The Synergistic Effect of Branched-Preformed Particle Gel and

Jul 6, 2017 - particle gel (B-PPG) is a newly developed chemical agent to ... The results are consistent with the core flood test and confirm that B-P...
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The Synergistic Effect of Branched-Preformed Particle Gel and Hydrolyzed Polyacrylamide on Further-Enhanced Oil Recovery after Polymer Flooding Houjian Gong,*,† Hao Zhang,† Long Xu,*,† Kangning Li,† Long Yu,† Qian San,† Yajun Li,† and Mingzhe Dong‡ †

School of Petroleum Engineering, China University of Petroleum (East China), Qingdao 266580, P. R. China Department of Chemical and Petroleum Engineering, University of Calgary, Calgary T2N 1N4, Canada

‡

ABSTRACT: Polymer flooding is widely and successfully used to enhance oil recovery. How to further enhance oil recovery after polymer flooding becomes an important question that needs to be solved to stabilize oil production. Branched-preformed particle gel (B-PPG) is a newly developed chemical agent to enhance the oil recovery from heterogeneous reservoirs. Here, laboratory experiments were performed to investigate the enhanced oil recovery of B-PPG/hydrolyzed polyacrylamide (HPAM) mixed solutions through heterogeneous porous media by the core flood test. The results show that the B-PPG/HPAM mixed solutions have a higher oil recovery than solutions containing HPAM or B-PPG alone because of the synergistic effect between BPPG and HPAM. B-PPG can adjust flows in different permeability zones by its properties of blocking, deforming, and passing through the throat during flow, which can be proved by the fractional flow behaviors in the parallel-sandpack displacement test. HPAM can not only increase the viscosity of the flooding but also enhance the sustained effect of B-PPG. The resistance factors during the flow of B-PPG/HPAM mixed solutions through heterogeneous porous media were also measured. The B-PPG/ HPAM mixed solutions have higher resistance factors and residual factors than the solutions of HPAM or B-PPG alone. The relationships between oil recovery and resistance factor show that B-PPG/HPAM mixed solutions have better abilities to enhance oil recovery because of the synergistic effect. Furthermore, the microscopic displacement behaviors in the heterogeneous microscopic model were investigated. The results are consistent with the core flood test and confirm that B-PPG and HPAM have the synergistic effect on further-enhanced oil recovery after polymer flooding. flooding. The results showed that oil recovery after polymer flooding can be further increased with the application of polymer solutions with high concentration, including alkaline/ surfactant/cross-linking polymer (ASP) multisystems and zeolite/polymer solutions. For heterogeneous reservoirs, the contribution to the recovery efficiency from increasing the swept volume is higher than that from increasing the oil displacement efficiency. Furthermore, the effects of foam systems with ultralow interfacial tension on the enhanced oil recovery after polymer flooding were investigated.10−12 The results showed that foam flooding has good shutoff and profile control capacity in porous media and can shut off high-permeability formations selectively with good displacement capacity in low-permeability formations, which are not swept after polymer displacement. However, the stability of foam limits its wide application in oilfields because the foam breaks once it meets the oil. Qiao and Zhu13 presented novel gels formed in situ by the reaction between subsequently injected cationic starch and the HPAM remaining in the reservoir formation after the polymer flooding. The formed gel system is more effective in plugging high-permeability zones and can significantly enhance oil recovery. Feng et al.14 investigated gel particle, cross-linking

1. INTRODUCTION In 1964, Pye and Sandiford found that the addition of very small amounts of hydrolyzed polyacrylamide (HPAM) could reduce the mobility of the brine used in water flooding, which resulted in greater oil recovery than that attributable to conventional water flooding.1,2 Since then, polymer flooding has drawn more and more attention. To date, the polymer flooding process has been applied successfully in several major Chinese oil fields such as Daqing and Shengli.3,4 Polymer flooding has been widely applied after water flooding in Daqing Oilfield and Shengli Oilfield. Compared with water flooding, polymer flooding could improve the swept volume, resulting in an enhanced recovery of 10%. However, 50% of the geological reserves still remained in the original reservoirs after polymer flooding.5 With the application of polymer flooding, the conflicts of intra- or interlayer formation heterogeneity were the most influential factors in the development of the main reserves. Consequently, polymer fingering or channeling phenomena occur when the injected polymer solution meets high permeability zones. Therefore, new methods of enhanced oil recovery after polymer flooding are of crucial significance.6 After polymer flooding, a polymer/surfactant mixed system can be used to further enhance the oil recovery by improving the swept volume and increasing the displacement efficiency.7,8 Lu and Zhang9 evaluated the methods to further increase the swept volume and oil displacement efficiency after polymer © XXXX American Chemical Society

Received: April 9, 2017 Revised: May 17, 2017 Published: July 6, 2017 A

DOI: 10.1021/acs.energyfuels.7b01012 Energy Fuels XXXX, XXX, XXX−XXX

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Energy & Fuels

Figure 1 shows a half-packed sandpack with a permeability of 1.77− 3.83 μm2. First, the coarse sand (60−80 mesh) and fine sand (160−

agent, and high effective surfactant multiple systems to enhance oil recovery after polymer flooding. The multiple systems can block the high-permeability layers and channels and improve the whole sweep efficiency. Especially, the presence of surfactant can greatly improve the oil recovery after polymer flooding. Therefore, the utilization of gel to control water mobility is an important method to further enhance oil recovery after polymer flooding. In fact, gel treatment has been already one of the most effective methods to control water mobility in heterogeneous reservoirs or reduce permeability for those reservoirs with fractures or channels.15−20 Recently, a novel branched-preformed particle gel (B-PPG) has been developed and applied in oilfields.21−23 B-PPG is a preformed particle gel with some branched chains. Experiments have shown that BPPG injection can significantly create fluid diversion and increase the swept volume in the low-permeability zones after water injection.23 Polymer flooding can increase the swept volume and enhance the oil recovery by increasing the viscosity of the fluid after water flooding. B-PPG has a weak effect on increasing the viscosity, but it has an excellent elastic property to block, deform, and pass through pore throats during displacement.23 It is not clear whether B-PPG and HPAM have a synergistic effect to further increase the swept volume after polymer flooding. This paper reports laboratory experiments that were performed to investigate the synergistic effect of B-PPG and HPAM on enhanced oil recovery through heterogeneous porous media by the core flood test, measurements of the flow behaviors through heterogeneous porous media, and microscopic displacement experiments in the heterogeneous microscopic model. The objectives of this work were to determine the synergistic effect of B-PPG and HPAM on enhancing oil recovery after HPAM flooding and to understand the mechanisms of enhanced oil recovery using B-PPG/HPAM mixed systems in heterogeneous reservoirs.

Figure 1. Schematic of the heterogeneous sandpack holder. 180 mesh) were respectively packed inside the sandpack holder to determine the weight of the packed sand and the permeability of the homogeneous sandpack holder. For packing of a heterogeneous sandpack, a 120-mesh screen was designed and positioned in the center of the sandpack holder. Coarse sand (60−80 mesh) and fine sand (160−180 mesh) with the half weight used for the whole sandpack holder were packed inside on both sides of the screen to form the heterogeneous layers in the sandpack holder. The 60−80 and 160−180 mesh sand was packed in the sandpack holders using a mechanical hydraulic pump. The required absolute permeability could be obtained by adjusting the mesh of the sand and the applied pressure. The weight of the sand loaded into the sandpack holder was recorded, and the volume of the material was determined accurately for each experiment. The pore volume of the porous media was measured by subtracting the volume of the sand in the core holder from the total volume of the holder. The porosity could be calculated as the ratio of the pore volume to the total volume of the sandpack holder. The absolute permeability of the sandpacks varied between 1.77 and 3.83 μm2, as calculated by Darcy’s law. A pressure transducer was used to measure the injection pressure when the brine was injected through the sandpack holder at different flow rates. The sandpacks were saturated first with the brine and then saturated with crude oil. The crude oil was injected continuously until the water cut was less than 2.0%. The sandpacks underwent initial water flooding until the water cut was larger than 98%. After that, 0.5 pore volume (PV) HPAM solutions with a concentration of 1500 mg·L−1 were injected, and an extended 0.3 PV water flooding was continued. Then, a 0.5 PV B-PPG/HPAM mixed solution was injected, followed by 1.0 PV water flooding. The injection rate of the displacing fluids was controlled at 0.5 mL·min−1. The increment of oil recovery by the BPPG/HPAM slug and extended water flooding was adopted to evaluate the efficiencies of different slugs. 2.3. Measurement of the Resistance Factor and Residual Resistance Factor. A half-packed sandpack that was packed as shown in Figure 1 was also used to measure the resistance factor. Differently from the core flood test, the sandpacks were just saturated with brine. First, the sandpacks underwent initial water flooding until the pressure reached a stable value. The pressure drop between the two ends of the sandpack (ΔP1) was measured. Second, HPAM solutions with a concentration of 1500 mg·L−1 were injected until the pressure reached a stable value, and the pressure drop (ΔP2) was measured. Third, extended water flooding was continued until the pressure reached a stable value, and the pressure drop (ΔP3) was determined. Then the B-PPG/HPAM mixed solution was injected until the pressure reached a stable value, and the pressure drop (ΔP4) was measured. Last, water flooding was carried out until the pressure reached a stable value. At this moment, the pressure drop (ΔP5) was found. In the entire displacement process, the injection rate of the displacing fluids was controlled at 0.5 mL·min−1. The resistance factor is equal to the ratio of the pressure drop across the sandpack during the polymer displacement to that during the initial water flooding.20,24,25 Therefore, the resistance factors of HPAM and B-PPG/HPAM can be calculated by the following equations:

2. EXPERIMENTAL SECTION 2.1. Materials. B-PPG, HPAM, ultrahigh-molecular-weight HPAM (HPAM-U), and crude oil samples were provided by the Geological Scientific Research Institute of Sinopec Shengli Oilfield Company (SINOPEC). The intrinsic viscosity and degree of hydrolysis of HPAM were 2658 mL/g and 20.4%, respectively. The intrinsic viscosity and degree of hydrolysis of HPAM-U were 3677 mL·g−1 and 19.3%, respectively. The crude oil sample from a Shengli oil reservoir used in this study was already divested of water and gas. At the reservoir temperature of 70 °C, the oil had a density of 0.915 g·cm−3 and a viscosity of 37.4 mPa·s. The simulated formation water was prepared in the laboratory using NaCl, CaCl2, and MgCl2·H2O purchased from Sinopharm Chemical Reagent Co., Ltd. (SCRC). The composition of the simulated formation water is shown in Table 1.

Table 1. Composition of the Simulated Formation Water ion concentrations (mg·L−1) Na

+

3419

Mg2+

Ca2+

Cl−

total salinity (mg·L−1)

51

206

5826

9502

2.2. Core Flood Test. The displacement tests were carried out in half-packed sandpack holders that were 30.0 cm in length and 2.5 cm in diameter. Fluid distributors spot-welded with a 200 mesh stainless steel screen were located at both ends of the sandpack holders. The tests were conducted at 70 °C in a temperature-controlled box. B

DOI: 10.1021/acs.energyfuels.7b01012 Energy Fuels XXXX, XXX, XXX−XXX

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Energy & Fuels FR1 = ΔP2/ΔP1

(1)

FR2 = ΔP4 /ΔP3

(2)

3. RESULTS AND DISCUSSION 3.1. Enhanced Oil Recovery of the B-PPG/HPAM Mixed Solution. Because the polymer concentration was 1500 mg·L−1 during polymer flooding in the core flood test, mixed solutions of B-PPG and HPAM with different mass ratios at a total concentration of 1500 mg·L−1 were first chosen. However, the experimental results showed that the oil recovery enhanced by B-PPG/HPAM flooding after HPAM flooding was almost 0. Then the total concentration of B-PPG/HPAM was increased to 2500 mg·L−1, and the results of the core flood test are shown in Table 2. The oil recoveries after polymer flooding were about 60% original oil in place (OOIP). The oil recovery enhanced by B-PPG/HPAM flooding first increased and then decreased with increasing B-PPG percentage in the total polymer content. When the B-PPG percentage was 0, the oil recovery was 9.8% OOIP. This means the subsequent HPAM flooding with a higher concentration (2500 mg·L−1) can also displace some residual oil after 1500 mg·L−1 HPAM flooding. When the B-PPG percentage was 60%, the oil recovery reached the maximum value of 13.4% OOIP. When the B-PPG percentage was 100%, that is, the flooding system was a 2500 mg·L−1 B-PPG solution, the oil recovery was only 2.4% OOIP. It can be seen that when the total amount of B-PPG and HPAM was fixed at 2500 mg·L−1, the mixture of B-PPG and HPAM had a higher oil recovery than the B-PPG-only solution. Meanwhile, when the B-PPG percentage was lower than 60%, the mixture of B-PPG and HPAM also had a higher oil recovery than the HPAM-only solution. The results mean that B-PPG and HPAM have a synergistic effect on further-enhanced oil recovery after polymer flooding if the total concentration is higher than the HPAM concentration during the polymer flooding. In order to further investigate the mechanism of B-PPG/ HPAM mixed solution for oil recovery, the variation of the viscosity of the B-PPG/HPAM mixed solution as a function of the B-PPG content was investigated, and the results are shown in Figure 3. The viscosity of the B-PPG/HPAM mixed solution decreases with increasing B-PPG content. This means that BPPG molecules have a weaker viscosifying action than HPAM. The viscosity of the 1500 mg·L−1 HPAM solution is 12.0 mPa· s. When the total concentration of B-PPG and HPAM is 1500 mg·L−1 and the B-PPG percentage is larger than 20%, the viscosity is lower than 10 mPa·s. The low viscosity may be the major reason that the oil recovery enhancement by 1500 mg· L−1 B-PPG/HPAM flooding after HPAM flooding is almost 0. When the B-PPG percentage is lower than 80% as the total concentration is increased to 2500 mg·L−1, these B-PPG/ HPAM mixed solutions have larger viscosities than the HPAM solution with the concentration of 1500 mg·L−1. However, with increasing B-PPG content, the viscosity values of the B-PPG/ HPAM mixed solution decrease, and the oil recovery increases.

The residual resistance factor is equal to the ratio of the pressure drop across the sandpack during the last water flooding after the polymer displacement to that during the initial water flooding.20,24,25 Therefore, the residual resistance factors of B-PPG and B-PPG/HPAM can be calculated by the following equations: FRR = ΔP5/ΔP1

(3)

2.4. Viscosity Measurements. The experimental solutions of BPPG/HPAM, HPAM, and HPAM-U were prepared by mechanical stirring at the ambient temperature (25 °C). The viscosity measurements were carried out on DV-ii ultraprogrammable rheometer (Brookfield Company, USA) at a temperature of 70.0 ± 0.1 °C. 2.5. Micromodel Test. The heterogeneous micromodel was first cleaned using solvents and water. Then the model was heated in an oven at 400 °C for 1 h to remove any organic material left in order to ensure that the model was strongly water-wet. Before a test, the cleaned model was first evacuated and then saturated with brine and oil. A heterogeneous micromodel after the saturation with brine and oil is shown in Figure 2. After an initial water flooding, injection of

Figure 2. Heterogeneous micromodel after the saturation of brine and oil.

HPAM with a concentration of 1500 mg·L−1 was carried out and followed by subsequent water flooding. Then the B-PPG and HPAM mixed solution was injected, followed by water flooding. The total concentration of B-PPG and HPAM was 2500 mg·L−1, and the mass percentage of B-PPG was 60%. The injection period would be stopped and changed to next one if no oil was produced at the outlet of the micromodel. A syringe pump was used to inject the fluids at an injection rate of 1.5 μL·min−1.

Table 2. Summary of Core Flood Tests with 2500 mg·L−1 B-PPG/HPAM Mixed Solutions B-PPG content (mass %)

porosity (%)

permeability (μm2)

initial oil saturation (%)

oil recovery after HPAM flooding (% OOIP)

oil recovery after B-PPG/ HPAM flooding (% OOIP)

oil recovery enhanced by B-PPG/ HPAM flooding (% OOIP)

0 20 40 60 80 100

40.7 42.3 41.8 40.4 41.5 41.9

2.38 2.69 2.58 2.34 2.55 2.54

80.3 83.1 82.5 80.2 82.3 82.4

59.8 60.8 60.5 60.8 59.6 59.5

69.6 71.6 72.9 74.2 68.9 61.9

9.8 10.8 12.4 13.4 9.3 2.4

C

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Figure 3. Viscosity variation of B-PPG/HPAM mixed solution as a function of B-PPG content.

Figure 4. Enhanced oil recovery as a function of viscosity ratio of flooding solution to oil.

This means that it is essential that the viscosity of the subsequent B-PPG/HPAM flooding solution is higher than that of the polymer flooding system. The increase in viscosity can enhance the swept volume of the subsequent flooding to raise the oil recovery. Meanwhile, with increasing B-PPG percentage, although the viscosity of the mixed solution decreases, the BPPG molecules can block the channel in high-permeability zones to further increase the swept volume. The results show that the effect of B-PPG on the enhanced oil recovery is larger than the further increase in viscosity when the viscosity of the B-PPG/HPAM mixed solution is higher than that of the previous HPAM flooding. To investigate what effect the increase in viscosity has on the enhanced oil recovery, HPAM with ultrahigh molecular weight was chosen as the flooding system after HPAM flooding. The results of the core flood tests with HPAM-U solution and the viscosity of the HPAM-U solution are summarized in Table 3. It can be seen that the 1500 mg·L−1 HPAM-U solution has an oil recovery of 7.3% after HPAM flooding because the HPAMU has a higher viscosity than HPAM. This means that the increase in viscosity can enhance the oil recovery after polymer flooding. When the concentration of HPAM-U is increased to 2000 mg·L−1, the oil recovery can increase to 9.7% OOIP. However, when the concentration of HPAM-U is further increased, the oil recovery is not enhanced. The results show that the oil recovery can be enhanced by the increase in viscosity to some extent but is not enhanced all the time with the increase in viscosity. Figure 4 shows the relationship between oil recovery and the ratio of the viscosities of the flooding solution and oil. It is clear that the B-PPG/HPAM mixed solutions have larger oil recoveries than HPAM-U. That is, the enhanced oil recovery is greater by application of the B-PPG/HPAM mixed solution than by increasing the viscosity by application of the HPAM-U solution. Therefore, the B-PPG/HPAM mixed solution can further enhance the oil recovery after polymer flooding if the

viscosity of the B-PPG/HPAM flooding system is higher than that of the previous HPAM flooding solution. B-PPG and HPAM have synergistic effects on the enhanced oil recovery. Parallel-sandpack displacement tests were also carried out to prove the effect of B-PPG on the swept volume. The total concentration of B-PPG and HPAM was 2500 mg·L−1, and the B-PPG percentage was 60%. The curve of the fractional flow of produced liquid (including oil and brine) as a function of injected pore volume in the parallel-sandpack displacement test is shown in Figure 5. It can be seen that during the water

Figure 5. Fractional flow curve of the parallel-sandpack displacement test.

flooding period, the flow in the high-permeability sandpack first decreases and then increases while the flow in the lowpermeability sandpack first increases and then decreases gradually. After 0.5 PV water flooding, the fractional flow

Table 3. Summary of Core Flood Tests with HPAM-U Solution

HPAM-U concentration (mg·L )

viscosity of the flooding solution (mPa·s)

porosity (%)

1500 2000 2500 3000

16.5 31.7 55.6 76.4

41.4 42.8 40.1 44.5

−1

D

permeability (μm2)

initial oil saturation (%)

oil recover after HPAM flooding (% OOIP)

2.34 2.26 2.23 2.38

82.1 86.9 86.1 83.7

60.4 61.8 62.1 62.7

oil recover after HPAM-U flooding (% OOIP)

oil recover enhanced by HPAM-U flooding (% OOIP)

67.7 71.5 71.6 72.5

7.3 9.7 9.5 9.8

DOI: 10.1021/acs.energyfuels.7b01012 Energy Fuels XXXX, XXX, XXX−XXX

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the high-permeability sandpack and make more solution flow into the low-permeability sandpack. Sang et al.23 studied the flow and displacement behaviors of B-PPG after water flooding, the results showed that the same flow diversion behaviors happen for the B-PPG/HPAM mixed solutions. It is different that the fluctuated flow behaviors in the high- and low-permeability sandpacks disappear during the extend water flooding for the B-PPG-only solution and the lowpermeability sandpack has a higher flow than the highpermeability one. For the B-PPG/HPAM mixed solution, the flow diversion behaviors continuously happen for a period after the extended water flooding. The results further prove that BPPG and HPAM have a synergistic effect on the enhanced oil recovery. The presence of HPAM in the mixed solutions can not only increase the viscosity but also enhance the sustained effect of B-PPG, which can make the flow diversion and enhance the swept volume during the subsequent water flooding. 3.2. Resistance Factor and Residual Resistance Factor of the B-PPG/HPAM Mixed Solution. In the B-PPG/HPAM mixed solutions, HPAM can increase the viscosity of the flooding solution and B-PPG can adjust the flows in heterogeneous media. Furthermore, B-PPG and HPAM have a synergistic effect on enhancing the sustained effect of B-PPG. The above effect can make the mixed solution have a higher oil recovery than solutions containing only HPAM or B-PPG. In order to prove these effects, the resistance factor and residual resistance factor of the B-PPG/HPAM mixed solutions during the flow process in half-packed sandpacks were measured, and the results are shown in Table 5. When the B-PPG percentage is 0, that is, when just an HPAM solution with a concentration of 2500 mg·L−1 is flowed after the 1500 mg·L−1 solution, the resistance factors for the 2500 and 1500 mg·L−1 HPAM solutions are 33.6 and 24.7, respectively. The increase in the HPAM concentration can enhance the resistance factor significantly because of the enhancement of the viscosity. The resistance factor for the B-PPG solution with a concentration of 2500 mg·L−1 is 29.9, which is larger than that of the 1500 mg· L−1 HPAM solution and smaller than that of the 2500 mg·L−1 HPAM solution. This means that B-PPG can increase the resistance factor after the flow of HPAM, but the degree of improvement is lower than for HPAM with the same concentration. The degrees of improvement for B-PPG/ HPAM mixed solutions are much larger than for the HPAMonly or B-PPG-only solution. When the B-PPG percentage is 40%, the resistance factor of the mixed solution is the highest. Meanwhile, the residual resistance factor also shows the same changing trend as the resistance factor. B-PPG and HPAM can affect the resistance factor by different mechanisms: HPAM can increase the viscosity of the solution, and B-PPG can block the high-permeability zone and divert the flow to the lowpermeability zone. The B-PPG/HPAM mixed solutions have

ratio through the two sandpacks is 100:0, i.e., there is nearly no flow in the low-permeability sandpack. During the HPAM flooding, the fractional flow in the high-permeability sandpack decreases while the fractional flow in the low-permeability sandpack increases. After 0.3 PV HPAM flooding, the ratio of fractional flows through the the two sandpacks is 80:20. However, after the subsequent water flooding, the fractional flow ratio becomes 100:0. Then during the B-PPG/HPAM flooding, the fractional flow in the high-permeability sandpack decreases greatly and the fractional flow in the low-permeability sandpack increases quickly. It is clear that the two fractional flow curves fluctuate alternately. During the subsequent water flooding, the two fractional flow curves also fluctuate alternately. Then the fractional flow in the low-permeability sandpack is higher than that in the high-permeability sandpack. The above fractional flow behavior of the B-PPG/HPAM mixed solution in the parallel sandpack tests illustrates the blocking-and-passing feature of the B-PPG system in heterogeneous porous media. The experiments also show that B-PPG molecules have a better ability than HPAM to adjust flows in different zones of a heterogeneous medium and improve the sweep efficiency. The oil recovery summary of the parallel-sandpack displacement test with B-PPG/HPAM mixed solution is listed in Table 4. It can be seen that the oil recovery of the high-permeability Table 4. Summary of the Parallel-Sandpack Displacement Test with B-PPG/HPAM Mixed Solution enhanced oil recovery (% OOIP)

after HPAM flooding

after BPPG/ HPAM flooding

incremental recovery of HPAM flooding

incremental recovery of B-PPG/ HPAM flooding

46.8

70.7

82.8

23.9

12.1

26.7

43.3

74.2

16.6

30.9

36.5

56.8

78.3

20.3

21.5

water sandpack type flooding high permeability low permeability total

sandpack is 20.1% higher than that of the low-permeability one. During HPAM flooding, the difference in the incremental recovery between the two sandpacks decreases to 7.3% from the value of 20.1% in the water flooding. This means that the HPAM solution can flow into the low-permeability sandpack and displace the oil more than the brine. The total oil recovery after B-PPG/HPAM flooding in the high-permeability sandpack is just 8.6% larger than that in the low-permeability one, while the incremental recoveries of B-PPG/HPAM flooding in the high- and low-permeability sandpacks are 12.1% and 30.9%, respectively. That is, the recovery in the lowpermeability sandpack is higher than that in the highpermeability one. This result shows that the B-PPG can block

Table 5. Parameters for B-PPG/HPAM Mixed Solutions during the Flow Process in Half-Packed Sandpacks B-PPG content (mass %)

porosity (%)

permeability (μm2)

viscosity (mPa·s)

FR1

FR2

FRR

0 20 40 60 80 100

41.2 42.5 41.3 40.2 42.3 41.7

2.39 2.69 2.45 2.35 2.67 2.52

15 13.5 12.2 12.0 11.5 9.5

24.7 26.4 24.9 23.9 26.3 25.5

33.6 39.6 70.4 64.5 40.5 29.9

3.3 2.8 6.7 6.1 3.6 3.8

E

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Energy & Fuels larger resistance factors and residual resistance factors than the HPAM-only and B-PPG-only ones because of the synergistic effect of B-PPG and HPAM. The curves of oil recovery versus FR2 are shown in Figure 6. The compositions of the B-PPG/HPAM solutions and the

Figure 7. Distributions of oil in the micromodel at different flooding stages: (A) after water flooding; (B) after HPAM flooding; (C) after subsequent water flooding; (D−G) after B-PPG/HPAM flooding at different pore volumes; (H) after subsequent water flooding.

zone is displaced than in the high-permeability zone. At last, half of the saturated oil is residual in the model, and some zones, e.g., the bottom of the model, are never swept. Figure 7C shows the distribution of oil after subsequent water flooding. The water flow can break through quickly, and only a little residual oil can be displaced at this stage. Figure 7D−G shows the distributions of oil in the micromodel at different flooding stages during B-PPG/HPAM flooding at different pore volumes. It is notable that the B-PPG/HPAM solution first flows through the water channels in the high-permeability zone. When the flow resistance becomes higher with more B-PPG/ HPAM flow into the water channels, the fluid is diverted to the low-permeability zones. B-PPG has the ability to plug pore throats of different sizes and can adjust the flow between the different permeability zones to eventually recover the substantial residual oil in both the high- and low-permeability zones by HPAM flooding. More residual oil is displaced and more zones are swept. After the B-PPG/HPAM flooding, only 20−30% of the saturated oil is residual in the model, especially in the right part of the model. After subsequent water flooding, most of the residual oil is displaced again and there is only a little residual oil in the model. The results of the micromodel experiments confirm that B-PPG and HPAM have a synergistic effect. The B-PPG/HPAM mixed solutions not only can increase the viscosity of the flooding system but also have a dynamic and flow-diverting ability to displace more residual oil. B-PPG/HPAM can displace most of the residual oil after HPAM flooding. Figure 8 shows the distributions of oil in the micromodel before and after the B-PPG/HPAM flooding procedure in the high- and low-permeability zones. Figure 8A shows the discontinuous and continuous residual oil in two different zones with high permeability before B-PPG/HPAM flooding. After HPAM flooding, there is still some amount of residual oil in the continuous and discontinuous states. The HPAM solutions flow according to the formed water channels and cannot displace more residual oil. Figure 8B shows the distribution of oil in the micromodel after the B-PPG/HPAM flooding procedure in the corresponding high-permeability zones. It is notable that both the continuous and discontinuous residual oil is displaced by the subsequent HPAM/PPG flooding. Figure 8C,D shows the case in the low-permeability zones before and after B-PPG/HPAM flooding. The displacement effect of the B-PPG/HPAM on the residual oil is more

Figure 6. Relationship between oil recovery and FR2.

concentrations of HPAM-U are the same as those investigated in Tables 2 and 3. The B-PPG/HPAM mixed solutions have much larger resistance factors than HPAM-U, though HPAM-U has a higher concentration than the mixed B-PPG/HPAM. The oil recovery during the HPAM-U flooding period after HPAM flooding first increases quickly and then reaches a plateau as the resistance factor increases. The oil recovery of the mixed BPPG/HPAM flooding is enhanced with increasing resistance factor. When FR2 is lower than 40, the oil recovery increases quickly with the resistance factor. When FR2 is higher than 40, the growth trend is slowed. Meanwhile, when the mixed solution has a reasonable resistance factor, which is higher than 40, the B-PPG/HPAM mixed solution can have a higher oil recovery than HPAM-U. The results also show that B-PPG and HPAM have a synergistic effect on increasing the resistance factor, which can improve the swept volume accordingly to enhance the oil recovery. 3.3. Microscopic Displacement of the B-PPG/HPAM Mixed Solution after Polymer Flooding. A micromodel designed with two different permeability zones was used to investigate the mechanism of oil displacement of B-PPG/ HPAM mixed solution after HPAM flooding. Figure 7 shows the distributions of oil in the micromodel at different flooding stages. After water flooding, many of the pores in the highpermeability zone (upper section of the photo) are swept, and the connected channel for water flow is formed (Figure 7A). Once the channel is formed, water flows in the channel so that there is little oil displaced again. In the low-permeability zone, some of the pores are swept, but the area swept is much less than that in the high-permeability zone. No water channels are formed in the low-permeability zone. Figure 7B shows the distribution of residual oil after HPAM flooding. When the HPAM solution is injected after water flooding, more oil is displaced again, neither in the high-permeability zone nor the low-permeability zone. The oil and water are redistributed after polymer flooding. The channels are formed in both the highand low-permeability zones. More oil in the low-permeability F

DOI: 10.1021/acs.energyfuels.7b01012 Energy Fuels XXXX, XXX, XXX−XXX

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ACKNOWLEDGMENTS We gratefully acknowledge financial support from the National Natural Science Foundation of China (Grant 51204197), the Fundamental Research Funds for the Central Universities (17CX05005), and the Program for Changjiang Scholars and Innovative Research Team in University (IRT1294).

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Figure 8. Distributions of oil in the micromodel before and after the B-PPG/HPAM flooding procedure in the high- and low-permeability zones: (A) two different zones with high permeability before B-PPG/ HPAM flooding; (B) the corresponding zones with high permeability after B-PPG/HPAM flooding; (C) two different zones with low permeability before B-PPG/HPAM flooding; (D) the corresponding zones with low permeability after B-PPG/HPAM flooding.

notable in these zones than that in the high-permeability zones. B-PPG has a more excellent elastic property than HPAM, allowing it to deform and pass through pore throats during displacement. Due to this property, B-PPG can displace the continuous and discontinuous residual oil. Furthermore, HPAM can not only increase the viscosity of the flooding but also enhance the sustained effect of B-PPG. Therefore, the BPPG/HPAM mixed solutions have a synergistic effect on enhanced oil recovery by displacing both the continuous and discontinuous residual oil after polymer flooding.

4. CONCLUSIONS Laboratory experiments have been carried out to investigate the synergistic effect of B-PPG and HPAM on further-enhanced oil recovery after HPAM flooding. The core flood tests and the flow and micromodel experiments show that the B-PPG/ HPAM mixed solutions have a higher oil recovery than the HPAM- and B-PPG-only solutions after HPAM flooding. Meanwhile, the B-PPG/HPAM mixed solutions have a higher oil recovery than the polymer HPAM-U, which has a higher viscosity than the mixed solutions. Furthermore, the B-PPG/ HPAM mixed solutions have higher resistance factor and residual resistance factor than the HPAM-only and B-PPG-only solutions. The B-PPG/HPAM mixed solutions can displace both the continuous and discontinuous residual oil to enhance the oil recovery. These results mean that the increase in viscosity is essential to enhance the oil recovery after polymer flooding. Except for this effect, B-PPG can adjust flows in different zones of a heterogeneous medium by its properties of blocking, deforming, and passing through the throat during flow. HPAM can not only increase the viscosity of flooding but also enhance the sustained effect of B-PPG. Therefore, B-PPG and HPAM have a synergistic effect, which can further enhance the oil recovery after polymer flooding.

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AUTHOR INFORMATION

Corresponding Authors

*E-mail: [email protected]. *E-mail: [email protected]. ORCID

Houjian Gong: 0000-0002-3304-1605 Long Xu: 0000-0003-1859-6538 Notes

The authors declare no competing financial interest. G

DOI: 10.1021/acs.energyfuels.7b01012 Energy Fuels XXXX, XXX, XXX−XXX