A polymer flooding mechanism for mature oil fields: Laboratory measurements and field results interpretation

Accepted Manuscript A polymer flooding mechanism for mature oil fields: Laboratory measurements and field results interpretation Ivonete P.G. Silva, Amaury A. Aguiar, Viviane P. Rezende, Andre L.M. Monsores, Elizabete F. Lucas PII:

S0920-4105(17)30964-6

DOI:

10.1016/j.petrol.2017.12.008

Reference:

PETROL 4498

To appear in:

Journal of Petroleum Science and Engineering

Received Date: 29 August 2017 Revised Date:

6 November 2017

Accepted Date: 4 December 2017

Please cite this article as: Silva, I.P.G., Aguiar, A.A., Rezende, V.P., Monsores, A.L.M., Lucas, E.F., A polymer flooding mechanism for mature oil fields: Laboratory measurements and field results interpretation, Journal of Petroleum Science and Engineering (2018), doi: 10.1016/j.petrol.2017.12.008. This is a PDF file of an unedited manuscript that has been accepted for publication. As a service to our customers we are providing this early version of the manuscript. The manuscript will undergo copyediting, typesetting, and review of the resulting proof before it is published in its final form. Please note that during the production process errors may be discovered which could affect the content, and all legal disclaimers that apply to the journal pertain.

AC C

EP

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

ACCEPTED MANUSCRIPT

A polymer flooding mechanism for mature oil fields: laboratory measurements and

2

field results interpretation

3

Ivonete P. G. Silva1, Amaury A. Aguiar2, Viviane P. Rezende3, Andre L. M. Monsores2, Elizabete F.

4

Lucas1,4* 1

Universidade Federal do Rio de Janeiro, Instituto de Macromoléculas/LMCP, Av. Horácio Macedo, 2030, block J, 21941598, Rio de Janeiro, Brazil [email protected], [email protected]

6

2

7 3

Instituto Federal do Rio de Janeiro, Av. República do Paraguai, 120, Duque de Caxias - RJ, 25050-

SC

8

100, Rio de Janeiro, Brazil, [email protected]

9 10

Free Consultants - [email protected], [email protected]

4

M AN U

5

RI PT

1

Universidade Federal do Rio de Janeiro, COPPE/PEMM/LADPOL, Av. Horácio Macedo, 2030, block F, 21941972, Rio de Janeiro, Brazil, [email protected]

11

13

AC C

EP

TE D

12

14

Abstract

15

Although polymer flooding has been widely studied in the literature on oil recovery, many questions

16

remain about the technique’s action mechanisms. It is widely accepted that the process is based on

17

increasing viscosity of the aqueous phase (injected fluid). The polymer can also act secondarily by

18

reducing the relative permeability to water. Fields that are markedly heterogeneous, highly depleted

19

or that contain fluids with strong salinity are not good candidates for the process. To overcome these

20

restrictions, the most recent applications have used more resistant polymers, with higher molar 1

ACCEPTED MANUSCRIPT masses, injected in larger quantities, to preserve the level of viscosity under these adverse conditions.

22

However, a pilot test in a field under adverse conditions showed surprising results and unexpected

23

pressure abnormality, even with small quantities of partially hydrolyzed polyacrylamide (HPAM)

24

with relatively low molar mass (6 x 106 g/mol). This paper reports the investigation of the prevailing

25

mechanism responsible for these unexpected results, by means of laboratory tests of flow in porous

26

media and rheological analysis of fluids and hydrodynamic diameter of polymer molecules. The Salt

27

effect (NaCl) on polymer solutions was researched by rheology and particle size analysis at 25 and

28

50°C. The results showed that mechanical/hydrodynamic retention prevails over polymer adsorption

29

at the rock, with the former being caused by the increase in the polymeric hydrodynamic volume in

30

fluid dilution processes. Besides this, increased temperature was found to favor greater

31

hydrodynamic volume under tested conditions, while salinity had little influence. The results also

32

shed new light on the flow behavior of polymer solutions in porous media, particularly in polymer

33

injection for enhanced oil recovery from mature fields.

M AN U

SC

RI PT

21

Keywords: Enhanced oil recovery; polymer flooding; mobility; rheology; particle size.

36 37

1. Introduction

EP

35

TE D

34

Most current world oil production comes from mature fields by water flooding (Alvarado and

39

Manrique, 2010; Lopes et al, 2014). The amount of water that circulates (injected and produced) in

40

the reservoir hugely increases over time, until reaching water/oil ratios that make further extraction

41

unprofitable (Bailey et al, 2000). In heterogeneous rock formations, or when the water/oil mobility

42

ratio is unfavorable, water preferentially flows through the more permeable formation zones, causing

43

low sweep efficiency and premature water breakthrough. Polymers (in association or not with other

44

substances) have been frequently used to increase the areal and vertical sweep efficiency, by

45

correcting the mobility ratio (M), a process known as polymer flooding, or with use the conformance

AC C

38

2

ACCEPTED MANUSCRIPT 46

control agents (Chauveteau et at., 1974; 1982; 1984; Needham and Doe, 1987; Delshad et al, 1998;

47

Caili et al., 2010; Lyons, 2010; Zou et al., 2013; Abdulbaki, 2014; Lucas et al., 2015; Xie et al.,

48

2015; Xie et al., 2016; Li et al., 2017). The most commonly used mobility correction technique is polymer solution injection, known as

50

polymer flooding. This process consists of addition of polymers with high thickening potential in the

51

injection water (Lake, 1989; Lucas et al., 2015). The polymer increases the aqueous phase viscosity

52

promoting the mobility ratio reduction and increasing the sweep efficiency. Additionally, depending

53

on the polymer type, the permeability to water in the zones swept by the polymer can be reduced

54

(Sorbie, 1991; Du and Guan, 2004; Lake and Wash, 2008; Sandegen et al., 2017). This permeability

55

reduction can have a favorable additional secondary effect, by sealing the formation and restoring

56

part of the pressure of the highly permeable zones through which the polymer preferably flows in

57

heterogeneous reservoirs. The effect of these two mechanisms, which generate so-called resistance

58

and residual resistance factors, combines with the effect of increased viscosity of the injection water

59

to reduce the mobility ratio of the water-oil displacement even more, and consequently raises the

60

recovery factor. These are the fundamental mechanisms widely accepted. Others mechanisms have

61

been proposed to explain the macroscopic and microscopic effects of polymer flooding process.

62

They are detailed in Wei (2014) review.

EP

TE D

M AN U

SC

RI PT

49

Since the most accepted principle behind the polymer flooding process is the increase of viscosity

64

of the mobile aqueous phase, maintenance of viscosity while the polymer fluid propagates in the

65

reservoir is the key parameter to ascertain the effectiveness of the process (Sheng, 2011; Chang,

66

1987; Sorbie, 1991; Choi et al., 2014). The polymer most often used in these processes is

67

polyacrylamide (Zou et al., 2013; Wever et al., 2011, 2013; Li et al., 2017; Sharma et al., 2016)

AC C

63

68

Polyacrylamide is a water-soluble polymer that has many applications, alone or associated with

69

other polymers or surfactants (Sadicoff et al., 2000; Chagas et al., 2004; Kaggwa et al., 2005; Fan et

70

al., 2014; Silveira et al., 2015; Sharma et al., 2016; Kan et al., 2016; Reis et al, 2016a,b).

3

ACCEPTED MANUSCRIPT Polyacrylamide can also undergo partial hydrolysis, generating a copolymer composed of acrylamide

72

and acrylic acid, called partially hydrolyzed polyacrylamide (HPAM). This structure can also

73

obtained by copolymerizing acrylamide and acrylic acid. HPAM is a polymer with strong thickening

74

potential in fresh water, but it degrades and loses stability in adverse conditions of salinity, hardness

75

and temperature (Wever et al, 2011; Melo and Lucas, 2008; Silva et al., 2010). These conditions

76

require the use of larger amounts of polymers, more resistant polymers, or water that does not

77

contain ions damaging to the polymer (Pope, 2007; Chang et al., 2006). Sometimes a preflush has

78

been conducted (Algharaib and Alajmi, 2014), but it may not always work (Sheng et al., 2015). The

79

typical HPAM used in polymer flooding is a flexible synthetic polyelectrolyte with linear

80

architecture, high molar mass (5 x 106 to 40 x 106 g/mol) and controlled hydrolysis degree (15 to

81

40%), giving it high thickening potential. The permeability reduction attributed to polymeric

82

retention in the porous medium is the sum of the contributions of adsorption, mechanical and

83

hydrodynamics retentions (Chauveteau and Kohler, 1974; Maeker, 1973; Dawson and Lantz, 1972;

84

Oliveira et al., 2016). Mechanical retention is a similar mechanism to filtration that occurs when the

85

macromolecules are retained by the pore throat. In this mechanism, the dominant factor is the ratio

86

between the polymer hydrodynamic diameter and the pore throat diameter (Du et al, 2013). Some

87

researchers suggest that adsorption may be the dominant polymer retention mechanism in high-

88

permeability sands (Huh et al. 1990), while mechanical entrapment dominates in low-permeability

89

rock (Szabo 1975, 1979, Dominguez and Willhite 1977, Huh et al. 1990). In the first period of the

90

polymer flooding application history, permeability reduction was considered more significant than

91

the viscosity effects (Pye et al, 1964; Dauben and Menzie, 1967). The retention was attributed to the

92

high polymer molar mass and the dispersions were injected at the lowest concentration (about 250

93

mg/L) and total mass of 100 mg / VP (Chang et al., 2006; Seright, 2016).

AC C

EP

TE D

M AN U

SC

RI PT

71

94

The literature review has reported that the success rate for implementing polymer injection

95

projects in secondary mode was higher than when injecting polymer in tertiary mode (Chang, 1978;

4

ACCEPTED MANUSCRIPT Needham and Doe, 1987; Standness and Skjevrak, 2014). Tertiary polymer flood requires more

97

polymer per barrel of oil recovery (Needham and Doe, 1987). Since the 1990s, a performance

98

increase of the polymer flooding process in high water cut conditions has been reported and

99

associated with the use of higher concentration and higher injected total mass (about 600 mg/L.VP)

100

(Wang et al., 2001, 2009, 2013; Sheng, 2011). Such fluid characteristics can result in injectivity

101

decrease, depending on the reservoir and pressure-limited conditions (Du and Guan, 2004).

RI PT

96

However, good results were obtained in a Pilot tested under adverse conditions, using a small

103

injected total mass. The Pilot had very marked heterogeneity (Dykstra Parson > 0.97), heavy oil (22

104

°API), 200,000 mg/L of original salinity, and intense fingering due to high mobility ratio and

105

advanced stage of production (Melo et al, 2017; Silva et al., 2017). This study seeks to shed light on

106

the mechanisms involved in the process leading to that unexpected result, through laboratory

107

investigation involving flow tests in porous media, rheological analysis and evaluation of

108

hydrodynamic volume.

M AN U

SC

102

TE D

109

2. Materials and methods

111

2.1. Materials

112

Partially hydrolyzed polyacrylamide - HPAM (a random copolymer composed of 30% acrylate and

113

70% acrylamide monomers) was used in this study, with a nominal molar mass of 6 x 106 g/mol. This

114

polymer was supplied by SNF in powder form and 99% pure, trade name Flopaam 3230S. 99%

115

sodium chloride (NaCl) P.A. was supplied by Vetec Química Fina, Duque de Caxias, Brazil. The

116

softened injection water, from a Brazilian field, was supplied by Petrobras, with composition

117

described in Table 1.

118

2.2. Preparing the polymer dispersions

119

The polymer dispersions were prepared (Silva et al., 2010) at 25 ºC, in concentrations of 10 to 1000

120

mg/L in four distinct media: distilled and deionized water; water containing 500 mg/L of NaCl; brine

AC C

EP

110

5

ACCEPTED MANUSCRIPT 121

containing 38,000 mg/L of NaCl; and softened water (Table 1). The solutions were analyzed at 25° C

122

and 50°C, after resting periods of 24 hours, 7 days and 14 days. All the solutions were prepared with

123

initial dissolution of the HPAM in deionized water, after which the salt was added by dilution of the

124

HPAM solution with a saline solution. Table 1. Composition of softened injection water produced by a Brazilian petroleum field

RI PT

125 126

2.3. DLS measurements

128

Dynamic light scattering (DLS) measurements were performed with a Nano ZS Zetasizer (Malvern

129

Instruments, UK) with detection angle of 173°. The diffusion coefficients (D) of the HPAM solutions

130

were converted into hydrodynamic diameter (Dh) by using the Stokes-Einstein equation (Equation 1)

131

(Coviello et al., 1987; Rousseau et al., 2005; Kaszuba et al., 2008; Maia et al., 2011).

M AN U

SC

127

132

133

Equation 1

where k is the Boltzmann constant, T is the temperature, and η is the dispersant viscosity. For the hydrodynamic diameter analysis, the sample viscosities were measured with an A&D SV-

135

10 vibrational viscometer, as recommended by the Malvern Instruments Ltd Manual, since the

136

viscosity required for this measurement is that the particle being studied experiences as it undergoes

137

Brownian motion (Kaszuba et al, 2008). The measurements were performed at temperatures of 25 °C

138

and 50 °C. The Z-average (harmonic intensity averaged particle diameter) was calculated by the

139

device’s software from 14 automatic readings. Each analysis was performed in triplicate.

140

2.4. Rheological measurements

141

The dynamic viscosity of the polymer solutions was determined with an Anton Parr Physica MCR

142

501 rheometer with a 75 mm sensor. The specific viscosity (ηsp) was determined using Equation 2:

AC C

EP

TE D

134

143 144

ηsp = (η - ηs)⁄ηs

145

where η is the solution viscosity and ηs is the solvent viscosity. Graphs of reduced viscosity, ηsp⁄C, vs.

Equation 2

6

ACCEPTED MANUSCRIPT 146

concentration were plotted and three distinct regions were noted. The flow consistency and flow

147

behavior indices were obtained from the curves of deformation rate versus shear stress, fitted by a

148

power law model, represented by Equation 3: Equation 3

149

where τ is the shear stress; k is the consistency index, γ is the shear rate; and n is the behavior index

151

(Vidal et al., 2004). The results will be expressed in terms of consistency index (k), which is a

152

parameter that gives an idea of the viscosity of the fluid and it is not depend on the shearing.

153

2.5. Tests in porous media

154

The porous media tests were performed in natural samples from a Berea sandstone core and from the

155

Rio Bonito outcrop in Brazil (Table 2) . The tests were performed as described in the API RP 40

156

1998 standard (Melo and Lucas, 2008; Silva et al., 2010). These tests were correlated with tests in

157

Swagelok SS-2F-K4-15 sintered stainless steel filter elements (15 µm pore size), reported in Silva

158

and Lucas (2017) and field results of Carmópolis Pilot reported by Melo et al. (2005, 2017).

159

Polymer concentration from the effluent was measured as described in the API RP 63 1990

160

engineering standard.

161

TE D

M AN U

SC

RI PT

150

3. Results and discussion

163

3.1. Concentration regimes of the HPAM solutions determined by viscometry

164

The concentration regimes of the HPAM solutions were identified in the curves of consistency index

165

versus solution concentration. Figure 1 presents these curves for both HPAM in water and in saline

166

solution (500 mg/L of NaCl). Table 3 summarizes the values of overlapping concentration C*,

167

transition from dilute to semidilute regime (Al Hashmi et al., 2013) and C**, transition from

168

semidilute to concentrated regime (De Gennes, 1979), for the systems presented in Figure 1, as well

169

as for the HPAM in saline solution of 500 mg/L of NaCl, at 50 ºC. The concentrations indicating the

170

regime transitions were determined by the intersection of the linear fit of the respective concentration

AC C

EP

162

7

ACCEPTED MANUSCRIPT 171

ranges (Figure 1). For the HPAM dissolved in distilled water at 25 ºC, the transition from the dilute to the semidilute

173

regime (C*) occurred at 30 mg/L and the transition to the concentrated regime (C**) at 1,000 mg/L.

174

The salinity of 500 mg/L in the solvent of the HPAM dispersions shifted the critical concentration

175

C* from 30 to 70 mg/L.

RI PT

172

In the semidilute concentration range (C > C*), the consistency index of the saline solution (500

177

mg/L) of HPAM declined from 227 mPa.s to 26 mPa.s. The presence of sodium ions reduces the

178

repulsion force between the carboxyl units present in the HPAM molecules, possibly constraining

179

their dynamic volume and reducing the intermolecular entanglement, which displaces the transition

180

from the dilute to semidilute regime to higher concentrations. The consistency index of the HPAM

181

solutions at a concentration of 500 mg/L of NaCl was also analyzed at 50 °C. The temperature

182

increase shifted the critical concentration C* from 70 to 100 mg/L (Table 3). Therefore, the

183

consistency index analysis showed that the thickening potential of HPAM decreases with increasing

184

salinity and temperature, as observed by other authors who have determined the critical

185

concentrations from the variation of apparent viscosity and intrinsic viscosity in function of

186

concentration (Rousseau et al., 2005; Kaszuba et al., 2008).

M AN U

TE D

EP

187

SC

176

Figure 1. Consistency index in function of HPAM concentration in distilled water and in saline

189

solution (500 mg/L NaCl), at 25 ºC.

190 191

AC C

188

Table 3. Transitions of concentration regime for the HPAM solutions

192 193

3.2. Hydrodynamic volume of HPAM in solution determined by light scattering

194

Since the viscosity of polymer dispersions depends not only on the concentration, but also on the

195

hydrodynamic volume of the molecules in the solvent, we analyzed the hydrodynamic volume of the

8

ACCEPTED MANUSCRIPT 196

HPAM solutions. The influence of concentration, salinity and temperature on the hydrodynamic volume (in a wide

198

concentration range) was measured by dynamic light scattering (DLS). The DLS technique measures

199

the diffusion coefficients of molecules undergoing Brownian motion technique (Raphael and Pincus,

200

1992; Wernert et al., 2010, Maia et al., 2013). To convert the diffusion coefficient data into a

201

hydrodynamic size, the sample viscosity must be entered into Stokes-Einstein’s equation (Kaszuba et

202

al. 2008). As recommended in the Malvern Instrument UK, manual, the sample viscosities were

203

analyzed with a vibro viscometer, which simulates the shear of Brownian molecular motion. Thus, it

204

is possible to compensate for the diffusion coefficient restriction due to the high viscosity of

205

dispersions of polymers with high thickening potentials.

M AN U

SC

RI PT

197

Dispersions of polyacrylamide in the concentration range between 1 and 1,000 mg/L in distilled

207

water were analyzed at 25 ºC after preparation times of 1, 7 and 14 days. At higher HPAM

208

concentrations, “apparent hydrodynamic radius/diameter” would be better to express the results,

209

however, in this work, hydrodynamic radius/diameter will be used to express all results.

TE D

206

The data presented in Figure 2 show that the hydrodynamic radius: (i) was larger at the

211

concentrations of the dilute regime; (ii) increased with reduction of concentrations in the dilute

212

regime; (iii) varied between 60 and 700 nm in the concentration range analyzed (10 to 1,000 mg/L)

213

at temperature of 25 °C; and (iv) stabilized reasonably after 24 hours. The tendency for the

214

hydrodynamic radius to increase with reduction of the concentrations in the dilute regime is in

215

accordance with the findings of De Gennes (1976, 1979) for flexible macromolecules, as the case of

216

the HPAM analyzed. The order of magnitude of the hydrodynamic diameter corresponds to values

217

reported previously in the literature (Campbell and Backman, 1987; Rousseau et al, 2005).

AC C

EP

210

218 219

Figure 2. Particles sizes (Z-average) of HPAM in distilled water, at 25 ºC, in function of polymer

220

concentration and time to prepare the dispersion.

221 9

ACCEPTED MANUSCRIPT In an ideal system of a θ-solvent, in the dilute regime, the hydrodynamic radius dimensions

223

remain unchanged in relation to a hypothetical ideal system. For dispersions diluted in good solvents,

224

the hydrodynamic radius is enlarged (De Gennes, 1976; 1979; Graessley, 1980). This happens when

225

the polymer-solvent interaction is stronger than the polymer-polymer and solvent-solvent

226

interactions. The dimensions vary from one solvent to another, depending on the thermodynamic

227

features of the mixture. They contract with rising concentration due to the repulsions from the

228

volume excluded between segments of the same chain and segments of neighboring chains. At high

229

concentrations, the dimensions approach the unperturbed value (De Gennes, 1976, 1979; Graessley,

230

1980). In the HPAM analyzed here, a large difference between the hydrodynamic diameter of

231

dispersions with varied concentrations were observed, probably due to the relatively high hydrolysis

232

degree of the molecule (30 %), responsible for the affinity with the dispersant (water). The

233

hydrodynamic radius increase was greater at lower concentrations (dilute regime), probably because

234

the smaller the number of dispersed molecules: (i) the weaker the repulsion between the molecules

235

is; and (ii) the greater the hydration is, leading to a larger hydrodynamic diameter (De Gennes, 1976,

236

1979; Graessley, 1980). The polymer concentration curves presented in Figure 2 show an inflection

237

point at approximately 30 mg/L. This value is in line with the value found for the critical

238

concentration obtained in the dynamic viscosity studies (Figure 1 and Table 3).

EP

TE D

M AN U

SC

RI PT

222

The effect of salinity on the HPAM’s particle size was analyzed at concentrations of 10 and 1,000

240

mg/L of polymer in deionized water, with 0, 500 and 38,000 mg/L of salt, at 25 °C, and deionized

241

water with 500 mg/L of salt at 50 °C. The hydrodynamic diameters at 50 ºC were more stable than

242

those at 25 ºC. For this reason, we only performed further analysis of the system containing 500 mg/L

243

of salt at this temperature. The polymer concentrations were chosen to represent the dilute and

244

concentrated regimes, respectively. The salt concentrations were selected to represent the fresh water,

245

sometimes used in polymer dispersion preparation. Besides this, a softened injection water was also

246

analyzed (treated to remove divalent cations), resulting in the composition described in Table 1.

AC C

239

10

ACCEPTED MANUSCRIPT 247

The hydrodynamic diameter results are presented in Figure 3.

248 249

Figure 3. Hydrodynamic diameter of HPAM in different dispersion medium, at 25 e 50 ºC.

250

The dispersions of HPAM at concentration of 10 mg/L (dilute regime) had larger hydrodynamic

252

diameter than those at concentration of 1,000 mg/L (concentrated regime) under all the conditions

253

analyzed. The enlargement of the hydrodynamic diameter of flexible polyelectrolytes with dilution

254

of the dispersion occurs due to the increase of hydration (De Gennes, 1976, 1979; Graessley, 1980).

SC

RI PT

251

For both polymer concentration regimes, rising salinity caused a reduction of the hydrodynamic

256

diameter. This can be attributed to the shielding of the negative charges of the carboxylate groups of

257

the polyacrylamide by the cations present in the dispersion medium ((Nars-El-Din and Taylor, 1995).

258

At the concentration of 10 mg/L of HPAM (dilute regime), the salinity sharply reduced the

259

hydrodynamic diameter, from 770 nm (at 0 mg/L of NaCl) to 298 nm (at 500 mg/L of NaCl).

260

However, the further increase of salinity to 38,000 mg/L did not cause a significant reduction in the

261

hydrodynamic diameter, which fell to 289 nm.

TE D

M AN U

255

At the HPAM concentration of 1,000 mg/L (concentrated regime), the effect of salinity was not

263

substantial, with values of 56, 52 and 48 nm for the dispersant media distilled water, 500 mg/L of

264

NaCl and 38,000 mg/L of NaCl, respectively.

266

Therefore, the impact of salinity mainly occurs in the dilute regime of the HPAM concentration,

AC C

265

EP

262

and is relatively unimportant at higher salt concentrations.

267

The softened water, with 500 mg/L of TDS (total dissolved solids) and different chemical species

268

caused a slightly greater hydrodynamic diameter reduction than the dispersant containing only 500

269

mg/L of NaCl, both at a HPAM concentration of 10 mg/L (respectively, 243 and 298 nm) and 1,000

270

mg/L (respectively, 44 and 52 nm), at temperature 25°C. This result indicates that the NaCl

271

decreases the hydrodynamic diameter less than some chemical species of the softened injection

272

water. 11

ACCEPTED MANUSCRIPT 273

In general, this study shows that the polymer concentration variation exerts a stronger influence

274

on the hydrodynamic diameter than the variation of the type and concentration of salt in the

275

dispersion medium. On the other hand, salinity has a greater impact than polymer concentration on

276

the viscosity values of the solutions (Figure 1). Figure 3 also shows the results of the HPAM systems, at 10 and 1,000 mg/L, containing 500 mg/L

278

of NaCl, at 25 and 50 ºC, enabling analysis of the effect of temperature on the hydrodynamic

279

diameter of the polymer. This reveals that in the dilute regime (10 mg/L of HPAM), a sharp increase

280

in the hydrodynamic diameter (Dh), from 298 to 2,500 nm (roughly a nine-fold increase), occurred

281

with a temperature increase from 25 to 50 ºC. The hydrodynamic volume increase with increasing

282

temperature is also reported by Akasus (1980). In the concentrated regime (1,000 mg/L of HPAM),

283

the hydrodynamic diameter increase was very small, from 56 to only 71 nm, when the temperature

284

increased from 25 to 50 ºC.

M AN U

SC

RI PT

277

The comparison of the hydrodynamic diameter results for HPAM in distilled water at 25 ºC, on the

286

one hand, and HPAM in distilled water and in saline solution of 500 mg/L of NaCl at 50 ºC, on the

287

other, showed larger particle sizes at 50 ºC (2,500 and 71 nm) than at 25 °C (770 and 56 nm) for both

288

analyzed concentrations. This indicates that the effect of temperature (Equation 11 of Stokes-

289

Einstein) overrides the effect of charge shielding of the polymer due to the presence of salt.

EP

TE D

285

The hydrodynamic diameter variation of the HPAM dispersions in deionized water containing

291

500 mg/L of NaCl at the temperature of 50 ºC was evaluated in the concentration range of 10 to

292

1,000 mg/L, along with the consistency index (Figure 4). These conditions are similar to the initial

293

conditions in many oil recovery applications regarding the initial salinity of polymer dispersions and

294

reservoir temperature and the variation of concentration during the injection process (Melo et al,

295

2005; Silva at al, 2007).

AC C

290

296 297

Figure 4. Polymer hydrodinamic diameter (

) and consistency index (---) in function of HPAM

298

concentration in saline water (500 mg/L NaCl), at 50 ºC. 12

ACCEPTED MANUSCRIPT 299 300

Similar to the result for variation of Dh in function of polymer concentration in distilled water at

301

25 ºC (Figure 2), the hydrodynamic diameter decreased with rising concentration for the lower

302

HPAM concentrations, but remained practically constant for the higher polymer concentrations. Figure 4 shows that the C* value determined by light scattering (50 mg/L of polymer) was lower

304

than the value determined by viscometry (100 mg/L of polymer, Table 3) for HPAM in saline

305

solution of 500 mg/L of NaCl at 50 ºC. This behavior has been reported by other authors

306

(Papanagopoulos et al, 1998; Rodd at al., 2001) and it has been attributed to the differences in shear

307

applied by the two techniques, since an increase in shear causes chain elongation, hindering

308

interpenetration and increasing the value of C* detected.

M AN U

SC

RI PT

303

Comparison of the polymer concentration effects, salt concentration and temperature on the

310

viscosity (η) and hydrodynamic diameter (Dh) showed that viscosity increased with higher polymer

311

concentration and lower salt concentration and temperature. In turn, the hydrodynamic diameter

312

increased with lower polymer concentration and higher temperature, but was affected very little by

313

salt concentration. These findings also have implications for the behavior of the polymer in porous

314

media, as addressed next.

EP

315

TE D

309

3.3. Correlation of viscosity and hydrodynamic diameter with the flow behavior of the HPAM

317

dispersions in porous media

AC C

316

318

To evaluate the influence of the HPAM concentration regimes on the flow in porous media, first a

319

test with a polymer solution of 1,000 mg/L was conducted (concentrated regime) in a Berea

320

sandstone sample (international standard). First, 1 PV (pore volume) of NaCl solution of 500 mg/L

321

was injected. Then, 3.5 PV of the HPAM dispersion at 1,000 mg/L containing 500 mg/L of NaCl

322

was injected. Finally, 6 PV more of the saline solution was injected. The results of pressure

323

(normalized by the pressure of the injected water) in function of pore volume injected are presented

13

ACCEPTED MANUSCRIPT in Figure 5. The pressure increased during the phase of injecting the concentrated HPAM solution

325

(viscosity of 30 mPa.s) and decreased with subsequent injection of salt water (viscosity of 0.6

326

mPa.s). The findings on pressure and residual resistance factor from water injection (around 2) are

327

very near those reported previously in the literature (Chauveteau, 1982, 1984; Chang, 1978; Sorbie,

328

1991; Zitha at al, 2001, Zhang and Seright, 2014; Wei, 2015).

329

RI PT

324

Figure 5. Injection into Berea’s porous media (1000 mD): (a) 1 PV of salt solution (500 mg/L

331

NaCl); (b) 3.5 PV of 1000 mg/L HPAM dispersion, containing 500 mg/L NaCl; and (c) 6 PV of salt

332

solution (500 mg/L NaCl).

SC

330

M AN U

333

The flow of the HPAM solution at 50 mg/L (dilute regime) was also evaluated in a porous rock

335

sample from the Rio Bonito outcrop (Brazil), at a temperature of 50 °C and salinity of 38,000 mg/L.

336

This salinity condition is even more unfavorable than that used in the concentrated regime test. A

337

solution of 38,000 mg/L of NaCl was injected first, followed by injection of the saline solution

338

containing the polymer. Figure 6 shows the effluent polymer concentration (normalized by the

339

injected polymer concentration) and pressure (normalized by pressure of injected water) in function

340

of injected porous volume. As expected, the pressure remained low and stable during injection of the

341

saline solution (first 2 PV). During the polymer dispersion flow (2.4VP), the pressure initially

342

increased and then remained stable. Similar conditions and results were reported by other researchers

343

(Melo et al, 2002; Wei, 2015). However, a sudden pressure increase was observed soon after starting

344

the second saline solution injection (Figure 6).

AC C

EP

TE D

334

345

This test result was similar to that found previously under similar conditions (Silva and Lucas,

346

2017). The polymer retention in the rock, calculated by measuring the polymer concentration in the

347

effluent (Figure 6), was very small (10 µg⁄g), in agreement with the results obtained by other

348

researchers (Zhang and Seright, 2014) for this polymer in the same concentration range (dilute

14

ACCEPTED MANUSCRIPT regime). The immediate and rising increase in pressure caused by the second saline solution injection

350

can be attributed to the increase in mechanical and hydrodynamic retention of HPAM. Since the

351

quantity of HPAM retained in the rock was very small, it can be concluded that this pressure increase

352

is associated with the sudden expansion of the polymer’s hydrodynamic volume with the increase in

353

dilution, as indicated previously in this article.

354

RI PT

349

Figure 6. Injection, into natural porous media (Rio Bonito sandstone), of HPAM 50 mg/L

356

(concentration diluted regime), at high concentration of NaCl (38,000 mg/L), at 50°C.

SC

355

357

The HPAM dispersion evaluation in porous medium flow showed that: the residual resistance factor

359

of HPAM dispersions in sandstone porous media, at 50 ° C, was consistent with the results of

360

hydrodynamic volume evaluation. That is, 50 mg/L HPAM dispersion (below the overlapping

361

concentration), promoted a much higher residual resistance factor than the dispersion with 1000mg /

362

L (above overlapping concentration), in sandstone core (1000 mD). This results showed substantial

363

mechanical retention only occurs when a great variation of hydrodynamic diameter in a dilute regime

364

occurs.

365

3.4. Correlation with result previously reported

EP

TE D

M AN U

358

Silva and Lucas (2017) tested the same HPAM dispersions in artificial metallic porous media,

367

where adsorption is not expected. The porous medium had permeability of 60000 mD and a 15

368

microns porous diameter. The results showed the injection of HPAM 1000 mg / L (concentration

369

above the overlapping and Dh = 71 nm) resulted in a higher resistance factor, but no residual

370

resistance factor. While the 10 mg / L HPAM (concentration below the overlapping and 2500 nm)

371

dispersion promoted a lower resistance factor, but a significant residual resistance factor. This

372

behavior exemplifies the hydrodynamic volume dependence on the concentration and the influence

373

of the ratio between the pore and hydrodynamic diameters (Zitha et al., 2001).

AC C

366

15

ACCEPTED MANUSCRIPT As reported in a previous pilot field study (Silva and Lucas, 2017) the injectivity test showed that:

375

(1) when injecting saline solution after the polymer solution, the pressure was higher than that during

376

the polymer solution flow (in the concentrated and semidilute regimes); (2) the residual resistance

377

factor was high only in the production well direction, which already had an indication of channeling;

378

(3) the permeability to water was selectively reduced, since the permeability reduction only occurred

379

in the presence of accentuated fingers, indicated by the high injected tracer recovery before the

380

HPAM solution; and (4) the permeability decline had a long reach, i.e., it occurred throughout the

381

injection and production wells extension (50 m). These unexpected results can now be understood

382

based on the laboratory study presented here.

384

M AN U

383

SC

RI PT

374

4. Conclusions

The HPAM utilized in a polymer flooding Pilot and analyzed in this study, molar mass 6 x 106

386

g/mol and 30% GH, showed that: in the dilute concentration regime, the temperature increase (25°C

387

to 50°C) and the concentration reduction cause an expansion of the hydrodynamic volume polymer.

388

This effect is significant and prevails over the polymeric hydrodynamic volume reduction due the

389

salinity.

TE D

385

During its propagation in the porous medium, polymer dispersion can suffer a great concentration

391

reduction when flowing to the more permeable and washed zones, where, depending on the dilution,

392

the polymeric hydrodynamic diameter may suffer high expansion.

AC C

EP

390

393

Mechanical retention depends on the ratio between pore diameter and hydrodynamic diameter.

394

However, this ratio can vary along the polymer dispersion propagation in the porous medium. Then,

395

the polymer dispersion can promote mechanical retention in different intensities and different

396

reaches. The concentration and volume of polymer dispersion is a key parameter, as following:

397

If the injection concentration is much above the overlapping and the injected volume too large, as

398

usually occurs in current applications, mechanical retention can be minimal or not occur. As this

16

ACCEPTED MANUSCRIPT 399

study, mechanical retention did not occur when the dispersion of 1000 mg/L (Dh 71 nm) was injected

400

into sandstone core and metallic medium with permeabilities of 1000 mD and 60000 mD,

401

respectively, and both with Dp (medium) 15 µm. If the injected polymer dispersion concentration is very close to the overlapping (or even being

403

high, the injected mass is relatively small) mechanical retention (due to dilution) can be very close to

404

the injection point and lead to plugging the porous medium, as an example, the injection of HPAM

405

dispersion at 50 mg/L in sandstone core.

RI PT

402

If the solution concentration is already much diluted, before long-range injection, blockage near

407

the injection point may occur or the retention in the reservoir may not occur, or may occur slowly,

408

depending on Dh/Dp ratio. As an example, HPAM injection 10 mg/L, (Dh = 2600 nm), caused slow

409

mechanical retention in porous medium with Dp = 15 µm.

M AN U

SC

406

When the polymer concentration reduction occurs in an extensive range of dilute regimes, the

411

hydrodynamic diameter expansion can cause severe mechanical retention and reduced permeability

412

of these zones, with little retention of polymer mass, as shown in this study. The reduction of

413

permeability of the more permeable and washed zones diverts the flow to areas not yet swept, thus

414

causing increased of swept efficiency. Thus, an alternative to these mature reservoirs is proposed here

415

involving the variation of the hydrodynamic diameter with the concentration. The prevalence of

416

temperature on the effect, markedly in diluted regimes, the process becomes less restrictive to the

417

salinity of the reservoir fluids.

AC C

EP

TE D

410

418

The mechanism presented favors the application of this polymer flooding process in mature fields

419

with high heterogeneity and salinity, of most economical form. Other factors not evaluated may be

420

very relevant to the studied mechanism such as the influence of divalent cations, molar mass,

421

polydispersity, oil saturation, flow velocity and reversibility.

422

This work also evidences the relevance of including polymer hydrodynamic size values in the

423

simulation and dimensionless of the EOR process when deploying HPAM in the field, which will

17

ACCEPTED MANUSCRIPT 424

result in a relative lower mass injected and effluent of polymer and, as a consequence, a simpler

425

logistic and lower cost of the operation. It is stressed that the impact of concentration and hydrodynamic volume observed in this study can

427

naturally be extended to other physical systems, and even biological systems, with respect to the flow

428

of solutions of flexible macromolecules in porous medium.

429

5. Acknowledgments

RI PT

426

E. F. Lucas thanks CNPq (307193/2016-0) and FAPERJ (E-26/201.233/2014) for the financial

431

support. I. P. G. Silva gives thanks to Roberto Francisco Mezzomo and Maria Aparecida de Melo for

432

their technical support and encouragement.

M AN U

433

SC

430

6. References

435 436 437

Abdulbaki, M., Huh, C., Sepehrnoori, K., Delshad, M., Varavei, A., 2014. A critical review on use of polymer microgels for conformance control purposes. Journal of Petroleum Science and Engineering 122(2014)741–753.

438 439

Akcasu, A. Z., 1980. Temperature and concentration dependence of diffusion coefficient in dilute solutions. Polymer, 1981, Vol 22, September.

440 441 442 443

Al Hashmi A.R. Al Maamari, R.S.; A.L Shabibi, I.S.; Mansoor, A.M.; Zaitoun, A. Al Sharji, H.H., 2013. Rheology and mechanical degradation of high-molecular-weight partially hydrolyzed polyacrylamide during flow through capillaries. Journal of Petroleum Science and Engineering 105(2013)100–106.

444 445

Algharaib, M, Alajmi, A, Gharbi, R., 2014. Improving polymer flood performance in high salinity reservoirs. Journal of Petroleum Scienceand Engineering 115 (2014)17–23.

446 447

Alvarado, V; Manrique, E., 2010. Enhanced Oil Recovery: An Update Review. Energies 2010, 3(9), 1529-1575.

448 449

Asghari, K., Nakutnyy, P., 2008. Experimental Results of Polymer Flooding of Heavy Oil Reservoirs. Canadian International Petroleum Conference, Calgary, Canada, PETSOC-2008-189.

450 451

Bailey, B., Crabtree, M., Tyrie, J., Elphick, J., Kuchuck, F., Romano, C., and Roodhart, L., 2000. Water Control. Oilfield Review 12 (2000) 30-51.

452 453

Caili, D., Qing, Y., Fulin, Z., 2010. In-depth Profile Control Technologies in China - A Review of the State of the Art. Petroleum Science and Technology, 28:1307–1315, 2010

454 455

Campbell, T. A., Bachman, R. C., 1987. Polymer Augmented Waterflood in The Rapdan Upper Shaunavon Uasnit. J. Canada. Petrol. Technol. 1987, 26(4), 67-73.

456 457 458

Chagas, B. S., Machado Jr, D. L. P.; Haag, R.; Sousa, C. R.; Lucas, E. F., 2004. Evaluation of hydrophobically associated polyacrylamide-containing aqueous fluids and potential use of it in petroleum recovery. J. Appl. Polym. Sci. 2004, 91(6), 3686-3692.

AC C

EP

TE D

434

18

ACCEPTED MANUSCRIPT Chang, H. L.,1978. Polymer floodind technology yesterday, today, and tomorrow. J. Petrol. Technol. 1978, SPE 7043.

461 462 463

Chang, H. L, Zhang, Z.Q., Wang, Q.M., XU, Z. S., Guo, Z.D.; Sun, H.Q.; Cao, X.L. Qiao, Q. Advanced in polymer flooding alkali/surfactant/polymer processes as developed and applied in the republic of China. J. Petrol. Technol. 2006, SPE-89175.

464 465

Chauveteau, G. Rodlike polymer solution flow through fine pores: influence of pore size on rheological behavior. J. Rheol. 1982, 26(2), 111-142.

466 467

Chauveteau, G. Thickening Behavior of Dilute Polymer Solutions in Non-Inertial Elongational Flows. J. Nonnewton. Fluid Mech. 1984, 16, 315-327.

468 469

Chauveteau,G., Kohler, N., 1974. Polymer Flooding: The Essential Elements for Laboratory Evaluation. Society of Petroleum Engineers of AIME, Dallas,Texas, USA.

470 471

Choi, B., Jeong, M. S.; Lee, K. S. Temperature-dependent viscosity model of HPAM polymer through high-temperature reservoirs. Polym. Degrad. Stab. 2014, 110, 225-231.

472 473 474 475

Clemens, T.; Deckers, M.; Komberger, M.; Gumpenberger, T.; Zechner, M. Polymer Solution Injection – Near Wellbore Dynamics and Displacement Efficiency, Pilot Test Results, Matzen Field, Austria. EAGE Annual Conference & Exhibition incorporating SPE Europec, London, UK, 2013, SPE 164904.

476 477

Coviello, T., Burchard, T. W., Dentini, M., Crescenzi, V. Solution Properties of Xanthan. 2. Dynamic and Static Light Scattering from Semidilute Solution. Macromolecules 1987, 20, 1102-1107.

478 479

Craig, F. F., 1971. The Reservoir Engineering Aspects of Waterjlooding. SPE Monograph Series No. 3. SPE Richardson, TX.

480 481

Dauben, D. L., Menzie, D. E., 1967. Flow of Polymer Solution in Porous Media. Journal of Petroleum Technology, August, 1063-1073.

482 483

De Gennes, P. G. 1979. Scaling concepts in polymer solutions; Cornell University Press: Ithaca, 1979.

484 485

De Gennes, P. G. Dynamics of Entangled Polymer Solutions. II. Inclusion of hydrodynamic interactions. Macromolecules, 1976, 9, 594-598.

486 487

Dominguez, J. G.; Willhite, G. P. Retention and Flow Characteristics of Polymer Solutions in Porous Media. SPE J. 1977, 17(2), 111–121.

488 489 490

Du, Y.; Guan, L., 2004. Field-Scale Polymer Flooding: Lessons Learnt and Experiences Gainned During Past 40 Years. SPE International Petroleum Conference in Mexico, Puebla Pue., Mexico, SPE 91787.

491 492 493

Fan, Y., Wu, C., Wang, M., Wang, Y., Thomas. R. K. Self-Assembled Structures of Anionic Hydrophobically Modified Polyacrylamide with Star-Shaped Trimeric and Hexameric Quaternary Ammonium Surfactants. Langmuir 2014, 30(23), 6660–6668.

494 495

Gao, C. H. Advances of Polymer Flood in Heavy Oil Recovery. SPE Heavy Oil Conference and Exhibition, Kuwait City, Kuwait, 2011, SPE 150384.

496 497

Gogarty WB, Meabon HP, Milton H.W., 1970. Mobility control design for miscible-type waterfloods using micellar solutions. J Pet Technol 22:141–147. doi:10.2118/1847-E-PA

498 499

Graessley, W. W. Polymer chain, dimensions and the dependence of viscoelastic properties on concentration, molecular weight and solvent power. Polymer 1980, 21, 258-262.

500

Kaggwa, G. B., Froebe, S., Huynh, L., Ralston, J., Bremmell, K. Morphology of Adsorbed Polymers

AC C

EP

TE D

M AN U

SC

RI PT

459 460

19

ACCEPTED MANUSCRIPT and Solid Surface Wettability. Langmuir 2005, 21(10), 4695–4704.

502 503 504

Kang, E.; Jung, S.; Abel, J. H.; Pine, A.; Yi, H. Shape-Encoded Chitosan–Polyacrylamide Hybrid Hydrogel Microparticles with Controlled Macroporous Structures via Replica Molding for Programmable Biomacromolecular Conjugation. Langmuir 2016, 32(21), 5394–5402.

505 506

Kaszuba, M.; McKnight, D.; Connah, M. T.; McNeil-Watson, F. K.; Nobbmann, U. J. Measuring sub nanometre sizes using dynamic light scattering. J. Nanopart. Res. 2008, 10, 823–829.

507

Lake, L. W. Enhanced oil recovery; Prentice-Hall Inc.: New Jersey, 1989.

508 509

Lake, L. W.; Schmidt, R. L.; Venuto, P. B. A niche for enhanced oil recovery in the 1990s. Oilfield Review, 1992, 4(1), 55-61.

510 511

Lake, L.W, Walsh, M.P, Enhanced Oil Recovery (EOR) Field Datas Literature Search. Technical Report, 2008.

512 513

Levitt, D.B., Pope, G.A., 2008. Selection and screening of polymers for enhanced-oil recovery. SPE113845 Presented at the Improved Oil Recovery Symposium held in Tulsa,USA,19–23 April.

514 515

Li, X., Xu, Z., Yin, H.,Feng, Y., Quan, H. Comparative Studies on Enhanced Oil Recovery: thermo viscosifying Polymer Versus Polyacrylamide. Energy Fuels 2017, 31, 2479–2487.

516 517

Lopes, L. F., Silveira, B. M. O., Moreno, R. B. Z. L. Rheological Evaluation of HPAM fluids for EOR Applications. Int. J. Eng.Technol. 2014, 14(03), 35-41.

518 519 520

Lucas, E. F., Ferreira, L. S., Khalil, C. N. Polymers Applications in Petroleum Production, in Encyclopedia of Polymer Science and Technology; Ed. Mark, H. F., John Wiley & Sons, Inc.: New York, 2015.

521

Lyons, W. Working Guide to Reservoir Engineering; Elsevier Inc.: New York, 2009.

522 523 524 525

Maia, A. M. S., Villetti, M. A., Vidal, R. R. L., Borsali, R., Balaban, R. C. Solution Properties of a Hydrophobically Associating Polyacrylamide and its Polyelectrolyte Derivatives Determined by Light Scattering, Small Angle X-ray Scattering and Viscometry. J. Braz. Chem. Soc. 2011, 22, 489500.

526

Malvern Instruments LDT. (2005). Zetasizer Nano Series User Manual. 2ed. Worcestershire.

527 528

Melo, M. A., Lucas, E. F. Characterization and selection of polymer for use in future research on improved oil recovery. Chem. Chem. Technol. 2008, 2(4), 295-303.

529 530 531

Melo, M. A., Lins, Jr, A. G., Silva, I. P. G. Lessons Learned From Polymer Flooding Pilots in Brazil. SPE Latin America and Caribbean Mature Fields Symposium, Salvador, Bahia, Brazil, 2017, SPE 184941.

532 533 534 535

Melo, M.A., Holleben, C.R., Silva,I.P.G., Correia,A.C., Silva,G.A.,Rosa, A.J.,Lins,A.G., Junior,A.G.L., and Lima, J. C., 2005. Evaluation of Polymer Injection Projects in Brazil. SPE94898 presented at the SPE Latin America and Carribean Petroleum Engineering Conference held in Rio de Janeiro, Brazil, June 20-23.

536 537 538

Melo, M.A., Silva, I.P.G.,Godoy,G.M., and Sanmartin,A.M., 2002. Polymer Injection Projects in Brazil: Dimensioning, Field Application and Evaluation. SPE75194 Presented at the SPE 13th.Symposium on Improved Oil Recovery held in Tulsa, USA, April13-17.

539 540

Nars-El-Din, H. A; Taylor, K. C. Rheology of water-soluble polymers used for improved oil recovery. J. Petrol. Sci. Eng. 1995, 19(3), 265-280.

541

Needham, R. B., Doe, P.H. Polymer flooding review. J. Petrol. Technol. 1987, SPE 17140.

542

Oliveira, L.F.L., Schiozer, D.J., Delshad, M., 2016. Impacts of polymer properties on field indicators

AC C

EP

TE D

M AN U

SC

RI PT

501

20

ACCEPTED MANUSCRIPT of reservoir development projects. Journal of Petroleum Science and Engineering 147(2016)346–355.

544

Pope, G. A. Overview of Chemical EOR. Casper EOR Workshop 2007.

545 546

Pye, D.J., 1964. Improved Secondary Recovery by Control of Water Mobility. Journal of Petroleum Technology, SPE 845. August (1964) 911-916.

547 548

Raphael, E., Pincus, P. Scaling theory of polymer solutions trapped in small pores: the -solvent case. J. Phys. II 1992, 2(6), 1341-1344.

549 550 551

Reis, L. G., Oliveira, R. S., Palhares, T. N.; Spinelli, L. S.; Lucas, E. F.; Vedoy, D. L.; Asare, E.; Soares, J. Using acrylamide/propylene oxide copolymers to dewater and densify oil sands tailings. Mineral Eng. 2016, 95, 29-39.

552 553 554

Reis, L. G., Pires, R. V., Lucas, E. F. Influence of structure and composition of poly(acrylamide-gpropylene oxide) copolymers on drag reduction of aqueous dispersions. Colloid Surfaces A 2016, 502, 121-129.

555 556 557

Rodd, A. B., Dunstan, D. E., Boger, D. V., Schmidt, J., Burchard, W. Heterodyne and Nonergodic Approach to Dynamic Light Scattering of Polymer Gels: Aqueous Xanthan in the Presence of Metal Ions. (Aluminum (III). Macromolecules 2001, 34, 3339-3352.

558 559 560

Rousseau, D., Chauveteau, G., Renard, M., Tabary, R., Zaitoun, A., Mallo, P., Braun, O., Omari, A. Rheology and transport in porous media of new water shutoff/conformance control microgels. SPE International Symposium on Oilfield Chemistry. The Woodlands, Texas, 2005, SPE 93254.

561 562 563

Sadicoff, B. L., Brandão, E. M., Lucas, E. F. Rheological behaviour of poly(acrylamide-g-propylene oxide) solutions: effect of hydrophobic content, temperature and salt addition. Int. J. Polym. Mat. 2000, 47, 399-406.

564 565

Sandengen, K., Melhuus, K., Kristoffersen, A., 2017. Polymer “viscoelastic effect”; does it reduce residual oil saturation*. Journal of Petroleum Science and Engineering 153 (2017) 355–363

566 567

Seright, R. S. Potential for Polymer Flooding Reservoirs with Viscous Oils. SPE Reserv. Eval. Eng. 2010, SPE 129899.

568 569

Seright, R. S., Fan, T., Wavrik, K.; Balaban, R. C. New Insight into Polymer Rheology in Porous Media. SPE J. 2011, SPE 129200.

570 571 572

Sharma, T., Iglauer, S., Sangwai, J. S. Silica Nanofluids in an Oilfield Polymer Polyacrylamide: Interfacial Properties, Wettability Alteration, and Applications for Chemical Enhanced Oil Recovery. Ind. Eng. Chem. Res. 2016, 55, 12387–12397.

573 574

Sheng, J.J., 2011. Modern chemical enhanced oil recovery. Theory and practice. Elsevier Inc., USA Burlington, MA01803, ISBN: 978-1-85617-745-0.

575 576

Sheng, J.J., Leonhardt, B., Azri, N., 2015. Status of Polymer-Flooding Technology. Journal of Canadian Petroleum Technology, March 2015, March, 116-126.

577 578

Silva, I. P. G., Lucas, E. F. New Insight on the Polymer Flooding to Mature Fields. SPE Latin America and Caribbean Mature Fields Symposium, Salvador, Bahia, Brazil, 2017, SPE 184907.

579 580

Silva, I. P. G., Lucas, E. F., França, F. P. Study of conditions for polyacrylamide use in petroleum reservoirs: physical flow simulation in porous media. Chem. Chem. Technol. 2010, 4(1), 73-80.

581 582 583

Silva, I. P. G., Melo, M. A., Luvizotto, M., Lucas, E. F. Polymer flooding a sustainable enhanced oil recovery in the current scenario. Society of Petroleum Engineers, Latin American & Caribbean Petroleum Engineering Conference, Buenos Aires, Argentina, 2007, SPE-107727.

584

Silveira, K. C., Sheng, Q., Tian, W., Lucas, E. F., Wood, C. D. Libraries of modified

AC C

EP

TE D

M AN U

SC

RI PT

543

21

ACCEPTED MANUSCRIPT polyacrylamides using post-synthetic modification. J. Appl. Polym. Sci. 2015, 132(47), 42797.

586 587

Sorbie, S.K., 1991. Polymer-Improved Oil Recovery. CRC Press Inc, ISBN 9780216926936, http://dx.doi.org/10.1007/978-94-011-3044-8, CRC Press, Inc. USA and Canada.

588 589

Standnes, D.C., Skjevrak, I, 2014. Literature review of implemented polymer field projects. Journal of Petroleum Science and Engineering 122(2014)761–775.

590 591

Szabo M. T., 1975. Laboratory investigation of factors influencing polymer flood performance. SPE J 15:338–346. Doi: 10.2118/ 4669-PA.

592 593

Taber, J. J, Martin, F. D., Seright, R .S. EOR screening criteria revisited-part 2: applications and impact of oil prices. SPE Reserv. Eng. 1997, 12(3),199-206.

594 595

Vidal, J. R. M. B., Pelegrine, D. H., Gasparetto, C. A. Efeito da temperatura no comportamento reológico da polpa de manga (Mangífera indica L-Keitt). Ciênc. Tecnol. Aliment. 2004, 24(1), 39-42.

596 597 598 599

Wang Demin, Xia Huifen, Liu Zhongchun, Yang Qingyan, 2001. Study Of The Mechanism Of Polymer Solution With Visco-Elastic Behavior Increasing Microscopic Oil Displacement Efficiency And The Forming Of Steady “Oil Thread” Flow Channels. Society of Petroleum Engineers, SPE 68723.

600 601

Wang, D. Dong, H., Lv, C., Fu, X., Nie, J., 2009, Review of Practical Experience of Polymer Flooding at Daqing. Society of Petroleum Engineers, SPE 114342.

602 603 604

Wang, Z., Le, X., Feng, Y, Zhang, C., 2013. The role of matching relationship between polymer injection parameters and reservoirs in enhanced oil recovery. Journal of Petroleum Science and Engineering 111 (2013)139–143.

605 606

Wei, B. Flow Characteristics of Three Enhanced Oil Recovery Polymers in Porous Media. J. Appl. Polym. Sci. 2015, 132, 41598.

607 608 609

Wei, B., Romero-Zerón, L., Rodrigue, D., 2014. Oil displacement mechanisms of viscoelastic polymers in enhanced oil recovery (EOR): a review. J Petrol Explor Prod Technol (2014) 4:113–12. DOI: 10.1007/s13202-013-0087-5.

610 611

Wernert, V.; Bouchet, R.; Denoyel, R. Influence of Molecule Size on Its Transport Properties through a Porous Medium. Anal. Chem. 2010, 82, 2668–2679.

612 613

Wever, D. A. Z.; Picchioni, F.; Broekhuis, A. A. Polymers for enhanced oil recovery: A paradigm for structure-property relationship in aqueous solution. Prog. Polym. Sci. 2011, 36, 1558-1628.

614 615

Wever, D. A. Z; Picchioni, F.; Broekhuis. A. A. Comblike Polyacrylamides as Flooding Agent in Enhanced Oil Recovery. Ind. Eng. Chem. Res. 2013, 52, 16352–16363.

616 617

Xie, D.; Hou, J.; Doda, A.; Trivedi, J. Application of Organic Alkali for Heavy-Oil Enhanced Oil Recovery (EOR), in Comparison with Inorganic Alkali. Energy Fuels 2016, 30, 4583–4595.

618 619

Zhang, G.; Seright, R. S. Effect of Concentration on HPAM Retention in Porous Media. SPE J. 2014, SPE-166265-PA.

620 621

Zitha, P. L., Chauveteau, G., Leger, L. Unsteady-state Flow of Flexible Polymers in Porous Media. J. Colloid Interface Sci. 2001, 234, 269-283.

622 623 624

Zou, C., Zhao, P., Hu, X., Yan, X., Zhang, Y., Wang, X., Song, R., Luo, P. β-CyclodextrinFunctionalized Hydrophobically Associating Acrylamide Copolymer for Enhanced Oil Recovery. Energy Fuels 2013, 2827–2834.

AC C

EP

TE D

M AN U

SC

RI PT

585

22

ACCEPTED MANUSCRIPT Table 1. Composition of softened injection water produced by a Brazilian petroleum field Softened water

Barium

mg/L

<1

Bicarbonate

mg/L

230

Bromide

mg/L

<1

Calcium

mg/L

<1

Chloride

mg/L

60

Magnesium

mg/L

<1

-

7.4

pH

mg/L

Sodium

mg/L

TDS

mg/L

AC C

EP

TE D

Viscosity (25°C)

<1 7.2

500

M AN U

Potassium

RI PT

Unit

SC

Parameter

mPa.s

0.88

ACCEPTED MANUSCRIPT Table 2. Some coreflow test data

Diameter (cm)

3.8

3.8

Length (cm)

9.2

13.0

Area (cm2)

11.4

11.1

Total volume (cm3)

104.3

144.3

Porous volume (cm3)

23.5

31.5

Permeability to air (mD)

1178

920

Sandstone

Sandstone

800

620

24.0

30.0

Mineralogy

M AN U

Permeability to water

RI PT

Rio Bonito

SC

Coreflood

Berea

(mD)

AC C

EP

TE D

Flow rate (cm3/h)

ACCEPTED MANUSCRIPT Table 3. Transitions of concentration regime for the HPAM solutions

Water Saline solution

25

70

50

100

-

AC C

EP

TE D

M AN U

SC

(500 mg/L NaCl)

Temperature Transitions of the concentration (ºC) regime C* C** (mg/L) (mg/L) 25 30 1,000

RI PT

Dispersion medium

-

AC C

EP

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

AC C

EP

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

AC C

EP

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

AC C

EP

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

AC C

EP

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

AC C

EP

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

ACCEPTED MANUSCRIPT Highlights • Good oil recovery results obtained with dilute polymer solution • Mechanical/hydrodynamic retention prevails over polymer adsorption at the rock

AC C

EP

TE D

M AN U

SC

RI PT

• Increasing in the polymeric hydrodynamic volume in fluid dilution processes