Investigation on the interfacial properties of a viscoelastic-based surfactant as an oil displacement agent recovered from fracturing flowback fluid

Abstract

The utilization of a viscoelastic-based surfactant recovered from fracturing flowback fluid in chemical flooding was investigated in this paper. The interfacial tension behavior, wettability alteration, dynamic adsorption capacity and incremental oil recovery ability were studied. The oil/water interfacial tension was lowered to 10⁻⁴ to 10⁻³ mN m⁻¹ due to 0.06 to 0.15 wt% of VES in the fracturing flowback fluid. The oil-wet surface can be easily converted to weak water-wet through adsorption of VES. A series of sandpack core flooding tests were conducted under the Dingbianluo reservoir condition to investigate the effects of interfacial tension and slug sizes on enhanced oil recovery. Finally, an SEM scanning test and microscopic displacement test were used to investigate the mechanism of surfactant flooding. This investigation confirmed that the fracturing flowback fluid recovered from fracturing treatment can be reused for surfactant flooding with probable environmental and economic benefits.

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Introduction

Hydraulic fracturing is the most effective technique in the development of low-permeability reservoirs all over the world.^1–4 During the fracturing process, the fracturing fluid and proppant are blended together, and then injected into the targeted reservoir to create “cracks” or “fractures” in the adjacent zone and thereby enhance oil recovery (EOR).^5,6 Therefore, selection of the fracturing fluid is of vital importance to the productivity of a well after hydraulic fracturing simulation. In recent years, surfactant-based viscoelastic (VES) fluids have been widely used in oil and gas wells for fracturing due to their better performance on anti-shearing, low-friction, easy gel breaking without a gel breaker and low formation damage.^7,8 Since their initial application in fracturing treatment in the Gulf of Mexico, over 2100 fracturing treatments were performed with VES fluids before the year 2000.⁹

Although VES fluids are widely used in fracturing simulation, there still exists a serious problem, which is common for all kinds of fracturing fluids. That is how to deal with flowback fluids (typically several million gallons per well), which partially returns from target reservoirs.^10,11 At present the research mainly focus on disposing flowback fluids for drilling fluids or hydraulic fracturing fluid to supplement limited fresh water resources.^12–14 Yet, all these treatments and recycling options are at cost of wasting large amount of chemicals existing in flowback fluids, which is not efficient and cost-effective.

In order to avoid such issues, the reutilization of flowback fluids is regarded as the best methods. The benefits of reusing include the cost savings associated with recycling chemicals, the cost savings of reduced fresh water resources for subsequent treatment and elimination of disposal costs. In addition, the total volume of chemicals required for reutilization is significantly reduced, thus reducing the demand on our environment.¹⁵

Generally, VES fluids contain anionic surfactants, cationic surfactants and zwitterionic surfactants.¹⁶ Furthermore, the surfactant concentration in fracturing flowback fluids is generally high because of their huge consumption mentioned above and high application concentration from 2 wt% to 9 wt%.¹⁷ This inspires us to study the feasibility of reutilization of VES fracturing flowback fluids in surfactant flooding for further enhanced oil recovery (EOR) after fracturing simulation.

Surfactant-based chemical-flooding aiming at producing the residual oil remained after secondary recovery has become more attractive in recent years.^18–20 These studies focused on three inter-related mechanisms for EOR: (i) the ability of the surfactant to produce ultra-low interfacial tension (IFT) between surfactant solution and residual oil,^21,22 (ii) the wettability alteration by the surfactant on the reservoir rock surface^23–25 and (iii) emulsification–entrainment, emulsification–entrapment to improve the sweep efficiency.²⁶

In this paper, our aim is to evaluate the performance of VES fracturing flowback fluid from fracturing simulation for EOR by investing the IFT, wettability ability, adsorption capacity and conducting sandpack flooding tests. As we known, this may be the first time to recovering actual flowback fluids (nor prepared in laboratory) from target reservoir and using in surfactant flooding for further EOR. Through this work, we expect to present an efficient and cost-effective treatment method on disposing fracturing flowback fluids and provide a solid foundation for its field application.

Material and methods

Materials

Fracturing flowback fluid was provided by Changqing Oilfield. The main component of the flowback fluid was viscoelastic surfactant (VES). Before this study, the fracturing flowback fluid was treated to remove solids through natural sedimentation, centrifugation (3000 rpm for 15 min) and micropore filter (Φ = 0.45 μm). Orange II sodium salt was an AR grade product of the Aladdin Chemistry Company and was used without purification. Their molecular structures are shown in Fig. 1(a) and (b), respectively.

Fig. 1 Molecular structure of VES (a) and orange II sodium salt (b).

The fracturing flowback fluid used in this study was collected from Dingbianluo reservoir. The compositional analysis of the sample is shown in Table 1.

Table 1 Compositional analysis of the formation brine sample

	Ions
	K^+ + Na^+	Ca^2+	Mg^2+	Cl^−	HCO3^−	Surfactant
Concentration (mg L^−1)	11 470	2601	146	22 649	259	3000
Total salinity (mg L^−1)	37 125

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Determination of VES concentration in fracturing flowback fluid

The VES concentration was detected by the colorimetric method through UV-vis measurement.^27,28 This method was based on the precipitation which was reacted by VES and orange II sodium salt. The typical analytical process was as following:

The orange II sodium salt solution was freshly prepared by adding 0.35 g orange II sodium salt into 1000 mL distilled water. This reagent must be prepared just prior to use, because it would gradually decomposed leading to huge measurement errors.

About 10.0 mL of fresh prepared VES solution with concentrations ranging from 0.0035 to 0.035 wt% together with 10.0 mL orange II sodium salt solution were pipetted into 50 mL separating funnel separately and shake it well for 5 minutes. Following that, 20.0 mL chloroform was added to funnel separately to extract the precipitation reacted by VES and orange II sodium salt by shaking for 5 minutes and standing for 15 minutes. The filtrate was collected in 25 mL volumetric flasks, and then diluted to a fixed volume with chloroform. A part of solution was transferred to the colorimetric ware to measure the absorbance at a wavelength of 485 nm, with chloroform as a reference solution. The Lambert Beers Law was observed with the VES concentration ranging from 0.0035 to 0.035 wt% as shown in Fig. 2.

Fig. 2 Standard curve of VES solution.

IFT measurement

The oil/water interfacial tension (IFT) was tested with Texas-500C spinning drop tensiometer according to the following equation.²⁹ The interfacial tension was performed with a single-measurement method at 80.0 °C ± 0.5 °C, and all measurements were repeated at least twice.where A is the oil/water interfacial tension (mN m⁻¹); r_w and r_o respectively are the densities of the water and oil phases (g cm⁻³); w is the rotational speed (rpm); D and L respectively are the width and length of the oil droplet (mm); and n is the refractive index of the water phase.

Wettability test

The wettability was evaluated by contact angle.³⁰ The schematic diagram of the apparatus³¹ for measuring the contact angle is shown in Fig. 3. Firstly, the slides were soaked in chromic acid for 24 h, and then washed by deionized water. Secondly, as during the adsorption and precipitation of crude oil onto the rock surface, there is usually brine present in the reservoir, and to simulate this process, the quartz plates were treated in the following ways: dried, soaked in deionized water for 24 h, and soaked in simulated formation brine for 24 h. The last two processes were mentioned as wet aging. Thirdly, the wet slides taken out from salt solutions were put into centrifugation at 3000 rpm for 10 min to remove the excess water, and then immediately transferred into crude oil mixed with 20 v% n-heptane to age for 24 h at 80 °C. Then the plates were treated with n-heptane to get rid of spare crude oil on the plates' surface. Put these plates mentioned above into VES solutions with different concentration to age for 24 h at 80 °C and then dried them out following step 2. Finally, the contact angle (CA) measurements were performed at room temperature (25 °C) using Attension Theta Lite as shown in Fig. 3. Each point was repeated at least twice.

Fig. 3 Schematic diagram of the drop-shape analyzer (Attension Theta Lite) for contact angle measurement (a); test platform of Attension Theta Lite for contact angle (CA) measurement (b).

Dynamic adsorption test

After being saturated with simulated formation brine, the sandpack core was placed in the core holder and then aged for 2 h at 80 °C. Before the surfactant flooding experiment, simulated formation water was injected into the sandpack core and the injection pressure was monitored until it reached stable. Surfactant solution was then continuously injected until the surfactant concentration from the outlet was close to the initial injection concentration. Then simulated formation brine was injected until the surfactant concentration from the outlet was reduced to zero. During the whole process, the injection rate was maintained at 0.1 mL min⁻¹. Dynamic adsorption was calculated according to the equation as following:where Γ is the amount of surfactant adsorption on the core surface per gram of rock (mg g⁻¹); C₀ is the initial surfactant concentration before adsorption (mg mL⁻¹); V is the total volume of injected surfactant solution when the surfactant concentration from the outlet was close to the initial surfactant concentration (mL); C_i is the surfactant concentration from the outlet (mg mL⁻¹), V_i is the volume of every collected outlet sample (mL); m is the mass of the natural core (g), and n is the total of effluent samples until the surfactant concentration was reduced to zero.

Core plug flooding test

The core holder of size 2.54 cm in diameter and length of 30.00 cm (Haianxian Oil Scientific Research Apparatus Co Ltd, China) was used for the core plug flooding test. The cylindrical cores (Haianxian Oil Scientific Research Apparatus Co Ltd, China) with permeabilities varying from 2 mD to 5 mD were used in this test.

The core plug flooding test was carried out with procedures as following; (1) the permeability was measured with simulated formation water with flowchart shown in Fig. 4 at a flow rate of 0.1 mL min⁻¹; (2) the wet cores were saturated with crude oil until the water-cut produced from outlet was less than 1%; (3) the cores were flooded with simulated formation water until the oil production was negligible (water-cut >98%); (4) the fracturing flowback fluid slugs were then injected; and (5) the water flooding was continued until no more oil was produced from the outlet (water cut >98%). All the tests were carried out at 80 °C. The injection flow rate was 0.1 mL min⁻¹.

Fig. 4 Flowchart of sandpack core flooding.

A total of 10 core plug flooding tests were conducted. The parameters of the core plugs are shown in Table 2. The parameters of the fracturing flowback fluid slugs injected in the test are shown in Table 3. Each core plug flooding test was repeated at least twice.

Table 2 Summary of the core plugs parameters

Core plug parameter		Core plug no.
		1	2	3	4	5
Porosity	v%	18.3	15.2	19.5	14.6	17.7
Diameter	cm	2.5	2.5	2.5	2.5	2.5
Length	cm	10.0	10.0	10.0	10.0	10.0
Water permeability	mD	2.7	3.5	4.2	4.3	3.6
Original oil saturation	OOIP%	72.0	78.2	77.8	75.4	73.1
Water flooding recovery	OOIP%	55.2	50.8	55.7	53.2	51.6

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Core plug parameter		Core plug no.
		6	7	8	9	10
Porosity	v%	15.9	17.1	16.8	18.2	17.2
Diameter	cm	2.5	2.5	2.5	2.5	2.5
Length	cm	10.0	10.0	10.0	10.0	10.0
Water permeability	mD	3.4	4.0	3.7	3.5	4.1
Original oil saturation	OOIP%	75.2	78.3	72.3	80.2	77.5
Water flooding recovery	OOIP%	57.4	55.8	56.8	57.3	54.2

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Table 3 Summary of the chemical slugs in the core plug flooding test (80 °C)

Core plug no.	Chemical agents (wt%)	Slug size (PV)
1	0 wt%	—
2	0.04 wt%	0.50
3	0.06 wt%	0.50
4	0.08 wt%	0.50
5	0.10 wt%	0.50
6	0.12 wt%	0.50
7	0.08 wt%	0.10
8	0.08 wt%	0.30
9	0.08 wt%	0.70
10	0.08 wt%	0.90

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SEM measurement

The viscoelastic surfactant in fracturing flowback fluid deposited on the silica surface was imaged using a scanning electron microscopy (SEM).³³ Imaging was conducted in air with the standard tapping mode, at room temperature. Freeze-dried samples were prepared for scanning electron microscopy (SEM) using lyophilization.³⁴ Lyophilization is a dehydration process where the material is frozen and then the surrounding pressure is reduced to allow the frozen water in the material to sublimate. This allowed the sample to keep its original morphology in the water solution.

Microscopic displacement test

The two dimension micro-model as shown in Fig. 5, was firstly cleaned using solvents and water. To ensure that the model was strongly water-wet, it was heated in an oven at 400 °C, for 1 h, to remove any organic materials remained from the previous test.³⁴ To begin a test, the cleaned model was first vacuumed, and then saturated with simulated formation water. Crude oil was injected into the model to set the initial oil saturation. After the model was saturated with crude oil, an initial water flooding was carried out using the simulated formation water. At water flooding residual oil saturation, surfactant injection was carried out. A syringe pump was used to inject the fluids. The injection rate in all the stages was 3.0 μL min⁻¹.

Fig. 5 Flowchart of microscopic displacement test.

Results and discussion

Interfacial tension behavior

In surfactant flooding system, interfacial tension (IFT)³⁵ is a basic parameter to the residual oil saturation of reservoir. The IFT is significantly reduced by the adsorption of surfactant molecules because these interactions are much stronger than the original interaction between the oil and water molecules. In order to achieve a significant residual oil recovery, ultra-low to low interfacial tension (0.0001–0.1 mN m⁻¹) is required.^36,37 A series of tests were conducted to determine the ability of fracturing flowback fluid to reduce IFT.

Fig. 6 shows plots of the interfacial tensions between fracturing flowback fluid and crude oil versus VES concentration at 80 °C. With increasing VES concentration, the IFT decreases rapidly and reaches a minimum value, indicating the adsorption of surfactants on the oil/water interface reached saturation shown from Fig. 6(a)–(b).^38–41 For further increases in the VES concentration, the IFT gradually increases which may be due to the solubilization of surfactants in the micelles, as shown in Fig. 6(c). According to the interfacial tension data, the IFT is reduced to 10⁻³ mN m⁻¹ at VES concentrations in the range of 0.05 wt% to 0.3 wt%. The lowest IFT is approximately 4 × 10⁻⁴ mN m⁻¹, which satisfies the requirements of surfactant flooding.

Fig. 6 IFT between fracturing flowback fluid and crude oil with different VES concentration.

Wettability alteration

According to Craig, wettability is defined as “the tendency of one fluid to spread on or adhere to a solid surface in presence of other immiscible fluids.⁴² Water flooding as a secondary oil recovery process is confirmed to be more effective for water-wet reservoirs. However, large amounts of residual oil would remain in the oil-wet matrix after water flooding. Wettability alteration of the oil-wet rocks to water-wet or intermediate-wet conditions is proposed as an effective mechanism to improve the oil recovery efficiency.^43,44

Fig. 7 illustrates that with the increase of VES concentration, their adsorptions on the mica surface leads to the wettability alteration. At low concentration smaller than 0.06 wt%, it is a stage of adsorption and the absorbing capacity increases with concentration, resulting in the reduction of contact angel, as shown in Fig. 7(a)–(c). At the concentration of 0.06 wt%, the surfactant molecules are saturated and packed closely on the surface of quartz plate that form a closest adsorption layer, and results in a greatest change of static contact angel, as shown in Fig. 7(d). The static contact angel changes from 110.5° to 56.5°, indicating the better performance of fracturing flowback fluid on wettability alteration.

Fig. 7 Effect of VES concentration on contact angle in fracturing flowback fluid.

The mechanism lies in that, generally, surfactant consists of a hydrophobic chain and a hydrophilic group. The amphiphilicity of surfactants makes them form a multitude of different structures in solution and adsorb at interfaces to change wettability.

Dynamic adsorption capacity

The reservoir is a porous media with a large specific surface area; therefore, surfactant adsorption on the reservoir rock undoubtedly reduces its concentration in the bulk phase during the process of enhanced oil recovery (EOR). Thus, less adsorption on the rock is required parameter for the selected surfactant.³⁸

The adsorption results are shown in Fig. 8. From Fig. 8, it can be found that there was a long adsorption and desorption process for the dynamic adsorption of VES on the natural core. When the injection volume of 0.06 wt% VES solution was over 122 PV, the dynamic adsorption reached saturation and the adsorption amount of VES was 7.48 mg g⁻¹. When the injection volume was more than 160 PV, the dynamic retention amount of VES was 2.11 mg g⁻¹. The adsorption capacity of VES is similar with the adsorption of amphoteric surfactant cocamidopropyl betaine which has been used in high temperature and high pressure reservoir, about 2.069 mg g⁻¹ reported by Zhao, J. et al.³⁰

Fig. 8 Dynamic adsorption of 0.06 wt% VES in fracturing flowback fluid on the natural core at 80 °C as a function of the injection volume.

Incremental oil recovery

To study the optimal VES concentration and slug sizes, ten core flooding tests were conducted under the Dingbianluo reservoir condition. Five tests were conducted at VES concentrations ranging from 0.04 to 0.12 wt% while keeping the slug size at 0.5 PV. The remaining five tests were carried out with slug sizes ranging from 0.1 to 0.9 PV while maintaining the VES concentration at 0.08 wt%.

To examine the effectiveness of VES concentration in the surfactant flooding system for enhanced oil recovery, six sandpack flooding tests (runs no. 1–6) were conducted with VES concentration ranging from 0 to 0.12 wt%. Fig. 9(a) illustrates the relationships between incremental oil recovery and VES concentration and the relationships between incremental oil recovery and interfacial tension, respectively. As the VES concentration increases from 0.04 to 0.08 wt% the incremental oil recovery increases rapidly from 9.2 to 12.5 OOIP% (original oil in place). For further increases in VES concentration from 0.08 to 0.12 wt%, the incremental oil recovery reaches a plateau. The results indicate that oil recovery can be enhanced by choosing the proper VES concentration. The result presents that, lower interfacial tensions with proper VES concentration in fracturing flowback fluid, corresponded to higher incremental oil recovery, for the residual oil can be flooded out easily, representing one important oil recovery mechanism.^45​–48

Fig. 9 Relationship between incremental oil recovery and interfacial tension (a) and relationship between incremental oil recovery and injection pore volume (b).

To examine the effectiveness of slug sizes in the surfactant flooding system for enhanced oil recovery, five sandpack flooding tests (runs no. 4 and 7–10) were conducted with slug sizes ranging from 0.1 to 0.9 PV. Fig. 9(b) shows the effect of chemical slug size on incremental oil recovery. The figure shows that the incremental oil recovery increases rapidly with slug sizes in the range of 0.1 PV (5.3 OOIP%) to 0.5 PV (12.5 OOIP%). However, for further increases in the slug size, the increasing trend of incremental oil recovery drops, especially in the range of 0.5 PV (12.5 OOIP%) to 0.9 PV (13.2 OOIP%). Larger slug sizes corresponded to higher incremental oil recovery. To increase the efficiency of the fracturing flowback fluid flooding process, an optional slug size of 0.3 to 0.7 PV was chosen for the field applications. One phenomenon was observed, with the slug size exceeds 0.5 PV, the incremental oil recovery increases slowly. The reason lies in that, the reservoir is a porous media with a large specific surface area; therefore, less adsorption on the rock is required parameter for the selected surfactant. When the slug size was small (less than 0.5 PV in this paper), most of the surfactant was adsorbed onto the rock surface. With the increasing of slug sizes, the adsorption and desorption of surfactants on the rock surface reaches equilibrium. Then, the surfactant molecules at the oil/water contact can reduce the oil/water IFT to a reasonably low degree and make the residual oil flooded-out easily. It can also explain why IFT plays an important role in chemical flooding.

Cumulative oil recovery

In the laboratory, core flooding test was conducted to assess the ability of fracturing flowback fluid to enhance oil recovery under the Dingbianluo condition, salinity of 37 125 mg L⁻¹ and temperature of 80 °C. The injecting concentration is fixed at 0.08 wt% and the injecting slug size is 0.5 PV. The Fig. 10 shows the plot for cumulative oil recovery and water cut curves with the three injection flooding slugs (initial water flooding, fracturing flowback fluid flooding, and subsequent water flooding). It can be seen that there is a sudden drop in water cut for the injection slugs of fracturing flowback fluids and subsequent water flooding. Meanwhile, there exists an increase in oil recovery accompanied by water cut drop. The reason for this trend is that, on one hand, at the ultra-low interfacial tension between oil and fracturing flowback fluid the displacement efficiency is strengthened, which leads to the starting of residual oil recovery and decreasing the water cut. On the other hand, the surfactant molecules at the oil/water contact can make the oil emulsification occur more easily, which plays an another important role in chemical flooding. As a result, the subsequent injected water is diverted to the unswept area and leads to a high cumulative oil recovery.⁴⁰ The incremental oil recovery is found to be 12.5 OOIP%, which indicates fracturing flowback fluid's excellent performance on enhanced oil recovery.

Fig. 10 Cumulative oil recovery and water cut under condition of Dingbianluo reservoir, initial water flooding (a); fracturing flowback fluid flooding (b) and subsequent water flooding (c).

Microscopic displacement mechanism of surfactant flooding

To understand how surfactant flooding can improve oil recovery, it is necessary to examine the distribution of residual oil after waterflooding.²⁷ Therefore, a microscopic displacement test was carried out with simulated formation water as the displacement agent, and the microscopic images of residual oil distribution after the waterflooding process are shown in Fig. 11(A)–(E). It can be seen that the morphologies of residual oil after waterflooding mainly exist as island-like, columnar, film-like and blind-end. Then, a following micro-model test with fracturing flowback fluid as the displacement agent was carried out, and the images of starting of the residual oil are shown in Fig. 11(A)–(E). To island-like, columnar and blind-end residual oil shown in Fig. 11(A), (B) and (E), surfactant in fracturing flowback fluid sharply decreases the interfacial tension between the displacement agent and the oil droplet to ultra-low. The ultra-low interfacial tension strongly reduces the capillary resistance and improves the deformability of oil droplet as shown in Fig. 11(a), (b) and (e), which leads to their easily pass across the pore throat. As to the film-like residual oil shown in Fig. 11(C) and (D), firstly, the front of oil film stretches and deforms along the flow direction under the shearing force of the flowing system. Then, on one hand, the oil film could become attenuation enough to pass through the pore throat as Fig. 11(d). On the other hand, the micelles formed in fracturing flowback fluid realize the solubilization of the attenuated oil film and finally enhance oil displacement efficiency, as shown in Fig. 11(c). To obtain a better understanding of effect of solubilization on enhanced oil recovery, SEM was used to investigate the distribution of asphaltene in core pore during different flooding stages. Compared with image of clean pore shown in Fig. 12(a), the asphaltene in oil-wet core mainly exists in pore throat and few on particle surface as shown in Fig. 12(b). When treated by surfactant flooding and subsequent water flooding, both the amount of asphaltene on core surface and the sizes of asphaltene in pore throat decreases as shown in Fig. 12(c) and (d), which illustrated system's good solubilization. The final incremental oil recovery value through microscopic displacement test is approximately 20.30 (OOIP)%.

Fig. 11 Microscopic images of residual oil after waterflooding (A–E) and movement of residual oil during surfactant flooding (a–e).

Fig. 12 Distribution of asphaltene in core pore scanned by SEM, image of clean core pore (a), image of core pore saturated with oil (b), image of core pore after surfactant flooding (c), image of core pore after subsequent water flooding (d).

Conclusion

In this work, the reutilization of fracturing flowback fluid in surfactant flooding was investigated, which is believed to be a good solution for the disposal of fracturing flowback fluid. The interfacial tension between the oil and the fracturing flowback fluids obtained from fracturing treatment was reduced to 10⁻⁴ mN m⁻¹ for VES concentrations ranging from 0.06 to 0.015 wt%. The fracturing flowback fluid system can easily convert the oil-wet surface (110.5°) to weak water-wet (56.5°) through adsorption of surfactant on the surface. The dynamic adsorption amount and retention amount of 0.06 wt% VES in fracturing flowback fluid were 7.48 mg g⁻¹ and 2.11 mg g⁻¹, respectively. Although larger slug sizes contributed to higher incremental oil recovery, the optimal chemical slug size was found in the range of 0.3–0.7 PV for the efficient reutilization of fracturing flowback fluid. The incremental oil recovery test conducted under Dingbianluo reservoir condition revealed promising results, about 12.5 (OOIP)% residual oil recovered after water flooding. SEM scanning test and microscopic displacement test were used to investigate the distribution of residual oil after waterflooding and the starting of residual oil during surfactant flooding.

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