Water Plugging Performance of Preformed Particle Gel in Partially

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Thermodynamics, Transport, and Fluid Mechanics

Water Plugging Performance of Preformed Particle Gel in Partially Filled Fractures Lin Sun, Qi Han, Daibo Li, Xiao Zhang, Wan-Fen Pu, Ximing Tang, Yongchang Zhang, and Baojun Bai Ind. Eng. Chem. Res., Just Accepted Manuscript • Publication Date (Web): 25 Mar 2019 Downloaded from http://pubs.acs.org on March 30, 2019

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Industrial & Engineering Chemistry Research

Water Plugging Performance of Preformed Particle Gel in Partially Filled Fractures Lin Sun,1,2, Qi Han,1 Daibo Li, 1 Xiao Zhang,3 Wanfen Pu,1 Ximing Tang,1 Yongchang Zhang1, Baojun Bai,2, 1 ) State

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

610500, China 2) Department

of Geosciences and Geological and Petroleum Engineering, Missouri University of Science and Technology, Rolla,

65401, USA 3) Research

Institute of Petroleum Engineering, Northwest Oilfield Company, Sinopec, Urumqi, Xinjiang, 830011, China

ABSTRACT: Preformed particle gel (PPG) treatment has been well-recognized as an efficient method to reduce excessive water production in fractured reservoirs. However, previous research on its plugging efficiency was mainly conducted in open fractures. In this paper, calcite-filled fracture models were designed to comprehensively investigate the water plugging performance of PPG in partially filled fractures which are extremely common in fractured reservoirs. Systematic plugging performance tests have proceeded under various calcite-filling conditions. The results show that the calcite particles can improve the breakthrough and retention of the PPG as well as the plugging efficiency. With increased size and concentration of the calcite particles, the PPG breakthrough pressure gradient increases, the fracture permeability decreases. When the ratio of average calcite particle diameter to fracture width (RC) is small (0.15), the fracture permeability is difficult to be further reduced by increasing PPG concentration or PPG size. However, when the RC increases to 0.21, the plugging performance in fractures filled with more calcite particles or PPG particles, especially the latter, is better than that filled with larger calcite particles. This study provides new insight into the PPG treatment and will contribute to the water control in fractured reservoirs. KEYWORDS: Preformed particle gel; Water control; Partially filled fracture; Plugging efficiency; Breakthrough pressure



Corresponding authors.

Email: [email protected] (L. Sun), [email protected] (B.Bai)

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Industrial & Engineering Chemistry Research 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. INTRODUCTION Excessive water production is one of the greatest challenges faced by mature oilfields worldwide, which not only limits oil recovery efficiency but also increases oil-production costs.1-3 Gel treatment has been broadly applied to address this problem,4-7 and abundant plugging agents thus have been developed, including in situ polymer-based gels, preformed particle gel (PPG), microgel, and so on.8-14 In western China, some fractured carbonate reservoirs take the fracture as the only flow path for both oil and water caused by the impermeable matrix. For this type of reservoirs, the gel treatment should reduce the conductivity of fracture channeling rather than entirely block it. Therefore, PPG that can form a permeable gel pack in fractures receives great attention.15-17 PPGs are synthesized at surface facilities before injection and thus can overcome some drawbacks inherent in in situ polymer-based gels, for example, lack of gelation time and gelling uncertainty.18-19 They are slightly sensitive to physic-chemical conditions, such as pH, salinity, multivalent ions, H2S, temperature, and shear rates.20 Whereas, as superabsorbent polymers,21 conventional PPGs would quickly swell to dozens of times its original volume once coming into contact with water.22-23 Swollen PPGs are usually not able to transport into the in-depth of a reservoir, resulting in the treatment is usually restricted to the near-wellbore. Hence, swelling delayed PPG that takes several days or weeks to achieve equilibrium swelling has been attracting a lot of interest.24-26 This PPG could remain small size in the injection stage of PPG treatment and further swell after placement. However, whether the equilibrium swelling ration can reach the maximum swelling ratio has remained unclear. The sizes of PPGs range from micrometer to centimeter,27 so PPGs are well suited to be employed in fractured reservoirs. Therefore, a considerable amount of research has been focused on the plugging performance of PPGs in fractures. Bai et al.16 constructed transparent fracture models to visually investigate the water flow after PPG was packed in fractures and the effect of brine injection rate, brine concentration, and fracture width on it. Imqam et al.28 used five-foot tubes to mimic fractures and analyzed the water plugging performance of PPGs with different sizes and strengths. Recently, Song et al29 employed semi-transparent fracture models to systematically evaluate the plugging performance of PPG under various conditions, such as different PPG sizes and concentrations. These studies facilitate our understanding of the PPG treatment in fractured reservoirs, but all of them are limited in open fractures. In reality, fractures 2


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in reservoirs are often filled by secondary or diagenetic mineralization, and the mineral fillings may or may not be completed. 30-33 Infilling minerals can reduce the effective fracture width and increase the roughness of the fracture surface, which would impact the plugging performance of PPGs. Therefore, the primary objective of this work is to investigate the combined effect of PPG and mineral filling on the water flow in partially filled fractures. To accomplish this research objective, comprehensive plugging performance tests were conducted in calcite-filled fracture models. Firstly, the plugging behaviors of PPG in an open fracture and a partially filled fracture were compared to confirm whether the calcite particles can improve the breakthrough and retention of PPG. Afterward, the plugging efficiencies were discussed as a function of the ratio of average calcite particle diameter to fracture width (RC). Finally, the interactive effects of particle sizes and particle concentrations on the plugging performance were presented and analyzed. 2. EXPERIMENTAL SECTION 2.1. Materials. Given the experiment timescale, a slight swelling delayed PPG with the mesh size of 7-18 was used in our experiments. It was synthesized by a free-radical polymerization using acrylamide, 2-acrylamido-2-methylpropane sulfonic acid, and nano-montmorillonite. The PPG was initially in a dry state and needed 40 hours to fully swell to 36 times its original volume at room temperature and 0.5 wt% NaCl. 2.2. Experimental Setup and Procedure. 2.2.1. Experimental Setup. The schematic of the setup used in the plugging performance tests is presented in Figure 1. The calcite-filled fracture model was mainly composed of two transparent polycarbonate plates. A long square pocket (55010010 mm) was drilled in the center of one plate. Rock slabs with different thicknesses can be placed into this pocket to simulate various fracture widths. The fracture height was adjustable via affixing two acrylic plates to both sides of the top surface of the rock slab. In this study, a piece of impermeable carbonate slab glued with calcite particles and acrylic plates was fixed in the pocket to build a partially filled fracture with an apparent size of 550123.4 mm. The size and volume of the calcite particles were variable to mimic different calcite-filling conditions. The volume of the calcite particles to that of the fracture was defined as the calcite particle concentration. If no calcite particle was glued on the carbonate slab, the fracture could be switched to an open fracture. There are two holes on the other polycarbonate 3



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plate, which functioned as the inlet and the outlet, separately. The internal diameters of the joints and tubes contacting with particles were more than 6.5 mm, and the lengths of the tubes were minimized. Hence, the additional shear and pressure drop would be negligible.

Figure 1. Schematic of the experimental apparatus for plugging performance tests. 2.2.2. Experimental Procedure. The plugging performance tests proceeded at room temperature and 0.5 wt% NaCl. The following steps were included in the experiments: (a) PPG particles and brine were blended in a magnetic stirring vessel to produce PPG suspension. (b) One fracture volume (FV) of the PPG suspension was injected into an open fracture model or a partially filled fracture from its inlet. Then, the fracture model was closed for 48 hours to allow the PPG to achieve equilibrium swelling. There was no chemical reaction between the calcite particles and the PPG. (c) Brine was injected from the outlet at the rate of 1ml/min to examine the plugging efficiency. The pressure data were recorded over time, and the fracture permeability after brine injection (Ka) was calculated by Darcy's law using the equilibrium pressure (Pa). (d) The PPG residing in the fracture model was collected, dried, and weighed (𝑀′𝑃). Its volume was measured before and after drying (Vb and Va). The retention ratio (RR), volume swelling ratio (Sv), and equivalent average diameter swelling ratio (SD) were described in Equations 1 to 3. 𝑀′𝑃

RR = 𝑀𝑃100%

(1)

𝑆𝑉 = 𝑉 𝑏 𝑉 𝑎

(2)

𝑆𝐷 = 3 𝑆𝑉

(3)

where MP is the mass of the injected PPG. 4


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2.3. Experimental Scenarios. A total of 12 experiments, as listed in Table 1, were conducted to study the plugging performance of PPG in partially filled fractures. The influence parameters involved the RC, the ratio of average PPG particle diameter to fracture width (RP), the calcite particle concentration (CC), and the PPG concentration (CP). The average particle diameter (d) was obtained based on Equation 4.

𝑑=

2 1 𝑑𝑚𝑖𝑛

+𝑑

(4)

1

𝑚𝑎𝑥

where dmin and dmax are the diameters of the minimum particle and the maximum particle, in mm. Table 1. Summary of the plugging performance tests average average PPG calcite particle particle diameter(mm) diameter(mm) 1.84

scenario No.

calcite size (mesh)

PPG size (mesh)

1

/

10-12

2

10-20

12-18

1.19

3

10-20

12-18

4

20-30

5

RC

RP

CC (vol%)

CP (wt%)

/

0.54

0

10

1.26

0.35

0.37

10

10

1.19

1.26

0.35

0.37

10

16

12-18

0.70

1.26

0.21

0.37

10

10

20-30

12-18

0.70

1.26

0.21

0.37

10

16

6

20-30

12-18

0.70

1.26

0.21

0.37

15

10

7

20-30

12-18

0.70

1.26

0.21

0.37

15

6

8

30-40

12-18

0.50

1.26

0.15

0.37

15

6

9

30-40

12-18

0.50

1.26

0.15

0.37

15

10

10

20-30

12-18

0.70

1.26

0.21

0.37

15

16

11

20-30

7-10

0.70

2.33

0.21

0.69

10

10

12

30-40

7-10

0.50

2.33

0.15

0.69

15

10

3. RESULTS AND DISCUSSION 3.1. Plugging Behaviors of PPG in open fracture and partially filled fracture. Scenarios 1 and 2 were performed to compare the plugging efficiency of PPG in an open fracture and a partially filled fracture. Due to the low RP, the PPG suspensions were readily injected into the fracture models, and relatively small particles were observed at the fluid front caused by their superior flowability. The fracture models were flooded with brine after the PPGs swelled to equilibrium. The pressure gradients during brine injection and the appearance of the calcite-filled 5



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fracture model at the end of it are shown in Figure 2 and Figure 3, respectively. It can be seen from Figure 2 that the pressure gradients in both tests first progressively rise to a peak level then rapidly drop with the injection of brine. This pressure behavior is consistent with that reported by Song et al.29 PPG particles were found to discharge from the fracture outlet at the peak pressure gradient, which thus is termed as the breakthrough pressure gradient (PB). Compared with those in the open fracture case, the breakthrough pressure gradient and the corresponding brine injection time, which is defined as the breakthrough time, in partially filled fracture are distinctly greater, indicating that the calcite particles could improve the PPG breakthrough.

Figure 2. Pressure gradients across fracture models during brine injection.

(a)

(b)

Figure 3. (a)Partially filled fracture model packed with PPG particles after brine injection and (b) swollen PPG particles collected from the fracture model after brine injection

6


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For both tests, pure PPG particles, a mixture of PPG particles and brine, and 100% brine were produced in sequence from the fracture outlet. The equivalent average diameter swelling ratios of the PPGs are around 2.6, which indicates that the swollen PPGs should be deformed to pass through the fractures.34 However, no significant breakage was observed in the extruded PPG particles (Figure 3) by virtue of their excellent toughness. Small size PPG is supposed to be washed out easily, whereas the retention ratio of the small size PPG in the partially filled fracture is 89.2%, which is much higher than that of the large size PPG in the open fracture (58.4%). This finding confirms that the calcite particles can enhance the PPG retention in fractures. In the last 4FV of brine injection, the pressure gradients are stable, implying that steady water channels were formed within the PPG packs. The permeabilities of the newly produced channels in the open fracture and the partially filled fracture are 4780 md and 1728 md, respectively. The remarkable difference proves that the calcite particles can significantly improve the plugging efficiency of PPG. 3.2. Effect of RC on Plugging Efficiency. To explore the relationship between the RC and the plugging performance of PPG, four sets of experiments with the same RP (0.37) were conducted. The RC was the only difference for the two scenarios in each set, while the particle concentration varied between sets. Table 2 summarizes the results obtained from these experiments. Table 2. Plugging efficiency under different calcite particle size conditions set No. 1

2

3 4

scenario No. 8

0.15

7

0.21

9

0.15

6

0.21

4

0.21

2

0.35

5

0.21

3

0.35

RC

CC (vol%)

CP (wt%)

28.1

6 15 10

10

SV

10 16

PB Pa (MPa/m) (MPa/m) 0.27 0.09

Ka (md) 4493

26.7

0.58

0.25

1605

17.5

0.45

0.11

3745

15.5

0.98

0.31

1322

17.5

0.82

0.2

2042

17.1

0.91

0.24

1728

13.5

1.16

0.29

1404

13.3

1.42

0.33

1248

The tendency of pressure gradients, as plotted in Figure 4, and the properties of the effluents in all experiments of this section are in line with those of earlier mentioned (section 3.1). Table 2 and Figure 4 demonstrates that the plugging efficiency strongly depends on the RC. As the RC 7



increases, the breakthrough pressure gradient increases and the fracture permeability decreases, but the differences weaken once the RC is higher than 0.21. Meanwhile, when the RC increases from 0.15 to 0.21, the breakthrough time increases; but when the RC further increases to 0.35, the breakthrough time decreases owing to the excessively fast growth of the pressure gradient.

(a)

(b) Figure 4. Pressure gradient profiles of brine injection as a function of the ratio of average calcite particle diameter to fracture width (a) 15 vol% calcite particle and (b) 10 vol% calcite particle.

8


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It is also observed from Table 2 that the growth of breakthrough pressure gradient and equilibrium pressure stemming from the increased RC are more evident at high PPG concentrations. For example, when the RC increases from 0.15 to 0.21, the increments of breakthrough pressure gradient and equilibrium pressure are 0.31 MPa/m and 0.16 MPa/m at the PPG concentration of 6 wt%, while the two values are 0.53 MPa/m and 0.2 MPa/m at the PPG concentration of 10 wt%. Meanwhile, when the RC and the PPG concentration are maximum, the breakthrough pressure gradient and equilibrium pressure also arrive their peak values. These results suggest there is a synergy between high RC and high PPG concentration. In order to further reveal the interactive effect of particle sizes and particle concentrations on the plugging performance, more experiments and analyses were presented below. 3.3. Plugging Efficiency under Medium RC conditions. Based on scenario 4, plugging performance of PPG with increased particle concentrations and particle sizes were discussed. The effects of the particle concentrations on the plugging efficiency were set out in Table 3 and Figure 5. The RC and RP of the involved experiments were 0.21 and 0.37, respectively. Table 3. Effect of particle concentrations on plugging efficiency scenario No. 4

CC (vol%) 10

CP (wt%) 10

17.5

PB (MPa/m) 0.82

Pa (MPa/m) 0.2

Ka (md) 2042

5

10

16

13.5

1.16

0.29

1404

6

15

10

15.5

0.98

0.31

1322

10

15

16

13.10

1.29

0.32

1248

SV

Table 3 exhibits that high particle concentrations, especially high PPG concentration, can enhance the plugging efficiency. This can be explained by the fact that the flowing space of PPG and brine reduced when more particles were packed in the fracture. Compared with the calcite particles, the PPG particles could fill the fracture better at the same increase of concentration owing to their swelling. Furthermore, the strength of the swollen PPG is also relevant to the plugging efficiency. The maximum mass swelling ratio of the PPG is 21 g/g at room temperature and 0.5 wt% NaCl. That is, when PPG concentration exceeds 4.8wt%, the PPG could not fully swell, and its swelling ration decreases as the concentration increases. With the declined swelling ratio, the strength of PPG is improved,35 which gives rise to the outstanding water blocking behavior.36

9



Figure 5. Pressure gradient profiles of brine injection as a function of the particle concentrations. As illustrated in Figure 5, the PPG breakthrough shifts to an earlier brine injection stage when only the calcite particle concentration increases. Interestingly, it can switch to a later brine injection stage if the calcite particle concentration and the PPG concentration increase at the same time. When the large size or high concentration calcite particles were filled in a fracture model, the apparent pore size of the partially filled fracture and then the mobility of PPG and brine would decrease. Therefore, on the one hand, the breakthrough pressure gradient and the fracture permeability were improved. On the other hand, swollen PPG particles were unable to enter into some small pores and thus tend to breakthrough. By increasing the PPG concentration, the size of swollen PPG particles and the inaccessible pore volume of them decreased, as a result, the breakthrough was postponed. From Table 2 and Table 3 we can see that the PPG swelling ratio decreases with increased PPG concentration, but its value is inconstant at the same PPG concentration. The differential pressure across the fracture model might be responsible for this result. Under high differential pressure conditions, the swollen PPG experiences strong compressional force,37 which will impair its water-holding capacity and then decrease its volume. However, the swelling ratio is not linearly correlated with the differential pressure, as demonstrated by Figure 6. The swelling ratio in the 15 vol% calcite particle cases is lower than those in the 10 vol% calcite particle cases. It is possible, therefore, that the space for swelling is also associated with the swelling ratio.

10


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Figure 6. Swelling ratio of PPG against equilibrium differential pressure of brine injection Table 4. Effect of particle sizes on plugging efficiency scenario No.

RC

RP

PB (MPa/m)

Ka (md)

4

0.21

0.37

0.82

2042

11

0.21

0.69

1.07

1605

2

0.35

0.37

0.91

1728

Table 4 shows the improvement of plugging efficiency because of increasing particle sizes. The three experiments were performed at the same particles concentrations. Similar results were found in the previous studies about the effect of PPG size on the water flow in open fractures.38 Comparing Tables 3 and 4, the plugging performance with increased particle sizes are not as good as that with increased particles concentrations. The most likely cause is that the large size particles could only enhance the flow resistance of some parts along the fracture due to the constant mass. 3.4. Plugging Efficiency under Small RC Conditions. Taking scenario 8 as a base case, plugging performance tests with increased PPG concentration, RP, and RC were compared, as Table 5 and Figure 7 presented. The calcite particle concentration of these experiments were 15 vol%.

11



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Table 5. Plugging efficiency improvement based on small size calcite particles scenario No.

RC

RP

CP (wt%)

PB (MPa/m)

Ka (md)

8

0.15

0.37

6

0.27

4493

9

0.15

0.37

10

0.45

3745

12

0.15

0.69

10

0.84

1872

7

0.21

0.37

6

0.58

1605

Figure 7. Pressure gradient profiles of brine injection under different particle parameters Table 5 and Figure 7 indicate, with more PPG particles packed in the fracture (scenario 9), a higher pressure is required to displace some of them out, but the particles remaining in the fracture are not able to efficiently enhance the flow resistance of brine. Increasing the PPG concentration and the RP simultaneously (scenario 12), the plugging efficiency could be further improved, especially the breakthrough pressure gradient, but the response of the fracture permeability is not as evident as that to the increased RC (scenario 7). These findings highlight the crucial effect of the RC on the fracture permeability reduction. The small size calcite particles appear to be inefficient in impeding the flow of PPG and brine. In this paper, we used relatively uniform calcite particles to build partially filled fractures, which are pretty simple than the real fractures. Therefore, the irregular filling in fractures should be mimicked in future investigations to reveal the plugging behavior of PPG in fractured reservoirs further. 12


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4. CONCLUSIONS Partially filled fractures are very common in fractured reservoirs. However, they are seldom involved in studies about the water plugging efficiency of PPGs. By simulating various calcitefilled fractures in semi-transparent fracture models, the plugging performance of a swelling delayed PPG in partially filled fractures was explored. Particular consideration was given to the effect of the calcite particle size on the plugging performance. Based on the results, the following conclusions can be generally drawn: (1) Comparing to that in an open fracture, the PPG breakthrough in a partially filled fracture requires higher pressure and more brine injection; more PPG particles can reside in the partially filled fracture after brine injection, leading to more evident fracture permeability reduction. (2) The plugging efficiency of PPG enhances with the calcite particle size, but when the RC is higher than 0.21, the PPG breakthrough occurs at an earlier brine injection stage. Meanwhile, the RC is closely related to the fracture permeability after PPG treatment. When the RC is 0.15, this permeability is hard to be further decreased by increasing PPG concentration or PPG size. (3) With more PPG particles or calcite particles filled in fractures, the flowability of the PPG and brine decrease, the plugging efficiencies thus are improved. When the RC is 0.21, the plugging efficiencies in the fractures filled with more particles, especially more PPG particles, are much better than those filled with larger particles. (4) For swelling delayed PPG, the equilibrium swelling is achieved after the placement. The PPG may not be able to fully swelling in fractures, and its swelling ratio will affect by its concentration, the differential pressure and the space for swelling. ■ ACKNOWLEDGMENTS The authors gratefully acknowledge the financial support of the National Science and Technology Major Project of China (2016ZX05053-004-004) and the Youth Science and Technology Innovation Team of SWPU (2017CXTD04). The valuable comments made by the anonymous reviewers are also sincerely appreciated. ■ REFERENCES Uncategorized References 1. Seright, R.; Lane, R.; Sydansk, R. A strategy for attacking excess water production. SPE production & facilities 2003, 18 (03), 158-169.

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19. Liu, Y.; Bai, B.; Shuler, P. J. Application and development of chemical-based conformance control treatments in China oilfields. SPE/DOE Symposium on Improved Oil Recovery; Society of Petroleum Engineers: 2006. 20. Song, Z.; Bai, B.; Challa, R. Using Screen Models to Evaluate the Injection Characteristics of Particle Gels for Water Control. Energy & Fuels 2017, 32 (1), 352-359. 21. Bai, B.; Zhou, J.; Yin, M. A comprehensive review of polyacrylamide polymer gels for conformance control. Petroleum Exploration and Development 2015, 42 (4), 525-532. 22. Alhuraishawy, A. K.; Sun, X.; Bai, B.; Wei, M.; Imqam, A. Areal sweep efficiency improvement by integrating preformed particle gel and low salinity water flooding in fractured reservoirs. Fuel 2018, 221, 380-392. 23. Imqam, A.; Bai, B.; Al Ramadan, M.; Wei, M.; Delshad, M.; Sepehrnoori, K. Preformedparticle-gel extrusion through open conduits during conformance-control treatments. SPE Journal 2015, 20 (05), 1,083-1,093. 24. Tang, H. Preformed particle gel for conformance control in an oil reservoir. 2007. 25. Liu, H.; Hanbing, X. Deep Fluid Diversion for Profile Control and Oil Displacement Technologies. International Petroleum Technology Conference; International Petroleum Technology Conference: 2011. 26. Pu, W.; Xiong, Y.; Yang, Y.; LI, Z. Micro-scale swelling-delayed dispersed gel and its performannce evaluation (in chinese). ACTA PETROLEI SINICA 2016, 37 (S2), 93-98. 27. Bai, Y.; Xiong, C.; Wei, F.; Li, J.; Shu, Y.; Liu, D. Gelation study on a hydrophobically associating polymer/polyethylenimine gel system for water shut-off treatment. Energy & Fuels 2015, 29 (2), 447-458. 28. Imqam, A.; Wang, Z.; Bai, B.; Delshad, M. Effect of heterogeneity on propagation, placement, and conformance control of preformed particle gel treatment in fractures. SPE Improved Oil Recovery Conference; Society of Petroleum Engineers: 2016. 29. Song, Z.; Bai, B.; Zhang, H. Preformed particle gel propagation and dehydration through semi-transparent fractures and their effect on water flow. Journal of Petroleum Science and Engineering 2018, 167, 549-558. 30. Nelson, R., Geologic analysis of naturally fractured reservoirs. Elsevier: 2001. 31. Morrow, N. R.; Brower, K. R.; Ma, S.; Buckley, J. S. Fluid flow in healed tectonic fractures. Journal of Petroleum Technology 1990, 42 (10), 1,310-1,318. 32. Egeberg, P. K.; Saigal, G. C. North Sea chalk diagenesis: cementation of chalks and healing of fractures. Chemical Geology 1991, 92 (4), 339-354. 33. Aydin, A. Fractures, faults, and hydrocarbon entrapment, migration and flow. Marine and petroleum geology 2000, 17 (7), 797-814. 34. Bai, B.; Liu, Y.; Coste, J.-P.; Li, L. Preformed particle gel for conformance control: transport mechanism through porous media. SPE Reservoir Evaluation & Engineering 2007, 10 (02), 176-184. 35. Elsharafi, M. O.; Bai, B. Effect of weak preformed particle gel on unswept oil zones/areas during conformance control treatments. Industrial & Engineering chemistry research 2012, 51 (35), 11547-11554. 36. Imqam, A.; Bai, B.; Delshad, M. Preformed particle gel propagation through super-K permeability sand and its resistance to water flow during conformance control. SPE/IATMI Asia Pacific Oil & Gas Conference and Exhibition; Society of Petroleum Engineers: 2015.

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37. Sun, X.; Bai, B. Dehydration of polyacrylamide-based super-absorbent polymer swollen in different concentrations of brine under CO2 conditions. Fuel 2017, 210, 32-40. 38. Bai, B. Preformed particle gel for conformance control. 07123-2; RPSEA: 2012.

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Table of Contents Graphic


Water Plugging Performance of Preformed Particle Gel in Partially

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