales with inhibited,

29

potassium-based drilling fluids. J. Pet. Technol., 1973, 25 (9), 1089-1100.

30

(22) Bai, X.; Wang, H.; Luo, Y.; Zheng, X.; Zhang, X.; Zhou, S.; Pu, X. The Structure and


Page 18 of 20

Page 19 of 20 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

Application of Amine-Terminated Hyperbranched Polymer Shale Inhibitor for Water-Based

2

Drilling Fluid. J. Appl. Polym. Sci. 2017, 134 (46), 45466.

3

(23) Guancheng, J.; Yourong, Q.; Yuxiu, A.; Xianbin, H.; Yanjun, R. Polyethyleneimine as Shale

4

Inhibitor in Drilling Fluid. Appl. Clay Sci. 2016, 127-128, 70-77.

5

(24) Wu, Y.; Wang, R.; Dai, C.; Xu, Y.; Yue, T.; Zhao, M. Precisely Tailoring Bubble Morphology

6

in Microchannel by Nanoparticles Self-assembly, Ind. Eng. Chem. Res. 2019, 58, 3707–3713

7

(25) Jain, R.; Mahto, V.; Sharma, V. P. Evaluation of polyacrylamide-grafted-polyethylene

8

glycol/silica nanocomposite as potential additive in water-based drilling mud for reactive

9

shale formation. J. Nat. Gas Sci. Eng. 2015, 26, 526–37.

10

(26) Jain, R.; Mahto, V. Evaluation of polyacrylamide/clay composite as a potential drilling

11

fluid additive in inhibitive water-based drilling fluid system. J. Pet. Sci. Eng. 2015, 133,

12

612–21.

13

(27) Mao, H.; Qiu, Z.; Shen, Z.; Huang, W. Hydrophobic associated polymer based silica

14

nanoparticles composite with core–shell structure as a filtrate reducer for drilling fluid at

15

ultra-high temperature. J. Pet. Sci. Eng. 2015, 129, 1-14.

16

(28) Akhtarmanesh, S.; Shahrabi, M. A.; Atashnezhad, A. Improvement of Wellbore Stability

17

in Shale using Nanoparticles. J. Pet. Sci. Eng. 2013, 112, 290–295.

18

(29) Nasser, J.; Jesil, A.; Mohiuddin, T.; Al Ruqeshi, M.; Devi, G.; Mohataram, S. Experimental

19

investigation of drilling fluid performance as nanoparticles. World J. Nano Sci. Eng. 2013,

20

3(3), 11-25.

21

(30) Rafati, R.; Smith, S. R.; Haddad, A. S.; Novar, R.; Hamidi, H. Effect of nanoparticles on the

22

modifications of drilling fluids properties: A review of recent advances. J. PETROL. SCI. ENG.

23

2018, 161, 61-76.

24

(31) Kosynkin, D. V.; Ceriotti, G.; Wilson, K. C.; Lomeda, J. R.; Scorsone, J. T.; Patel, A. D.

25

Graphene oxide as a high-performance fluid-loss-control additive in water-based drilling

26

fluids. ACS Appl. Mater. Interfaces 2011, 4, 222-227.

27

(32) William, J. K. M.; Ponmani, S.; Samuel, R.; Nagarajan, R.; Sangwai, J. S. Effect of CuO and

28

ZnO nanofluids in xanthan gum on thermal, electrical and high pressure rheology of

29

water-based drilling fluids. J. Pet. Sci. Eng. 2014, 117, 15-27.

30

(33) Vryzas, Z.; Kelessidis, V. C. Nano-based drilling fluids: a review. ENERGIES 2017, 10(4),


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

540.

2

(34) Washburn, E. The dynamics of capillary flow ． Physical Review Online Archive, 1921,

3

17(3), 273-283．


Page 20 of 20

Inhibition of the Hydration Expansion of Sichuan Gas Shale by

Recommend Documents