Heterogeneity control ability in porous media: Associative polymer versus HPAM

Journal of Petroleum Science and Engineering 183 (2019) 106425

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Heterogeneity control ability in porous media: Associative polymer versus HPAM

T

Yan Lianga,b, Zeng-lin Wangc, Yan-xin Jind, Yu-qin Tiand, Xi-ming Liud, Yong-jun Guoa,b,e,∗, Li Fane, Jie Wange, Xin-min Zhanga,e, Miao Caoa,e, Ming-yuan Zhoue a

State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, Chengdu 610500, PR China College of Chemistry and Chemical Engineering, Southwest Petroleum University, Chengdu 610500, PR China c Shengli Oilfield Branch, Sinopec, Dongying 257000, PR China d Petroleum Engineering Technology Research Institute, Shengli Oilfield Branch, Sinopec, Dongying 257000, PR China e Sichuan Guangya Polymer Chemical Co.,Ltd, Nanchong 637500, PR China b

A R T I C LE I N FO

A B S T R A C T

Keywords: Heterogeneity control Associative polymer HPAM Oil reservoir EOR

In chemical EOR (especially polymer flooding), the swept area and oil recovery of displacing fluids were strongly affected by reservoir heterogeneity. To qualitatively study and discuss the oil reservoir heterogeneity control capacity of a new water-soluble polymer, associative polymer (AP-X), this work, compared with HPAM, conducted a series of laboratory experiments involving apparent viscosity, fluorescence, rheological properties, threshold pressure, flow and transport in porous media, as well as the oil micro-/macro-displacements in interstratified connected and parallel heterogenous micro-/macro-models. The results showed that AP-X had more significant thickening capacity and viscoelasticity than HPAM and presented noticeable self-association effect due to the associative interaction between hydrophobic groups. To enter into the porous media with the same or higher permeability, AP-X needed much greater injection (threshold) pressure than HPAM although the threshold pressure of AP-X significantly decreased as increasing permeability. More importantly, AP-X could not only present a good conductivity but also establish significantly higher flow resistance. In addition, at a greater permeability contrast of 8 times (8000/1000 mD), AP-X mainly swept the high permeable layer and slightly swept the low permeable layer slowly within 0.5 PV, which was accompanied by the significant sweep for the low layer after 0.5 PV. More interestingly, AP-X could also make the fluid diversion of the post-water to further mobilize the oil in low permeable layer and obtain a higher EOR than HPAM. All results indicate that associative polymer has remarkable application potential and advantages than HPAM in EOR not only regarding to better thickening property and viscoelasticity but also involving higher flow resistance and significant heterogeneity control capacity, which can provide a new system design concept and technical ideas for reservoir heterogeneity control.

1. Introduction As an important technology, chemical enhanced oil recovery (CEOR), especially polymer flooding, has been widely used to improve water injection efficiency for those matured oilfields mainly developed by water injection during entering into the stage of high (or ultra-high) water cut, and used to develop heavy oil as well as unconventional oilgas resources. In many cases, it has made great pilot and field-scale achievements in many oilfields worldwide (Chappell et al., 2017; Delamaide et al., 2016; Lazzarotti et al., 2017; Leon et al., 2018; Mehta et al., 2016; Melo et al., 2017; Pandey et al., 2012; Pérez et al., 2017; Sharma et al., 2016; Wassmuth et al., 2007a, b; Wassmuth et al., 2009).

∗

Generally, the main mechanism is considered as that the adverse mobility ratio between displacing and displaced phases can be improved by increasing the viscosity of displacement fluids using polymers, so that the sweep volume can be significantly enlarged to achieve the purpose of enhanced oil recovery (Asghari and Nakutnyy, 2008; Bondino et al., 2013; Miller and Fogler, 1995; Seright, 2010a, b; Tang et al., 2014; Wang and Dong, 2007; Wang and Dong, 2009). However, both in matured oilfields and heavy oil reservoirs, the reservoir heterogeneity is an important parameter for a successful polymer flooding. Many researchers have conducted some work relating to the effect of heterogeneity on the oil recovery of polymer flooding and have unanimously indicated that the swept area and oil

Corresponding author. State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, Chengdu 610500, PR China. E-mail address: [email protected] (Y.-j. Guo).

https://doi.org/10.1016/j.petrol.2019.106425 Received 8 May 2019; Received in revised form 23 June 2019; Accepted 25 August 2019 Available online 26 August 2019 0920-4105/ © 2019 Elsevier B.V. All rights reserved.

Journal of Petroleum Science and Engineering 183 (2019) 106425

Y. Liang, et al.

Table 1 Components of gudong injection water. Components

K+

Na+

Ca2+

Mg2+

Fe2+

HCO3−

SO42−

Cl−

TDS

Concentration (mg/L)

62.31

4480.25

549.78

57.94

4.73

540.16

12.37

6252.11

11,959.65

generate higher resistance factor (RF) and residual resistance factor (RRF), and could present a ‘piston-like’ displacement front (Guo et al., 2016; Guo et al., 2017; Han et al., 2018; Seright et al., 2011a, b, c). The unique characteristics imply that associative polymer may control the heterogeneity well under some conditions, which is highly worth of investigation and enrichment. Therefore, compared with HPAM, this work conducted a series of experiments involving apparent viscosity, fluorescence measurement, rheological properties, threshold pressure, flow and transport in porous media, as well as the oil micro-/macro-displacements in heterogenous models to experimentally study and discuss the injection behavior and oil reservoir heterogeneity control capacity in porous media of associative polymer. All findings indicate associative polymer has significant advantages in heterogeneity control, which would be benefit to largely enhance oil recovery.

recovery were strongly affected by heterogeneity (Emami et al., 2008; Nguyen et al., 2015; Seyed and Jalal, 2019), where it have been proved that the strong heterogeneity would cause it is very difficult to effectively sweep reservoir middle-low-permeability layers by displacing fluids even the ineffective circulation of displacing fluids through the high permeability layer. Based on this, it can well be imagined that significant heterogeneity is bound to cause serious problems in two aspects: one is an uneven injection profile and a lower mobilizing energy storage in injected well; another is significantly prevailing channels, higher water cut and low productivity in produced well. Therefore, in order to further noticeably increase oil recovery, it is necessary to seek and develop the displacing fluids with strong heterogeneity control capacity, so that the in-depth crossflow (or bypass) of displacing fluids can be weaken (even avoided) and the sweep volume for middlelow-permeability layers can be greatly enlarged. Over past years, many researches and field pilots involving in-depth profile control, using the preposed cross-linked polymer slug or preformed particle gel (PPG) slug and so forth, have been attempted to control the heterogeneity, and most of them indeed achieved the increase of oil recovery (Wu et al., 2016a, b, c). However, due to the shearing, adsorption retention and chromatographic separation of chemicals, and water infiltration dilution, etc., the cross-linking capacity of polymers is usually an uncontrollable cross-linking process, where the cross-linking strength of polymers is very weak and even the polymer cannot efficiently crosslink in deep reservoir. Thus, it is difficult to achieve the long-term in-depth profile control because of the poorer gel strength, plugging capacity and long-term stability. Moreover, many used cross-linking agents are very adverse to the environment. For those reasons, the scale application of the profile control technology using cross-linking systems has being greatly restricted. It is well-known that, as a linear macromolecule, partially hydrolyzed polyacrylamide (HPAM) has been widely used in CEOR due to its better resistance to biodegradation and significant thickening capacity compared with others polymers such as biopolymers, etc (Lewandowska, 2007; Sabhapondit et al., 2003; Zhang et al., 2011). However, HPAM can only be used as a conventional oil displacing agent and has a limited application range due to its characteristic of single molecular structure. In contrast, associative polymer is a new class of water-soluble polymer, where a small fraction (generally less than 2 mol%) of associating monomer (or amphiphilic monomer) was incorporated into the main water-soluble macromolecular backbone of HPAM. In recent years, due to better thickening capacity, excellent shearing/salinity/temperature resistance and more remarkable viscoelasticity in comparision to HPAM (Chassenieux et al., 2011; Cram et al., 2005; English et al., 2002; Guo et al., 2012; Kujawa et al., 2006; Li et al., 2018; Liu et al., 2012, 2014; Penott-Chang et al., 2007), associative polymer has exhibited enormous potential in chemical EOR and has been proved to be successful in the scale applications for offshore and onshore oil recovery (Bai et al., 2012; Guo et al., 2018; Han et al., 2006; Kang et al., 2011; Wassmuth et al., 2012; Zhou et al., 2007, 2008). More importantly and interestingly, many excellent review articles also have described and indicated that associative polymer could

2. Experimental section 2.1. Materials Gudong (Shengli Oilfield) injection water, which is composed of different ions shown in Table 1, was provided by Research Institute of Petroleum Engineering Technology, Shengli Oilfield Company (Sinopec) and was used as received without further treatment. Simulated heavy oil, which has a shearing viscosity of 200 and 64 mPa·s at 7.34 s−1 under 25 and 70 °C, respectively, was made by diluting Bohai crude oil (the compositions are shown in Table 2) with 0# diesel and filtrating with 200-mesh stainless steel sieve. Associative polymer, AP-X (7952 kDa), was provided by Sichuan Guangya Polymer Chemical Co.,Ltd; partially hydrolyzed polyacrylamide, HPAM (8494 kDa), was provided by Shandong Polymer Bio-Chemicals Co.,Ltd. 2.2. Preparation of polymer solution The stoichiometric polymer powder was weighed and dissolved in Gudong injection water by stirring to prepare polymer mother solution with a concentration of 5000 mg/L at 35 °C and then left still for 24 h. And the polymer stock solutions were prepared by diluting the mother solution to desired polymer concentrations with injection water. Before use, all polymer solutions were filtered with 500-mesh stainless steel sieve and let stand for 2 h. 2.3. Apparent viscosity measurements Apparent viscosity was measured at 70 °C by a Brookfield DV-II ULTRA rheometer (USA) equipped with automatic data recording software, where 00# measuring rotor was used at a speed of 6 rad/min (corresponding to a shear rate of approximately 7.34 s−1). 2.4. Fluorescence measurements The fluorescence measurements were conducted at 70 °C on a

Table 2 Components of bohai crude oil. Components

Saturates hydrocarbon (wt%)

Aromatic hydrocarbon (wt%)

Resin (wt%)

Asphaltene (wt%)

Total acid number (mgKOH/g)

Basic nitrogen value (mg/g)

Content

35.37

23.51

33.71

4.57

7.26

9.47

2

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Flouromax-4 Spectrofluorometer (Japan, HORIBA) with the CzemyTumer excitation/emission monochromator. The excitation and emission wavelengths were 335 nm and 350–550 nm respectively, and the excitation and emission slits were 1 nm. The pyrene-labeled polymer stock solutions were measured in a 1-cm quartz cell. The emission spectra were corrected by eliminating the effect of light source and dark noise during the measurement. 2.5. Rheological measurements Fig. 2. Schematic illustration of long flat-sand-inclusion micro-model.

Zero shearing viscosity (η0), first normal stress difference (N1), and storage/loss modulus (G’/G″) were measured by a Physica MCR301 rheometer (Austria, Anton Paar) equipped with automatic data recording and processing software. η0 and N1 were measured in a shear rate range of 0.01–100 s−1, and G’/G’ were also measured in a shear rate range of 0.01–100 Hz. The measuring system was cone-and-plate geometry system (CP50-1, diameter 49.980 mm, angle 0.997°) and the measuring temperature was 70 °C. All polymer solutions were previously sheared at 20 s−1 for 3 min and then were left still for 20 min before the measurement to eliminate the shear history dependence. During the measurements, a small fraction of simethicone (approximately 0.5 mL) was smeared on the surface of the cone-and-plate to prevent moisture evaporation. 2.6. Threshold pressure measurements The threshold pressures of polymers in porous media were measured through three parallel flat-sand-inclusion micro-models, which were the reusable and quantitative visualization micro-models. Each model has the same size of 6.8 × 7.2 × 0.25 cm (L × W × H). During the experiments, the models were firstly sand-packed with silica sand to achieve different gas permeability of 1000–8000 mD using the previous method,43 and then the models were saturated with simulated oil for 2 h at a constant injection rate of 0.12 mL/min, respectively. Afterwards, the three models were connected according to the schematic illustration shown in Fig. 1. Continuously, polymer solutions were simultaneously injected into the three models at a constant injection pressure to displace the oil. The injection pressure was gradually increased and displacement images were recorded to observe the displacement front until the polymer solution vividly entered into the model and there was continuous effluent, where the corresponding pressures were regarded as the threshold pressures of polymers at different permeability. All experiments were performed at 25 °C.

Fig. 3. Schematic illustration of interstratified connected heterogeneous flatsand-inclusion micro-model.

2.7. Flow and transport in porous media The long flat-sand-inclusion micro-model with a size of 24 × 1.5 × 0.15 cm (L × W × H) was used to investigate the flow and transport in porous media of polymers. The schematic illustration of the model is shown in Fig. 2. During the experiments, the model was also sand-packed firstly to achieve different gas permeability (1000 and 8000 mD) and then was saturated by injection water. On the one hand, polymer solutions were continuously injected into a single model at a constant injection rate of 0.12 mL/min to record the pressure until the pressure tended to be stable. On the other hand, two models with

Fig. 4. Schematic illustration of the interstratified connected heterogeneous core.

Fig. 1. Schematic illustration of three parallel flat-sand-inclusion micro-models. 3

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Fig. 5. Flowchart of the oil macro-displacement experiment in artificial cores.

to perform the oil micro-displacement experiments at 25 °C and the schematic illustration is shown in Fig. 3. By use of the same method described previously, the micro-model was sand-packed with silica sand and saturated with simulated oil. Subsequently, the injection water was injected to displace the oil at a constant rate of 0.12 mL/min until there was no oil effluent from the outlet. And then the polymer solution of 0.5 PV (pore volume) was continuously injected to displace the oil, which was followed by post-water flooding until there was no oil in the outlet again. Before starting the post-water flooding, the injection water was dyed with rhodamine B.

2.9. Oil macro-displacement experiments in interstratified connected heterogeneous core The interstratified connected heterogeneous core with a size of ∅3.8 × 7.0 cm (D × L) was used to perform the oil macro-displacement experiments at 70 °C. The schematic illustration of the core is shown in Fig. 4. The pore throat size distribution of the high permeable layer (8000 mD) and the low one (1000 mD) was 10–20 and 1–7 μm, respectively, which was pre-determined by the high pressure mercury injection test. During the experiments, the cores were dried, evacuated and placed into the core holder to calculate the pore volume and porosity by saturation with injection water. Then the cores were saturated with simulated oil and the injection water as well as polymer solutions were injected with a constant rate of 3 m/d to displace the oil with 2 PV pre-water and 0.5 PV polymer solutions. Moreover, the oil recovery was calculated. The experiment flowchart is shown in Fig. 5. Starting with the water saturation, the core was immediately scanned to obtain the T2 time spectrum by an MacroMR12-150H-I nuclear magnetic resonance (NMR) analyzer (Niumag, China), and then the spectrum was further inversed to calculate the pore throat size distribution after each fluid injection.

Fig. 6. Apparent viscosity of the polymer as a function of polymer concentration.

different permeability were previously connected in parallel and then 0.5 PV polymer solutions were injected into the models at the same injection rate to record the injection pressure, which was followed by post-water flooding until the pressures were steady. Afterwards, the injection pressures were used for further analysis. All experiments were performed at 25 °C.

2.8. Oil micro-displacement experiments in interstratified connected heterogeneous model An interstratified connected heterogeneous flat-sand-inclusion micro-model with a size of 10 × 10 × 0.15 cm (L × W × H) was used 4

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3. Results and discussion 3.1. Thickening capacity of the polymer The apparent viscosity of AP-X and HPAM as a function of polymer concentration in a range of 250–3000 mg/L are plotted in Fig. 6. As shown, the viscosity of AP-X and HPAM increased with increasing polymer concentration, which is consistent with the conventional concentration dependence. The viscosity of HPAM nearly presented a linear variation. Whereas, it can also be noted that unlike HPAM, the viscosity of AP-X first slightly increased in the concentration range of 200–1000 mg/L and then presented a rapid increase once the concentration beyond 1000 mg/L. AP-X has noticeable thickening capacity. The result can be ascribed as the associative effect generated by hydrophobic groups incorporated in associative polymer and the critical position (approximately 1250 mg/L) can be called as critical associating concentration (CAC) (Cram et al., 2005; González and JiménezRegalado, 2011; Kujawa et al., 2004).

Fig. 7. I3/I1 of the polymer as a function of polymer concentration.

2.10. Oil macro-displacement experiments in parallel heterogeneous cores

3.2. Self-association effect of the polymer

The parallel artificial cores with a size of 30 × 4.5 × 4.5 cm (L × W × H) were used to perform the oil macro-displacement experiments at 70 °C and the flowchart is the same as Fig. 5. As mentioned above, the cores were firstly prepared and saturated with simulated oil. Then the cores were connected in parallel, and different displacement fluids (injection water, polymer solutions, and post-injection water) were injected with a constant rate of 3 m/d to displace the oil within total injected volumes of 4 PV, involving 2 PV pre-water, 1 PV polymer solutions and 1 PV post-water. Finally, the enhanced oil recovery on the basis of 2 PV pre-water flooding, RF and RRF were calculated and used for further analysis.

Self-association effect is a unique feature of the polymers with molecular interactions. As for associative polymer, intra- and inter-aggregates even reversible three-dimensional network structures can be formed to impart it excellent properties and unique characteristics through self-associations between the hydrophobic groups on macromolecular chains. Therefore, from pyrene emission spectra, the intensity ratio of the third vibrational band (approximately 383.5 nm) to the first band (approximately 373 nm), namely I3/I1 (Li et al., 1997; Vorobyova et al., 1998; Yekta et al., 1993), was calculated to study the self-association effect of AP-X. The variation curves of I3/I1 as a function of polymer concentration are given in Fig. 7. It can be vividly seen that the I3/I1 of AP-X first enhanced steeply and moderately increased

Fig. 8. η0, N1, and G′/G″ variation curves at a polymer concentration of 2000 mg/L: (a) η0; (b) N1; (c) G′/G″. 5

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Fig. 9. Threshold pressures of AP-X and HPAM in micro-models at different permeabilities: (a) AP-X 1000 mD; (b) AP-X 3000 mD; (c) AP-X 8000 mD; (d) HPAM 1000 mD. Oil and polymer solution is darkly and lightly shaded, respectively.

to a stable value with increasing polymer concentration concerned, and the critical position (1015 mg/L) was very close to the CAC (1250 mg/ L) obtained from viscosity measurements. In contrast, that of HPAM had almost no change at all concentrations concerned. This indicates that AP-X could present significant self-association effect, which enhanced as the concentration increased. Therefore, according to the CAC and taking possible polymer retention and adsorption in porous media into consideration, the polymer concentration of 2000 mg/L was determined to carry out the following study.

Table 3 Threshold pressures of AP-X and HPAM in micro-model at different permeability. Polymers

AP-X HPAM

Threshold pressure (kPa) 1000 mD

3000 mD

8000 mD

70 1.8

56 –

21 –

3.3. Shearing thinning and viscoelasticity of the polymer As shown in Fig. 8a, at a polymer concentration of 2000 mg/L, both

Fig. 10. Injection pressure variation curves of AP-X and HPAM in single long micro-model as a function of injected volumes at a permeability of 8000 mD: (a) AP-X; (b) HPAM. 6

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Fig. 11. Injection pressure variation curves of AP-X in parallel micro-models as a function of injected volumes: (a) 8000 mD; (b) 1000 mD.

Fig. 12. Injection pressure variation curves of HPAM in parallel micro-models as a function of injected volumes: (a) 8000 mD; (b) 1000 mD.

associative polymer (Kaffashi et al., 2005; Wei et al., 2014). More interestingly, it can be vividly seen from that G′ of AP-X was remarkably greater than G″ over entire frequency range concerned. This phenomenon has been previously reported elsewhere (An et al., 2011; Kujawa et al., 2004), where it was considered that the polymers had gel-like properties in the cases. In contrast, G′ of HPAM was mostly smaller than G″ in a wider frequency range, and only a cross point appeared at a higher frequency of approximately 20 Hz. Therefore, compared with HPAM, AP-X has presented gel characteristic in this case, which implies the potential for heterogeneity control. In addition, an interesting phenomenon can also be found from Fig. 8b that the N1 of AP-X firstly increased to be a maximum value and then stepwise decreased within shear rates concerned. Unfortunately, so far, there are no related reports and interpretations on this phenomenon, which is still needed to further investigated and discussed.

the zero shearing viscosity (η0) of AP-X and HPAM noticeably decreased with increasing shear rate, namely presented notable shearing thinning behavior and pseudo-plasticity of the viscoelastic polymer (Al-Sofi et al., 2009). However, compared AP-X with HPAM, it is not difficult to find that at all shear rates concerned, the shearing viscosity of AP-X was significantly greater than that of HPAM. It can also be seen that the shearing viscosity of AP-X with increasing shear rate firstly presented a slow decrease or almost kept a stable value at the lower shear rate range, while then rapidly decreased at higher shear rate. In contrast, HPAM nearly exhibited an identical (or linear) change within all shear rates. The results indicate that AP-X has a better thickening capacity and shear resistance than HPAM at the same concentration. Many literatures have reported the same phenomena and those are ascribed as the associative effect (Cram et al., 2005; Shashkina et al., 2003). First normal stress difference (N1), storage modulus (G′) and loss modulus (G″) are important rheological parameters of polymers, which quantitatively characterize the viscoelastic behavior of polymers and are usually used as the important indicators for screening different chemical working fluids. Among them, N1 and G′ reflect the elastic behavior, while G″ reflects the viscous behavior. In CEOR, many literatures have indicated the viscoelasticity is not only benefit to enhance macroscopic-sweep efficiency but also conducive to improve microscopic-displacement efficiency of polymers (Huh and Pope, 2008; Ranjbar et al., 1992; Urbissinova et al., 2010; Veerabhadrappa et al., 2013; Wang et al., 2000). The variation curves of N1, G′ and G″ at a polymer concentration of 2000 mg/L are shown in Fig. 8b and c. It can be seen that AP-X presented the much higher N1 and G′ than HPAM. This indicates that HPAM has poor elasticity while AP-X has better elasticity than HPAM, which can also be attributed to the unique associative effect of

3.4. Threshold pressures in three parallel flat-sand-inclusion micro-models As shown in Fig. 9, at the lower permeability (1000 mD), the injection pressure of AP-X was noticeably greater than that of HPAM, and the polymer obviously cannot enter into the model until the injection pressure achieved to 70 and 1.8 kPa for AP-X and HPAM, respectively. Even the injection pressures of HPAM at 3000 and 8000 mD were too low to be accurately measured by pressure sensor. Moreover, the injection pressure of AP-X gradually decreased with the increase of the permeability and the pressure corresponded by the entrance into the model at 3000 and 8000 mD was 56 and 21 kPa, separately, which was still significantly higher than that of HPAM at 1000 mD. Not surprisingly, the threshold pressures (shown in Table 3) of AP-X at different permeabilities remarkably kept greater than that of HPAM at lower 7

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Fig. 13. Oil micro-displacement images in interstratified connected heterogeneous micro-model at a permeability contrast of 8 times (8000/1000 mD): (a) AP-X; (b) HPAM. Oil and pre-water (or polymer solution) is darkly and lightly shaded, respectively, and post-water is colorized.

Fig. 14. T2 time spectrum scanned by NMR after each fluid injection in interstratified connected heterogeneous core at a permeability contrast of 8 times (8000/ 1000 mD): (a) AP-X; (b) HPAM.

pressures of AP-X and HPAM could gradually be stable with increasing injected volumes. Moreover, the injection pressures of AP-X were order of magnitude higher than that of HPAM. The results indicated that AP-X could not only present a good flow and conductivity but also establish significantly higher flow resistance than HPAM, which would also be a favorable characteristic to achieve the better profile control. As shown in Figs. 11 and 12, two long flat-sand-inclusion micromodels with a high permeability of 8000 mD and a low permeability of 1000 mD were connected in parallel to simulate the interstratified heterogeneity. It can be seen that the injection pressures of AP-X presented obvious difference with that of HPAM. With starting polymer flooding, the injection pressure of AP-X in high permeable layer rapidly

permeability. The results indicated that compared with HPAM, it needed much greater injection pressure for AP-X to enter into the porous media with the same or higher permeability. In addition, as for AP-X, the threshold pressure decreased from 70 to 21 kPa as the permeability was increased from 1000 to 8000 mD, which would be a favorable characteristic to achieve the better profile control.

3.5. Flow and transport in long flat-sand-inclusion micro-models The injection pressure variation curves of AP-X and HPAM as a function of injected volumes are shown in Figs. 10–13. As shown in Fig. 10, in single long flat-sand-inclusion micro-model, all injection 8

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Fig. 15. Pore throat size distributions after each fluid injection in interstratified connected heterogeneous core at a permeability contrast of 8 times (8000/1000 mD): (a) AP-X; (b) HPAM.

Table 4 Pore throat size distributions and oil recovery results of AP-X and HPAM. Polymers

Porosity (%)

Gas permeability (mD)

Pore throat size distribution (%)

Oil recover (%)

1–7 μm

10–20 μm

Pre-water flooding AP-X HPAM

18.40 18.63

8000/1000 8000/1000

17.73 23.61

Increment

18.47 26.56

0.74 2.95

a

Water saturation

Polymer flooding

Increment

11.76 9.10

11.66 8.35

−0.10 −0.75

Pre-water flooding

Polymer flooding

EOR

31.56 33.80

41.41 40.03

9.85 6.23

b

a

: the difference value of the pore throat size distribution (1–7 μm) before and after polymer flooding, which implies the sweep capacity for low permeable layer. : the difference value of the pore throat size distribution (10–20 μm) before oil saturation and after polymer flooding, which implies the sweep capacity for high permeable layer. b

Fig. 16. Oil macro-displacement curves in two parallel artificial cores at 8000/1000 mD: (a) AP-X; (b) HPAM.

permeable layer, while the HPAM obviously entered into the high and low permeable layers. In the stage of post-water flooding, the postwater mainly entered into the low permeable layer due to the remarkable profile control of AP-X, whereas, the post-water almost entered into the high permeable layer and finally presented breakthrough because of the poorer profile control of HPAM.

exhibited noticeable increase and that in low permeable layer only presented a slight increase at the end of polymer flooding. Moreover, with starting post-water flooding, the injection pressure of AP-X in high permeable layer rapidly decreased and then tended to be stable. Whereas, the pressure in low permeable layer obviously increased and then became steady after post-water flooding. In contrast, the injection pressure of HPAM in high permeable layer had significant increase accompanied by slight increase in low permeable layer once starting the polymer flooding. After post-water flooding, the injection pressure of HPAM in high one slowly decreased to be a stable value, while HPAM only established the pressures in first two pressure taps in low one, which was rapidly closed to zero as the pressures in high one were steady. Obviously, it can be indicated that during the polymer flooding within the injected volumes concerned (0.5 PV), AP-X mainly entered into the high permeable layer preferentially and slightly swept the low

3.6. Oil micro-displacement in interstratified connected heterogeneous micro-model The oil micro-displacement images of AP-X and HPAM in interstratified connected heterogeneous micro-model at a permeability contrast of 8 times (8000/1000 mD) are shown in Fig. 13. It can be seen that the pre-water only could sweep the high permeable layer. After the injection of 0.5 PV polymer solutions, AP-X mainly swept and mobilized 9

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the higher total oil recovery and EOR over the pre-water flooding than HPAM. Obviously, this could be ascribed to the higher RF and RRF leading to a better sweep for the low permeable layer, which can be verified from the fractional flow curves shown in Fig. 18. In Fig. 18, compared with HPAM, the fractional flow of AP-X presented significant difference. During the polymer injection of 1.0 PV, the fractional flow in high permeable layer firstly kept stable and then gradually decreased, especially the decrease was very noticeable after approximately 0.5 PV polymer injection. While that in low permeable layer presented opposite trend. This indicated that AP-X had played a role of profile control as increasing injected volumes during polymer flooding. Moreover, it was unusually that with starting post-water flooding, the fractional flow in high one increased steeply accompanied by the rapid decrease in low one, while the phenomenon quickly reversed after approximately 0.5 PV post-water injection. As a result, it was proved that AP-X had stronger heterogeneity control capacity.

Fig. 17. EOR of AP-X and HPAM in two parallel artificial cores.

4. Conclusions

the oil in high one and also had a slight sweep for low one, while HPAM not only obviously swept the high one but also moderately swept the low one. Moreover, for AP-X, at the starting of post-water injection, the post-water could swept both layers, while the post-water more prevalently swept the low permeable layer with the injection of post-water before the complete sweep for the high permeable layer. In contrast, for HPAM, the post-water mostly swept the high one and exhibited a preferential breakthrough from the high one, while only achieved the smaller sweep for the low one before the breakthrough. This visually confirmed the significant heterogeneity control capability of AP-X.

Compared with HPAM, the thickening property, viscoelasticity, flow resistance generation and reservoir heterogeneity control capacity of associative polymer were experimentally studied and discussed. Some special outcomes and implications are highlighted as follow. (1) Compared with HPAM, associative polymer presented significant thickening property, remarkable self-association effect, noticeable shear-thinning behavior, pseudo-plasticity and viscoelasticity, which could be attributed to the associative interaction between hydrophobic groups. Furthermore, a remarkably greater G′ than G″ over entire frequency range concerned indicated the gel-like properties of associative polymer, which implies the potential for heterogeneity control. (2) At a same polymer concentration, associative polymer needed much greater injection (threshold) pressure than HPAM to enter into the porous media with the same or higher permeability although the pressure significantly decreased as increasing permeability. Additionally, associative polymer could not only present a good conductivity but also establish significantly higher flow resistance. (3) At a greater permeability contrast of 8 times, associative polymer mainly swept the high permeable layer rather than the low layer within the injection of 0.5 PV, and reversed to the low layer after injecting 0.5 PV. More importantly and interestingly, associative polymer could also achieve the fluid diversion of the post-water to efficiently mobilize the oil in low permeable layer and obtain a higher EOR. (4) Thanks to better thickening property and viscoelasticity, higher flow resistance and significant heterogeneity control capacity, associative polymer present enormous application advantages and potential in chemical EOR, which could provide a new system design concept and technical ideas for reservoir heterogeneity control.

3.7. Oil macro-displacement in interstratified connected heterogeneous core The T2 time spectrum scanned by NMR after each fluid injection in interstratified connected heterogeneous core at a permeability contrast of 8 times (8000/1000 mD) is shown in Fig. 14, and the pore throat size distributions as well as the oil recovery results are shown in Fig. 15 and Table 4. Compared AP-X with HPAM, it can be seen that the increment of AP-X in the pore throat size distribution of 1–7 μm before and after polymer flooding was smaller than that of HPAM, and the increment of AP-X in the pore throat size distribution of 1–7 μm before oil saturation and after polymer flooding was also smaller than that of HPAM. This further demonstrated that the AP-X mostly swept the high permeable layer more efficiently and had smaller sweep for low permeable layer within the injected volumes concerned (0.5 PV), which led to the higher EOR of AP-X than HPAM by polymer flooding. 3.8. Oil macro-displacement in two parallel artificial cores The oil macro-displacement curves of AP-X and HPAM in two parallel artificial cores at a permeability contrast of 8 times (8000/1000 mD) are shown in Fig. 16. As shown in Fig. 16, the injection pressures by polymer flooding and post-water flooding of AP-X were also higher than that of HPAM. The oil recovery, EOR results, RF and RRF are shown in Fig. 17 and Table 5. It can be vividly seen that both in the stages of polymer flooding and post-water flooding, AP-X could achieve

Acknowledgments This work was supported financially by the National Science and

Table 5 Oil recovery results of AP-X and HPAM in two parallel artificial cores. Polymers

High/low

Porosity (%)

Gas permeability (mD)

Oil saturation (%)

Oil recovery by prewater flooding (%)

Oil recovery after polymer flooding (%)

Oil recovery after postwater flooding (%)

EOR (%)

RF

RRF

AP-X

High Low Total High Low Total

41.02 38.70 – 40.08 39.74 –

8000 1000 – 8000 1000 –

87.20 83.89 – 86.64 80.31 –

53.27 5.89 29.12 51.69 4.93 27.52

65.23 51.41 58.19 75.53 21.70 47.50

71.91 65.87 68.83 79.96 23.67 50.87

18.64 59.98 39.71 28.27 18.74 23.35

– – 58 – – 24

– – 10 – – 5

HPAM

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Fig. 18. Fractional flow curves in two parallel artificial cores at 8000/1000 mD: (a) AP-X; (b) HPAM.

Technology Major Project, China (grant No. 2016ZX05011-004), ‘TenDragons’ Project of Sinopec, China, and the Key Science and Technology Project of Sinopec, China (grant No. P217007). The authors are grateful for the financial support.

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