Reutilization of Fracturing Flowback Fluids in Surfactant Flooding for

Mar 30, 2015 - China National Offshore Oil Corporation Research Institute, Beijing 100028, .... Petroleum Exploration and Development 2017 44 (4), 636...
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Reutilization of Fracturing Flowback Fluids in Surfactant Flooding for Enhanced Oil Recovery Caili Dai,† Kai Wang,†,‡ Yifei Liu,† Hui Li,† Ziyang Wei,† and Mingwei Zhao*,† †

School of Petroleum Engineering, State Key Laboratory of Heavy Oil Processing, China University of Petroleum (East China), Qingdao, Shandong 266580, People’s Republic of China ‡ China National Offshore Oil Corporation Research Institute, Beijing 100028, People’s Republic of China ABSTRACT: The reutilization of fracturing flowback fluids (which are primarily composed of viscoelastic surfactants) in surfactant flooding was investigated with the aim of making the surfactant flooding process more efficient and cost-effective. The dynamic and equilibrium interfacial tensions and the effects of salinity and temperature on interfacial tension were studied. The oil/water interfacial tension was lowered to 10−3 mN/m due to 0.004−0.008 wt % viscoelastic surfactant in the flowback fluids. The fracturing flowback fluids were found to be suitable for reservoirs, with a salinity ranging from 0 to 110000 mg/L and temperatures ranging from 50 to 90 °C. In the solid/liquid system, the saturated adsorption capacity and dynamic retention capacity were 8.09 mg/g and 2.29 mg/g, respectively. A series of sandpack core-flooding tests were conducted under the reservoir condition to investigate the effects of concentration and the slug size of chemicals on oil recovery. The results showed that the oil recovery value was highest with a surfactant concentration of 0.006 wt %. The oil recovery improved with slug sizes. The optimal chemical slug size in this study was maintained between 0.7 and 0.9 pore volumes (PV) for the efficient reutilization of fracturing flowback fluids. This investigation established that the simulated flowback fluids recovered from fracturing treatment using viscoelastic surfactants can be reused for surfactant flooding with probable environmental and economic benefits. research on the reuse of fracturing flowback fluids in surfactant flooding is scarce, and no results have been reported. Enhanced oil recovery (EOR) by surfactant flooding has recently received widespread attention.9−11 Low interfacial tension (IFT) at low surfactant concentrations and the resulting economy are considered significant design parameters in optimizing the usage of surfactants to recover the residual oil trapped in reservoirs.12,13 A wide variety of surfactants, such as α-olefin (AOS), internal olefin sulfonates (IOS), alkybenzenesulfonate (ABS), dodecyl benzenesulfonate (SDBS) and viscoelastic surfactants, have been used for tertiary oil recovery.14−17 Azad et al.18 studied the applicability of viscoelastic surfactants for enhanced oil recovery from a high salinity, high temperature reservoir. They found that the 0.5−1 wt % VES as a single system reduced the IFT to 10−2 mN/m. It is known that clean fracturing flowback fluids are generally formed by adding VESs, such as anionic, cationic, and zwitterionic surfactants, to water.19 In addition, the amount of viscoelastic surfactants present in flowback fluids is high with concentrations ranging from 3 to 8 wt %.20,21 This fact provided the impetus for studying whether VESs in the flowback fluids can be used in surfactant flooding by decreasing the oil/water IFT.22 This study focuses on the reutilization of fracturing flowback fluids in surfactant flooding. To the best of our knowledge, this is the first study of the reuse of fracturing flowback fluids in surfactant flooding for EOR. In this work, the authors propose a novel method of reutilizing fracturing flowback fluids, aiming

1. INTRODUCTION Cross-linked polymer fluids are widely used in hydraulic fracturing because of their high viscosity and low leak-off rates.1 However, the polymer residues left in fractures significantly damage the reservoir permeability after fracturing, which limits the field application of this technique.2 Over the past 2 decades, viscoelastic surfactant (VES) fluids have been used for hydraulic fracturing because of their low friction, properties of easy gel breaking without inner breakers, and low formation damage.3,4 Since their initial use in fracturing treatment in the Gulf of Mexico, over 2100 fracturing treatments were performed using VES fluids before the year 2000.5 Although VES fluids are widely used to enhance the oil productivity, disposing the large quantities of fracturing flowback fluids from the fracturing processes remains an unsolved problem regarding their application, in addition to other fracturing fluids. The consumption of fracturing fluids generally ranges from a few thousand gallons to several hundred thousand gallons.6 In addition, fracturing flowback fluids generally contain methanal and various types of highly toxic additives. Without proper treatment, such additives may cause serious environmental hazards. The reutilization of fracturing flowback fluids is considered as an ideal solution to this problem. Until now, most researchers have reused fracturing flowback fluid based on the guar gum only for secondary fracturing simulation. Qu et al. studied the reutilization of guar gum-based fracturing fluid by adjusting the pH of flowback fluids.7 Li et al.8 studied the reutilization of hydroxypropyl guar gum fracturing fluid by adding a fresh cross-linking agent and a thickener to the flowback fluids to promote the secondary fracturing process. Nevertheless, the © XXXX American Chemical Society

Received: January 8, 2015

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Energy & Fuels to expand the application of flowback fluids and improving its operational efficiency and economy.

concentration by taking UV−vis measurements. This method is based on the precipitation generated due to the reaction of VES and orange II sodium salt. The analytical process was as follows, The orange II sodium salt solution was freshly prepared by adding 0.1 g of orange II sodium salt into 100 mL of distilled water. A buffer solution was prepared with distilled water and adjusting the pH value to 4.5 using an acetate solution. The reagent was prepared just prior to use because it gradually decomposes, which may lead to measurement errors. Approximately 5.0 mL of standard viscoelastic surfactant solution at concentrations ranging from 0.002 to 0.04 wt % and 10 mL buffer solution were separately pipetted into 100 mL conical flasks and shaken well for 5 min. Next, 20 mL of chloroform was added to the conical flasks to extract the precipitation formed by the reaction of the VES and the orange II sodium salt. The precipitates were extracted in the chloroform by shaking for 5 min and allowing to stand for 15 min until the solvent was colorless. The filtrate was collected in 100 mL volumetric flasks and then diluted to a fixed volume with chloroform. A part of the solution was transferred to the adsorption cell, and the absorbance at a wavelength of 485 nm was measured, using chloroform as a reference solution. The Lambert−Beers law was observed, and the VES concentration obtained was in the range of 0− 0.10 wt %, as shown in Figure 1.

2. EXPERIMENTAL SECTION 2.1. Chemicals and Fluids. The chemicals used in this study included clean fracturing fluid (which is primarily composed of quaternary ammonium surfactants, obtained from the Changqing oilfield, China), sodium chloride, and calcium chloride anhydrous (Sinopharm Chemical Reagent Co. Ltd.). The oil was collected from the Dingbianluo reservoir (Changqing oilfield, China). The viscosity of the oil used in the experiments was 1.34 mPa·s−1 at 80 °C (the reservoir temperature) measured using a Brookfield DV-II Pro viscometer. The density of the oil was 730 kg/ m3. For the experiments, the oil was separated from water and solids via centrifugation. Deionized water was used in the experiments. The formation brine of the Dingbianluo reservoir was used for the sandpack flooding test. The formation brine was treated to eliminate the solids and floating oil droplets. The compositional analysis of the formation brine is shown in Table 1.

Table 1. Quality Analysis of the Formation Water ions

K+ + Na+

Ca2+

Mg2+

Cl−

HCO3−

concentration (mg/L) total salinity (mg/L)

11470

2601

146 37125

22649

259

2.2. Preparation of the Fracturing Flowback Fluids. In the laboratory, fracturing flowback fluids were obtained by simulating the formation and destruction of wormlike micelles used during fracturing operations in the field. The gelling fluid was prepared using 5 wt % VES and 95 wt % deionized water. The gel breaking process was carried out by adding 2 wt % kerosene to the gelling system. It was then maintained at 80 °C in a separating funnel until the viscosity of the system reduced to that of brine. The supernatant obtained from the separating funnel was considered equivalent to the flowback fluids and was used in the following experiments. 2.3. IFT Measurement. The oil/water IFT was measured using a Texas-500 spinning drop tension meter. The interfacial tension was calculated using the following equation.23 The interfacial tension was determined according to a single-measurement method, and all measurements were repeated at least twice.

⎛ D ⎞3 A = 1.2336(rw − ro)w 2⎜ ⎟ , ⎝n⎠

Figure 1. Stand curve of the VES solution. 2.6. 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 was stable. Surfactant solution was then continuously injected until the surfactant concentration from the outlet was close to the initial injection concentration. Then simulated formation water 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. Dynamic adsorption was calculated according to the following equation:

L ≥4 D

where A is the oil/water interfacial tension (mN/m); rw and ro are the densities of the water and oil phases (g/cm3), respectively; w is the rotational speed (rpm); D and L are the width and length of the oil droplet (mm), respectively; and n is the refractive index of the water phase. 2.4. Porosity Measurement. The porosity was determined gravimetrically according to the following procedure; (1) The volume of the artificial cores, V, was calculated; (2) the dry weight of the artificial cores, m1, was determined; (3) the artificial cores were saturated by circulating formation water with a density ρ using a pump (SHZ-DIII, Shanghai Cheng Ming Instrument Equipment Co. Ltd., China) for 24 h, and the saturation was assumed to be complete when no more bubbles were produced; (4) the wet weight of the artificial cores, m2, was determined; and (5) the porosity was calculated according to m − m1 Φ= 2 Vρ

n

Γr =

C0V − ∑i = 1 CiVi m

where Γr is the amount of surfactant adsorption on the core surface per gram of rock (mg/g); C0 is the initial surfactant concentration before adsorption (mg/g); V is the total volume of injected surfactant solution when the surfactant concentration from the outlet was close to the initial surfactant concentration (mL); Ci is the surfactant concentration from the outlet; Vi is the volume of every collected outlet sample (mL); m is the mass of the natural core (g); and n is the total of the effluent samples until the surfactant concentration was reduced to zero. 2.7. Sandpack Core-Flooding Test. A core holder 2.54 cm in diameter and 30 cm in length (Haianxian Oil Scientific Research

where Φ is the porosity, m1 and m2 are the dry weight and the wet weight of the artificial cores, respectively, V is the volume of the artificial cores, and ρ is the density of the formation brine. 2.5. Determination of the Viscoelastic Surfactant Concentration. The colorimetric method was used to determine the VES B

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Energy & Fuels Apparatus Co Ltd., China) was used for the flooding tests. Cylindrical cores (Haianxian Oil Scientific) with a permeability ranging from 3 to 5 mD were used to simulate the actual conditions of the Dingbianluo reservoirs. The following procedure was followed in conducting the core plug flooding test: (1) The permeability of the formation water was measured using the apparatus shown schematically in Figure 2 at a

Table 3. Summary of the Chemical Slugs in the Core Plug Flooding Test (80 °C)

Figure 2. Flowchart of the permeability measurement: (1) constantflux pump; (2) six-way valve; (3) water container; (4) pressure meter; (5) core holder; (6) confining pressure pump; (7) graduated cylinder.

and influences the dynamic and static interfacial tensions between the oil and fracturing flowback fluids. Figure 3a shows plots of the DIT between the simulated flowback fluids and the Dingbianluo crude oil at different VES concentrations. As shown in Figure 3a, the time required for the DIT to reach equilibrium decreases with the increasing VES concentrations. This trend is due to the larger gradient between the aqueous phase and the interface that result from the VES concentrations. The larger the gradient between the aqueous phase and the interface, the faster is the diffusion of surfactants. As a result, the time required for the DIT to reach equilibrium decreases.26 Figure 3b shows graphs of the equilibrium interfacial tensions between the oil and fracturing flowback fluids system versus VES concentration at 80 °C. With increasing VES concentrations, the IFT decreases rapidly and reaches a minimum value, indicating the adsorption of surfactants on the oil/water interface reached saturation.27 For further increases in the VES concentration, the IFT gradually increases which may be due to the solubilization of surfactants in the micelles. According to the equilibrium interfacial tension data, the IFT is reduced to 10−2 mN/m at VES concentrations in the range of 0.002−0.04 wt %. The lowest IFT is approximately 10−3 mN/m, which satisfies the requirements of surfactant flooding. 3.2. Effect of Salinity on the Interfacial Tension between Oil and Fracturing Flowback Fluids. For actual

flow rate of 0.3 mL/min; (2) the wet cores were saturated with crude oil until the water-cut produced from the outlet was less than 1%; (3) the cores were flooded with 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 oil no longer flowed from the outlet (water-cut > 98%). All of the tests were carried out at 80 °C. The injection flow rate was 0.3 mL/min. 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 injected fracturing flowback fluid slugs are shown in Table 3. Each core plug flooding test was repeated at least twice.

3. RESULTS AND DISCUSSION 3.1. Dynamic and Static Interfacial Tension Behavior of the Oil/Fracturing Flowback Fluids. The interfacial tension refers to the surface tension at the interface between two phases. The dynamic interfacial tension (DIT) and the equilibrium interfacial tension are the basic parameters of surfactant flooding systems, the values of which should be reduced to 10−2 mN/m.24 According to Zhao et al., interfacial tension is a process of adsorption of surfactants onto the oil/ water interface due to the surfactant concentration.25 The surfactant concentration critically affects the adsorption layer,

core plug no.

chemical agents (wt %)

slug size (PV)

1 2 3 4 5 6 7 8 9 10

0.002 0.004 0.006 0.008 0.01 0.006 0.006 0.006 0.006 0.006

0.70 0.70 0.70 0.70 0.70 0.10 0.30 0.50 0.90 1.10

Table 2. Summary of the Core Plug Parameters for given core plug no. core plug param

1

2

3

4

5

porosity (V, %) diameter (cm) length (cm) pressure drop (MPa) water permeability (mD) original oil saturation (OOIP%) water flooding recovery (OOIP%)

17.5 2.5 10.0 0.27 3.8 70.9 56.70

16.8 2.5 10.0 0.24 4.2 75.4 51.92

17.2 2.5 10.0 0.23 4.5 79.0 57.90 for given core plug no.

15.8 2.5 10.0 0.29 3.5 73.5 54.40

18.1 2.5 10.0 0.21 4.9 74.8 55.30

core plug param

6

7

8

9

10

porosity (V, %) diameter (cm) length (cm) pressure drop (MPa) water permeability (mD) original oil saturation (OOIP%) water flooding recovery (OOIP%)

15.3 2.5 10.0 0.22 4.7 79.0 56.65

16.2 2.5 10.0 0.24 4.2 75.4 51.90

18.5 2.5 10.0 0.32 3.2 77.0 55.20

17.9 2.5 10.0 0.28 3.6 81.0 52.60

16.4 2.5 10.0 0.21 4.8 73.7 53.70

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Figure 3. (a) Dynamic interfacial tension curves for the flowback fluids and oil at VES concentrations of 0.006, 0.02, and 0.2 wt %. (b) Static interfacial tension between the flowback fluids and the oil for different concentrations of VES at a temperature of 80 °C.

Figure 4. (a) Effect of sodium chloride on the interfacial tension versus various VES concentrations. (b) Effect of sodium chloride on the interfacial tension for various concentrations of Na+, where the concentration of VES is 0.006 wt % at a temperature of 80 °C.

Figure 5. Model for the partition of surfactant at various sodium chloride concentrations: (a) 10000, (b) 30000, (c) 50000, (d) 70000, and (e) 90000 mg/L.

at the interface.28 The effect of sodium chloride concentration on the interfacial tension is shown in Figure 4b. With increasing NaCl concentrations, the IFT gradually decreases and reaches a minimum for an NaCl concentration of approximately 5000 mg/L. Further increasing the NaCl concentration causes the IFT to gradually increase. The IFTs reach an ultralow value (less than 10−2 mN/m) for NaCl concentrations in the range of 0−110000 mg/L with a VES concentration of 0.006 wt %. The results can be illustrated using a partition model for the surfactants, as shown in Figure 5.29,30 As shown in Figure 5a−e, with increasing NaCl concentrations, the adsorption of surfactants at the interface initially increases and then subsequently decreases. Moreover, comparing parts a and e of Figure 5 reveals that more surfactants exist in the aqueous phase at a low NaCl concentration, whereas more exist in the oil phase at high sodium chloride concentrations.31 It can be

reservoirs, the salinity generally ranges from several hundreds to hundreds of thousands of milligrams per liter. The saltresistant capability is an important parameter in optimizing the performance of surfactants. In this study, the effect of sodium chloride concentration on the interfacial tension was studied to determine the salt-resisting ability of the fracturing flowback fluid system and to establish the most appropriate range of concentrations of sodium chloride for field applications. Figure 4a shows the effect of sodium chloride concentration on the interfacial tension at various VES concentrations. As the sodium chloride concentration increased from 0 to 3000 mg/L, the interfacial tension, particularly the minimum IFT, decreased. This result is in agreement with that of Zhao. Zhao found that the interfacial tension decreased with the addition of sodium chloride due to the hydrophilic−lipophilic balance, leading to increased adsorption of surfactant molecules D

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3.4. Dynamic Adsorption of Fracturing Flowback Fluid. The dynamic adsorption of viscoelastic surfactant in fracturing flowback fluid on the natural core was investigated at 80 °C by sandpack core-flooding test with an injection rate of 0.1 mL/min. The core parameters, injection surfactant volume, injection water volume, saturated adsorption capacity, and dynamic retention capacity are shown in Table 4.

assumed that both synergy and antagonism exist between the surfactants and sodium chloride. To some extent, the increase in sodium chloride concentration strengthens the hydrophobic ability of the surfactants, which induces their movement from the aqueous phase to the interface, as shown in Figure 5a,c. Further increasing the sodium chloride concentrations induces a decrease in the adsorption of surfactants at the interface due to the surfactants’ affinity for the oil phase, as illustrated in Figure 5c,d. This result agrees well with the microscopic observation of the transfer of surfactants from the aqueous phase to the oil phase, as noted earlier.29,30 At the optimum salinity, there is a large amount of surfactants at the interface for all cases, leading to the lowest the interfacial tension. 3.3. Effect of Temperature on the Interfacial Tension between Oil and the Fracturing Flowback Fluid System. Temperature affects the oil viscosity and adsorption of surfactant molecules, which is closely related to the interfacial tension.32 To investigate the effect of temperature on the interfacial tension for establishing the appropriate temperature range for field application, a series of IFT tests were conducted. These tests were conducted at various temperatures, and the results are shown in Figure 6.

Table 4. Dynamic Adsorption Results surfactant concn (wt %)

wt of nature core (g)

0.04

81.25

a

Kgasa (mD)

pore vol (mL)

saturated adsorpn (mg/g)

dynamic retention (mg/g)

4.2

12.0

8.09

2.09

Kgas = permeability.

The adsorption results are shown in Figure 7. From Figure 7, it can be found that there was a long adsorption and desorption

Figure 7. Dynamic adsorption of 0.04 wt % VES in fracturing flowback fluid on the natural core at 80 °C as a function of the injection volume.

process for the dynamic adsorption of VES on the natural core. When the injection volume of 0.04 wt % VES solution was over 410 PV, the dynamic adsorption reached saturation and the adsorption amount of VES was 8.09 mg/g. When the injection volume was more than 600 PV, the dynamic retention amount of VES was 2.29 mg/g. The adsorption capacity of VES is similar to the adsorption of amphoteric surfactant cocamidopropyl betaine which has been used in high temperature and high pressure reservoir, about 2.069 mg/g reported by Zhao et al.22 The moderate adsorption of VES in fracturing flowback fluid guaranteed its field application during the reutilization process. 3.5. Effect of VES Concentration and Slug Sizes on Incremental Oil Recovery. To study the optimal VES concentration and slug sizes, 10 core-flooding tests were carried out under the prevailing conditions in the Dingbianluo reservoir. Five tests were conducted at VES concentrations ranging from 0.002 to 0.01 wt % while maintaining the chemical slug size at 0.7 PV. The remaining five tests were conducted with chemical slug sizes ranging from 0.1 to 1.1 PV while maintaining the VES concentration at 0.006 wt %. Figure 8a illustrates the graphical relationships between incremental oil recovery and VES concentration and between incremental oil recovery and interfacial tension. As the VES concentration increases from 0.002 to 0.006 wt %, the incremental oil recovery increases rapidly from 5.3 to 10.1 OOIP%. For further increases in VES concentration from 0.006

Figure 6. Effect of temperature on the interfacial tension between the oil and fracturing flowback fluid system, where the concentration of VES is fixed at 0.006 wt %.

The plots of interfacial tension and temperature can be divided into two regions. The interfacial tension decreases as the temperature is increased from 50 to 80 °C, and the lowest interfacial tension of 10−3 mN/m is obtained at 80 °C. For further increases in the temperature from 80 to 90 °C, the interfacial tension gradually increases. These results show that temperature has both positive and negative influences on the interfacial tension. For temperatures below 80 °C, any increase in temperature reduces the IFT. Any increase in temperature over 80 °C increases the IFT. This phenomenon can be attributed to thermodynamic molecular movement. At higher temperatures, the surfactant molecules may have a higher velocity, and thus more surfactant functionality is adsorbed at the interface. However, for further increases in the temperature, the surfactants on the interface tend to shift to the oil phase, resulting in decreased adsorption at the interface.33 For the fracturing flowback fluid system considered in this study, the IFTs reached an ultralow value less than 10−2 mN/m for temperatures in the range of 50−90 °C. Thus, a wide temperature range is available for field applications. E

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Figure 8. Relationship between the interfacial tension and incremental oil recovery and (b) the effect of the injecting slug size on incremental oil recovery.

Figure 9. Mechanism diagram of reutilization of fracturing flowback fluids.

When hydrophobic substances such as oil or gas are dissolved in a micellar hydrocarbon core,38 worm-like micelle structures swell and transform into smaller-sized spherical micelles, resulting in a loss of fluid viscosity. Because no inner chemical agent or enzyme breaker is required for the process of gel breaking, there is no damage to the viscoelastic surfactant molecules, providing a solid basis for the reutilization of fracturing flowback fluids. The mechanism involved in the reutilization of flowback fluids for surfactant flooding is illustrated to the right in Figure 9. During the process of reutilization for surfactant flooding, the surfactants in the fracturing flowback fluids move toward the oil/water interface, with the oil-soluble hydrocarbon chain oriented toward oil phase and the water-soluble group oriented toward water phase. The adsorption of surfactants on the interface significantly contributes to decreasing the oil/water interfacial tension, which is a very important parameter and mechanism for enhanced oil recovery.

to 0.01 wt %, the incremental oil recovery reaches a plateau. The results indicate that oil recovery can be enhanced by choosing the proper VES concentration. A phenomenon was observed during optimization of the VES concentration. Lower interfacial tensions corresponded to higher incremental oil recovery, representing an important oil recovery mechanism. Figure 8b shows the effect of chemical slug size on IFT and incremental oil recovery. The figure shows that the incremental oil recovery is linearly related to the chemical slug size in the range of 0.1 PV (4.3 OOIP%) to 0.7 PV (10.3 OOIP%). However, for further increases in the slug size, the increasing trend of incremental oil recovery drops, especially in the range of 0.7 PV (10.3 OOIP%) to 1.1 PV (11 OOIP%). Larger slug sizes corresponded to higher incremental oil recovery. To increase the efficiency of the fracturing flowback fluid process, an optional slug size of 0.7−0.9 PV was chosen for the field applications. 3.6. The Proposed Mechanisms of Reutilization of Fracturing Flowback Fluids. The proposed mechanisms of reutilization of the fracturing flowback fluids are illustrated in Figure 9, which outlines the processes of gelling, gel breaking, and reutilization of flowback fluids. In a solution containing a group of counter anions, viscoelastic surfactant molecules can gather together to form worm-like micelles with a structure similar to that of a polymer.34 Cates and Hoffmann reported that worm-like micelles twisting with one another form a viscoelastic system and increase the viscosity of the system.35−37 Such a viscoelastic system is suitable for hydraulic fracturing due to its high viscosity.

4. CONCLUSION In this study, the reutilization of fracturing flowback fluids for surfactant flooding was investigated, which is believed to be a good solution for the disposal of clean fracturing flowback fluids. The interfacial tension between the oil and the simulated flowback fluids from fracture treatment was reduced to 10−3 mN/m for VES concentrations of 0.004−0.008 wt %. The fracturing flowback fluids system is suitable for applications in a wide range of reservoirs with salinity ranging from 0 to 11 wt % and temperature ranging from 50 to 90 °C. The dynamic adsorption amount and retention amount of 0.04 wt % VES in F

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Energy & Fuels fracturing flowback fluid were 8.09 mg/g and 2.29 mg/g, respectively, which is moderate. Although larger chemical slug sizes contributed to higher incremental oil recovery, the optimal chemical slug size was found in the range of 0.7−0.9 PV for the efficient reutilization of fracturing flowback fluids. The incremental oil recovery test conducted under the prevailing conditions in the Dingbianluo reservoir revealed promising results. This work confirms the feasibility of reclaiming fracturing flowback fluids after fracturing and reusing the fluids in surfactant flooding to increase the efficiency and cost-effectiveness of the process.

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(11) Flaaten, A. K.; Nguyen, Q. P.; Zhang, J.; Mohammadi, H.; Pope, G. A. Alkaline/Surfactant/Polymer Chemical Flooding without the Need for Soft Water. SPE J. 2010, 15 (1), 184−196. (12) Elraies, K. A.; Tan, I. M.; Awang, M. B.; Fathaddin, T. A New Approach to Low-Cost High Performance Chemical Flooding System, SPE Production and Operations Conference and Exhibition, Tunis, Tunisia, Jun. 8−10, 2010; SPE-133004-MS; Society of Petroleum Engineers: Richardson, TX, USA, 2010; http://dx.doi.org/10.2118/ 133004-MS. (13) Qutubuddin, S.; Miller, C. A.; Fort, T., Jr. Phase behavior of pHdependent microemulsions. J. Colloid Interface Sci. 1984, 101 (1), 46− 58. (14) Morvan, M.; Moreau, P.; Degre, G.; Leng, J.; Masselon, C.; et al. New viscoelastic fluid for chemical EOR, SPE International Symposium on Oilfield Chemistry. Woodlands TX, USA, Apr. 20−22, 2009, SPE121675-MS; Society of Petroleum Engineers: Richardson, TX, USA, 2009; http://dx.doi.org/10.2118/121675-MS. (15) Barakat, Y.; Fortney, L. N.; Schechter, R. S.; Wade, W. H.; Yiv, S. H. Alpha-olefin sulfonates for enhanced oil recovery. Proceedings of the 2nd European Symposium on Enhanced Oil Recovery, November 1982; Technip: Paris, 1982; pp 11−20. (16) Barnes, J. R.; Smit, J.; Smit, J.; Shpakoff, G.; Raney, K. H.; Puerto, M. Development of surfactants for chemical flooding at difficult reservoir conditions, SPE Symposium on Improved Oil Recovery. Tulsa, OK, USA, Apr. 20−23, 2008, SPE-113313-MS; Society of Petroleum Engineers: Richardson, TX, USA, 2008; http://dx.doi.org/10.2118/ 113313-MS. (17) Yang, H. T., Britton, C., Liyanage, P. J., Solairaj, S., Kim, D. H., Nguyen, Q.; et al. Low-Cost High-Performance Chemicals for Enhanced Oil Recovery, SPE Improved Oil Recovery Symposium. Tulsa, OK, USA, Apr. 24−28, 2010, SPE-129978-MS; Society of Petroleum Engineers: Richardson, TX, USA, 2010; http://dx.doi.org/10.2118/ 129978-MS. (18) Azad, M. S.; Sultan, A. S. Extending the Applicability of Chemical EOR in High Salinity, High Temperature & Fractured Carbonate Reservoir Through Viscoelastic Surfactants [C], SPE Saudi Arabia Section Technical Symposium and Exhibition. Society of Petroleum Engineers, 2014. (19) Sullivan, P. F.; Gadiyar, B. R.; Morales, R. H.; Holicek, R. A.; Sorrells, D. C.; et al. Optimization of a visco-elastic surfactant (VES) fracturing fluid for application in high-permeability formations, SPE International Symposium and Exhibition on Formation Damage Control. Lafayette, LA, USA, Feb. 15−17, 2006, SPE-98338-MS; Society of Petroleum Engineers: Richardson, TX, USA, 2006http://dx. doi.org/10.2118/98338-MS. (20) Levitt, D.; Jackson, A.; Heinson, C.; Britton, L. N.; Malik, T.; Dwarakanath, V.; Pope, G. A. Identification and evaluation of highperformance EOR surfactants. SPE Reservoir Eval. Eng. 2009, 12 (2), 243−253. (21) Bulat, D.; Chen, Y.; Graham, M. K.; Marcinew, R. P.; Adeogun, A. S.; et al. A Faster Cleanup Produced Water-Compatible Fracturing Fluid: Fluid Designs and Field Case Studies, SPE International Symposium and Exhibition on Formation Damage Control. Lafayette, LA, USA, Feb. 13−15, 2008; SPE-112435-MS; Society of Petroleum Engineers: Richardson, TX, USA, 2008; http://dx.doi.org/10.2118/ 112435-MS. (22) Zhao, J.; Dai, C.; Fang, J.; Feng, X.; Yan, L.; Zhao, M. Surface properties and adsorption behavior of cocamidopropyl dimethyl amine oxide under high temperature and high salinity conditions. Colloids Surf., A 2014, 450, 93−98. (23) Bai, Y.; Xiong, C.; Shang, X.; Xin, Y. Experimental Study on Ethanolamine/Surfactant Flooding for Enhanced Oil Recovery. Energy Fuels 2014, 28 (3), 1829−1837. (24) Melrose, J. C.; Brandner, C. F. Role of capillary forces in determining microscopic displacement efficiency for oil recovery by water flooding. J. Can. Pet. Technol. 1974, 54−62. (25) Zhao, Z.; Li, Z.; Qiao, W.; Cheng, L. Dynamic interfacial behavior between crude oil and octylmethylnaphthalene sulfonate surfactant flooding systems. Colloids Surf., A 2005, 259 (1), 71−80.

AUTHOR INFORMATION

Corresponding Author

*E-mail: [email protected]. Tel.: +86-532-86981183. Fax: +86-532-86981161. Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS The work was supported by the National Science Fund for Distinguished Young Scholars (Grant 51425406), the National Natural Science Foundation of China (Grants 51174221 and 21303268), Doctoral Fund from the National Ministry of Education (Grant 20120133110010), the China Postdoctoral Science Foundation funded project (Grant 2013T60689), and the Program for Changjiang Scholars and Innovative Research Team in University (Grant IRT1294).

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DOI: 10.1021/acs.energyfuels.5b00507 Energy Fuels XXXX, XXX, XXX−XXX