Comparative Studies on Enhanced Oil Recovery: Thermoviscosifying

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Comparative Studies on Enhanced Oil Recovery: Thermoviscosifying Polymer versus Polyacrylamide Xian'e Li, Zhi Xu, Hongyao Yin, Yujun Feng, and Hongping Quan Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.6b02653 • Publication Date (Web): 15 Feb 2017 Downloaded from http://pubs.acs.org on February 18, 2017

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Comparative Studies on Enhanced Oil Recovery: Thermoviscosifying Polymer versus Polyacrylamide Xian’e Li,1 Zhi Xu,2 Hongyao Yin,1 Yujun Feng1,2* Hongping Quan3 1

Polymer Research Institute, State Key Laboratory of Polymer Materials Engineering, Sichuan University, Chengdu 610065, P. R. China

2

Chengdu Institute of Organic Chemistry, Chinese Academy of Sciences, Chengdu 610041, P. R. China

3

Oil & Gas Field Applied Chemistry Key Laboratory of Sichuan Province, School of Chemistry and Chemical Engineering, Southwest Petroleum University, Xindu 610500, P. R. China

KEYWORDS: Enhanced oil recovery; Polymer flooding; Smart polymer; Thermoviscosifying; Rheological properties

ABSTRACT: High-molecular-weight polyacrylamide (PAM) has been widely used in chemically enhanced oil recovery (EOR) processes under mild conditions, but its poor tolerance to high temperature and high salinity impeded the use in severe oil reservoirs. To overcome the inadequacies of PAM, thermoviscosifying polymers (TVPs) whose viscosity increases upon 1 ACS Paragon Plus Environment

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increasing temperature and salinity were developed in recent years. In this work, comparative studies with PAM and TVP having closer molecular weight were performed with regard to their rheological behaviors, thermal stability, and core flooding feasibility. It was found that the TVP aqueous solution exhibited thermothickening ability even at 0.2wt% polymer concentration with a total dissolved solids ratio (TDS) of 101,000 mg⋅L−1 upon increasing temperature, while PAM only showed monotonic decrease in viscosity under identical condition. Remaining viscosity of TVP was higher than that of PAM after aging at 45 °C or 85 °C for one month. Core flooding tests demonstrated both polymers show good transportation in porous media, and a higher oil recovery of 16.4% and 15.5% can be attained by TVP at 45 °C and 85 °C, respectively, while those of PAM are only 12.0% and 9.20%.

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1. INTRODUCTION Approximately two thirds of the original oil in place (OOIP) still remains in reservoirs after conventional primary and secondary production.1 Much of the residual oil could be further produced by the so-called chemically enhanced oil recovery (EOR) process especially polymer flooding,2 which has been verified the most effective technology implemented in China for incremental oil production over the last 20 years.3 In the polymer flooding operation, a high-molecular-weight water-soluble polymer, polyacrylamide (PAM) or its derivatives, is added to thicken the displacing fluid, so as to reduce the mobility of the aqueous phase, enlarge the swept volume, consequently, to improve oil recovery efficiency.4,5 Additionally, polymer adsorption onto the rocks decreases the permeability to water, and the viscoelasticity of the polymer solution can increase the microscopic displacement efficiency.6 Partially hydrolyzed polyacrylamide (HPAM), the most widely used polymer in EOR applications, shows strong viscosifying power in fresh water and relative low temperature (< 75 °C), due to its extremely high molecular weight and the electrostatic repulsion between the negative carboxylate charges along the polymer chain; nevertheless, such viscosity buildup ability is seriously weakened when inorganic ions such as Na+ and K+ in brine, because the negative charge repulsion is shielded, thus the polymer coils collapse. Different teams worldwide7−11 all verified that presence of Ca2+ and Mg2+ will aggravate the viscosity because they can complex with the anionic carboxylate groups along the HPAM skeleton, thus demixing and precipitation may occur. Moradi-Araghi and Doe10 observed that the higher the hardness, the lower temperature can be tolerated. Consequently, further application of HPAM is limited in high-salinity and high-hardness oil reservoirs. Great efforts have been made by many researchers 3 ACS Paragon Plus Environment

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to reduce the salt sensitivity of PAM. For example, the ultrahigh molecular weight PAM has been synthesized to increase the hydrodynamic radius of a single molecular chain. However, these polymers degrade easily when subjected to shear stresses, and also it is expensive to increase molecular weight. Furthermore, the strong adsorption between positive quaternary or weak tertiary cationic groups and the sand surfaces will strongly decrease the polymer concentration when it propagates in the porous media. Copolymerizing of AM with functional monomers such as vinylpyrrolidone,12 1,3-oxazolic,13 and N-phenylmaleimide14 is an alternative strategy to enhance the salt tolerance. However, the low polymerization activity of theses monomers makes it difficult to achieve high molecular weight and the molar ratio of functional monomers is within the range of 10% to 30% which implies much higher cost is needed to produce this kind of polymer.15 Furthermore, the fatal thermothinning defect of these polymers impedes them to be used in extremely harsh oil reservoirs, such as the Class III reserve of Shengli Oilfield in China where the temperature exceeds 85 °C and the salinity (total dissolved solids, TDS) is higher than 30,000 mg⋅L−1 even up to 110,000 mg⋅L−1 with total amount of divalent cations higher than 800 mg⋅L−1. In recent years, one of the most promising replacement, smart thermoviscosifying polymers (TVP) has been developed, which was pioneered by Hourdet and his coworkers in early 1990s.16,17 In such polymers, some “grafts” with the character of lower critical solution temperature (LCST) were incorporated onto the hydrosoluble skeleton. LCST is the critical temperature of a certain mixed system beyond which the phase separation would occur owing to the changes of interactions among different components with increasing temperature. In this situation, these grafts in the thermoviscosifying polymers will change their characters from hydrophilicity to hydrophobicity over this transition temperature. The final copolymer is 4 ACS Paragon Plus Environment

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well-dissolved in water and behaved as conventional HAPM at room temperature, but the thermo-responsive “grafts” self-assemble into hydrophobic microdomains when heating to a critical associating temperature (Tass). In the semi-dilute region, except for the common entanglements of macromolecules, the physical crosslinks will be formed by the hydrophobic association of LCST grafts from different water-soluble backbones above Tass, giving rise to thermothickening response macroscopically, in contrast to the “thermothinning” behaviors always observed in traditional water-soluble polymers. When the temperature is decreased below Tass, the inter-molecular hydrophobic interactions will be diminished and thus the viscosity will restore back to the initial value. Such smart reversibility in tuning the viscosity upon the variation of temperature furnishes the TVP polymers as good candidates to be used in hot oil reservoirs. However, inadequacies from the earlier studies on such polymers were still evidenced, in particular, the intrinsic molecular weight of the as-prepared polymers is rather low, generally less than half a million,18 thus the “thermothickening” power can only be obtained at much higher polymer concentration; in addition, expensive coupling agent is obligatorily necessary in the preparation of polymers, and the grafting reaction must be conducted at relative low polymer loadings in the reaction medium.19 Most importantly, some specific inorganic salts particularly K2CO3 are always needed to induce the thermoassociation between the grafts.20 These limitations seriously impeded large-scale manufacturing of the polymers and the acceptance of petroleum engineers who always desire less expensive, high-molecular-weight acrylamide-based products. Attempts have been made in our laboratory to overcome the above deficiencies, and a series of novel TVPs were prepared via direct free radical copolymerization of acrylamide21 or 2-acrylamido-methylpropane sulfonic acid22 with our newly-developed thermosensitive


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comonomer MPAD based on N-(1,1-dimethyl-3-oxobutyl)-acrylamide with more convenient and cost-effective procedures. The basic thermoviscosifying ability of these TVPs was evaluated in the presence of different inorganic salts,21−23 and their oil recovery efficiency was assessed preliminarily via sand-pack flooding tests.24 Recently, we extend our laboratory synthesis to small-scale factory pilot manufacturing, and the rheological behaviors of such pilot products in sea water, formation brine were examined, their oil recovery factor along with co-injection of surfactant was tested.25 The brief introduction of these TVPs developed in our group are summarized in Table S1 in the supporting information. Nevertheless, there is still lack of the direct comparison of the TVP against commonly-used PAM polymer with closer molecular weight; in particular, no studies were devoted on their thermal stability, transportation and oil recovery efficiency under simulated severe conditions of oil reservoirs. Therefore, in the present work, the rheological behaviors, thermal stability, and core flooding feasibility of TVP were studied in comparison with PAM to discover its potential in oil recovery. 2. EXPERIMENTAL SECTION 2.1. Materials. Both commercial PAM and pilot product TVP were kindly provided by Beijing Hengju Polymer Co., Ltd. The viscosity-averaged molecular weight of PAM and TVP is 1.20×107 g⋅mol−1 and 1.01×107 g⋅mol−1, respectively, estimated from the intrinsic viscosity [η] with the Mark-Houwink equation [η] = 9.33×10−3 M0.75.26,27 By comparing the ratio of the integrated characteristic peaks listed in

13

C NMR spectra (Figure 1),21 one can get the mole

percentage of MPAD in the TVP copolymer is 9%, and also no hydrolysis was found in both polymers by

13

C NMR spectroscopy.

13

C NMR spectra of both PAM and TVP with


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concentration of around 0.03 mg·µL–1 were recorded on an 800 MHz Bruker spectrometer in D2O at 25 °C under 4,000 scans.

Figure 1. 13C NMR spectra of (A) PAM and (B) TVP. The salts including NaCl, CaCl2 and MgCl2 and antioxidant thiourea are all analytical grade and purchased from Chengdu Kelong Chemical Reagents Corporation, China. The deionized water (conductivity, κ = 7.9 µS·cm–1) used was treated by the ultrapure water purification system (CDUPT-Ш, Chengdu Ultrapure Technology Co., Ltd., China). 2.2. Sample preparation. Different amount of salts were dissolved in deionized water to prepare a series of brines with designated salinity. Then designed amount of dry polymer powders were added slowly to the brine with gentle magnetic stirring to avoid the formation of “fish eye” and mechanical degradation of the long chain molecules. After the powders dissolved in 2 h, it was followed by stirring hermetically for 1 day prior to tests. 2.3. Rheological measurements. All the rheological experiments were made on a Physica MCR 302 (Anton Paar, Austria) rotational rheometer equipped with a Searle-type concentric cylinder geometry CC27. The radii of the measuring bob and the measuring cup are 13.33 and


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14.46 mm, respectively. Samples were waited to get equilibrium at 20 °C for about 10 min before measurements, then steady shear viscosity was recorded during temperature scans going from 20 to 90 °C (heating rate = 2 °C⋅min−1) at fixed shear rate ( γ& = 10 s–1). The temperature was controlled by a Peltier system that provides fast and precise adjustment of the temperature during heating. Besides, a solvent trap was used to prevent evaporation of the solvents during measurement.

2.4. Thermal stability monitoring. 0.2wt% polymer solutions were prepared in brines with 10wt% NaCl and 0.1wt% CaCl2 (TDS: 101,000 mg⋅L−1). Then 0.05wt% of thiourea acting as the antioxidant was added to the homogeneous solution with stirring for 2 h. The well-dissolved sample solutions of TVP and PAM were distributed into a series of 50-mL glass bottles and then sealed with covers. All of these polymer solutions were divided into two groups aged at 45 °C and 85 °C, respectively. Every consecutive time interval, one of the sample bottles among each group was taken out for viscosity monitoring with the MCR rheometer mentioned above.

2.5. Core flooding tests. 2.5.1 Preparation of Core Test. The standard Berea cores with length (l), width (w), and height (h) of 30.5 cm, 4.6 cm, 4.6cm, respectively were dried at 80 °C for 24 h after which their weights and sizes were measured. The cores were saturated with synthetic brine under vacuum to obtain the pore volume (PV) through dividing the weight difference between water-saturated and dry core by the brine density, and the porosity ( φ ) was calculated as the ratio of the pore volume to the volume of the core. Then brine was injected with three different flow rates (10 mL⋅min−1, 6 mL⋅min−1, 2 mL⋅min−1) during which the pressure drop was recorded and brine permeability (ke) under each flow rate was calculated according to the Darcy’s law. The ultimate permeability of the core was averaged by the values got form different injection rates. In the experiments, the porosity and permeability of the cores were approximately


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20% and 200 mD, respectively. The core properties are given in Table 1 below.

Table 1 The Physical Properties of the Berea Cores Used in This Work Core No. l (cm) w (cm) h (cm) PV (mL) φ (%)

ke (mD)

1

30.53 4.57

4.58

132

20.6

195

2

30.51 4.59

4.58

127

19.8

161

3

30.49 4.62

4.63

131

20.1

197

4

30.53 4.57

4.59

126

19.7

142

5

30.52 4.63

4.58

135

20.8

217

6

30.49 4.61

4.62

126

19.4

203

7

30.50 4.59

4.61

122

18.9

140

8

30.52 4.61

4.60

129

19.9

182

2.5.2 Injectivity Test. The core saturated with brine initially was injected with brine, polymer solution and brine in sequence at a constant rate of 2 mL⋅min−1. Each displacing slug was injected into the core until the flooding pressure stabilized. The tests were run at 45 °C and 85 °C separately for every polymer solution and the pressures were recorded by a data terminal. The resistance factor (RF) and residual resistance factor (RRF) were calculated from the pressure drop between different slugs. RF is the ratio between the pressure drop during polymer displacing and water flooding respectively which is a measure for the mobility reduction or the flow resistance of the polymer solution in the porous media, while RRF represents permeability reduction in the reservoir rocks which is determined by the ratio of differential pressure during


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water flooding after polymer injection and the corresponding pressure before polymer injection. The RF and RRF were defined as:28 RF =

( ∆P ) p ( ∆P ) wb

RRF =

(1)

( ∆P ) wa ( ∆P ) wb

(2)

where (∆P)p, (∆P)wb, and (∆P)wa refer to the pressure drop during polymer flooding, water flooding before polymer injection, and water flooding after polymer injection, respectively. 2.5.3 Flooding Test. The cores were initially saturated with brine under vacuum, followed by

injecting the mixed crude oil to set the initial oil saturation until the water cut was less than 2.0%. The viscosity of the mixed crude oil at 45 and 85 °C was 8.2 and 3.6 mPa·s, respectively. Water flooding was first carried out until the water cut of the produced fluid reached 98%, then polymer flooding was conducted with injecting 1.0 PV displacement plug, and an post water-flooding was carried out until the oil production became negligible. During the flooding process, the injection rate of the displacing fluids was controlled at 2 mL⋅min−1 and the tests were run at at 45 °C and 85 °C for each polymer solution, respectively. The incremental oil recovery by polymer slug injection and the post water-flooding was used to evaluate the efficiency of these systems. The pressure drop across the core during the flooding was also monitored. All polymer solutions used in the tests had the concentration of 0.2wt% and the TDS of brine was101,000 mg⋅L−1.

3. RESULTS AND DISCUSSION 3.1. Rheological behaviors of polymer solutions. Rheological behavior is one of the most important criteria of an injected chasing fluid during the chemical flooding process. In polymer flooding operation, an optimal viscosity of the displacing fluid is required to ensure a favorable 10 ACS Paragon Plus Environment

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mobility in order to achieve a better recovery with good injectivity and low cost.29 Thus, the viscosity variation of polymer solutions was compared by examining the influence of polymer concentration, brine composition and other factors. 3.1.1. Concentration dependence of TVP. Compared in Figure 2 are the viscosity variation of

PAM and TVP with temperature in 5wt% NaCl brine for polymer concentration (Cp) between 0.1wt% and 1.0wt%. As can be seen, the viscosity of both polymer solutions is almost the same at the starting temperature 20 °C. As depicted in Figure 2A, however, PAM aqueous solutions exhibit the thermothinning behavior in all concentrations as most water-soluble polymers do, with a general trend following the Arrhenius law (see Figure S1 in Supporting Information).30 On the contrary, when Cp of TVP is higher than 0.35wt% (Figure 2B), the viscosity first decreases with increasing temperature, then keeps constant, and finally increases, which is mainly aroused by the hydrophobic association among the thermosensitive grafts contributing to the formation of elastic 3D network. The dynamic oscillatory data presented in Figure S2 in the supporting information also verified this hypothesis. Consequently, a relatively high viscosity is remained at high temperature of 90 °C. Besides, the Tass decreases upon increasing polymer concentration. For example, Tass

decreases from 71 °C to 55 °C when changing the polymer concentration from 0.4wt% to 1.0wt%. Such phenomenon was also observed by Hourdet team on a series of aqueous solution from copolymer of acrylic acid and N-isopropyl acrylamide.31 They ascribed the association mechanism as a subtle equilibrium between electrostatic repulsion and hydrophobic attraction. With increasing this copolymer concentration, higher ionic strength can be obtained from more negative carboxylate charges along the backbone which favors the inter-chain association;


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simultaneously, the total number of elastically active chains in the 3D network is enlarged contributing to the thickening effect. In this work, hydrophobic attraction is the prominent effect to the viscosity of TVP for its original nonionic character, though slight hydrolysis may occur during the temperature ascending process as the temperature hysteresis curves show in Figure S3 in the supporting information. So such a thermoviscosifying behavior of TVP aqueous solutions is closely related to the total number of physical crosslinks aggregated by the thermosensitive sidechains which are proportional to the polymer concentration. The higher the polymer concentration is, the more the hydrophobic microdomains will be formed. Consequently, the thermoviscosifying ability of TVP will be strengthened.19,32

Figure 2. Apparent viscosity plotted as a function of temperature for (A) PAM and (B) TVP at different polymer concentrations in 5wt% NaCl brine ( γ& = 10 s−1).

3.1.2. Effect of salt on thermoviscosifying behavior. It is well recognized that inorganic ions

perform as either “structure makers” or “structure breakers”,22,33 decreasing or increasing LCST of thermo-responsive polymers in aqueous media.34,35 Na+, Ca2+, and Mg2+, the three common 12 ACS Paragon Plus Environment

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cations existing in the oil reservoirs, are generally considered as the “structure makers”, strengthen the water structure around the ions, while reduce the hydration shell volume of the polymer chains, making them more hydrophobic, therefore promote the hydrophobic association among polymer chains.33 Similarly, they may play a crucial role on influencing the thermo-association behavior of the TVP in this work. Figure 3 shows the parallel rheological results of NaCl influence on both PAM and TVP aqueous solutions between 20 °C and 90 °C. One can see obviously the viscosity of TVP or PAM solution in NaCl brine is significantly lower than that in pure water due to the contraction of the polymer coils caused by the dehydration of backbone chains in the presence of Na+. The viscosity of PAM solution decreases smoothly upon increasing temperature in both pure water and all concentrations of NaCl brine (Figure 3A), while TVP solution shows a thermoviscosifying behavior as the concentration of NaCl is beyond 5wt% (Figure 3B). Furthermore, when increasing NaCl concentration from 5wt% to 15wt%, the Tass of TVP solutions decreases from 61 °C to 21 °C. In addition, what shouldn’t be ignored is that the viscosity of TVP solution with addition of 5wt% NaCl first decreases, then keeps at a constant value when temperature is over 60 °C, stopping its further decreasing. Such an interesting salt-induced thickening behavior should be attributed to the “hydrophobic effect” aroused by Na+, the “structure maker” which destroys the hydration sheath of polymer and makes it more hydrophobic. On the one hand, the “hydrophobic effect” shrinks TVP coils, thus decreasing the apparent viscosity; on the other hand, this effect promotes a stronger tendency of hydrophobic aggregation among thermosensitive sidechains, developing a 3D network in the solution which results in the increase of viscosity.36 In short, the thermoviscosifying ability of TVP mainly depends on the competition of these two opposite 13 ACS Paragon Plus Environment

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effects of polymer chains, when these two effects get balanced, the viscosity would keep constant just as the TVP solution with 5wt% NaCl shows; and when the stretch of the hydrophobic aggregations becomes the dominant motion with increasing temperature, the viscosity enhancement will be observed. It is also generally considered that the addition of salt increases the polarity of aqueous solution followed by a decrease of association energy among sidechains, rendering the thermoassociation to proceed easily, as indicated by the drop of Tass.35,36

Figure 3. Apparent viscosity plotted as a function of temperature for (A) PAM and (B) TVP aqueous solution in different NaCl solutions (Cp = 0.5wt%, γ& = 10 s−1). The existence of divalent cations like Ca2+ and Mg2+ increases the hardness of the formation brine which makes a great difference on the viscosifying efficacy of the polymer in EOR. Several studies show that the viscosity of HPAM is affected substantially by divalent ions which is mainly owing to the strong binding between the carboxylate groups and the divalent ions.37 But it is still unknown for this nonionic TVP what will happen when the brine contains CaCl2 or MgCl2. Depicted in Figure 4 is variation in viscosity of TVP solutions with temperature in 5wt% 14 ACS Paragon Plus Environment

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NaCl brine containing different concentrations of CaCl2 or MgCl2. It is clear that the addition of CaCl2 or MgCl2 does not weaken the thermoviscosifying power of TVP, while instead, they do enhance the thermothickening ability to some extent. For instance, viscosity of TVP solution increases nearly 26 mPa·s in the NaCl brine containing 1wt% CaCl2 and 11 mPa·s containing 1wt% MgCl2 between Tass and 90 °C, while viscosity in NaCl brine without divalent ions increases only around 5 mPa·s in the same temperature range. Additionally, the viscosifying magnitude increases and Tass decreases when increasing the amount of divalent ions. For example, when increasing the CaCl2 concentration from 0 to 0.25wt%, 0.5wt%, 0.75wt%, and 1.0wt%, viscosity increment between Tass and 90 °C raises from 5.1 mPa·s to 9.7, 10.2, 16.3 and 26.3 mPa·s, respectively; meanwhile, Tass is shifted from 77 °C to 70, 62, 57 and 54 °C accordingly. As described earlier, the thermoviscosifying ability of TVP in brine mainly depends on the competition between the collapse of the main chains and the stretch of the side chains. There is no exception for the solution containing Ca2+ and Mg2+ which are also classified as “structure-making ions” just as Na+ with positive viscosity B-coefficient, the parameter in the Jones-Dole equation38 used to describe the interaction of solute ions and solvent. Generally, positive B-coefficient values are for the structure-making ions and negative ones are for the structure-breaking ions and the B values for Na+, Ca2+, and Mg2+ are 0.085, 0.298, and 0.385 mol−1, respectively.39 It is grateful to see that the thermoviscosifying ability of this TVP can be strengthened in the presence of divalent ions, suggesting that the TVP may maintain a relative high viscosity when encountering the formation brine with high hardness.


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Figure 4. Apparent viscosity plotted as a function of temperature for TVP aqueous solution in different concentration of (A) CaCl2 solutions and (B) MgCl2 solutions (Cp = 0.5wt%, CNaCl = 5wt%, γ& = 10 s−1).

3.1.3. Thermoviscosifying behavior under high salinity. As discussed above, both polymer and

salt concentration can facilitate the thermoviscosifying process within a certain range, i.e., viscosity of displacing fluid can be increased by increasing either TVP concentration or salinity. But, high viscosity is not always desirable in flooding process owing to high cost and poor injectivity. So in the premise of desirable oil recovery factor, a relatively low concentration of polymer is required. For this purpose, the rheological behavior of a series of TVP and PAM aqueous solutions with relatively low polymer concentration were examined comparatively under high salinity. As shown in Figure 5, the viscosity of polymer solutions with concentration of 0.1wt%, 0.15wt%, and 0.2wt% was plotted as a function of temperature in different NaCl solutions ranging from 5wt% to 15wt%. Apparently, all the PAM solutions show a monotonic decrease in viscosity with 16 ACS Paragon Plus Environment

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increasing temperature. As for the TVP solutions, thermoviscosifying phenomenon can still be observed when increasing NaCl concentration to over 10wt%. Moreover, it is found that the lower the polymer concentration, the higher NaCl concentration is needed to get thermoviscosifying response. For example, when fixing Cp at 0.2wt%, the viscosifying behavior can be seen in 10wt% NaCl solution with viscosity increasing to 18.4 mPa·s at 90 °C even higher than the initial viscosity at 20 °C (14.4 mPa·s). However, there is an obvious drop of viscosifying effect when it comes to Cp of 0.15wt% in the same NaCl brine which proves again the polymer concentration dependence of thermoviscosifying ability aforementioned. Particularly, the viscosifying effect is not observed until the concentration of NaCl reaches 15wt% for 0.1wt% TVP solution. All the findings verified again the hypothesis that the viscosifying behavior of TVP solution would happen only when there were enough hydrophobic aggregations which facilitate the formation of the dynamic network. Under the condition of appropriate salt and polymer concentration, once the extension of polymer chains overwhelms the collapse with increasing temperature, the solution viscosity will ascend.


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Figure 5. Apparent viscosity plotted as a function of temperature and polymer concentration for (A) PAM and (B) TVP in different NaCl brines ( γ& = 10 s−1).

Furthermore, we investigated the viscosity of both TVP and PAM aqueous solutions under more realistic oil reservoir conditions where both monovalent and divalent cations exist. As displayed in Figure 6, in the presence of 10wt% NaCl and 0.1wt% CaCl2, the apparent viscosity of both 0.2wt% and 0.15wt% PAM solutions decreases from 14.5 and 8.0 mPa⋅s to 5.2 and 2.8 mPa⋅s when increasing temperature from 20 °C to 90 °C, with viscosity loss of 64% and 65%. By contrast, under the same condition, the apparent viscosity of both 0.2wt% and 0.15wt% TVP solutions varies from 12.1 and 8.2 mPa⋅s to 15.3 and 6.5 mPa⋅s, with viscosity retention as high as 126% and 79%, respectively, indicative of great potential in polymer flooding under hostile environment.


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Figure 6. Apparent viscosity plotted as a function of temperature for 0.2wt% and 0.15wt% PAM and TVP solutions under high salinity environment (CNaCl = 10wt%, CCaCl2 = 0.1wt%, γ& = 10 s−1).

3.2. Thermal stability of the TVP aqueous solutions. Since polymer flooding is a long-term process which may last for several months or years, the degradation of polymers used for EOR cannot be avoided especially in high-temperature and high-salinity oil reservoirs which results in viscosity decay. A good polymer candidature for EOR should not only have suitable viscosity and good compatibility with reservoir brine, but also keep thermal stability over time. The remaining viscosity after aging is generally regarded as a primary criterion for any chemicals to be used in EOR,40 thus the laboratory thermal stability data of polymer is necessary and important in designing a polymer flooding process. Presented in Figure 7 is the viscosity change of TVP and PAM aging in the synthetic brine containing antioxidant thiourea at 45 °C or 85 °C, the temperature of typical reservoirs in Daqing and Shengli Oilfields, China, respectively. Clearly, the apparent viscosity of PAM solution decreases from 10.0 and 5.9 mPa·s to 9.6 and 2.8 mPa·s after 30 days of aging at 45 °C and 85 19 ACS Paragon Plus Environment

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°C, respectively, with viscosity retention of 96.0% and 47.5%. Comparatively, one can find a

sharp reduction in viscosity for TVP in the first 10 days at both 45 °C and 85 °C, and then the viscosity drops very slowly until it maintains a constant value in the last 5 days. After a month of aging at 45 °C and 85 °C, the viscosity of TVP drops from 12.3 and 21.0 mPa·s to 10.0 and 5.4 mPa·s, with viscosity retention percentage of 81.3% and 25.7%. The results show that both PAM and TVP maintained their viscosity at a relative high level when aging at 45 °C, but undertook a big loss when aging at 85 °C even under the protection of antioxidant which can prevent them from the attack of radicals. The remarkable viscosity decay of both polymers at this high temperature may be attributed to the thermal degradation during aging period. It is generally accepted that the amide groups along PAM chains will undergo extensive hydrolysis into carboxylic units when the temperature is higher than 80 °C,12 and the presence of mono- and divalent ions could largely shield the mutual repulsion among the negatively charged hydrolyzed carboxylate units, bringing about the collapse of polymer coils, even the flocculation could happen. Consequently, the severe viscosity drop will be observed where there is no exception for the TVP which also bears the acrylamide mainchain. Based on this fact, both two polymers seem to be more suitable for applying in the reservoirs of relative low temperature, whereas more effective measures should be developed to improve their thermal stability in order to promote their applications in reservoirs of high temperature. However, what should be pointed out is that the viscosity of TVP is always higher than that of PAM during the aging period, though the viscosity retention is a bit lower. Besides, the remained viscosity goes to a constant value which is still capable of polymer flooding, implying its possibility to be used in EOR process.


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Figure 7. Apparent viscosity plotted as a function of aging time for PAM and TVP in synthetic brine (Cp = 0.2wt%, CNaCl = 10wt%, CCaCl2 = 0.1wt%, Cthiourea = 0.05wt%, γ& = 10 s−1). Both the aging and measuring temperature is (A) 45 °C and (B) 85 °C, respectively.

3.3. Core flooding. From the basic properties described above, TVP outperforms PAM at high temperature and high salinity with respect to thickening power and thermal stability. Besides, the shear flow behavior was also measured at higher shear rates for each polymer (see Figure S4 in supporting information), which suggests that TVP would keep relatively good viscosity when exposed to the high shear rates near the wellbore. In spite of the excellent properties of TVP exhibiting in such harsh conditions, no core flooding test so far has been performed with this kind of polymer. Here we explored the flooding behaviors of TVP and PAM comparatively in the same salinity brine as the aging test through the simulate oil displacement tests at 45 °C and 85 °C, respectively. In regarding to oil displacement in reservoirs, the primary concern is that if the polymer solution can be smoothly propagated in porous media. Thus, we first evaluated the resistance


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factors (RF) and residual resistance factors (RRF) of both polymer solutions through the injectivity test at 45 °C and 85 °C, respectively. The calculated values of RF and RRF are presented in Table 2 (the calculation details are specified in Table S2 in the Supporting Information), and the flooding pressure plotted as a function of injected pore volume of TVP or PAM at 45 °C and 85 °C is exhibited in Figure 8. Obviously, both RF and RRF values of TVP solution are higher its PAM counterpart at both 45 °C and 85 °C. The higher RF value of TVP is mainly resulted from for two reasons: first, the polymer aggregates formed at high temperature and high salinity increase the viscosity of chasing fluid dramatically, thus its propagation through the porous media is slowed down and much higher flooding pressure is needed; second, polymer retention may happen because of adsorption or mechanical entrapment,41 building flow resistance in watered-out zones and diverting the subsequently injected fluid to poorly swept zones,42 which means higher sweep efficiency is obtained along with the higher pressure. The polymer retention is also the main factor to affect the RRF value because aggregates with high hydrodynamic volumes will be trapped or absorbed by porous media more easily, plugging the pores and reducing core permeability. This phenomenon taken together with the enhanced viscosity could contribute to the higher RRF values than those of PAM. The higher RF and RRF values usually suggest a greater improvement of sweep efficiency which is preferable for the enhancement of polymer flooding efficiency. But, too high of these two values are not always desired as core-plugging and injection difficulty in the flooding process may occur. To test if the TVP or PAM displacing fluid could be smoothly propagated through the porous media, the adsorbed polymer layer thickness, e, was calculated according to equations (3) and


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(4),43 where rp represents the average pore radius for water flow, ke and φ is the effective permeability and porosity of the core, respectively. 1/ 2

r p = ( 8 ke / φ )

(3)

e = rp (1 − 1 / RRF 1/4 )

(4)

For better comparison, the reduction rate of pore radius e

rp

was calculated to evaluate the

retention extent of polymers. As shown in Table 2, more than half the pore throats remain open for fluid flow after adsorption which means that no physical plugging was observed after the core flooding for both polymer solutions, and it also can be verified by the drops of flooding pressure when post water was injected (Figure 8). Moreover, the adsorbed polymer layer of TVP is thicker than PAM at both 45 °C and 85 °C, and the e

rp

value is 8.7% and 19.7% higher than

its counterpart, respectively. This phenomenon testifies again the higher permeability reduction of TVP over PAM especially at high temperature of 85 °C, when the viscosity of TVP is far higher than PAM for its good temperature and salinity tolerance.

Table 2 Comparative Flowing Behaviors of PAM and TVP in Porous Media

Core No. Sample T (°C) φ (%)

ke (mD)

RF

RRF rp (µm) e (µm)

e (%) rp

1

PAM

45

20.6

195

13.7

8.33

2.75

1.13

41.1

2

TVP

45

19.8

161

19.7

15.7

2.55

1.27

49.8

3

PAM

85

20.1

197

6.00

4.33

2.80

0.86

30.7

4

TVP

85

19.7

142

19.3

16.8

2.40

1.21

50.4


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Figure 8. Flooding pressure plotted as a function of injected pore volume at (A) 45 °C and (B) 85 °C for PAM and TVP, respectively (Cp = 0.2wt%; TDS = 101,000 mg·L−1; injected rate = 2

mL⋅min−1). Since both polymer solutions can smoothly pass through the core porous media, further oil recovery experiments were conducted with such polymer solutions. Sweep efficiency, one of the most important issues in the oil recovery, is affected by many factors, among which the mobility


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ratio (M) is a crucial one. M is defined as the ratio of the displacing fluid (e.g. polymer solution) mobility to the displaced phase (e.g. crude oil) mobility:44

M=

λ p kp / η p = λ o ko / η o

(5)

where λp and λo refer to the mobility of polymer solution and oil, respectively; kp the effective polymer solution permeability at residual oil saturation, and ko is the effective oil permeability at interstitial water saturation; ηp and ηo denote the viscosity of polymer solution and oil, separately. It is generally accepted that the displacement of oil by polymer solution occurs in a piston-like fashion when the mobility ratio is less than or equal to 1, which is favorable for the good oil recovery. On this basis, the mobility ratios of polymer solutions and oil for TVP and PAM at 45 and 85 °C during the oil displacement test were calculated. As depicted in Table 3, the mobility ratios obtained for TVP and PAM at 45 and 85 °C are all far less than 1, suggesting both the polymer solutions can reach relatively good sweep efficiency in the flooding test. Furthermore, the viscosity ratios of oil and polymer solutions are all less than 1. It is worth noting that the viscosity ratio of oil and TVP is quite small at 85 °C because that the viscosity of oil decreases to only 3.6 mPa·s and meanwhile that of TVP increases to 13.6 mPa·s when increasing temperature. Such a difference in viscosity between oil and the polymer solution is believed to be favorable for the propagation of injected fluid when displacing oil. Besides the viscosity ratio of oil and PAM at 85 °C also remains lower than 1, though the viscosity of PAM decreases when increasing temperature. Hence the PAM solution also seems to be able to achieve the stable oil displacement at 85 °C to some extent.


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Table 3 Mobility of PAM and TVP Solutions

kp (mD) ko (mD) ηp (mPa·s)

ηo (mPa·s)

kp/ko

ηo/ηp

M

9.8

8.2

0.09

0.84

0.08

206

10.0

8.2

0.07

0.82

0.06

9.92

78.5

5.4

3.6

0.13

0.67

0.09

28.0

82.3

13.6

3.6

0.34

0.26

0.09

Sample

T (°C)

PAM

45

15.0

171

TVP

45

14.6

PAM

85

TVP

85

Particular attention will be given to their recovery factors. As depicted in Figure 9, at 45 °C, 16.4% and 12.0% of incremental oil could be recovered by TVP and PAM solutions over water flooding, and a good recovery of 15.5% still could be attained by TVP flooding, while only 9.20% of incremental oil was recovered by PAM at 85 °C. Such a big difference in recovery factor between TVP and PAM solutions is mainly associated with the excellent mobility control by TVP solution due to its high viscosity as well as good propagation exhibited in the simulated severe reservoir conditions. In addition, the recovery factors of the same polymer flooding at different temperatures are not compared for the lack of comparability, because both the oil and core properties changed with the temperature which was indicated by the different saturation volumes at 45 °C and 85 °C (Table 4). Through the core flooding tests, one can find that the TVP has the potential to be used as a candidate to replace PAM for EOR in the harsh reservoir conditions of high temperature and high salinity.


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Figure 9. Recovery factor and flooding pressure plotted as function of injected volume at (A) 45 °C and (B) 85 °C for PAM and TVP, respectively (Cp = 0.2wt%; TDS = 101,000 mg⋅L−1;

injected volume = 1.0 PV; injected rate = 2 mL⋅min−1).

Table 4 Summary of Recovery Factors of PAM and TVP

Core Sample T No.

φ

ke

Saturation

(°C) (%) (mD) oil volume

Water-flooding Polymer-flooding Total recovery recovery

recovery

(mL)

(%)

(%)

(%)

5

PAM 45 20.8

217

82.3

38.1

12.0

50.1

6

TVP 45 19.4

203

84.6

36.9

16.4

53.3

7

PAM 85 18.9

140

58.4

39.2

9.20

48.4

8

TVP 85 19.9

182

46.6

32.2

15.5

47.7


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4. CONCLUSIONS Rheological behaviors, thermal stability, and core flooding feasibility were comparatively studied for PAM and TVP aqueous solutions. In the rheological measurements, polymer concentration dependence and influence of salts on the viscosity were discussed. For the thermal stability, remaining viscosity was monitored continuously for one month aging at 45 °C and 85 °C, respectively, and the viscosity retention of TVP was compared with that of PAM. At last,

core flooding test was conducted in the simulated reservoir environment of high salinity at 45 °C and 85 °C, respectively, during which the transportation and flooding efficiency were examined comparatively for TVP and PAM. Based on the results obtained, the TVP solution shows a thermoviscosifying phenomenon and possesses a higher viscosity in severe conditions of high temperature and high salinity compared to PAM, even in much higher salinity brines with

TDS of 101,000 mg·L−1. Despite the

viscosity retention of TVP is lower than those of PAM both at 45 °C and 85 °C, the remaining viscosity of TVP solution is still higher than that of PAM after aging for one month, which is still capable of polymer flooding. Both the TVP and PAM solution can be smoothly propagated in porous media. TVP with higher RF and RRF values indicates a better sweep efficiency and excellent mobility control ability in the core flooding process, which contributes to a higher oil recovery of 16.4% and 15.5% at 45 °C and 85 °C, respectively, while those of PAM are only 12.0% and 9.20%. Despite the high performance of TVP in the high-temperature and high-salinity environment, there are still some problems to be resolved before putting into practice. For example, longer term of aging test for TVP is necessary because the flooding process usually lasts for several months or years, and the viscosity loss should be minimized by screening the proper antioxidants. 28 ACS Paragon Plus Environment

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Besides, more core flooding studies should be performed on this polymer with regard to its injectivity, propagation, retention, and recovery factor.

ASSOCIATED CONTENT Supporting Information. Differences of TVP polymers developed in Feng’s Team, Arrhenius equation fitting, dynamic rheology, temperature hysteresis, steady-shear rheology, calculation of RF and RRF values.

AUTHOR INFORMATION Corresponding Author *Email: [email protected]. Tel./Fax: +86-28-8540-8037.

Notes The authors declare no conflict of interest.

ACKNOWLEDGMENT The authors are grateful to the financial support by the opening fund from the State Key Laboratory of Polymer Materials Engineering (sklpme2014-2-06), and the Opening Project of Oil & Gas Field Applied Chemistry Key Laboratory of Sichuan Province (YQKF201403).

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